RELATED APPLICATION(S)  
       [0001]    This application is a continuation-in-part of commonly assigned U.S. patent application GUAR GUM POWDER POSSESSING IMPROVED HYDRATION CHARACTERISTICS, Ser. No. 09/991,356, filed Nov. 19, 2001, which is a division of commonly assigned U.S. patent application IMPROVED HYDRATION OF GUAR GUM POWDER, Ser. No. 09/501,559, filed Feb. 9, 2000. 
     
    
     
       TECHNICAL FIELD OF THE INVENTION  
         [0002]    This application relates generally to the field of subterranean drilling and more specifically to the use of guar powder in “on-the fly” treatment of subterranean formations.  
         BACKGROUND OF THE INVENTION  
         [0003]    Oil and natural gas (“gas”) are typically found in subterranean formations. To obtain the oil or gas, the subterranean formation must be penetrated, thereby allowing the oil or gas to be produced through a wellbore.  
           [0004]    In standard operations, a wellbore is drilled from the surface to the subterranean formation. The wellbore penetrates the subterranean formation, which allows the oil or gas to flow from the subterranean formation to the surface via the wellbore. For the oil or gas to escape the subterranean formation and flow to the wellbore, the oil or gas must have a sufficiently unimpeded path from the subterranean formation to the wellbore. Typically, this path is through the formation rock, which usually comprises sandstone or carbonates. For the formation rock to enable a sufficient oil or gas flow, the formation rock must have a sufficient number of pores with a size and connectivity to provide the proper conduit for the oil or gas.  
           [0005]    Frequently, the oil or gas is not able to escape the subterranean formation and flow through the wellbore, or oil or gas may only escape in less than optimal amounts. For instance, damage to the subterranean formation may plug the pores of the formation rock. Damage may be caused by fluids that were injected into the wellbore during drilling of the wellbore or injected during treatments of the subterranean formation. Typically, portions of these fluids may remain in the wellbore after the injection and may dehydrate and take solid form over time. These dehydrated fluids may then coat the wellbore or pores of the formation rock, which may result in stopping or reducing the flow of gas or oil. Additional reasons for reduced flow of oil or gas include pores with less than optimal size or number. With such pores, the formation rock may have a low permeability to the flow of oil or gas.  
           [0006]    One method for increasing the flow of oil or gas from the subterranean formation is to “stimulate” the subterranean formation. Stimulation of the subterranean formation involves fracturing the subterranean formation, thereby causing cracks that extend from the wellbore to the subterranean formation. Typically, this fracturing of the subterranean formation involves injecting a well-treating fluid that comprises chemicals in gel form through the wellbore and to the formation at pressures sufficient to fracture the formation. The standard components of the gelled well-treating fluid comprise a carrier fluid, a polymer, a cross-linker, and a propping agent. The well-treating fluid is inserted into the wellbore at a temperature and pressure sufficient to stimulate one or more fractures of the surface of the subterranean formation. Typically, the gel is inserted in 17 lb (8 kg) or 30 lb (14 kg) injections. After the fracture is sufficiently open, the well-treating fluid flows into the fracture and deposits the propping agent. A breaking agent is then introduced to the wellbore, and the breaking agent breaks the gelled well-treating fluid into a thin fluid, which allows for its removal from the wellbore. Alternatively, the well-treating fluid may further comprise a delayed breaking agent that breaks the well-treating fluid at a time after the fracture of the subterranean formation. After the well-treating fluid is broken and removed, the propping agent remains in the fractures. The propping agent keeps the fractures from closing after the broken well-treating fluid is removed. The propping agent also increases the flow of oil or gas through the fracture by providing channels through which the oil or gas may flow to the wellbore. Alternatively, the gelled well-treating fluid that stimulates the fracture of the formation may not comprise any propping agent. Instead, the propping agent is not added to the well-treating fluid until after the subterranean formation is stimulated and thereafter is introduced in to the fractures.  
           [0007]    High viscosity is an important aspect to these cross-linked gels. For instance, the width of the fracture may be proportional to the viscosity of the fracturing fluid. In addition, a high viscosity enables the well-treating fluid to transport the propping agents without the propping agents settling out of the well-treating fluid.  
