Technical Field

[0001] This application relates to methods and compositions for treating subterranean formations. More particularly, the application relates to novel gels covalently bonded to breakers and use of same for fracturing subterranean formations.

Background

[0002] Viscous fluids are used in a variety of operations and treatments in oil and gas wells. Such operations and treatments include forming gravel packs in well bores, fracturing producing zones, performing permeability control treatments and the like. Hydrocarbon producing wells are often stimulated by hydraulic fracturing treatments. In hydraulic fracturing, a viscous fracturing fluid is pumped into a subterranean formation at a rate and pressure such that one or more fractures are formed or enhanced in the formation. After the fractures are formed or enhanced, the fluid viscosity is reduced and the fluid is removed from the formation. In some cases, the fracturing fluid also functions as a carrier fluid, carrying proppant particles, e.g. graded sand, into the fractures. The proppant particles are suspended in the fracturing fluid and are deposited in the fractures when the fracturing fluid viscosity is reduced. More viscous fracturing fluids can more effectively form or extend fractures and carry proppant particles.

[0003] Fracturing fluids typically are made viscous by use of polymeric materials.

Generally, the more polymer that is used, the more viscous the fluid will become. For example, polymers such as cellulose, guar, and their derivatives have been used to form aqueous gel treating fluids having viscosities on the order of 1000's of centipoise. Gels made with linear polymers sometimes have sufficient viscosity to create fractures in some rock formations. For other formations, however, more viscous gels and/or gels with more internal structure are desirable. The polymeric material may be crosslinked to increase viscosity and build internal structure. The internal structure created by crosslinking is important because for at least some formations the fluid must be able to carry proppant, e.g. sand particles, into the fractures. Without internal structure proppant may settle out of the fluid even if the fluid is very viscous.

[0004] Fracturing fluids often include breakers for reducing the viscosity of the fluid after the fluid has effected fractures and/or positioned proppant particles. Breakers degrade polymers in the treating fluid, thus breaking the gel and reducing the fluid's viscosity. Breaking the gel converts the viscous fluid into a more free flowing fluid, which can be removed from the formation more easily than a viscous fluid. The thinned fluid also allows oil and/or natural gas to more freely flow out of the formation. Thinning the fluid also reduces the likelihood that the polymer will contribute to an oil/water emulsion. Unbroken polymer can stabilize emulsions of oil and water, which causes problems when the oil is extracted. The thinned fluid also leaves proppant particles in fractures where they function to prevent the fractures from closing and help to form conductive channels through which hydrocarbons and/or natural gas readily can flow.

[0005] Known breakers may be liquids or solids, and include, but are not limited to, chemical oxidizers, enzymes, and acids. Breakers are formulated to remain inactive while the treating fluid is introduced to the subterranean formation and until a reduction in viscosity is desired. The breaker may be formulated to be "activated" by certain conditions in the fluid (e.g., pH, temperature, etc.) and/or by interaction with some other substance. Alternatively, the breaker may be encapsulated with a coating that delays release of the breaker. Typically liquid breakers are activated by temperature or time delay. Another method of controlling breaker activity is by loading concentration of the breaker. [0006] It is desirable for a breaker to be evenly distributed throughout a treating fluid and to remain evenly distributed during its use and until it is activated and breaks the polymer. If it is not evenly distributed when it activates, some portion of the polymer will break while other portions may not. Uneven breaking will leave areas of viscous gel that can be difficult to remove, can block oil and gas flow, and can promote oil/water emulsions. Incomplete breaking can occur when the polymer and breaker are mixed improperly, for example, if insufficient breaker is added or if the breaker is not properly mixed throughout the polymer. Even if the correct amount of breaker is added, and the polymer and breaker are properly mixed, the polymer and breaker may not remain mixed, for example, if they move through the formation at different rates.

[0007] It would be advantageous to provide a treating fluid including a breaker that is substantially evenly distributed throughout a gel and that remains evenly distributed until a time when it is desirable for the breaker to be activated and degrade the gel. It would also be advantageous to package the breaker with the polymer to reduce mixing errors in the field. It would also be advantageous to simplify the formula for the treating fluid to reduce the number of ingredients and reduce the equipment required for the operation.

