Patent Publication Number: US-2005137094-A1

Title: Subterranean formation treatment fluids and methods of using such fluids

Description:
CROSS-REFERENCE TO RELATED APPLICATION  
      This Application is a Continuation-in-Part of U.S. application Ser. No. 10/254,268, filed Sep. 25, 2002, which is a divisional of U.S. application Ser. No. 09/879,634, filed on Jun. 11, 2001, now U.S. Pat. No. 6,488,091. 
    
    
     BACKGROUND OF THE INVENTION  
      The present invention relates to methods and compositions for treating subterranean well formations, and more specifically, to improved subterranean formation treating fluids and methods of using such treating fluids in subterranean formations.  
      Producing subterranean formations penetrated by well bores are often treated to increase the permeabilities or conductivities thereof. One such production stimulation treatment involves fracturing the formation using a viscous treating fluid. That is, the subterranean formation or producing zone therein is hydraulically fractured whereby one or more cracks or “fractures” are produced or enhanced. Fracturing may be carried out in wells that are completed in subterranean formations for virtually any purpose. The usual candidates for fracturing or other stimulation procedures are production wells completed in oil and/or gas containing formations. However, injection wells used in secondary or tertiary recovery operations for the injection of fluids may also be fractured in order to facilitate the injection of fluids.  
      Hydraulic fracturing may be accomplished by injecting a viscous fracturing fluid into a subterranean formation or zone at a rate and pressure sufficient to enhance or create one or more fractures in a desired location within the formation. As the fracture is created a portion of the fluid contained in the viscous fracturing fluid leaks off into the permeable formation and a filter cake comprised of deposited gelling agent may be built up upon the walls of the fracture which then helps to prevent or reduce further fluid loss from the fracturing fluid to the formation. The continued pumping of the viscous fracturing fluid may extend the fractures. Proppant, such as sand or other particulate material, may be suspended in the fracturing fluid and introduced into the fractures. The proppant particulates function to prevent the fractures from closing upon reduction of the hydraulic pressure and thereby leave conductive channels through which fluids may flow to the well bore upon completion of the fracturing treatment.  
      The fracturing fluid should have a sufficiently high viscosity to retain the proppant particulates in suspension as the fracturing fluid flows into the created fractures; A viscosifier has heretofore often been used to increase the viscosity of a base fluid. After the viscosified fracturing fluid has been pumped into the formation and fracturing of the formation has occurred, the fracturing fluid generally has been caused to revert into a low viscosity fluid for removal from the formation by breaking the viscosified fluid. The breaking of viscosified fracturing fluids has commonly been accomplished by using a breaker with the fracturing fluid.  
      The fracturing fluids used heretofore have predominantly been water-based liquids containing a gelling agent comprised of a polysaccharide such as guar gum. Guar and derivatized guar polymers such as hydroxypropylguar are water soluble polymers that may be used to create high viscosity in a fluid and may be readily crosslinked to further increases the viscosity of the fluid. While the use of gelled and crosslinked polysaccharide fracturing fluids has been highly successful, such fracturing fluids have not been thermally stable at temperatures above about 200° F. That is, the highly viscous gelled and crosslinked fluids may lose viscosity with time at high temperatures. To offset the loss of viscosity, the concentration of the gelling agent may be increased, which results in, among other things, increased costs and increased friction pressure in the tubing through which the fluid is injected into a subterranean formation which makes pumping of the fracturing fluids more difficult. Thermal stabilizers such as sodium thiosulfate have been included in the fracturing fluids to scavenge oxygen and thereby increase the stabilities of the fracturing fluids at high temperatures. However, the use of thermal stabilizers may also increase the cost of the fracturing fluids.  
      Another problem that has been experienced in the use of gelled and crosslinked polysaccharide fracturing fluids involves the breaking of such fracturing fluids after fractures have been formed. Breakers such as oxidizers, enzymes, and acid release agents that attack the polymer backbone have been used successfully.  
      In order to make the heretofore used gelled and crosslinked polysaccharide fracturing fluids carry sufficient proppant, the concentration of the crosslinking agent used has often had to be increased which in turn increases the cost and viscosity of the fracturing fluid. The water based fracturing fluids including gelled and crosslinked polysaccharide gelling agents have had significantly reduced fluid loss as compared to other fracturing fluids which reduces or eliminates the need for costly fluid loss additives. However, because the gelled and crosslinked polysaccharides have had high molecular weights, the filter cake produced from the viscous fracturing fluid on the walls of well bores penetrating producing formations and in fractures formed therein is often very difficult to remove.  
