Patent Application
20080078545
In certain embodiments, the present invention provides compositions and methods that are especially suitable for use in well bores comprising bottom-hole temperatures (“BHTs”) from about 30° F. to about 400° F. As known to one of ordinary skill in the art, the bottom hole circulating temperature may be below the BHT of the well bore, however, the BHT should be indicative of the temperature of a treatment fluid circulated in the bottom hole during the treatment. The temperatures to which the fluids are subjected can affect their particulate transport properties, depending on the concentration of the xanthan gelling agent in the fluid as well as other components. One advantage of the present invention is that the particulate transport properties of the fluids of the present invention are exceptional in that, in certain embodiments, the fluids can hold particulates in almost perfect suspension under static conditions at elevated temperatures for many hours, possibly several days.
Another advantage of the many advantages of the fluids of the present invention is that they are sheer thinning fluids.
The viscosified treatment fluids of the present invention generally comprise water and a gelling agent that comprises a modified xanthan.
The term “modified xanthan” as used herein means a xanthan that has been treated, either chemically, genetically, or otherwise, to modify or alter the normal polymeric structure of xanthan. Two preferable modifications are where a portion (or all) of the acetyl and/or the pyruvate groups have been removed.
Suitable modified xanthans generally exhibit pseudoplastic rheology (sheer reversible behavior). Suitable modified xanthans also are generally soluble in hot or cold water, and are stable over a range of pHs and temperatures. Additionally, they are compatible with and stable in systems containing salts, e.g., they will fully hydrate in systems comprising salts. Moreover, suitable modified xanthans should provide good suspension for particulates often used in subterranean applications, such as proppant or gravel. Preferred xanthans should have good filterability. For example, in gravel packing a desirable modified xanthan preferably has a flow rate of at least about 200 ml in 2 minutes at ambient temperature in a filtering laboratory test on a Baroid Filter Press using 40 psi of differential pressure and a 11 cm Whatman filter paper having a 2.7 .mu. pore size. An example of a suitable deactylated xanthan for use in conjunction with the compositions and methods of the present invention is commercially available from Degussa.
In some embodiments, suitable modified xanthans can be treated to help remove debris from the modified xanthan polymer. For example, an enzyme as known in the art for treating normal xanthan can be used to treat a modified xanthan to remove debris. This can be particularly advantageous for use of the modified xanthan in a brine. In certain preferred embodiments, the viscosified treatment fluids of the present invention comprise a brine and a gelling agent that comprises a modified xanthan.
Optionally, the gelling agent of the present invention can comprise an additional biopolymer if the use of the modified xanthan and the biopolymer produces a desirable result, e.g., a synergistic effect. Suitable biopolymers may include polysaccharides and/or derivatives thereof. Depending on the application, one biopolymer may be more suitable than another. One of ordinary skill in the art with the benefit of this disclosure will be able to determine if a biopolymer should be included for a particular application based on, for example, the desired viscosity of the viscosified treatment fluid and the bottom hole temperature (“BHT”) of the well bore.
The amount of gelling agent used in the viscosified treatment fluids of the present invention can vary from about 20 lb/Mgal to about 100 lb/Mgal. In other embodiments, the amount of gelling agent included in the treatment fluids of the present invention can vary from about 30 lb/Mgal to about 80 lb/Mgal. In a preferred embodiment, about 60 lb/Mgal of a gelling agent is included in an embodiment of a treatment fluid of the present invention. It should be noted that in well bores comprising BHTs of 200° F. or more, 70 lbs/Mgal or more of the gelling agent can be beneficially used in a treatment fluid of the present invention.