           [0008]    The standard polymer in the well-treating fluid is guar gum. Guar gum comes from a plant that is grown primarily in India and Pakistan, although other climates are also friendly to its cultivation. Guar is a legume-type plant that produces a pod, much like a green bean. In the pod, there are seeds that, upon heating, split open, exposing the endosperm and meal. The exposed endosperm contains a polymer that is of great use for thickening industrial and commercial fluids. The polymer is a polysaccharide material known as polygalactomannan. This material develops a high viscosity via hydration of the fluid to be thickened.  
           [0009]    The original process for making the gelled well-treating fluid involved an operator mixing bags of guar powder with water in a hopper and then transferring the mixture to a storage tank. The guar powder was allowed to hydrate in the storage tank for a period of time that typically spanned several hours. After the mixture was sufficiently gelled, the gelled fluid was then pumped into the wellbore. One serious drawback to this process was the large expense involved in such a large amount of time expended to hydrate the guar powder. In addition, the large amounts of guar powder that were required to have a sufficient viscosity added significantly to the cost in producing the oil or gas.  
           [0010]    To increase efficiency over this original process, the industry developed an “on-the-fly” process to make the gelled well-treating fluid. In this process, a liquid slurry comprising guar powder, a carrier fluid, and suspending agents is prepared remote from the wellbore site. The carrier fluid typically comprises a diesel fuel or mineral oil. The suspending agents, which are used to suspend the slurry, are inorganic and non-soluble in water. This liquid slurry is then taken to the wellbore site and mixed in hydration tanks with water to form the gelled well-treating fluid. These hydration tanks are also called on-the-fly hydration units. In these on-the-fly hydration units, the guar powder in the liquid slurry is allowed to hydrate for about seven to ten minutes. A cross-linker and any other additives are then added to the liquid slurry and then the gel is introduced to the wellbore.  
           [0011]    U.S. Pat. No. 4,336,145 (the “&#39;145 Patent”) also discloses a pre-prepared liquid slurry, but instead discloses water as the carrier fluid. In the &#39;145 Patent, the gel is prepared by suspending the polymer in water by using an inhibitor to retard the hydration rate of the polymer. When the gel is then later mixed with additional water, the inhibitor reverses and the hydration of the polymer commences.  
           [0012]    It is highly advantageous to have a well-treating fluid and a method for using the well-treating fluid that uses a fast-hydrating and high-viscosity polymer. The time involved in preparing the well-treating fluid for introduction to the wellbore is directly related to the increased efficiency, and, thereby, reduced expenses, in the production of oil and gas. The liquid slurry process has reduced the several hours time required of the original process. However, the liquid slurry is a pre-prepared mixture. The time and effort involved in preparing the liquid slurry decreases the cost efficiency of the production. A further drawback of the liquid slurry process includes the introduction of the non-soluble suspending agents to the wellbore, where the non-soluble suspending agents are not broken by the breaking agent. Therefore, these suspending agents remain in the fractures along with the propping agents and may lead to clogging of the pores, which may reduce or stop the flow of the oil or gas. In addition, the large amount of suspending agent required to suspend the slurry increases the cost of the production operation. Moreover, the suspending agents may interfere with cross-linking of the polymer. Drawbacks also include environmental concerns and additional cost increases. For instance, the inhibitor introduced to the wellbore in the &#39;145 patent presents harmful chemicals to the environment and the removal of such harmful chemicals poses storage problems. The added cost of storing and removing these chemicals and the initial cost of using these chemicals also decreases the cost efficiency of the production. In addition, the use of diesel in the liquid slurry is also potentially harmful to the environment. The large amount of diesel used may be cost prohibitive due to the initial cost of using the diesel and the added cost in removing the diesel. A further drawback includes the amount of polymer or guar powder that must be used to have a viscosity high enough to transport the propping agent. To increase the viscosity of the gelled well-treating fluid, operators typically add additional guar powder or polymer to attain the desired viscosity, which increases costs.  
           [0013]    Consequently, there is a need for a well-treating fluid that comprises a high-viscosity and fast-hydrating polymer. There is a need for a method of producing and using such a well-treating fluid. Further, there is a need for a way to minimize the amount of polymer used in preparing a well-treating fluid. In addition, there is a need for reducing the amount of harmful pollutants introduced to the environment during the treatment of a subterranean formation.  