      Another problem experienced in the use of a water based fracturing fluid including a gelled and crosslinked polysaccharide gelling agent is that it often must be mixed in holding tanks for a considerable length of time for hydration of the gelling agent to occur. During the fracturing process carried out in a well, the hydrated fracturing fluid generally is pumped out of the holding tanks, mixed with proppant and other additives on the fly and pumped down the well bore to the formation being fractured. If, during the job, the down hole pressure profile and other parameters that are obtained in real time indicate that a change in the fracturing fluid properties is required, that is, a change in the fracturing fluid viscosity to prevent a screen out of the fracture or the like, it is generally risky to do so since it takes a very long time for a change to be made and for the changed fracturing fluid to reach the formation being fractured. Another problem related to pumping the fracturing fluid from holding tanks and combining the proppant material, crosslinker, and other additives used on the fly is that the procedure requires the use of expensive equipment.  
      Additionally, in many environmentally sensitive areas, the water based fracturing fluids containing polysaccharide gelling agents must be recovered from the well and disposed of by environmentally appropriate means, which increases the overall cost of the fracturing treatment.  
      Certain types of subterranean formations, such as certain types of shales and coals have been observed to respond unfavorably to fracturing with conventional fracturing fluids. For example, in addition to opening a main, dominant fracture, the fracturing fluid may further invade numerous natural fractures (or “butts” and “cleats,” where the formation comprises coal) intersecting the main fracture, thereby permitting conventional gelling agents within the fracturing fluid to invade such intersecting natural fractures. When these openings re-close at the conclusion of fracturing, the conventional gelling agent may become trapped therein, which, among other things, may inhibit the production of hydrocarbons from the natural fractures to the main fracture. Further, even in circumstances where the gelling agent does not become trapped within the natural fractures, a thin coating of the gel may nevertheless remain on the surface of the natural fractures after the conclusion of the fracturing operation. This may be problematic, among other things, where the production of hydrocarbons from the subterranean formation involves processes such as desorption of the hydrocarbon from the surface of the formation, rather than production of hydrocarbons stored in interconnected pore spaces such as those found in more conventional oil and gas reservoirs. Previous attempts to solve these problems have involved the use of less viscous fracturing fluids, such as non-gelled water. However, this is problematic, among other things, because such fluids may prematurely dilate natural fractures perpendicular to the main fracture a problem referred to as “near well bore fracture complexity,” or “near well bore tortuosity.” This is problematic because the creation of multiple fractures, as opposed to one or a few dominant fractures, results in reduced penetration into the formation, i.e., for a given injection rate, many short fractures are created rather than one or a few lengthy ones. This is problematic because in low permeability formations, the driving factor to increase productivity is the fracture length. Furthermore, the use of less viscous fracturing fluids has typically also required excessive fluid volumes and/or excessive injection pressure. The excessive entry pressure may frustrate attempts to place proppant into the fracture, causing the fracturing operation to fail in its attempt to increase hydrocarbon production.  
     SUMMARY OF THE INVENTION  
      The present invention relates to methods and compositions for treating subterranean well formations, and more specifically, to improved subterranean formation treating fluids and methods of using such treating fluids in subterranean formations.  
      One embodiment of the present invention provides a treatment fluid comprising water, a crosslinking agent, and a substantially fully hydrated depolymerized polymer having a C* of at least about 0.27.  
      Another embodiment of the present invention provides a method of treating a portion of a subterranean formation comprising preparing a treatment fluid comprising water, a crosslinking agent, and a substantially fully hydrated depolymerized polymer having a C* of at least about 0.27; and, contacting the portion of the subterranean formation with the treatment fluid.  
      Another embodiment of the present invention provides a method of fracturing a portion of a subterranean formation comprising preparing a treatment fluid comprising water, a crosslinking agent, and a substantially fully hydrated depolymerized polymer having a C* of at least about 0.27; and, placing the treatment fluid into the portion of the subterranean formation at a pressure sufficient to create or extend at least one fracture therein.  
      The objects, features and advantages of the present invention will be readily apparent to those skilled in the art upon a reading of the description of the preferred embodiments that follows.  
    
    
     BRIEF DESCRIPTION OF THE DRAWINGS  
       FIG. 1 : Determining c*.  
    
    
     DESCRIPTION OF PREFERRED EMBODIMENTS  
      The present invention relates to methods and compositions for treating subterranean formations, and more specifically, to improved subterranean formation treatment fluids and methods of using such concentrated and fluids in subterranean formations.  
