Proppant addition method and system   

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. Provisional Patent Application Ser. No. 61/131,220, filed Jun. 6, 2008, entitled “Method of Fracturing Subterranean Formations Utilizing High Efficiency Fracturing Fluids and Apparatus Therefore,” and is related to co-pending U.S. application Ser. No. ______ (Attorney Docket No. HES 2008-IP-012563U1) entitled “Methods of Treating Subterranean Formations Utilizing Servicing Fluids Comprising Liquefied Petroleum Gas and Apparatus Thereof” filed concurrently herewith, the entire disclosures of which are incorporated herein by reference.

The present invention relates to methods of injecting a fracturing fluid into a well bore and, more particularly, in certain embodiments, to methods of injecting proppant downstream of clean high-pressure pumps.

In conventional fracturing operations as shown in FIG. 1, dirty high-pressure pumps 100 connect to central manifold 102. “High-pressure pumps” generally refer to pumps pumping 1,000 psi or more. Dirty high-pressure pumps 100 are high-pressure pumps through which fracturing fluid, including proppant and/or other abrasive material, passes. The proppant may be sand, manmade proppant particulates, sawdust, nutshells, or any other material a person having ordinary skill in the art would find useful for fracturing operations. Manifold 102 may be a trailer system that transfers high-pressure fracturing fluid to wellhead 104 and downhole to a perforated zone for fracturing.

Manifold 102 may also transfer fracturing fluid from at least one fluid treatment blender 106 to dirty high-pressure pumps 100. Fluid treatment blender 106 generally combines gelling agents, chemical additives from chemical storage 136, and dry proppant at relatively low pressures. The gelling agent solution typically hydrates with water from potable/treated water supply 108 and pre-blends in separate pregel blender 110 before pumping to fluid treatment blender 106. At fluid treatment blender 106, proppant meters from proppant supply 112 into the remaining mixture to become a fracturing fluid that feeds into dirty high-pressure pumps 100. Thus, dirty high-pressure pumps 100 are subject to erosive and abrasive forces resulting from proppant-laden (“dirty”) fluids.

In this configuration, all dirty high-pressure pumps 100 intake fracturing fluid having about 0.5-10 pounds of proppant per gallon of fluid. In some operations such as WaterFrac operations, the proppant concentrations may be as low as 0.1 pounds per gallon. Erosion in dirty high-pressure pumps 100 may be particularly problematic for valves, seats, and fluid ends. In many cases, maintenance on high-pressure pump consumables may be so frequent as to affect utilization rates by more than 20%.

The concentration of abrasive materials, for example, proppant, in a fluid, along with fluid velocity has an enormous impact on maintenance costs for dirty high-pressure pumps 100. By way of example, the relative maintenance cost of pumping a fluid with about 1.5 pounds of 10-20 sand per gallon may be 7 times greater than pumping an abrasive-free fluid; and the maintenance cost of pumping a fluid with about 1 pound of 20-40 UCAR proppant per gallon may be 34 times greater than pumping an abrasive-free fluid.

“Split-fluid-flow” is another known configuration for fracturing operations including WaterFrac operations. Split-fluid-flow as shown in FIG. 2 involves so-called “clean” and “dirty” high-pressure pumps, 114 and 100 respectively. In this context, clean pumps 114 pump “clean” fluids or those without proppant, while dirty pumps 100 pump “dirty” fluids, or those that are slurry-laden or have proppant therein. Depending on the configuration of a particular job, a given pump may be used as either a clean pump or a dirty pump. Thus, the same pump may be a clean pump for one job and a dirty pump for the next, or vice versa.

With split-fluid-flow, dry proppant from proppant supply 112, gelling agent solution from pregel blender 110, water or other treated fluid from potable/treated fluid supply 108, and chemical additives from chemical storage 136 combine in fluid treatment blender 106 before passing through dirty high-pressure pumps 100. The concentrations of these materials, however, are higher than in the more typical fracturing operations because the split-fluid-flow configuration is such that only a fraction of total fluid flow going to wellhead 104 contains proppant. The other portion of the split-fluid-flow may be comprised of simply water optionally with chemicals such as friction reducers. This water need not be from potable/treated fluid supply 108, but instead may be untreated produced or returned water, or other types of water from untreated fluid supply 118. Boost pump 138 may draw water or other fluid from untreated fluid supply 118, pass it through optional fluid treatment operations 140, and pump it to clean high-pressure pumps 114. Fluid treatment operations 140, when present, may include bacteria control, reducing solids, fluid clarification, removing suspended solids, chemical treatment, ion removal, or any of a number of other treatments.