         SUMMARY OF THE INVENTION  
         [0014]    These and other needs in the art are addressed in various aspects of the present invention. In one aspect, an inventive method of treating a subterranean formation using a well-treating fluid is provided, the subterranean formation penetrated by a wellbore, the method comprising (A) preparing the well-treating fluid by admixing a fast-hydrating high-viscosity guar powder to a hydrating liquid to prepare the well-treating fluid; (B) hydrating the guar powder; (C) admixing a cross-linker to the well-treating fluid; and (D) introducing the well-treating fluid to the wellbore at a temperature and a pressure sufficient to treat the subterranean formation.  
           [0015]    In another aspect of the present invention, a well-treating fluid for use in treating subterranean formations is provided, the well-treating fluid comprising a hydrating liquid; a gelling agent, the gelling agent comprising a fast-hydrating high-viscosity guar powder; and a cross-linker.  
           [0016]    In a third aspect of the present invention, a well-treating fluid for use in treating subterranean formations is provided, the treatment comprising a fracture stimulation, the well-treating fluid comprising a hydrating liquid; a gelling agent, the gelling agent comprising a fast-hydrating high-viscosity guar powder; a cross-linker; and a propping agent.  
           [0017]    In a fourth aspect of the present invention, a well-treating fluid for use in treating subterranean formations is provided, the treatment comprising a fracture stimulation, the well-treating fluid comprising a hydrating liquid; a gelling agent, the gelling agent comprising a fast-hydrating high-viscosity guar powder; a cross-linker, the cross-linker comprising a cross-linking agent and a delaying agent; a delayed breaking agent; and a propping agent.  
           [0018]    In a fifth aspect of the present invention, a method of treating a subterranean formation using a well-treating fluid is provided, the subterranean formation penetrated by a wellbore, the method comprising (A) preparing the well-treating fluid by admixing a fast-hydrating high-viscosity guar powder to a hydrating liquid to prepare the well-treating fluid; (B) hydrating the guar powder; (C) admixing a cross-linker and a delayed breaking agent to the well-treating fluid; and (D) introducing the well-treating fluid to the wellbore at a temperature and a pressure sufficient to treat the subterranean formation.  
           [0019]    In a sixth aspect of the present invention, a method of performing a fracture treatment in a subterranean formation using a well-treating fluid is provided, the subterranean formation penetrated by a wellbore, the method comprising (A) preparing the well-treating fluid by admixing a fast-hydrating high-viscosity guar powder to a hydrating liquid to prepare the well-treating fluid; (B) hydrating the guar powder; (C) admixing a cross-linker and a propping agent to the well-treating fluid; and (D) introducing the well-treating fluid to the wellbore at a temperature and a pressure sufficient to stimulate the fracture treatment of the subterranean formation.  
           [0020]    In a seventh aspect of the present invention, a method of performing a fracture treatment to a subterranean formation using a well-treating fluid is provided, the subterranean formation penetrated by a wellbore, the method comprising (A) preparing the well-treating fluid by admixing a fast-hydrating high-viscosity guar powder to a hydrating liquid to prepare the well-treating fluid; (B) hydrating the guar powder; (C) admixing a cross-linker, a propping agent, and a delayed breaking agent to the well-treating fluid, wherein the cross-linker comprises a delaying agent and a cross-linking agent, and wherein the cross-linker is disposed to delay the cross-linking until after the well-treating fluid is introduced to the wellbore; (D) introducing the well-treating fluid to the wellbore at a temperature and a pressure sufficient to stimulate the fracture treatment of the subterranean formation; and (E) breaking the well-treating fluid with the delayed breaking agent, the delayed breaking agent disposed to delay breaking of the well-treating fluid until after stimulation of the fracture treatment.  
           [0021]    The foregoing has outlined rather broadly many of the features and technical advantages of the present invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter which form the subject of the claims of the invention. It should be appreciated by those skilled in the art that the conception and the specific embodiments disclosed may be readily utilized as a basis for modifying or designing other structures for carrying out the same purposes of the present invention. It should also be realized by those skilled in the art that such equivalent constructions do not depart from the spirit and scope of the invention as set forth in the appended claims.  