The viscosified treatment fluids of the present invention can vary widely in density. One of ordinary skill in the art with the benefit of this disclosure will recognize the particular density that is most appropriate for a particular application. In certain preferred embodiments, the viscosified treatment fluids of the present invention will have a density of about 8.3 pounds per gallon (“ppg”) to about 19.2 ppg. The desired density for a particular viscosified treatment fluid may depend on characteristics of the subterranean formation, including, inter alia, the hydrostatic pressure required to control the fluids of the subterranean formation during placement of the viscosified treatment fluids. The types of salts or brines used to achieve the desired density of the viscosified treatment fluid can be chosen based on factors such as compatibility with the formation, crystallization temperature, and compatibility with other treatment and/or formation fluids. Availability and environmental impact also may affect this choice. In certain embodiments, the viscosified treatment fluid can be foamed with a gas, such as nitrogen or carbon dioxide.
A brine suitable for use in the viscosified treatment fluids of the present invention with a modified xanthan can include brines of monovalent cations brines, which can be of any weight up to saturation of the salt. Brines that comprise divalent or trivalent cations, e.g., magnesium, calcium, iron, in some concentrations and at some pH levels may cause undesirable crosslinking of a normal xanthan polymer, and to a lesser extent a modified xanthan polymer.
If a water source is used which contains such divalent or trivalent cations in concentrations sufficiently high to be problematic even for the modified xanthan, then the concentration of such divalent or trivalent salts can be reduced or completely removed. Such cations can be reduced or removed, for example, by a process such as reverse osmosis or by raising the pH of the water in order to precipitate out such divalent salts to lower the concentration of such salts in the water before the water is used. Another method for removing such ions is to include a chelating agent to chemically bind the problematic ions to prevent their undesirable interactions with the modified xanthan. Suitable chelants include, but are not limited to, citric acid or sodium citrate. Other chelating agents also are suitable.
Examples of suitable brines include monovalent brines such as sodium chloride brines, sodium bromide brines, potassium bromide brines, potassium chloride brines, sodium nitrate brines, potassium formate brines, cesium formate brines, and the like, and any mixture thereof in any proportion. In addition, however, the modified xanthans can be more easily hydrated with other brines of divalent and trivalent cations such as calcium bromide brines, zinc bromide brines, calcium chloride brines, mixtures thereof, and the like, and any mixture thereof in any proportion. The brine chosen should be compatible with the formation and should have a sufficient density to provide the appropriate degree of well control. Additional salts can be added to a water source, e.g., to provide a brine. The added salts can be used to help formulate a resulting viscosified treatment fluid having a desired density.
A preferred suitable brine is seawater. The gelling agents of the present invention can be used successfully with seawater.
In certain embodiments, the viscosified treatment fluids of the present invention also can comprise other salts, pH control additives, surfactants, breakers, bactericides, crosslinkers, fluid loss control additives, stabilizers, chelants, gases, mutual solvents, fibers, proppant, corrosion inhibitors, acids, bases, oxidizers, reducers, scale inhibitors, combinations thereof, or the like.
A salt may be included in the viscosified treatment fluids of the present invention for many purposes other than increasing the density of the fluid. For example, a salt also can be included for reasons related to compatibility of the viscosified treatment fluid with the formation and formation fluids. To determine whether a salt may be beneficially used for compatibility purposes, a compatibility test may be performed to identify potential compatibility problems. From such tests, one of ordinary skill in the art with the benefit of this disclosure will be able to determine whether and what salt should be included in a viscosified treatment fluid of the present invention. Suitable salts include, but are not limited to, calcium bromide, zinc bromide, calcium chloride, sodium chloride, sodium bromide, potassium bromide, potassium chloride, sodium nitrate, potassium formate, sodium formate, cesium formate, mixtures thereof, and the like. Regardless of the purpose for adding other salt, however, divalent and trivalent cations may still be of concern.
Optionally, the treatment fluids can include a material for retarding the movement of the proppant or fines. For example, materials in the form of fibers, flakes, ribbons, beads, shavings, platelets and the like that comprise glass, ceramics, carbon composites, natural or synthetic polymers, resins, or metals and the like can be admixed with the low-molecular-weight fluid and proppant. A more detailed description of such materials is disclosed in, for example, U.S. Pat. Nos. 5,330,005; 5,439,055; and 5,501,275, which are incorporated herein by reference.