Each of these separate streams, that is, the clean and dirty streams, passes independently through respective high-pressure pumps, 114 and 100. By separating the clean and dirty high-pressure pumps, 114 and 100, the overall abrasive effects of the proppant may diminish, and consequently, the maintenance costs may lessen. Additionally, fluid treatment blender 106 may be smaller in split-fluid-flow operations than in conventional fracturing operations.

However, even split-fluid-flow operations require job critical dry proppant handling, metering and mixing equipment at the jobsite. This dry proppant also requires transport to and storage on location. The equipment involved can be complicated, costly, and prone to failure due to the number of job critical systems and components involved.

SUMMARY

In some embodiments, a method of injecting a fracturing fluid may include pressurizing a first fluid with one or more clean high-pressure pumps, joining proppant with the pressurized first fluid to form the fracturing fluid, and moving the fracturing fluid to a wellhead and downhole into a formation for fracturing, wherein a pump pressurizes the proppant without passing the proppant therethrough.

In other embodiments, a fracturing fluid addition system may comprise one or more clean high-pressure pumps, a proppant supply, and a fluid supply that provides fluid for the clean high-pressure pumps to pressurize before the fluid joins proppant from the proppant supply. A pump may pressurize the proppant without the proppant passing therethrough.

In other embodiments, a method of injecting a fracturing fluid may include beginning a fracturing operation, pressurizing a first fluid with one or more clean high-pressure pumps, joining premixed proppant with the pressurized first fluid to form the fracturing fluid, and moving the fracturing fluid to a wellhead and downhole to a perforated zone for fracturing. The premixed proppant may include proppant mixed with a liquid prior to the beginning of the fracturing operation.

In other embodiments, a fracturing fluid addition system may include one or more clean high-pressure pumps, a proppant supply that stores premixed proppant, and a treated fluid supply that provides fluid for the clean high-pressure pumps to pressurize before the fluid joins premixed proppant from the proppant supply. The premixed proppant may include proppant mixed with a liquid and stored in the proppant supply until the beginning of a fracturing operation.

The features and advantages of the present invention will be readily apparent to those skilled in the art. While those skilled in the art may make numerous changes, such changes are within the spirit of the invention.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a schematic of a conventional fracturing operation.

FIG. 2 illustrates a schematic of a split-fluid-flow fracturing operation.

FIG. 3 illustrates a schematic of a fracturing operation using only clean high-pressure pumps in accordance with embodiments of the present invention.

FIG. 4 illustrates a schematic of a proppant injection system in accordance with embodiments of the present invention.

FIG. 5 illustrates a schematic of a modified split-fluid-flow fracturing operation in accordance with embodiments of the present invention.

FIG. 6 illustrates a schematic of a modified split-fluid-flow fracturing operation in accordance with embodiments of the present invention.

FIG. 7 illustrates a schematic of a fracturing operation using only clean high-pressure pumps in accordance with embodiments of the present invention.

DETAILED DESCRIPTION

Referring to FIG. 3, fluid treatment system 116 may supply water or other fluid, proppant, gels, and other chemical additives to wellhead 104. In the embodiment of FIG. 3, fluid treatment system 116 may include pregel blender 110, untreated fluid supply 118, fluid treatment blender 106, chemical storage 136, manifold 102, a number of clean high-pressure pumps 114, and proppant supply 112. Untreated fluid supply 118 may contain fluid, which need not be potable/treated water, but instead may be untreated produced or returned water, or other types of fluid. Boost pump 138 may draw fluid from untreated fluid supply 118 before passing it through optional fluid treatment operations 140 to fluid treatment blender 106, where it may combine with gels from pregel blender 110 and other chemical additives from chemical storage 136. The mixture in pregel blender 110 may include chemical additives such as friction reducing agents, gelling agents, clay control agents, surfactants, bactericides, gas permeability agents, and the like. Such chemical additives may move from pregel blender 110 to fluid treatment blender 106 and blend with water or other fluid before moving to clean high-pressure pumps 114 via manifold 102. While this embodiment includes both pregel blender 110 and fluid treatment blender 106, depending on the job, either or both may be omitted. Clean high-pressure pumps 114 may pressurize the fluid. After passing through clean high-pressure pumps 114, the pressurized fluid may join proppant from proppant supply 112, forming a fracturing fluid. The fracturing fluid may then move through manifold 102 to wellhead 104 and downhole to a perforated zone for fracturing. By providing for the addition of proppant after the fluid has passed through clean high-pressure pumps 114, life expectancy and reliability of the pumps may improve, and maintenance costs may diminish over traditional methods involving erosive and abrasive forces caused by proppant-laden fluids passing through dirty high-pressure pumps 100. Additionally, this method may allow for independent optimization of operations. In other words, the operator may separately optimize the high-pressure pumping operations and abrasive additive operations.