       
    
    
     BRIEF DESCRIPTION OF THE DRAWING  
       [0022]    For a more complete understanding of the present invention, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying drawing, in which:  
         [0023]    the drawing illustrates a processing unit for well-treating fluids.  
     
    
     DETAILED DESCRIPTION OF THE INVENTION  
       [0024]    The accompanying drawing illustrates a process for on-the-fly manufacture of well-treating fluids in which a trailer  10  supports process equipment  15 . The process equipment  15  comprises a hydraulic power pack  20 , chemical additives tanks  30 , a polymer tank  40 , and a hydration unit  50 . The hydraulic power pack  20  provides power to the other process equipment  15 . The chemical additives tanks  30  comprise chemical storage tanks that store and supply the chemical additives to the hydration unit  50 . The chemical additives that are stored in these tanks may comprise cross-linking agents, breaking agents, delaying agents, buffer solution additives, and/or any other suitable additives for admixing to the hydration unit  50 .  
         [0025]    The polymer tank  40  contains the polymers for adding to the hydration unit  50  in the preparation of the well-treating fluid. The polymer that is stored in the polymer tank  40  and used in preparing the well-treating fluid of various illustrative embodiments of the present invention is the fast-hydrating high-viscosity guar powder disclosed in co-pending, commonly assigned U.S. patent applications with Ser. Nos. 09/991,356 (the “&#39;356 application”) and 09/501,559 (the “&#39;559 application”) of which this invention is a continuation-in-part application. The &#39;356 application and the &#39;559 application are hereby incorporated by reference in their entirety. The polymer that is used in preparing the well-treating fluid may also comprise a de-polymerized fast-hydrating high-viscosity guar powder and derivatives of the fast-hydrating high-viscosity guar powder. Such derivatives may comprise hydroxy propyl guar powder, carboxy methyl guar powder, and carboxy methyl hydroxy propyl guar powder. The fast-hydrating high-viscosity guar powder is stored in the polymer tank  40  in powder form.  
         [0026]    The hydration unit  50  serves as a storage and mixing unit for the preparation of the well-treating fluid. In the hydration unit  50 , the guar powder is hydrated with a hydrating liquid and then mixed with the chemicals from the chemical additives tanks  30  by an agitator  60 . A pump  70  pumps the hydrating liquid from a water supply to the hydration unit  50 . An operator on an operator platform  90  oversees the operation of the process equipment  15 .  
         [0027]    The following describes an exemplary illustrative embodiment of the present invention as illustrated. The trailer  10  is located near a wellbore (not illustrated). The operator turns on the power of the hydraulic power pack  20  so that the other process equipment  15  may then be supplied with power. Hydrating liquid from the water supply is supplied to the hydration unit  50  by the pump  70 . The hydrating liquid may comprise fresh water, brine, or any other suitable liquid that does not adversely react with other components of the well-treating fluid. After a certain amount of hydrating liquid is added to the hydration unit  50 , fast-hydrating high-viscosity guar powder from the polymer tank  40  is added to the hydration unit  50 . The agitator  60  mixes the guar powder with the hydrating liquid. The guar powder is added to the hydrating liquid in an amount that may comprise about 0.15 to about 0.30 percent by weight of the hydrating liquid. The guar powder is not limited to this percent by weight of the hydrating liquid but, in various alternative illustrative embodiments, may alternatively comprise anywhere from about 0.05 to about 1.0 percent by weight of the hydrating liquid. The guar powder is allowed to hydrate in the hydrating fluid. In addition, the guar powder and hydrating liquid mixture form into a gel. The guar powder may be allowed to hydrate in the hydrating fluid for a time period up to about 5 minutes, which results in about a 90 percent hydration rate of the guar powder. Alternatively, the guar powder may be allowed to hydrate for a longer or a shorter period of time, depending on the circumstances.  