The treatment fluids can include a resin or resin coating on proppant or gravel. An example of suitable resins include those that are commercially available from Halliburton Energy Services, Inc. under the trade name Expedite® Service.
Alternatively, or in addition to such other resins or resin coatings, a material comprising a tackifying compound can be admixed with the low-molecular-weight fluid or the proppant particulates to coat at least a portion of the proppant particulates, or other solid materials identified above, such that the coated material and particulates adjacent thereto will adhere together to form agglomerates that may bridge in the created fracture to prevent particulate flowback. An example of suitable tackifying compounds include those that are commercially available from Halliburton Energy Services, Inc. under the trade name and SandWedge® Conductivity Enhancement Service. The tackifying compound also can be introduced into the formation with the low-molecular-weight fluid before or after the introduction of the proppant particulates into the formation. The coated material can be effective in inhibiting the flowback of fine particulate in the proppant pack having a size ranging from about that of the proppant to less than about 600 mesh. The coated proppant or other material is effective in consolidating fine particulates in the formation in the form of agglomerates to prevent the movement of the fines during production of the formation fluids from the well bore subsequent to the treatment. A more detailed description of the use of such tackifying compounds and methods of use thereof are disclosed in U.S. Pat. Nos. 5,775,415; 5,787,986; 5,833,000; 5,839,510; 5,871,049; 5,853,048; and 6,047,772, and 6,209,643 which are incorporated herein by reference thereto. Further, aqueous based tackifying compounds can be used as envisioned in U.S. patent applications 20050277554, 20050274517, 20050092489, and 20050059558, which are incorporated herein by reference thereto.
Suitable pH control additives, in certain embodiments, can comprise bases, chelating agents, acids, or combinations of chelating agents and acids or bases. A pH control additive can be necessary to maintain the pH of the treatment fluid at a desired level, e.g., to improve the effectiveness of certain breakers and to reduce corrosion on any metal present in the well bore or formation, etc. In some instances, it can be beneficial to maintain the pH at neutral or above 7.
In some embodiments, the pH control additive can be a chelating agent. When added to the treatment fluids of the present invention, such a chelating agent can chelate any dissolved iron (or other divalent or trivalent cation) that may be present in the water. Such chelating may prevent such ions from crosslinking the gelling agent molecules. Such crosslinking may be problematic because, inter alia, it may cause severe filtration problems. Any suitable chelating agent can be used with the present invention. Examples of suitable chelating agents include, but are not limited to, an anhydrous form of citric acid, commercially available under the tradename Fe-2™ iron sequestering agent from Halliburton Energy Services, Inc., of Duncan, Okla. Another example of a suitable chelating agent is a solution of citric acid dissolved in water, commercially available under the tradename Fe-2A™ buffering agent from Halliburton Energy Services, Inc., of Duncan, Okla. Another example of a suitable chelating agent is sodium citrate, commercially available under the tradename FDP-S714-04 from Halliburton Energy Services, Inc. of Duncan, Okla. Other chelating agents that are suitable for use with the present invention include, inter alia, nitrilotriacetic acid and any form of ethylene diamine tetracetic acid (“EDTA”) or its salts. Generally, the chelating agent is present in an amount sufficient to prevent crosslinking of the gelling agent molecules by any free iron (or any other divalent or trivalent cation) that may be present. In one embodiment, the chelating agent can be present in an amount of from about 0.02% to about 2.0% by weight of the treatment fluid. In another embodiment, the chelating agent is present in an amount in the range of from about 0.02% to about 0.5% by weight of the treatment fluid. One of ordinary skill in the art with the benefit of this disclosure will be able to determine the proper concentration of chelating agents for a particular application.
In another embodiment, the pH control additive can be an acid. Any known acid can be suitable with the treatment fluids of the present invention. Examples of suitable acids include, inter alia, hydrochloric acid, acetic acid, formic acid, and citric acid.