      The present invention provides an improved subterranean formation treating fluid that, in certain embodiments, may be prepared on the job site in a very rapid manner from a substantially fully hydrated subterranean formation treating fluid concentrate. In some embodiments, a treating fluid concentrate may be produced at an off-site manufacturing location and may be stored for a period of time prior to or after being transported to the job site. The improved subterranean formation treating fluid may then be prepared at the job site by simply mixing the substantially fully hydrated treating fluid concentrate with additional water and any desired additives not already contained in the concentrate. When a treatment concentrate of this invention is mixed with additional water and any other desired additives to form a treatment fluid, no additional hydration time is required as the treatment concentrate is already substantially fully hydrated.  
      The preparation of the treatment fluids generally involves the steps of metering the treatment fluid concentrate into a blender wherein it may be mixed with the additional water and additives. The mixture may then be substantially simultaneously pumped out of the blender and into the subterranean formation to be treated by way of a well bore penetrating it. In such a method, the time lapse from when the metering, mixing, and pumping process starts to when the treatment fluid reaches the subterranean formation may be only a few minutes. This allows changes in the properties of the treatment fluid to be made on the surface as required during the time the treating fluid is being pumped. For example, in a fracturing procedure carried out in a subterranean formation to stimulate production from the subterranean formation, changes may be made to the fracturing fluid during the pumping of the fluid in response to continuously monitored down hole parameters to achieve desired fracturing results, that is, the viscosity of the fracturing fluid, the amount of proppant material carried by the fracturing fluid and other properties of the fracturing fluid can be continuously measured on the surface and changed as required to achieve optimum down hole treatment results in real time.  
      The subterranean formation treatment fluids of the present invention generally comprise water and a substantially fully hydrated depolymerized polymer. Oftentimes, the treatment fluids of the present invention further comprise a crosslinking agent.  
      The hydratable polymer that is depolymerized to create the substantially fully hydrated depolymerized polymers of the present invention may be substantially any polysaccharide; in some embodiments it is guar. In other embodiments, the hydratable polymer is a guar derivative hydroxypropylguar, carboxymethylhydroxypropylguar, carboxymethylguar, hydroxyethyl cellulose, hydroxyethyl cellulose grafted with glycidol or vinyl phosphonic acid, carboxymethyl cellulose, carboxymethylhydroxyethyl cellulose, and the like. Of these, depolymerized hydroxypropylguar may be preferred. Alternatively, the polymer may be a synthetic polymer formed from lower molecular weight monomers that are polymerized until a desired molecular weight is achieved.  
      The substantially fully hydrated depolymerized polymer may be manufactured by any method known in the art. In one such method, a hydratable polymer having a relatively high molecular weight may be subjected to extensive depolymerization whereby the polymer backbone is divided into relatively short chain polymer segments. In some cases, the hydratable polymer may be derivatized. Such polymers may be made by derivatization and depolymerization techniques known in the art. Some such suitable methods of manufacture are described in U.S. patent application Ser. No. 10/793,705, filed on Mar. 5, 2004, the relevant disclosure of which is incorporated herein by reference. Other suitable methods of manufacture are described in U.S. patent application Ser. No. 10/170,113 filed Jun. 10, 2001, the relevant disclosure of which is incorporated herein by reference. In one embodiment, the depolymerized polymer of the present invention may be prepared by adding a polymer (such as a polysaccharide or a derivatized polysaccharide) to be depolymerized to a reactor vessel together with a quantity of hydrogen peroxide and water. The reactor vessel may be heated to an elevated temperature, such as about 100° F., to initiate the reaction in cases wherein the ambient temperature is insufficient to initiate the reaction. Once initiated, the depolymerization reaction is exothermic and the temperature of the reactor vessel generally should be maintained in the range of from about 100-200° F. for a sufficient time for the polymer to degrade to the desired molecular weight.  
      If desired for purposes of transportation, storage or otherwise, the depolymerized polymer may be stored in dry form and, when needed, can be rehydrated to form a treatment fluid. The water used to form the treatment fluids of the present invention may be fresh water, unsaturated salt water (including brines and seawater) or saturated salt water.  
      Generally, the depolymerized polymer has an average molecular weight in the range of from about 25,000 to about 1,500,000. In certain embodiments, the depolymerized polymer has an average molecular weight in the range of from about 50,000 to about 1,000,000. In certain preferred embodiments, the depolymerized polymer has an average molecular weight in the range of from about 50,000 to about 400,000. In certain preferred embodiments, the depolymerized polymer has an average molecular weight in the range of from about 100,000 to about 250,000. In certain embodiments, the depolymerized polymer has a polydispersity ratio of from 1 to about 12 as determined by gel permeation chromatography as disclosed in “Practical High Performance Liquid Chromatography” edited by C. F. Simpson (Hyden &amp; Son Ltd.,  1976 ). The polydispersity ratio of polysaccharides or other polymers generally can range from about 2 to as much as 250.  