In some embodiments, clean high-pressure pumps 114 may be staged centrifugal pumps, or positive displacement pumps, but other types of pumps may also be appropriate. In some embodiments, proppant supply 112 may be a high-pressure liquid sand injection system comprising a HT-400-type pump, but other supply mechanisms are also within the scope of this invention.

In addition to improving the life of clean high-pressure pumps 114 and reducing downtime, the methods disclosed herein may allow for a reduction in the size of manifold 102, leading to a quicker rig-up time. An easier rig-up may additionally reduce injuries on location. Further, the number of pumps on location may lessen, as the need for backup horsepower may diminish with pumps that are more reliable. Finally, injecting wet proppant downstream of clean high-pressure pumps may lead to a reduction of equipment on location because the proppant/fluid mixture may be a premix from some other location, which has arrived at the well location in transports. This mixture may then offload to the proppant injector and move directly into the high-pressure fluid stream.

An operator may choose any of a number of methods to inject proppant into the high-pressure stream. In some embodiments, clean high-pressure pumps 114 may pressurize proppant without actually passing proppant therethrough. Referring now to FIG. 4, proppant injection system 142 may include at least one high-pressure chamber 120 may be divided by a plunger or floating piston 132 such that pressure from a clean fluid in clean high-pressure line 127 may transfer to dirty fluid. In other words, pressurized fluid may pressurize the proppant, which may be part of a proppant laden fluid. As illustrated, this may be at a 1:1 ratio. However, other ratios may also be suitable, depending on the job conditions. Multiple high-pressure chambers 120 may allow for continual introduction of proppant through fill line 124, through high-pressure chamber 120, and into high-pressure stream 126 going to wellhead 104.

Still referring to FIG. 4, proppant may move from proppant supply 112 (not shown in FIG. 4) into proppant fill line 124 at low pressure. In some embodiments, proppant may be liquid-prop or master blend from proppant storage 134 (shown and discussed with respect to FIGS. 5-8). In other embodiments, proppant may move from a blender. Proppant injection system 142 may have an electric over hydraulic control system with poppet or other types of valves for check valves and relief valves.

Proppant fill line 124 may supply proppant with a minimum constant pressure. One or more high-pressure chambers 120 may open to atmospheric pressure via valves 122 in bleed line 128, such that the pressure supplied in proppant fill line 124 may be sufficient to open respective check valve(s) 130 and move respective floating piston(s) 132. When a high-pressure chamber 120 sufficiently fills, corresponding control valve 122 to bleed line 128 may close and corresponding control valve 122 to clean high-pressure line 127 may open. Since floating piston 132 floats, the pressure may equalize. The high pressure on the proppant-laden fluid may then push the fluid through corresponding check valve 130 into high-pressure stream 126 going to wellhead 104. The pressure differential across floating piston 132 may only be enough to overcome piston friction, unless floating piston 132 seats when filling with proppant. In this case, the pressure may be equivalent to the supply pressure of the proppant-laden fluid. A pressure relief valve on clean high-pressure line 127 may prevent a large pressure differential if floating piston 132 seats on the power stroke. The volume available in each high-pressure chamber 120 and the number of high-pressure chambers 120 may be sufficient to allow continuous injection of proppant into high-pressure stream 126 going to wellhead 104. Thus, all high-pressure pumps on location may be clean high-pressure pumps 114.

In various other embodiments, proppant may move from proppant supply 112 into high-pressure stream 126 going to wellhead 104. In other words, proppant may enter downstream, or on the high-pressure side, of clean high-pressure pumps 114. For example, proppant may move from proppant supply 112 via a parallel series of high-pressure tanks that may valve through a manifold. In another embodiment, proppant may move via a piston at the bottom of an addition container. In another embodiment, proppant may move from proppant supply 112 via a staged plunger-type injection with wet sand. In still another embodiment, proppant may move from proppant supply 112 via a high-pressure eductor for sand injection.