Detailed Description

[0008] Compositions described herein are useful as fluids for treating subterranean formations. In some embodiments described herein, the compositions are useful as fracturing fluids to enhance production of oil and natural gas from subterranean formations by creating and/or enhancing one or more fractures in the formations. The compositions include polymeric gels wherein the polymers are covalently bonded to breakers. The polymers may be crosslinked and the breaker may be any molecule capable of degrading the polymer after the breaker is activated. In one embodiment, the breaker is a polymer, so the gelled polymer is a graft copolymer comprising the main chain polymer and the grafted breaker side chains. [0009] As used herein, the terms "treat," "treatment," or "treating" refer to any subterranean operation that uses a fluid in conjunction with a desired function and/or for a desired purpose. The terms "treat," "treatment," and "treating," as used herein, do not imply any particular action by the fluid or any particular component thereof.

[0010] "Enhancing" one or more fractures in a subterranean formation, as that term is used herein, is defined to include the extension or enlargement of one or more natural or previously created fractures in the subterranean formation.

[0011] Compositions described herein may include any polymer known and used in fracturing operations, but are not limited to such polymers. Preferred polymers are polysaccharides and their derivatives, including, but not limited to, cellulose, guar, chitosan, xanthan, and their derivatives. Suitable polysaccharides also include the glycosaminoglycans (mucopolysaccharides), such as hyaluronic acid, and their derivatives. Derivatives include, but are not limited to, carboxymethyl cellulose, carboxymethylhydroxyethyl cellulose, carboxymethyl guar, and carboxymethylhydroxypropyl guar. The polymers may be used in combination as copolymers or blends. Preferably, the polymers are gels and in some embodiments are crosslinked.

[0012] The compositions described herein may include any breaker known and used in fracturing operations that can be covalently bonded to a suitable polymer. Suitable breakers may be small molecules or macromolecules, provided the breaker is capable of degrading the base polymer after the breaker is activated. Suitable breakers further include biological molecules, such as enzymes. Preferred breakers are hydrolysable polyesters, including, but not limited to, polylactic acid (PLA), polyglycolic acid (PGA), and polycaprolactone (PCL). Enzyme breakers may be useful for breaking crosslinked gels at low temperatures, such as from about 20 to about 50 °C. [0013] In one embodiment the main chain polymer is, or includes, a polysaccharide.

The polysaccharide may be covalently bonded to any breaker capable of degrading the polysaccharide after the breaker is activated. As one example, a polysaccharide, such as guar, may be grafted to a hydrolysable polyester, such as a polylactic acid. During use in fracturing operations, the polylactic acid degrades to lactic acid, which then breaks down the guar.

[0014] In one embodiment, a treating fluid includes a polymer covalently bonded to at least one breaker. In another embodiment, a treating fluid includes a polymer covalently bonded to at least two breakers. In some embodiments where the polymer is covalently bonded to more than one breaker, the polymer may be covalently bonded to a plurality of identical breaker molecules, or may be bonded to two or more breakers having different chemical structures, and may be covalently bonded to a plurality of each of such breakers. In one embodiment, the two or more different breakers may include, for example, a hydrolysable polyester and another type of breaker, such as an orthoester, enzyme or oxidizer. In another embodiment, the two or more different breakers may include two different hydrolysable polyesters, such as a polylactic acid and a polyglycolic acid. In still another embodiment, the two or more different breakers may include two of the same hydrolysable polyester, such as two polylactic acids, having different chain lengths or different conformations (e.g., PDLA or PLLA).

[0015] In certain compositions described herein, the main chain polymer may be present in the treating fluid in an amount in the range of 0.1 wt% to 1.5 wt%. The main chain polymers typically have molecular weights in the range of 100,000 - 10,000,000 g/mol. The breaker may be present in an amount in the range of 1-5 weight % of the main chain polymer. When the breaker is a polymer, the breaker typically has a molecular weight in the range of about 162 g/mol to 162000 g/mol. [0016] In some embodiments, a composition for treating a subterranean formation includes at least one polymer covalently bonded to at least one breaker. In some embodiments, the composition includes any polymer described herein, or equivalent thereof. In some embodiments, the polymer is, or includes, a polysaccharide, or a derivative or equivalent thereof. In some embodiments, the polysaccharide is cellulose, guar, chitosan, hyaluronic acid, xanthan, or a derivative or equivalent thereof. The polymer may be a copolymer or blend. In some embodiments, the polymer is crosslinked.