The pH control additive also can comprise a base to elevate the pH of the viscosified treatment fluid. Generally, a base can be used to elevate the pH of the mixture to greater than or equal to about 7. Having the pH level at or above 7 may have a positive effect on a chosen breaker being used. This type of pH may also inhibit the corrosion of any metals present in the well bore or formation, such as tubing, sand screens, etc. Any known base that is compatible with the gelling agents of the present invention can be used in the viscosified treatment fluids of the present invention. Examples of suitable bases include, but are not limited to, sodium hydroxide, potassium carbonate, potassium hydroxide and sodium carbonate. An example of a suitable base is a solution of 25% sodium hydroxide commercially available from Halliburton Energy Services, Inc., of Duncan, Okla., under the tradename MO-67™ pH control agent. Another example of a suitable base solution is a solution of potassium carbonate commercially available from Halliburton Energy Services, Inc., of Duncan, Okla., under the tradename BA-40L™ buffering agent. One of ordinary skill in the art with the benefit of this disclosure will recognize the suitable bases that can be used to achieve a desired pH elevation.
In still another embodiment, the pH control additive can comprise a combination of an acid and a chelating agent or a base and a chelating agent. Such combinations may be suitable when, inter alia, the addition of a chelating agent (in an amount sufficient to chelate the iron present) is insufficient by itself to achieve the desired pH level.
In some embodiments, the viscosified treatment fluids of the present invention can include surfactants, e.g., to improve the compatibility of the viscosified treatment fluids of the present invention with other fluids (like any formation fluids) that may be present in the well bore. An artisan of ordinary skill with the benefit of this disclosure will be able to identify the type of surfactant as well as the appropriate concentration of surfactant to be used. Suitable surfactants can be used in a liquid or powder form. Where used, the surfactants are present in the viscosified treatment fluid in an amount sufficient to prevent incompatibility with formation fluids or well bore fluids. In an embodiment where liquid surfactants are used, the surfactants are generally present in an amount in the range of from about 0.01% to about 5.0% by volume of the viscosified treatment fluid. In one embodiment, the liquid surfactants are present in an amount in the range of from about 0.1% to about 2.0% by volume of the viscosified treatment fluid. In embodiments where powdered surfactants are used, the surfactants can be present in an amount in the range of from about 0.001% to about 0.5% by weight of the viscosified treatment fluid. Examples of suitable surfactants are non-emulsifiers commercially available from Halliburton Energy Services, Inc., of Duncan, Okla., under the tradenames LOSURF-259™ nonionic nonemulsifier, “LOSURF-300M™ nonionic surfactant, and LOSURF-400™ surfactant. Another example of a suitable surfactant is a non-emulsifier commercially available from Halliburton Energy Services, Inc., of Duncan, Okla., under the tradename NEA-96M™ Surfactant. It should be noted that it may be beneficial to add a surfactant to a viscosified treatment fluid of the present invention as that fluid is being pumped downhole to help eliminate the possibility of foaming in the surface equipment.
In some embodiments, the viscosified treatment fluids of the present invention can contain bactericides to protect both the subterranean formation as well as the viscosified treatment fluid from attack by bacteria. Such attacks may be problematic because they may lower the viscosity of the viscosified treatment fluid, resulting in poorer performance, such as poorer sand suspension properties, for example. Any bactericides known in the art are suitable. An artisan of ordinary skill with the benefit of this disclosure will be able to identify a suitable bactericide and the proper concentration of such bactericide for a given application. Where used, such bactericides are present in an amount sufficient to destroy all bacteria that may be present. Examples of suitable bactericides include, but are not limited to, a 2,2-dibromo-3-nitrilopropionamide, commercially available under the tradename BE-3S biocide from Halliburton Energy Services, Inc., of Duncan, Okla., and a 2-bromo-2-nitro-1,3-propanediol commercially available under the tradename BE-6 biocide from Halliburton Energy Services, Inc., of Duncan, Okla. In one embodiment, the bactericides are present in the viscosified treatment fluid in an amount in the range of from about 0.001% to about 0.003% by weight of the viscosified treatment fluid. Another example of a suitable bactericide is a solution of sodium hypochlorite, commercially available under the tradename “CAT-1” chemical from Halliburton Energy Services, Inc., of Duncan, Okla. In certain embodiments, such bactericides can be present in the viscosified treatment fluid in an amount in the range of from about 0.01% to about 0.1% by volume of the viscosified treatment fluid. In certain preferred embodiments, when bactericides are used in the viscosified treatment fluids of the present invention, they are added to the viscosified treatment fluid before the gelling agent is added.