In some embodiments, injecting proppant from proppant supply 112 may involve a proppant suspended within a solution of liquid prior to the beginning of the fracturing operation. Such proppant slurry mixtures may be mixed onsite or offsite and may be high concentration solutions, e.g., 20 pounds per gallon and greater. In some embodiments, the proppant may mix with liquid offsite. In other embodiments, the proppant may mix onsite, but before the start of the job. Thus, the fracturing process may proceed without handling, metering, or mixing dry proppant during fracturing.

The method illustrated in FIG. 5 utilizes a split-fluid-flow, having corresponding clean and dirty high-power pumps, 114 and 100, and benefits from the advantages of lower equipment wear, increased reliability, etc. However, it differs from conventional split-fluid-flow methods because it involves different method of transport, handling, metering, and mixing of the proppant. In this embodiment, the proppant may be a premixed proppant, such as a concentrated, job specific slurry, mixed either on location before the job, or at a mixing station at a centralized location before transport to the jobsite as “liquid-prop.” The centralized location may be remote from the pad of a particular fracturing operation and a single centralized mixing station may supply several frac spreads. Tankers may transport the liquid-prop to the jobsite and pump it into holding tank 134, instead of pneumatic transport trailers trucking dry proppant to mountain movers at the jobsite. Alternatively, pipelines may transport the liquid-prop to the pad prior to the commencement of the fracturing operation. The liquid-prop may then move to dirty high-pressure pumps 100, for example, via booster pump (not shown), upon commencement of the job. Potable/treated fluid supply 108 may provide water or other fluid to pregel blender 110, which may provide gel and chemical additives from chemical supply 136 to fluid treatment operations 140, without the need for a separate fluid treatment blender 106 as is typically required. The flow rate of dirty high-pressure pumps 100 may vary to provide the desired proppant concentration downhole. The “clean” portion of this embodiment of a split-fluid-flow may be substantially the same as described above with respect to FIG. 2. The use of a centralized mixing station may reduce or eliminate the need for mountain movers and/or fluid treatment blender 106. By reducing the equipment required, the space required for a fracturing operation may contract, along with the number of operators. Additionally, reduction in equipment can increase reliability of the job by reducing the difficulties associated with job critical equipment. The centralized mixing station may also enhance the accuracy of the mixture because the weighing and dosing equipment may be stationary and the mixing time and personnel may be independent of the job schedule. The use of stationary equipment instead of mobile conveying, metering, and mixing equipment may also require lower capital investment. In addition to being less expensive, stationary equipment may be capable of supplying several frac spreads.

Similar to liquid-prop, other premixed proppants, such as concentrated liquid sand compositions may be prepared and transported to the well site in advance. Some such compositions may be high solids content slurries that may be substantially stable and may not substantially settle prior to admixing with treatment fluid.

In yet another alternative embodiment, premixed proppants may include a master blend that may be mixed either offsite or in advance on-site. This master blend may include proppant, gelling agents, friction reducers, and any other chemical additives needed in a single concentrated mixture. In other words, in addition to liquid and sand, the master blend may include of all chemicals and gelling agents needed for a fracturing stage containing proppant. For example, the master blend may contain corrosion inhibitors, biocides, and clay control surfactants. Such a master blend may allow for operations that are more efficient and minimize equipment at the well site, including equipment for blending operations.

In one embodiment, split-fluid-flow fracturing configurations may use the master blend. FIG. 6 illustrates a configuration without the need for fluid treatment blender 106 or pregel blender 110. The master blend may move from holding tank 134 directly to dirty high-pressure pumps 100. The movement of the master blend may occur at the same time as water or other fluid moves from potable/treated fluid supply 108 to fluid treatment operations 140 and chemical additives move from chemical storage 136 directly to dirty high-pressure pumps 100. The chemicals may move via a chemical addition system (not shown). Alternatively, a simple t-mixer prior to dirty high-pressure pumps 100 may be sufficient for mixing of the chemicals into the water or other fluid used for fracturing. The “clean” portion of this embodiment of a split-fluid-flow may be substantially the same as described above with respect to FIG. 2.