      In determining the amount of depolymerized polymer to add to the water, the concentration chosen should be selected to be greater than or equal to the critical overlap concentration (C*) of the polymer used to create the viscosified treatment fluid. C* may be described as that concentration necessary to cause polymer chain overlap, that is, the concentration above which the viscosity of a fluid containing the depolymerized polymer is influenced not just by the weight percent of the individual polymer strands, but also by the interaction of the individual polymer strands with one another. C* is a concentration value expressed in “true gum lbs./M gallons” or “true percent” that denotes the concentration of viscosifying agent (polymer) needed for optimum viscosity formation. As described in more detail below, C* may be determined by measuring the viscosity of several concentrations of the gel former in water. While C* is related to molecular weight, it is only directly related within the same polymer in the same solution environment having different molecular weights. By way of example, a guar polymer having a molecular weight of 400,000 will likely have a different C* than a derivatized guar polymer having the same molecular weight. Moreover, changing the environment can effect that C* of a polymer, for example, a guar polymer having a molecular weight of 400,000 will exhibit one C* in fresh water, but a different C* when methanol or some salt is added to the water. one skilled in the art will recognize the effect that additives such as methanol and salt can have on C* based on the expanding and contracting effect they have on the polymer itself in the water.  
      For relatively long polymer strand polymers, such as native guar, the C* generally ranges from 0.19 to 0.22. The depolymerized polymer used in the present invention, the C* is generally at least about 0.27. This higher C* concentration yields a viscosified fluid that may exhibit a greater gel stability. Generally, those skilled in the art minimize the weight percent of polymer in a fluid in an attempt to keep the fluid easily pumpable, to reduce polymer costs, and to make it easier to regain formation conductivity when a job is complete. This has meant that the polymer concentration has been kept below 0.22 weight percent, and thus a polymer having a C* of less than 0.22 was required. However, the depolymerized polymers of the present invention, even at concentrations of above about 0.27 weight percent provide superior clean-up properties and may yield extremely robust viscosified fluids. In some embodiments of the present invention the depolymerized polymer having a C* of at least about 0.27 is included in the treatment fluid in a concentration of at least about 0.27 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 0.3 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 0.35 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 0.4 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 0.45 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 0.5 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 0.6 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 0.7 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 0.8 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 0.9 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 1 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 1.2 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 1.4 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 1.6 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 1.8 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 2 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 2.2 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 2.4 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 2.6 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 2.8 weight percent; in other embodiments the depolymerized polymer may be included in the treatment fluid in a concentration of at least about 3 weight percent.  
      Many additives may be included in the treatment concentrates and treatment fluids of the present invention. Some such additives include dispersing agents, pH-adjusting compounds, buffers, surfactants, clay stabilizers, fluid loss control agents scale inhibitors, demulsifiers, clay stabilizers, bactericides, breaker activators and the like.  
      In some instances it may be desirable to add a dispersing agent to the polymer for dispersing the depolymerized hydratable polymer. Dispersing agents may be particularly preferred when a treatment fluid is being rehydrated from polymer that has been stored in a dry form. Any known dispersing agent may be used. In some embodiments the dispersing agent has been found to comprise light a hydrocarbon oil, diesel oil, kerosene, an olefins, a mineral oil, an another alkane, or the like. In some embodiments the dispersing agent may comprise polyethyleneglycol. In certain preferred embodiments, the dispersing agent may be diesel oil. When an oil dispersing agent is used, it is generally included with the polymer in an amount in the range of from about 5% to about 60% by weight of the polymer.  
      The treatment fluids may further comprise a pH-adjusting compound. Examples of such compounds that may be used include, but are not limited to, formic acid, fumaric acid, acetic acid, acetic anhydride, hydrochloric acid, sodium hydroxide, potassium hydroxide, lithium hydroxide, various carbonates or any other commonly used pH control agent that does not adversely react with the polymer to prevent its use in accordance with the method of the present invention. Of these, sodium hydroxide is preferred. When used, the pH-adjusting compound is generally present in a treatment concentrate of the present invention in an amount in the range of from about 0.5% to about 10% by weight of the water therein. And, when used, the pH-adjusting compound is generally present in a treatment fluid of the present invention in an amount in the range of from about 0.01% to about 0.3% by weight of the water therein.  
      A buffer also may be included in the treatment fluids of the present invention. Examples of buffers that may be used include, but are not limited to, sodium carbonate, potassium carbonate, sodium bicarbonate, potassium bicarbonate, sodium or potassium diacetate, sodium or potassium phosphate, sodium or potassium hydrogen phosphate, sodium or potassium dihydrogen phosphate and the like. When used, the buffer is generally present in the treatment concentrates in an amount in the range of from about 0.5% to about 10% by weight of the water therein. When used, the buffer is generally present in the treatment fluids of the present invention in an amount in the range of from about 0.01% to about 0.3% by weight of the water therein. The amount of buffer used will depend on the desired pH change. One of ordinary skill in the art with the benefit of this disclosure will recognize the appropriate amount of buffer to include to achieve a desired pH change.  