         [0028]    After the guar powder hydrates in the hydration unit  50 , a cross-linker may be admixed to the guar powder and water mixture to form the well-treating fluid. The cross-linker may comprise a cross-linking agent and a delaying agent. The cross-linking agent and delaying agent may be mixed at the trailer  10  or remote from the trailer  10 . The cross-linking agent may comprise from about 20.0 to about 35.0 percent by weight of the guar powder. Alternatively, the cross-linking agent may comprise from about 10.0 to about 40.0 percent by weight of the guar powder. The delaying agent may comprise from about 2.0 to about 10.0 percent by weight of the guar powder. Alternatively, the delaying agent may comprise from about 0.5 to about 25.0 percent by weight of the guar powder. Examples of available cross-linking agents include zirconium, titanium, chromium, aluminum, antimony, iron, zinc, borate, boron, and the like. Examples of available delaying agents include glycerol, erythritol, threitol, ribitol, arabinitol, xylitol, allitol, altritol, sorbitol, mannitol, dulcitol, iditol, perseitol, and the like. The cross-linking agent bonds molecules of the guar together by attaching to the hydroxyl groups of the guar. By such cross-linking, the viscosity of the well-treating fluid may be increased. The delaying agents in the cross-linker delay the cross-linking of the guar molecules until the well-treating fluid is down the wellbore, thereby maintaining a lower viscosity in the well-treating fluid while pumping into the wellbore. The delaying agents may delay the cross-linking from several minutes to several hours, depending on the requirements of the situation. By delaying the cross-linking, the amount of pressure needed to pump the well-treating fluid from the hydration unit  50  to the wellbore may be substantially decreased. Alternatively, the cross-linker may not comprise a delaying agent. Instead, the delaying agent may be admixed to the guar powder and hydrating liquid mixture before the cross-linking agent is admixed to the mixture. In various alternative embodiments, the delaying agent may not be admixed to the well-treating fluid. Consequently, the cross-linking agent may immediately begin the cross-linking of the guar upon its addition to the well-treating fluid.  
         [0029]    After admixing the cross-linker in the hydration unit  50  to form the well-treating fluid, a delayed breaking agent, which may be stored in the chemical additive tanks  30 , may be admixed to the well-treating fluid in the hydration unit  50 . The delayed breaking agent may be admixed to the well-treating fluid in an amount comprising from about 0.01 to about 2.5 percent by weight of the hydrating liquid in the well-treating fluid. The amount of the delayed breaking agent may be adjusted, depending on the required breaking time of the gelled well-treating fluid. Delayed breaking agents that may be used include alkali metal chlorites, hypochlorites, calcium hypochlorites, and any other suitable breaking agent. Such delayed breaking agents are described in U.S. Pat. No. 5,413,178, issued on May 9, 1995; U.S. Pat. No. 5,669,446, issued on Sep. 23, 1997; and U.S. Pat. No. 5,950,731, issued on Sep. 14, 1999, the entire disclosures of which are incorporated by reference. Alternatively, the delayed breaking agent may not be admixed to the well-treating fluid before the well-treating fluid is introduced to the wellbore. Instead, the delayed breaking agent may not be introduced to the wellbore until after the well-treating fluid has completed the treatment of the subterranean formation.  
         [0030]    After the delayed breaking agent is admixed to the well-treating fluid in the hydration unit  50 , the well-treating fluid may be removed from the hydration unit  50 , and a propping agent may be admixed and suspended in the well-treating fluid. The propping agent may be admixed to the well-treating fluid in an amount comprising from about 1 pound (0.45 kg) to about 10 pounds (4.5 kg) of propping agent per gallon (4 liters) of well-treating fluid. This concentration may be increased or decreased, depending on the circumstances. Propping agents that may be used include sand, tempered glass beads, aluminum pellets, sintered bauxite, nylon pellets, and any other suitable propping agent. Alternatively, the propping agent may be admixed along with the cross-linker, which may comprise the cross-linking agent and delaying agent, and simultaneously suspended. In other alternative embodiments, the propping agent may be admixed along with a cross-linker, without delaying agents, and simultaneously suspended.  