In the embodiment illustrated in FIG. 7, only clean high-pressure pumps 114 are used. In this particular configuration, centrifugal and/or staged pumps may be advantageous, depending on the pressure required. The master blend, dry proppant, or other proppant may move from proppant supply 112 or holding tank 134 (not shown), through proppant injection system 142, and into high-pressure stream 126 downstream of clean high-pressure pumps 114. While proppant injection system 142 is illustrated in FIG. 7, a staged centrifugal pump (not shown) or other types of injection may be used. In fracturing stages that do not contain proppant, chemicals may also move into high-pressure stream 126 from chemical storage 136, via chemical injection system 145. Chemical injection system 145 may operate in a manner similar to that of proppant injection system 142, or may be any other type of injection system. Thus, the embodiment depicted in FIG. 7 may eliminate the need for fluid treatment blender 106, pregel blender 110, transport, storage, and conveyance of dry proppant, and dirty high-pressure pumps 100. Further, the embodiment depicted in FIG. 7 may allow for injection remote from manifold 102 and clean high-pressure pumps 114. For example, chemicals and proppant may be injected at a pad remote from the pad of the manifold and pumps. In some embodiments, the distance between the pads may be about a mile or more. Alternatively, proppant supply 112 and chemical storage 136 may be coordinated units, used in conjunction with, and situated on the same pad as manifold 102.

The term “proppant” may include any of a number of particulates suitable for use in the present invention, which may be comprised of any material suitable for use in subterranean operations. Suitable particulate materials include, but are not limited to, sand; bauxite; ceramic materials; glass materials; polymer materials; Teflon® materials; nut shell pieces; seed shell pieces; cured resinous particulates comprising nut shell pieces; cured resinous particulates comprising seed shell pieces; fruit pit pieces; cured resinous particulates comprising fruit pit pieces; wood; composite particulates and combinations thereof. Composite particulates may also be suitable, suitable composite materials may comprise a binder and a filler material wherein suitable filler materials include silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide, meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, solid glass, and combinations thereof. Typically, the particulates have a size in the range of from about two to about 400 mesh, U.S. Sieve Series. In particular embodiments, preferred particulates size distribution ranges are one or more of 6/12 mesh, 8/16, 12/20, 16/30, 20/40, 30/50, 40/60, 40/70, or 50/70 mesh. It should be understood that the term “particulate,” as used in this disclosure, includes all known shapes of materials including substantially spherical materials, fibrous materials, polygonal materials (such as cubic materials) and mixtures thereof. Moreover, fibrous materials that may or may not bear the pressure of a closed fracture are often included in proppant and gravel treatments.

Generally, the teachings of the present invention may use any treatment fluid suitable for a fracturing, gravel packing, or frac-packing application, including aqueous gels, viscoelastic surfactant gels, oil gels, foamed gels, and emulsions. Suitable aqueous gels are generally comprised of water and one or more gelling agents. Suitable emulsions can be comprised of two immiscible liquids such as an aqueous liquid or gelled liquid and a hydrocarbon. The addition of a gas, such as carbon dioxide or nitrogen may create foams. In exemplary embodiments of the present invention, the fracturing fluids are aqueous gels comprised of water, a gelling agent for gelling the water and increasing its viscosity, and, optionally, a crosslinking agent for crosslinking the gel and further increasing the viscosity of the fluid. The increased viscosity of the gelled, or gelled and cross-linked, treatment fluid, inter alia, reduces fluid loss and allows the fracturing fluid to transport significant quantities of suspended proppant particles. The water used to form the treatment fluid may be fresh water, salt water, brine, seawater, or any other aqueous liquid that does not adversely react with the other components. The density of the water can increase to provide additional particle transport and suspension in the present invention.