[0017] In some embodiments, the composition includes any breaker described herein, or equivalent thereof. In some embodiments, the breaker is, or includes, a hydrolysable polyester or derivative or equivalent thereof. In some embodiments, the composition includes more than one type of breaker including, but not limited to, two or more polylactic acids having different chain lengths. In some embodiments, the at least one polymer is covalently bonded to a plurality of identical breakers. In some embodiments, the at least one polymer is covalently bonded to a plurality of each of at least two breakers having different chemical structures.

[0018] The treating fluid may also include a crosslinking agent, among other purposes, to further enhance the viscosity of the treating fluid. The term "crosslinking agent" is defined herein to include any molecule, atom, or ion that is capable of forming one or more crosslinks between molecules of a polymer and/or between one or more atoms in a single molecule of a polymer. The crosslinking agent may comprise a borate, a metal ion, or similar component that is capable of crosslinking at least two molecules of the sulfonated gelling agent polymer(s). Examples of suitable crosslinking agents that can be utilized include, but are not limited to the following: boron compounds such as boric acid, disodium octaborate tetrahydrate, sodium diborate and pentaborates; ulexite; colemanite; compounds that can supply zirconium IV ions such as zirconium lactate, zirconium lactate triethanolamine, zirconium carbonate, zirconium acetylacetonate and zirconium diisopropylamine lactate; compounds that can supply titanium IV ions such as titanium ammonium lactate, titanium triethanolamine and titanium acetylacetonate; aluminum compounds such as aluminum lactate and aluminum citrate; and compounds that can supply antimony ions. In certain embodiments, the crosslinking agent may be formulated to remain inactive until it is "activated" by, among other things, certain conditions in the fluid (e.g., pH, temperature, etc.) and/or interaction with some other substance. In some embodiments, the crosslinking agent may be delayed by encapsulation with a coating (e.g., a porous coating through which the crosslinking agent may diffuse slowly, or a degradable coating that degrades downhole) that delays the release of the crosslinking agent until a desired time or place. The choice of a particular crosslinking agent will be governed by several considerations that will be recognized by one skilled in the art, including, but not limited to, the following: the type of gelling agent included, the molecular weight of the gelling agent(s), the conditions in the subterranean formation being treated, the safety handling requirements, the pH of the treating fluid, temperature, and/or the desired delay for the crosslinking agent to crosslink the gelling agent molecules.

[0019] In certain embodiments, a crosslinking agent may be included in the treating fluid in an amount in the range of from about 0.1 lbs to about 40 lbs per 1000 gal of the treating fluid. In certain embodiments, a crosslinking agent may be included in the treating fluid in an amount in the range of from about 4 lbs to about 12 lbs per 1000 gal of the treating fluid.

[0020] The treating fluids described herein optionally may comprise particulates, such as proppant particulates or gravel particulates. Particulates suitable for use in the treating fluids may comprise any material suitable for use in subterranean operations. Suitable materials for these particulates include, but are not limited to, sand, bauxite, ceramic materials, glass materials, polymer materials, polytetrafluoroethylene materials, nut shell pieces, cured resinous particulates comprising nut shell pieces, seed 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. Suitable composite particulates may comprise a binder and a filler material wherein suitable filler materials include silica, alumina, fumed carbon, carbon black, graphite, mica, titanium dioxide, metasilicate, calcium silicate, kaolin, talc, zirconia, boron, fly ash, hollow glass microspheres, solid glass, and combinations thereof. The mean particulate size generally may range from about 2 mesh to about 400 mesh on the U.S. Sieve Series; however, in certain circumstances, other mean particulate sizes may be desired and will be entirely suitable for practice of the present invention. In particular embodiments, preferred mean particulates size distribution ranges are one or more of 6/12, 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 be used to bear the pressure of a closed fracture, may be included in certain embodiments of the present invention. In certain embodiments, the particulates included in the compositions described herein may be coated with any suitable resin or tackifying agent known to those of ordinary skill in the art. In certain embodiments, the particulates may be present in the compositions described herein in an amount in the range of from about 0.5 pounds per gallon ("ppg") to about 30 ppg by volume of the treating fluid.