      Another additive that may be included in the treatment fluid is a surfactant. When a treatment fluid of the present invention is used in a subterranean formation, the presence of a surfactant may aid in preventing the formation of emulsions between the treatment fluid and subterranean formation fluids. Examples of surfactants that may be used include, but are not limited to, alkyl sulfonates, alkyl aryl sulfonates including alkyl benzyl sulfonates such as salts of dodecylbenzene sulfonic acid, alkyl trimethylammonium chloride, branched alkyl ethoxylated alcohols, phenol-formaldehyde nonionic resin blends, cocobetaines, dioctyl sodium sulfosuccinate, imidazolines, alpha olefin sulfonates, linear alkyl ethoxylated alcohols, trialkyl benzylammonium chloride and the like. Of these, salts of dodecylbenzene sulfonic acids are preferred. Substantially any surfactant that is known to be suitable for use in the treatment of subterranean formations and which does not adversely react with the fluid of the present invention may be used. When used, a surfactant is generally present in a treatment fluid of the present invention in an amount in the range of from about 0.01% to about 0.1% by weight of the water in the treatment fluid.  
      Yet another additive that may be included in the treatment fluids of the present invention is a clay stabilizer. Examples of clay stabilizers that may be used include, but are not limited to, potassium chloride, sodium chloride, ammonium chloride and tetramethyl ammonium chloride and the like. Examples of some temporary clay stabilizers that are suitable for use in the present invention are disclosed in, for example, U.S. Pat. Nos. 5,197,544; 5,097,904; 4,977,962; 4,974,678; and 4,828,726, the relevant disclosures of which are incorporated herein by reference. Of these, potassium chloride and tetramethyl ammonium chloride are preferred. When used, the clay stabilizer is generally present in a treatment fluid of the present invention in an amount in the range of from about 0.5% to about 10% by weight of the water therein.  
      The treatment fluids of the present invention may also comprise fluid loss control agents. Examples of fluid loss control agents that may be used include, but are not limited to, silica flour, starches, waxes and resins. When used, the fluid loss control agent is generally present in the treating fluid in an amount in the range of from about 0% to about 1% by weight of water therein.  
      The treating fluids of the present invention may also include compounds for retarding the movement of the proppant introduced in the fluid within the created fracture. For example, materials in the form of fibers, flakes, ribbons, beads, shavings, platelets and the like comprised of glass, ceramics, carbon composite, natural or synthetic polymers or metals and the like may be admixed with the fluid and proppant introduced into the subterranean formation to retard or prevent the movement of the introduced proppant. A more detailed description of the forgoing materials is disclosed in, for example, U.S. Pat. Nos. 5,330,005; 5,439,055; and 5,501,275, the relevant disclosures of which are incorporated herein by reference.  
      The treatment fluids of the present invention often further comprise a crosslinking agent in addition to the substantially fully hydrated polymer and water. Such crosslinking agents act to further increase the viscosity of the treatment fluid. The short chain segments of the substantially fully hydrated depolymerized polymer in the treatment fluid may be crosslinked by the crosslinking agent thereby producing a viscous treating fluid having unexpected properties. Such crosslinked fluids exhibit unexpected thermal stability at temperatures above about 200° F., operating particularly well in the temperature range from about 200 to about 275° F. without the need for gel stabilizers. Moreover, the filter cake produced by such crosslinked fluids has been found to be easier to remove from than filter cakes formed by traditional fracturing fluids. Also, due to the process used to create the substantially depolymerized polymer fluids of the present invention, only minimal is residue left behind with the fluids are broken. In addition, as prehydration of the treating fluids of the present invention is unnecessary, the treating fluid may rapidly be mixed with additional water and additives on the surface, thereby facilitating the execution of real time changes in the properties of the treating fluid as it is being pumped.  
      Examples of preferred crosslinking agents that may be used in the treatment fluids include, but are not limited to, boron compounds such as, for example, boric acid, disodium octaborate tetrahydrate, sodium diborate and pentaborates, ulexite and colemanite, compounds that may supply zirconium IV ions such as, for example, zirconium lactate, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate and zirconium diisopropylamine lactate, compounds that can supply titanium IV ions such as, for example, titanium ammonium lactate, titanium triethanolamine, titanium acetylacetonate, aluminum compounds such as aluminum lactate or aluminum citrate or compounds that can supply antimony ions. In certain preferred embodiments, the crosslinking agent is a borate compound. The exact type and amount of crosslinking agent or agents used depends upon the specific depolymerized polymer to be crosslinked, formation temperature conditions and other factors known to those individuals skilled in the art. Generally, the crosslinking agent is present in the treating fluid in an amount in the range of from about 50 ppm to about 5000 ppm active crosslinker.  