A useful variety of gelling agents may include hydratable polymers that contain one or more functional groups such as hydroxyl, carboxyl, sulfate, sulfonate, amino, or amide groups. Suitable gelling typically comprises polymers, synthetic polymers, or a combination thereof. A variety of suitable gelling agents for use in conjunction with the methods and compositions of the present invention, include, but are not limited to, hydratable polymers that contain one or more functional groups such as hydroxyl, cis-hydroxyl, carboxylic acids, and derivatives of carboxylic acids, sulfate, sulfonate, phosphate, phosphonate, amino, or amide. In certain exemplary embodiments, the gelling agents may be polymers comprising polysaccharides, and derivatives thereof that contain one or more of these monosaccharide units: galactose, mannose, glucoside, glucose, xylose, arabinose, fructose, glucuronic acid, or pyranosyl sulfate. Examples of suitable polymers include, but are not limited to, guar gum and derivatives thereof, such as hydroxypropyl guar and carboxymethylhydroxypropyl guar, and cellulose derivatives, such as hydroxyethyl cellulose. Additionally, synthetic polymers and copolymers that contain the above-mentioned functional groups may be used. Examples of such synthetic polymers include, but are not limited to, polyacrylate, polymethacrylate, polyacrylamide, polyvinyl alcohol, and polyvinylpyrrolidone. In other exemplary embodiments, the gelling agent molecule may be depolymerized. The term “depolymerized,” as used herein, generally refers to a decrease in the molecular weight of the gelling agent molecule. U.S. Pat. No. 6,488,091 issued Dec. 3, 2002 to Weaver, et al., the relevant disclosure of which incorporates herein by reference, describes depolymerized gelling agent molecules. Suitable gelling agents generally are present in the viscosified treatment fluids of the present invention in an amount in the range of from about 0.1% to about 5% by weight of the water therein. In certain exemplary embodiments, the gelling agents are present in the viscosified treatment fluids of the present invention in an amount in the range of from about 0.01% to about 2% by weight of the water therein.

Crosslinking agents may be used to crosslink gelling agent molecules to form crosslinked gelling agents. Crosslinkers typically comprise at least one ion that is capable of crosslinking at least two gelling agent molecules. Examples of suitable crosslinkers include, but are not limited to, boric acid, disodium octaborate tetrahydrate, sodium diborate, pentaborates, ulexite and colemanite, compounds that can supply zirconium IV ions (such as, for example, zirconium lactate, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate, zirconium malate, zirconium citrate, and zirconium diisopropylamine lactate); compounds that can supply titanium IV ions (such as, for example, titanium lactate, titanium malate, titanium citrate, titanium ammonium lactate, titanium triethanolamine, and titanium acetylacetonate); aluminum compounds (such as, for example, aluminum lactate or aluminum citrate); antimony compounds; chromium compounds; iron compounds; copper compounds; zinc compounds; or a combination thereof. An example of a suitable commercially available zirconium-based crosslinker is “CL-24” available from Halliburton Energy Services, Inc., Duncan, Okla. An example of a suitable commercially available titanium-based crosslinker is “CL-39” available from Halliburton Energy Services, Inc., Duncan Okla. Suitable crosslinkers generally are present in the viscosified treatment fluids of the present invention in an amount sufficient to provide, inter alia, the desired degree of crosslinking between gelling agent molecules. In certain exemplary embodiments of the present invention, the crosslinkers may be present in an amount in the range from about 0.001% to about 10% by weight of the water in the fracturing fluid. In certain exemplary embodiments of the present invention, the crosslinkers may be present in the viscosified treatment fluids of the present invention in an amount in the range from about 0.01% to about 1% by weight of the water therein. Individuals skilled in the art, with the benefit of this disclosure, will recognize the exact type and amount of crosslinker to use depending on factors such as the specific gelling agent, desired viscosity, and formation conditions.

The gelled or gelled and cross-linked treatment fluids may also include internal delayed gel breakers such as enzyme, oxidizing, acid buffer, or temperature-activated gel breakers. The gel breakers cause the viscous treatment fluids to revert to thin fluids for production back to the surface after use to place proppant particles in subterranean fractures. The gel breaker used is typically present in the treatment fluid in an amount in the range of from about 0.5% to about 10% by weight of the gelling agent. The treatment fluids may also include one or more of a variety of well-known additives, such as gel stabilizers, fluid loss control additives, clay stabilizers, bactericides, and the like.

While the term “fracturing” as used herein generally refers to conventional fracturing operations, it may include frac pack operations or any of a number of other treatments, comprising fracturing. Additionally, the methods of this disclosure may be used for non-fracturing operations.

Therefore, the present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as those skilled in the art, having the benefit of the teachings herein may modify and practice the invention in different but equivalent manners. Furthermore, the details of construction or design herein shown do not provide limitations, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered or modified and all such variations fall within the scope and spirit of the present invention. All numbers and ranges disclosed above may vary by any amount (e.g., 1 percent, 2 percent, 5 percent, or, sometimes, 10 to 20 percent). Whenever a numerical range with a lower limit and an upper limit appears, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. In addition, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.