[0021] The treating fluids described herein optionally may include one or more of a variety of well-known additives, such as surfactants, de-emulsifiers, scale inhibitors, corrosion inhibitors, catalysts, clay stabilizers, biocides, bactericides, friction reducers, gases, foaming agents, iron control agents, solubilizers, pH adjusting agents (e.g., buffers), and the like. For example, in some embodiments, it may be desired to foam a treating fluid of the present invention using a gas, such as air, nitrogen, or carbon dioxide. Those of ordinary skill in the art, with the benefit of this disclosure, will be able to determine the appropriate additives for a particular application.

[0022] Polysaccharides having covalently bonded breakers can be prepared according to methods illustrated in Schemes 1-4 below and further detailed in Examples 1 and 2. Schemes 1-4 illustrate grafting of hyaluronic acid (HA) and guar with PLA, but one of skill in the art could use similar procedures for other polysaccharides and/or polyesters. The N- hydroxysuccinimide (NHS) derivative of PLA is synthesized as shown in Scheme 1.

PLA

FLA-NHS

Scheme 1 : Functionalization of PLA with NHS. [0023] HA is made soluble in organic solvents by transformation to its tetrabutylammonium (TBA) salt and is reacted with the NHS-PLA as shown in Scheme 2 to produce a HA-PLA grafted polymer.

Scheme 2: Synthesis of HA-PLA graft copolymer. ther embodiment, guar is reacted with NHS-PLA according to Scheme 3 rafted polymer.

Guar-PLA grafted polymer

Scheme 3: Synthesis of guar-PLA graft copolymer [0025] In still another embodiment, a graft copolymer of carboxymethylcellulose

(CMC) and PLA can be synthesized by similar methods.

Scheme 4: CMC-PLA graft copolymer.

Scheme 4 shows the PLA grafted onto a -CH ₂ COOH group of the CMC. Alternatively, the PLA could be grafted onto one or more of the -OH groups.

[0026] Once the polymer is synthesized, the compositions described herein may be prepared by any method suitable for a given application. In practice, treating fluids including the graft copolymers may be prepared and shipped to a fracturing site ready to use, or may be shipped as separate components and combined at the site of the fracturing operation. For example, certain components of the treating fluid (e.g., the polymer covalently bonded to the breaker and/or other additives) may be provided as one or more pre-blended powders, which may be combined with an aqueous base fluid at a subsequent time, for example, at the site of the fracturing operation. In preparing the compositions described herein, the pH of the aqueous base fluid may be adjusted, among other purposes, to facilitate the hydration of the gelling agent. The pH range in which the gelling agent will readily hydrate may depend upon a variety of factors that will be recognized by one skilled in the art. This adjustment of pH may occur prior to, during, or subsequent to the addition of the gelling agent and/or other components of the compositions described herein. After the pre-blended powders and the aqueous base fluid have been combined, crosslinking agents and/or other suitable additives may be added prior to introduction into the well bore. Those of ordinary skill in the art, with the benefit of this disclosure will be able to determine other suitable methods for the preparation of the compositions described herein. For example, typically when compositions are mixed on site, the mixing is carried out at the surface and the composition is introduced to the wellbore shortly thereafter. Alternatively, however, one or more ingredients of the composition may be introduced to the wellbore separately such that the composition is complete only after all of the components are in the wellbore. After the composition is introduced to the wellbore, pressure is used to introduce the composition into the subterranean formation.

[0027] An advantage to using the covalently bonded polymer/breakers described herein is the ratio of polymer to breaker and distribution of breaker in the polymer remains constant throughout the operation. Another advantage to using the compositions described herein is the breaker need not be added as a separate component of the treating fluid. Omitting a component simplifies the composition, its manufacture, and its use and can reduce associate costs. In certain applications, however, an additional, separate breaker may be desired and may be included.