      When a borate crosslinking agent is used, a pH-adjusting compound (as described above) may be used to elevate the pH of the treating fluid to above about 9. At that pH, the borate compound crosslinking agent crosslinks the short chain hydrated polymer segments. When the pH of the crosslinked treatment fluid falls below about 9, the crosslinked sites are no longer crosslinked. Thus, when the crosslinked treatment fluid of this invention contacts the subterranean formation being treated, the pH is lowered to some degree, which begins the breaking process. In order to cause the treatment fluid to completely revert to a thin fluid in a short period of time, a delayed delinker capable of lowering the pH of the treating fluid may be included in the treating fluid. Examples of delayed delinkers that may be used include, but are not limited to, various lactones, esters, encapsulated acids and slowly soluble acid generating compounds, oxidizers which produce acids upon reaction with water (such as polyesters or polyorthoesters), water reactive metals such as aluminum, lithium and magnesium and the like. In certain preferred embodiments, the delayed delinker is an ester. Where used, the delinker is generally present in the treating fluid in an amount in the range of from about 0.01% to about 1% by weight of the water therein. Alternatively, any of the conventionally used delayed breakers employed with metal ion crosslinkers may be used, for example, oxidizers such as sodium chlorite, sodium bromate, sodium persulfate, ammonium persulfate, encapsulated sodium persulfate, potassium persulfate, or ammonium persulfate and the like as well as magnesium peroxide. Enzyme breakers that may be employed include alpha and beta amylases, amyloglucosidase, invertase, maltase, cellulase and hemicellulase. The specific breaker or delinker used, whether or not it is encapsulated, as well as the amount thereof employed will depend upon the breaking time desired, the nature of the polymer and crosslinking agent, formation characteristics and conditions and other factors.  
      The treatment fluids of the present invention also may include a particulate material such as proppant or gravel. While nearly any solid material can be used as particulates in the present invention, some commonly used particulates include graded sand, bauxite, ceramic materials, glass materials, walnut hulls, polymer pellets, and the like. Generally, the particulates have a size in the range of from about 4 to about 400 mesh, U.S. Sieve Series. In some embodiments of the present invention, the particulates are graded sand having a particle size in the range of from about 10 to about 70 mesh, U.S. Sieve Series. The chosen particulate may be coated with a resin or tackifier. The particulates are generally included in the treatment fluids of the present invention in an amount in the range of from about 0.5 to about 24 pounds of particulate per gallon of treatment fluid.  
      The subterranean formation treatment fluids of the present invention also may include substantially any of the conventionally known foaming agents that do not adversely react with the fluid constituents such that a gaseous compound such as nitrogen, air, carbon dioxide or another gasifying compound can be admixed with the fluid to form a foam for introduction into the subterranean formation. The gaseous compound may be admixed with the fluid in an amount in the range of from 5% to about 90% to form a foamed treatment fluid for use in stimulating a subterranean formation. When foamed, the fluid of the present invention provides the same benefits as are found in the use of other foamed treatment fluids. Among other benefits, the foamed fluid results in less polymer being introduced into the formation, may provide improved fluid loss control and may provide a gas assist in removing the treatment fluid from the well bore at the conclusion of the treatment.  
      To facilitate a better understanding of the present invention, the following examples of some of the preferred embodiments are given. In no way should such examples be read to limit the scope of the invention.  