The viscosified treatment fluids of the present invention also optionally can comprise a suitable crosslinker to crosslink the modified xanthan of the gelling agent in the viscosified treatment fluid. Crosslinking may be desirable at higher temperatures and/or when the sand suspension properties of a particular fluid of the present invention may need to be altered for a particular purpose. Suitable crosslinkers include, but are not limited to, combination crosslinker-breakers of the type disclosed in U.S. Pat. No. 7,090,015 issued Aug. 15, 2006, which is incorporated herein by reference; ferric iron derivatives; magnesium derivatives; and the like. Any crosslinker that is compatible with the modified xanthan in the gelling agent can be used. One of ordinary skill in the art with the benefit of this disclosure will recognize when such crosslinkers are appropriate and what particular crosslinker will be most suitable.
The viscosified treatment fluids of the present invention also can comprise breakers capable of reducing the viscosity of the viscosified treatment fluid at a desired time. Examples of such suitable breakers for viscosified treatment fluids of the present invention include, but are not limited to, sodium chlorites, hypochlorites, perborate, persulfates, peroxides, including organic peroxides. Other suitable breakers include, but are not limited to, suitable acids and peroxide breakers, as well as enzymes that may be effective in breaking xanthan. Preferred examples of peroxide breakers include tert-butyl hydroperoxide and tert-amyl hydroperoxide. A breaker can be included in a viscosified treatment fluid of the present invention in an amount and form sufficient to achieve the desired viscosity reduction at a desired time. The breaker can be formulated to provide a delayed break, if desired. For example, a suitable breaker can be encapsulated if desired. Suitable encapsulation methods are known to those skilled in the art. One suitable encapsulation method that can be used involves coating the chosen breakers with a material that will degrade when downhole so as to release the breaker when desired. Resins that can be suitable include, but are not limited to, polymeric materials that will degrade when downhole. The terms “degrade,” “degradation,” or “degradable” refer to both the two relatively extreme cases of hydrolytic degradation that the degradable material may undergo, i.e., heterogeneous (or bulk erosion) and homogeneous (or surface erosion), and any stage of degradation in between these two. This degradation can be a result of, inter alia, a chemical or thermal reaction or a reaction induced by radiation. Suitable examples include, but are not limited to, polysaccharides such as dextran or cellulose; chitins; chitosans; proteins; aliphatic polyesters; poly(lactides); poly(glycolides); poly(.epsilon.-caprolactones); poly(hydroxybutyrates); poly(anhydrides); aliphatic polycarbonates; orthoesters, poly(orthoesters); poly(amino acids); poly(ethylene oxides); and polyphosphazenes. If used, a breaker should be included in a composition of the present invention in an amount sufficient to facilitate the desired reduction in viscosity in a viscosified treatment fluid. For instance, peroxide concentrations that can be used vary from about 0.05 to about 30 gallons of peroxide per 1000 gallons of the viscosified treatment fluid.