[0028] The compositions described herein may be used in any subterranean operation wherein a fluid may be used. Suitable subterranean operations may include, but are not limited to, drilling operations, hydraulic fracturing treatments, sand control treatments (e.g., gravel packing), acidizing treatments (e.g., matrix acidizing or fracture acidizing), "frac- pack" treatments, well bore clean-out treatments, and other suitable operations where a treating fluid of the present invention may be useful.

[0029] In some embodiments, a method of treating a subterranean formation includes introducing a treating fluid into a subterranean formation at a rate and pressure sufficient to create or enhance one or more fractures therein, wherein the treating fluid is any fluid disclosed herein, or equivalent thereof. In some embodiments, the treating fluid includes at least one polymer covalently bonded to at least one breaker. In some embodiments, the polymer is, or includes, a polysaccharide or derivative or equivalent thereof. In some embodiments, the polysaccharide is cellulose, guar, chitosan, hyaluronic acid, xanthan, a derivative or equivalent thereof. The polymer may be a copolymer or blend. In some embodiments, the polymer is crosslinked.

[0030] In some embodiments, the breaker is a small molecule. In some embodiments, the breaker is a polymer. In some embodiments, the breaker is a biomolecule, such as an enzyme or equivalent thereof. In some embodiments, the breaker is, or includes, a hydrolysable polyester, or derivative or equivalent thereof. In some embodiments, the hydrolysable polyester is, or includes, polylactic acid, polyglycolic acid, polycaprolactone, or derivatives or equivalents thereof. In some embodiments the polymer is bonded to a plurality of breakers. In some embodiments the plurality of breakers includes breakers having identical or different chemical structures.

[0031] To facilitate a better understanding of the present invention, the following examples of certain aspects of some embodiments are given. In no way should the following examples be read to limit, or define, the scope of the invention.

Example 1

[0032] Preparation of PLA-grafted HA is illustrated in schemes 1 and 2, above. The synthesis is accomplished by following methods reported in Yoo and Park, J. Controlled Release, 96 (2004) 273-83 and Palumbo et al, Carbohydrate Polymers, 66 (2006) 379-385. PLA is dissolved in methylene chloride and activated by DCC and NHS at room temperature under nitrogen atmosphere for 24 hours to form NHS functionalized PLA, as shown in Scheme 1. The PLA:NHS:DCC stoichiometric molar ratio is 1 :2:2. After filtration, the product is precipitated by dropping into ice-cold diethyl ether, and the activated PLA is dried under vacuum.

[0033] The tetrabutylammonium (TBA) derivative of HA is prepared by acidifying the carboxylic groups of HA using a strong acidic ion exchange resin and subsequent neutralization with tetrabutylammonium hydroxide. The TBA-HA is recovered after freeze- drying. The TBA-HA is dissolved in DMSO and diethylamine is added. The PLA-NHS is added dropwise. As shown in Scheme 2, the reaction is carried out at 40 °C for 24 hours after which the TBA is exchanged with Na ⁺ using a cationic exchange resin. The final product is precipitated in acetone and washed to obtain the PLA-HA graft copolymer.

Example 2

[0034] Preparation of PLA-grafted guar is illustrated in scheme 3. NHS-PLA is prepared as described above. The NHS-PLA is reacted with guar to form a PLA-guar as shown in Scheme 3. The reaction proceeds with heat and addition of a catalyst such as an acid, a base, or heat, for example, 40-80 °C.

[0035] The compositions and methods of the appended claims are not limited in scope by the specific compositions and methods described herein, which are intended as illustrations of a few aspects of the claims and any compositions and methods that are functionally equivalent are within the scope of this disclosure. Various modifications of the compositions and methods in addition to those shown and described herein are intended to fall within the scope of the appended claims. Further, while only certain representative compositions, methods, and aspects of these compositions and methods are specifically described, other compositions and methods and combinations of various features of the compositions and methods are intended to fall within the scope of the appended claims, even if not specifically recited. Thus, a combination of steps, elements, components, or constituents may be explicitly mentioned herein; however, all other combinations of steps, elements, components, and constituents are included, even though not explicitly stated.