     EXAMPLE 1  
      The ability of the depolymerized polymer of the present invention to provide static fluid loss control to a treatment fluid introduced into a simulated subterranean formation and regained permeability subsequent to the treatment in comparison to conventional treatment fluids is determined in accordance with the following procedure. A synthetic core material comprising a ceramic having a 5 micron permeability is prepared in lengths of about 3.5 to 4 cm. The cores have a diameter of about 2.37 cm. The cores then are vacuum saturated in filtered API brine. Individual cores then are mounted in a Hassler sleeve device. The flow direction from left-to-right is designated as the production direction and from right-to-left is designated as the treatment direction to simulate the relative directions of movement in treating an actual subterranean formation. A hollow spacer is installed adjacent the core to act as a perforation cavity. Overburden pressure on the Hassler sleeve is administered by maintaining differential pressure from the treating pressure being used. The core is heated to and then maintained throughout the test at a temperature of 125° F. The core then is flushed with 25 ml of filtered API brine in the production direction. Initial permeability to API brine then is determined in the production direction by flow with a differential pressure of 20 psi. Rates are measured every 25 ml of throughput to determine the initial permeability. The fluid to be tested then is introduced into a reservoir in communication with the treatment direction flowlines. A high differential pressure of about 200 psi is placed across the core in the treatment direction as the treatment fluid is flowed into the core. The differential pressure is noted in the Table below for each test. The spurt loss fluid volume and all throughput volumes were collected over time intervals sufficient to determine the fluid loss. After the fluid loss phase of the test was completed, the return or regained permeability was measured by injecting 500 ml of API brine through the core in the production direction. No attempt is made to squeeze or chemically remove the filter cake created from the test fluid from the face of the core. The regained permeability then is determined from the flow data gathered. The regained permeability is set forth in Table I below. Each individual fluid which is tested is prepared from the polymers identified in the Table by hydration for a sufficient time to form a fully hydrated polymer and then a crosslinker comprising a borate source is admixed with the fluid in the amount indicated, if present.  
               TABLE I                          Static Fluid Loss and Regained Permeability Tests                                         Polymer       Crosslinker   Fluid Loss                                                 Test       Concentration,       concentration,   Calc.       % Regained       No.   Polymer   Lbs./1000 gal.   pH   ppm   Spurt   Cw   Permeability                                                     1   guar   41.6   —   0   3.3   0.019   50.6       2   guar   41.6   8.4   115   0.163   0.007   79.6       3   hydroxypropylguar   41.6   8.2   315   0.662   0.012   86.9       4   hydroxypropylguar   41.6   8.4   315   0.045   0.002   89.8       5   depolymerized HPG   41.6   9   105   0.232   0.008   92.95       6   depolymerized HPG   41.6   9   315   0.048   0.007   96.3                  
 
      The foregoing data clearly illustrate that for similar fluid loss, in comparison to conventional treatment fluids, the use of the depolymerized polymer of the present invention results in improved regained formation permeability.  
     EXAMPLE 2  
      To evaluate the performance of the various fluids, dynamic fluid loss tests are performed using the depolymerized polymer of the present invention in comparison to conventional treatment fluids in accordance with the following procedure. Core samples are prepared to fit into a modified API linear flow cell. Each sample has a surface area of 10 square inches. Two core wafers are set apart by a 0.30 inch gap to allow fluid to flow through the cell for the dynamic test conditions. The test fluid then is prepared including the addition of any crosslinker. The test fluid is pumped through 340 ft of 0.194 inch diameter steel tubing to provide preconditioning and a shear history to the test fluid. The shear rate on the fluid is about 1800 sec-1. The fluid then is introduced into a section of 0.62 inch diameter tubing immersed in a heating bath to simulate the lower shear rate of a fluid in a fracture. The shear rate is about 50 sec-1. The fluid is heated to a test temperature of about 180° F. as it goes through the tubing. The test fluid then is introduced into the flow cell where the dynamic fluid loss occurs. A 1000 psi differential pressure force is used to drive the fluid through the cores. The test then is continued for 60 minutes to permit determination of fluid loss coefficients based upon collected fluid volumes. The results are set forth in Table II below. The test fluids comprised for sample 1, a concentration of 129 gallons of treating fluid concentrate of depolymerized polymer and tap water containing 2% KCl per 1000 gallons of fluid which was crosslinked with a borate source at a pH of about 10.1. For sample 2, the fluid comprised guar hydrated in tap water with 2 gallons per 1000 gallons of fluid of a 50% tetramethyl ammonium chloride solution and a breaker comprising 0.25 pounds sodium persulfate and 0.25 pounds encapsulated sodium persulfate per 1000 gallons of fluid which was crosslinked with a borate source at a pH of above about 9.5. For sample 3, the fluid comprised guar hydrated in tap water with 2 gallons per 1000 gallons of fluid of a 50% tetramethyl ammonium chloride solution and a breaker comprising 15 gallons per 1000 gallons of fluid of a sodium chlorite solution and 3 gallons per 1000 gallons of fluid of a copper ethylenediaminetetraacetic acid solution which was crosslinked with a borate source at a pH of above about 9.5.  
               TABLE II                          Dynamic Fluid Loss Coefficients with Ohio       Sandstone Core Wafers (0.1 to 0.3 md)                                             Polymer                           Concen-       Sample       tration       C w     Spurt       No.   Polymer   % by wt   Breaker   (ft/min 0.5 )   (gal/ft. 2 )                                             1   depolymerized   1.49   None   0.001877   0.00294           HPG       2   Guar   0.3   Persulfate   0.00287   0       3   Guar   0.3   activated   0.00357   0.0027                   sodium                   chlorite                  
 
      The results illustrate the present invention provides a treatment fluid with a lower dynamic fluid loss than conventional treatment fluids.  