         [0031]    The on-the-fly process from the hydration of the guar powder in the hydrating liquid to the mixing of the well-treating fluid with the suspended propping agent may take place in a matter of minutes, with the hydration of the guar powder taking place in a period of time up to about 5 minutes with about a 90 percent hydration rate. The process may take more or less time, depending on the circumstances. After admixing the propping agent, the well-treating fluid with the suspended propping agent may then be introduced into the wellbore in 17 lb (8 kg) gel increments. Alternatively, the well-treating fluid may be introduced to the wellbore in 30 lb (14 kg) gel increments or in any other suitable increments. By these 17 lb (8 kg) gel increments, the well-treating fluid may stimulate the fracture treatment of the subterranean formation. After the subterranean formation is fractured, the well-treating fluid may deliver the propping agents to the fractures of the subterranean formation. Thereafter, the delayed breaking agent may break the gelled well-treating fluid into a thin liquid. The broken well-treating fluid may then be removed from the wellbore. In various alternative embodiments, the propping agent may not be admixed to the well-treating fluid until after the well-treating fluid has stimulated the fracture of the subterranean formation. Upon the fracture, the propping agent may be admixed to the well-treating fluid, and the well-treating fluid with the suspended propping agent may be introduced to the wellbore, through which process the propping agent may be deposited in the fractures.  
         [0032]    The preparation of the well-treating fluid and its introduction to the wellbore may be undertaken in ambient temperatures, which typically range from about 70 degrees F. (21° C., 294 K) to about 120 degrees F. (49° C., 322 K), and may have similar results in viscosities and hydration rates in temperatures lower and/or higher than the standard ambient temperatures. The temperatures in the wellbore and near the subterranean formation typically range between about 120 degrees F. (49° C., 322 K) to about 350 degrees F. (232° C., 450 K), which is also a suitable temperature range for various illustrative embodiments of the present invention.  
         [0033]    In various alternative embodiments, the well-treating fluid may comprise additional components that may be admixed to the well-treating fluids described above. For example, conventional additives such as pH control agents, bactericides, clay stabilizers, surfactants, and the like, which do not interfere with the other components, or adversely affect the treatment, may also be used.  
         [0034]    In addition to the stimulation of subterranean formation fractures, various illustrative embodiments of the present invention may be used in other treatments that include well completion operations, fluid loss control treatments, treatments to reduce water production, drilling operations, and any other suitable treatments.  
         [0035]    To further illustrate various illustrative embodiments of the present invention, the following examples are provided.  
       EXAMPLE 1  
       [0036]    TABLE 1 illustrates the hydration rate performance of an improved fast-hydrating high-viscosity guar powder (as disclosed in the &#39;356 and &#39;559 patent applications) over conventional guar powder. New Guar  1  and New Guar  2  represent products produced according to the &#39;356 and &#39;559 patent applications. The Old Guar represents a guar powder product prepared under the conventional standard process. In this example, 2.4 g of guar powder was mixed in 500 ml of tap water by a Waring blender for one minute at 2800 rpm. The resulting mixture corresponds to a 40 lb (18 kg) gel. Thereafter, about 350 ml of this mixture was measured at 300 rpm by a FANN-35 viscometer. The resulting viscosities were measured at varying time increments, and the results for each guar product are illustrated in TABLE 1. As shown in TABLE 1, the New Guar  1  and New Guar  2  result in about a 30 percent increase in viscosity over the Old Guar. In addition, these results indicate that the New Guar  1  and New Guar  2  hydrate at a faster rate than the Old Guar, with the New Guar  1  and New Guar  2  exhibiting about a 90 percent hydration rate at 5 minutes.  
                                                         TABLE 1                                       New Guar 1   New Guar 2   Old Guar           Time in Minutes   (cps)   (cps)   (cps)                                        3   33-35   42-44   22-24           5   35-39   44-46   24-26           15   39-41   46-48   28-30           60   42-44   48-50   33-36                      
 
       EXAMPLES 2-10, and 13  
       [0037]    In these examples, different amounts of New Guar  1 , New Guar  2 , and Old Guar were hydrated with water and mixed with cross-linking agents. These examples illustrate a procedure for on-the-fly making of the gelled well-treating fluid. TABLE 2 illustrates the resulting viscosities of the different guar mixtures of the examples.  