Optionally, a viscosified treatment fluid of the present invention can contain an activator or a retarder, inter alia, to optimize the break rate provided by the breaker. Any known activator or retarder that is compatible with the particular breaker used is suitable for use in the present invention. Examples of such suitable activators include, but are not limited to, acid generating materials, chelated iron, copper, cobalt, and reducing sugars. Examples of suitable retarders include sodium thiosulfate and diethylene triamine. In some embodiments, the sodium thiosulfate can be used in a range of from about 1 to about 100 lbs. per 1000 gallons of viscosified treatment fluid. A preferred range can be from about 5 to about 20 lbs per 1000 gallons. An artisan of ordinary skill with the benefit of this disclosure will be able to identify a suitable activator or retarder and the proper concentration of such activator or retarder for a given application.
The viscosified treatment fluids of the present invention also can comprise suitable fluid loss control agents. Such fluid loss control agents may be particularly useful when a viscosified treatment fluid of the present invention is being used in a fracturing operation. This may be due in part to xanthan's potential to leak off into formation. Any fluid loss agent that is compatible with the viscosified treatment fluid is suitable for use in the present invention. Examples include, but are not limited to, starches, silica flour, and diesel dispersed in the treatment fluid. Another example of a suitable fluid loss control additive is one that comprises a degradable material. Suitable degradable materials include degradable polymers. Specific examples of suitable polymers include polysaccharides such as dextran or cellulose; chitins; chitosans; proteins; aliphatic polyesters; poly(lactides); poly(glycolides); poly(glycolide-co-lactides); poly(p-caprolactones); poly(3-hydroxybutyrates); poly(3-hydroxybutyrate-co-hydroxyvalerates); poly(anhydrides); aliphatic poly(carbonates); poly(orthoesters); poly(amino acids); poly(ethylene oxides); poly(phosphazenes); derivatives thereof; or combinations thereof. If included, a fluid loss additive should be added to a viscosified treatment fluid of the present invention in an amount of about 5 to about 50 pounds per 1000 gallons of the viscosified treatment fluid. In certain preferred embodiments, the fluid loss additive can be included in an amount from about 15 to about 30 pounds per 1000 gallons of the viscosified treatment fluid. For some liquid additives like diesel, these can be included in an amount from about 1% to about 20% by volume; in some preferred embodiments, these can be included in an amount from about 3% to about 10% by volume.
If in a particular application a chosen viscosified treatment fluid is experiencing a viscosity degradation a stabilizer might be useful and can be included in the fluid. One example of a situation where a stabilizer might be beneficial is where the BHT of the well bore is sufficient by itself to break the viscosified treatment fluid with the use of a breaker. Suitable stabilizers include, but are not limited to, sodium thiosulfate. Such stabilizers may be useful when the viscosified treatment fluids of the present invention are utilized in a subterranean formation having a temperature above about 150° F. If included, a stabilizer can be added in an amount of from about 1 lb to about 50 lb per 1000 gal of viscosified treatment fluid. In other embodiments, a stabilizer can be included in an amount of from about 5 to about 20 lb per 1000 gal of viscosified treatment fluid.
Scale inhibitors can be added to the viscosified treatment fluids of the present invention, for example, when a viscosified treatment fluid of the present invention is not particularly compatible with the formation waters in the formation in which it is being used. Any scale inhibitor that is compatible with the viscosified treatment fluid in which it will be used in suitable for use in the present invention. An example of a preferred compound is “LP55™” scale inhibitor from Halliburton Energy Services in Duncan, Okla. Another example of a preferred compound is “LP65™” scale inhibitor available from Halliburton Energy Services in Duncan, Okla. If used, a scale inhibitor should be included in an amount effective to inhibit scale formation. Suitable amounts of scale inhibitors to include in the viscosified treatment fluids of the present invention can range from about 0.05 to 10 gallons per about 1000 gallons of the viscosified treatment fluid, more preferably from about 0.1 to 2 gallons per about 1000 gallons of the viscosified treatment fluid.
Any particulates such as proppant and/or gravel that are commonly used in subterranean operations can be used successfully in conjunction with the compositions and methods of the present invention. For example, resin and/or tackifier coated particulates can be suitable.