     EXAMPLE 3  
      To determine the fracture conductivity of a proppant pack, the following test was used to simulate production through a proppant pack to determine the conductivity of the fracture. The test cell from each test in Example 2 is opened and the space between the two core wafers is filled with a 20/40 mesh Ottawa sand proppant at a specified lb/ft 2  concentration. The test cell then is closed and placed in a press where closure stress can be applied and the reservoir temperature can be simulated by heating the cell to 180° F. The conductivity of the proppant pack then is measured over a period of at least 48 hours until a stable value is obtained by flowing water through the core and proppant pack within the test cell. The results of the tests are set forth in Table III below. The samples are compared to a baseline determination of conductivity determined by placing proppant between the two core wafers with the designated proppant concentration without any fracturing fluid having been passed through the core.  
               TABLE III                          Proppant Pack Conductivity Values                                     Proppant           Percentage       Sample   Concentration,   Closure Stress,   Conductivity,   of       No.   lb/ft 2     psi   md-ft   Baseline, %                                         1   2   2000   2744   65               4000   1705   74               6000   540   62       2   2   2000   674   16               4000   390   17               6000   209   24       3   2   2000   2526   60               4000   1011   44               6000   488   56                  
 
      The results illustrate the treatment fluid of the present invention achieves superior proppant pack conductivity in comparison to conventional treatment fluids without the necessity of the use of any breaker in the treatment fluid.  
     EXAMPLE 4  
      To evaluate the performance of the treatment fluid of the present invention in an actual field job, two wells were treated in accordance with the methods of the present invention. The wells in the Cottage Grove formation each had a depth of about 8000 ft and a bottom hole temperature of about 155° F. One treatment was performed with an added breaker in the treatment fluid and the other treatment was performed without any additional breaker. In the first job, 125 barrels of treatment fluid concentrate were prepared with a depolymerized hydroxypropylguar which was used to prepare 3000 gallons of linear gel that was used to perform a minifrac treatment on the well and 30,000 gallons of crosslinked fluid which was used to perform the principal treatment and place the proppant. The fluid included sodium hydroxide in an amount sufficient to raise the fluid pH to about 12.1 and a borate crosslinker for crosslinking the depolymerized polymer. The proppant was ramped from a concentration of from about 1 to about 5 lbs per gallon for a total injected quantity of 50,000 pounds. A conventional breaker comprising encapsulated ammonium persulfate was admixed with the crosslinked gelled fluid in an amount of from about 2 to about 4 lbs per 1000 gallons of fluid. The treatment was performed at an average rate of about 13 bpm and successfully placed the entire quantity of proppant.  
      Production of oil during the two months following the treatment exceeded per-treatment production by in excess of 200%.  
      The second job used the same depolymerized polymer. Approximately 110 barrels of treatment fluid concentrate were used to prepare 30,000 gallons of crosslinked fluid that is used to perform a fracturing treatment upon the well. The fluid includes sodium hydroxide in an amount sufficient to adjust the pH to a level of about 12.1 and a borate crosslinker for crosslinking the depolymerized polymer. The proppant introduced with the fluid was ramped in concentration from about 1 to about 5 lbs per gallon of fluid. The fluid did not include any breaker.  
      Production of oil during the two months after the treatment exceeded pre-treatment production by in excess of 100%.  
     EXAMPLE 5  
      To determine c* in the lab, first 500 mL tap water with 10 grams of 2% KCL and add the polymer to be tested to a 4% actual gum concentration. Adjust the pH of the mixture to 6.5 and stir in a waring blender for 30 minutes. Next, determine the viscosity of the 4% solution using a Fann  35  viscometer (a Brookfield viscometer may also be used) at 300 rpm. If the viscometer pegs out at 300 rpm then re-start the test with a 3.5% solution instead of a 4% solution, and then a 3% instead of the 3.5%, etc. until a good reading is found. Once a good viscosity reading is found, make further dilute solutions of, for example, 4%, 3%, 2%, 1.5%, 1%, 0.75%, 0.5%. 0.25%, 0.12%, etc, and determine the viscosity of each of the dilutions. Plotting the viscosity data obtained from the various dilutions yields a curve having two dominant paths. Regression line through those paths may then be drawn and their intersection will occur at the c* for the polymer being tested, as shown in  FIG. 1 .  
      Thus, the present invention is well adapted to attain the objects and advantages mentioned as well as those which are inherent therein. While numerous changes may be made by those skilled in the art, such changes are encompassed within the spirit of this invention as defined by the appended claims.