                                                                                             TABLE 2                                   Cross-   10   20   30   40   50   60       Example       Gel   linker   MIN.   MIN.   MIN   MIN.   MIN.   MIN.       No.   Product   (lbs)   (mls)   (cps)   (cps)   (cps)   (cps)   (cps)   (cps)                                2   Old Guar   30   0.2   237   343   384   422   483   425       3   Old Guar   30   0.3   237   365   429   490   528   542       4   Old Guar   30   0.35   223   336   415   493   542   551       5   New Guar 1   30   0.35   455   563   626   763   957   914       6   New Guar 1   30   0.4   403   516   657   687   830   1027       7   New Guar 1   30   0.45   461   680   841   1007   1007   1166       8   New Guar 1   30   0.5   756   818   923   1103   1174   1370       9   New Guar 1   30   0.6   821   956   1337   1259   1303   1374       10   New Guar 1   17   0.45   225   237   254   279   295   315       11   New Guar 1   17   1.25   254   263   322   334   339   342       12   New Guar 2   17   1.5   380   440   480   500   510   525       13   New Guar 2   17   0.45   380   395   409   430   415   448       14   New Guar 2   17   0.45   345   355   385   370   390   387       15   New Guar 2   17   0.45   370   360   390   385   400   420       16   Old Guar   30   2.0   774   729   691   727   768   703       17   Old Guar   17   1.25   N/A   N/A   N/A   N/A   N/A   N/A       18   New Guar 2   17   1.5   300   315   335   320   340   350                  
 
         [0038]    The guar powder was mixed with 150 ml of tap water. To make a gel that corresponds to a 17.0 lb (8 kg) gel, about 0.3 g of the guar powder was used to mix in the tap water. To make a gel that corresponds to a 30.0 lb (14 kg) gel, about 0.53 g of the guar powder was used to mix in the tap water. The guar powder and water were shaken for about 30 seconds to mix them together. Thereafter, about 0.2 ml of pH buffer solution was added into the mixture and shaken for about 10 seconds. A cross-linking agent was added to the mixture and then shaken for about 20 more seconds. Within 1 minute, the resulting cross-linked gel was then placed in a FANN-50 rheometer for viscosity measurements. In the rheometer, a B5 extended bob was used, and the measurements were taken at 95 rpm and at 140 degrees F. (60° C., 333 K). The viscosity measurements for 10 minute intervals and the amounts of cross-linker used are depicted in TABLE 2. From the results shown in TABLE 2, it may be seen that the New Guar  1  and New Guar  2  exhibit much higher viscosities than the Old Guar. In addition, the New Guar  1  and New Guar  2  powders maintain their viscosities and gelled form over time.  
       EXAMPLES 11, 12, 16, and 17  
       [0039]    Examples 11, 12, and 17 illustrate a procedure for on-the-fly making of a 17.0 lb (8 kg) gel. In these examples, several times more cross-linking agents were admixed to the water than in the previous examples. The results are also shown in TABLE 2.  
         [0040]    In these examples, 1.02 g of guar powder was hydrated in 500.0 ml of water for about 30 minutes in a Waring blender at about 1200 rpm. A borate cross-linking agent was then added to the fluid and further mixed for about two minutes. The resulting cross-linked gel was then placed in a FANN-50 rheometer for viscosity measurements. In the rheometer, a B5 extended bob was used, and the measurements were taken at 95 rpm and at 140 degrees F (60° C., 333 K). The viscosity measurements for 10 minute intervals and the amounts of cross-linker used are shown in TABLE 2. From the results shown in TABLE 2, it may be seen that the New Guar  1  and New Guar  2  exhibit much higher viscosities than the Old Guar, which did not even exhibit any measurable viscosity. Indeed, Example 17 shows that no cross-linking takes place in using the Old Guar to make a 17.0 lb (8 kg) gel according to various illustrative embodiments of the present invention, even with 1.25 ml of borate used to cross-link.  
         [0041]    Example 16 illustrates the making of a 30.0 lb (14 kg) gel using the Old Guar and the on-the-fly procedure described above. Using 2.0 ml of borate to cross-link, Example 16 exhibits a measurable viscosity and shows that cross-linking took place. For the sake of comparison, the 17.0 lb (8 kg) gel of Example 17 also used the Old Guar and the same procedure as Example 16 but did not exhibit any measurable viscosity. From the results of Examples 11, 12, 16, and 17, it may be seen that the use of the New Guar  1  and New Guar  2  allows for a measurable viscosity by the use of a 17.0 lb (8 kg) gel in the above procedure, whereas use of the Old Guar allows for a measurable viscosity by the use of a 30.0 lb (14 kg) gel in the above procedure but not by the use of a 17.0 lb (14 kg) gel.  