According to a preferred embodiment, the present invention provides a method of making a viscosified treatment fluid comprising the steps of: providing a brine; filtering the brine through a filter; dispersing a gelling agent that comprises a modified xanthan into the brine with adequate sheer to fully disperse the gelling agent therein to form a brine and gelling agent mixture; mixing the brine and gelling agent mixture; allowing the modified xanthan to fully hydrate in the brine and gelling agent mixture to form a viscosified treatment fluid; and filtering the viscosified treatment fluid. In a preferred embodiment, a viscosified treatment fluid of the present invention can be prepared according to the following process: providing a brine having a suitable density; adding optional chemical such as biocides, chelating agents, pH control agents, and the like; filtering the brine through a 2 micron. filter or a finer filter; dispersing the gelling agent comprising a modified xanthan into the brine with adequate sheer to fully disperse polymer therein; mixing the fluid until the modified xanthan is fully hydrated; shearing the viscosified treatment fluid to fully disperse any microglobs of xanthan polymer (e.g., a relatively small agglomeration of unhydrated xanthan polymer at least partially surrounded by a dense layer of at least partially hydrated xanthan polymer) that have not fully dispersed; filtering the fluid; and adding any additional optional ingredients including surfactants, breakers, activators, retarders, and the like.
In one embodiment, the present invention provides a method of treating a portion of a subterranean formation comprising the steps of: providing a viscosified treatment fluid that comprises a brine and a gelling agent that comprises a modified xanthan; and treating the portion of the subterranean formation.
In another embodiment, the present invention provides a method of treating a portion of a subterranean formation comprising: providing a viscosified treatment fluid that comprises seawater and a gelling agent that comprises a modified xanthan; and treating the portion of the subterranean formation.
The viscosified treatment fluids of the present invention are useful in gravel packing operations. In an example of such an embodiment, the present invention provides a method of placing a gravel pack in a portion of a subterranean formation comprising: providing a viscosified gravel pack fluid that comprises gravel, a brine and a gelling agent that comprises a modified xanthan; and contacting the portion of the subterranean formation with the viscosified gravel pack fluid so as to place a gravel pack in or near a portion of the subterranean formation.
The viscosified treatment fluids of the present invention can be useful in subterranean fracturing operations. In one embodiment, the present invention provides a method of fracturing a portion of a subterranean formation comprising: providing a viscosified fracturing fluid that comprises a brine and a gelling agent that comprises a modified xanthan; and contacting the portion of the subterranean formation with the viscosified fracturing fluid at a sufficient pressure to create or enhance at least one fracture in the subterranean formation.
In another embodiment, the present invention provides a method of producing hydrocarbons from a subterranean formation comprising using a viscosified treatment fluid that comprises a brine and a gelling agent that comprises a modified xanthan in a completion or a servicing operation.
In another embodiment, the present invention provides a method of producing hydrocarbons from a subterranean formation comprising using a viscosified treatment fluid that comprises a brine and a gelling agent that comprises a modified xanthan in a completion or a servicing operation, and the subterranean formation has a bottom hole temperature of from about 30° F. to about 400° F.
In another embodiment, the present invention provides a viscosified treatment fluid comprising seawater and a gelling agent that comprises a modified xanthan.
In another embodiment, the present invention provides a subterranean treatment fluid gelling agent that comprises a modified xanthan.
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, or define, the scope of the invention.
It has been found that modified xanthan has suitable filtration and rheological properties for gravel packing. According to an example for the invention, 3.6 grams of modified (deacetylated) xanthan gum was mixed with 500 mL of fresh water. The mixture was filtered through dry filter paper. Starting with a 200 mL sample of the mixture, after 2 minutes 43 mL was through the dry filter paper.
The viscosity of the mixture was measured at 300 revolutions per minute (“rpm”) as shown in the following table.
Therefore, the present invention is well adapted to carry out the objects and attain the ends and advantages mentioned as well as those that 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.