       EXAMPLE 14  
       [0042]    In this example, the New Guar  2  was used in the liquid slurry form of the prior art. The results are also shown in TABLE 2.  
         [0043]    A liquid slurry was made using a 48/50 ratio of New Guar  2  to Diesel No.  2  and about 1.45 ml of this liquid slurry was mixed with about 150 ml of tap water and shaken for about 30 seconds. Thereafter, about 0.2 ml of pH buffer solution was added into the mixture and shaken for about 10 seconds. A cross-linking agent was added to the mixture and then shaken for about 20 more seconds. The resulting cross-linked gel was then placed in a FANN-50 rheometer for viscosity measurements. In the rheometer, a B5 extended bob was used, and the measurements were taken at 95 rpm and at 140 degrees F. (60° C., 333 K). As shown in TABLE 2, the liquid slurry produces a lower viscosity than the on-the-fly gel using the New Guar  2  powder. For the sake of comparison, example 13 used the same New Guar  2  powder and the same amount of cross-linking agent but had a higher resulting viscosity.  
       EXAMPLE 15  
       [0044]    In this example, about 0.3 g of the New Guar  2  powder was mixed with 150 ml of tap water in a homogenizer with an open disc for about 30 seconds, which yields a mixture that is comparable to a 17.0 lb (8 kg) gel. Thereafter, about 0.2 ml of pH buffer solution was added into the mixture and mixed for about 10 seconds in the homogenizer. A cross-linking agent was added to the mixture and then mixed in the homogenizer for about 20 more seconds. The resulting cross-linked gel was then placed in a FANN-50 rheometer for viscosity measurements. In the rheometer, a B5 extended bob was used, and the measurements were taken at 95 rpm and at 140 degrees F. (60° C., 333 K). The viscosity measurements for 10 minute intervals are shown in TABLE 2.  
       EXAMPLE 18  
       [0045]    This example illustrates a procedure for on-the-fly making of a 17.0 lb (8 kg) gel with a 30 second mixing of the guar powder and hydrating liquid. The results are also shown in TABLE 2. In this example, 1.02 g of New Guar  2  was hydrated in 500.0 ml of water for about 30 seconds in a Waring blender at about 1200 rpm. About 1.25 mls of borate cross-linking agent was then added to the fluid and further mixed for about two minutes. The resulting cross-linked gel was then placed in a FANN-50 rheometer for viscosity measurements. In the rheometer, a B 5  extended bob was used, and the measurements were taken at 95 rpm and at 140 degrees F (60° C., 333 K). The viscosity measurements for 10 minute intervals and the amounts of cross-linker used are shown in TABLE 2. From the results shown in TABLE 2, it may be seen that the New Guar  2  exhibits a high viscosity and a fast hydration with only 30 seconds of mixing in the Waring blender. For the sake of comparison, Example 11, which used New Guar  1 , used the same procedure as this Example 18, except that Example 11 hydrated the guar powder in the water for about 30 minutes in the Waring blender, instead of the hydration for about 30 seconds of Example 18. However, the resulting viscosities of Example 11 and 18 are similar.  
         [0046]    Although the present invention and its advantages have been described in detail, it should be understood that various changes, substitutions and alterations can be made herein without departing from the spirit and scope of the invention as defined by the appended claims. In particular, every range of values disclosed herein is to be understood as referring to the power set (the set of all subsets) of the respective range of values, in the sense of Georg Cantor. Accordingly, the protection sought herein is as set forth in the claims below.
A method of treating a subterranean formation using a well-treating fluid is provided, the subterranean formation penetrated by a wellbore, the method comprising preparing the well-treating fluid by admixing a fast-hydrating high-viscosity guar powder to a hydrating liquid to prepare the well-treating fluid; hydrating the guar powder; admixing a cross-linker to the well-treating fluid; and introducing the well-treating fluid to the wellbore at a temperature and a pressure sufficient to treat the subterranean formation. A product is also provided comprising a well-treating fluid for use in treating subterranean formations with the well-treating fluid comprising a hydrating liquid; a gelling agent, the gelling agent comprising a fast-hydrating high-viscosity guar powder; and a cross-linker.