Alkylbenzenesulfonate flowback aids

Abstract

The present disclosure generally relates to a flowback aid composition for use in connection with the fracturing of a subterranean formation and the recovery of fossil fluids from the subterranean formation. The flowback aid composition generally includes an alkylbenzene sulfonate having a long alkyl chain and a solvent.

Description

ALKYLBENZENESULFONATE FLOWBACK AIDSCROSS-REFERENCE TO RELATED APPLICATION

[0001] This application claims the benefit of U.S. Provisional Patent Application Serial No. 63 / 457,455 filed April 6, 2023. The content of the aforementioned application is incorporated herein by reference in its entirety.FIELD

[0002] The present disclosure generally relates to a flowback aid composition containing an alkylbenzene sulfonate, a fracturing fluid containing the flowback aid composition, and methods for increasing flowback of fluids in a subterranean formation by contacting the subterranean formation with the fracturing fluid.BACKGROUND

[0003] Hydraulic fracturing involves injecting large volumes of water containing various additives (i.e., fracturing fluid) into a subterranean formation at rates sufficient to fracture the formation. Proppant, such as resin-coated sand, glass beads, aluminum pellets, rounded nut shells, steel shot, sintered bauxite, fused zirconium, and quartz gravel, is typically also transported via the fracturing fluid into the resultant fractures to hold the fractures open thereby creating a network of channels through which crude oil may flow. Examples of other additives which may be included in the fracturing fluid are: viscosifiers which enhance the viscosity of the fluid to support the proppant and allow the fluid to better penetrate the fractured formation; a friction reducing agent for reducing fluid friction and enhance pumpability of the fluid; and corrosion and scale inhibitors to inhibit corrosion and scale.

[0004] Flowback aids may also be included in the fracturing fluid as an additive to alter the wettability of the formation rock in order to maximize the return or flowback of the injected fracturing fluid to the surface, minimize adsorption of oil on the surface of the rock, andincrease both the rate and quantity of oil flow from the reservoir to the wellbore. Known flowback aids each have their own set of properties and may present a tradeoff of one beneficial property for another undesirable property. Thus, there exists an ongoing need to develop new flowback solutions which provide substantial flowback of fracturing fluids, such need, met at least in part, by the following disclosure.SUMMARY

[0005] The present disclosure generally provides a flowback aid composition including an alkylbenzene sulfonate having a formulawhere R can be in the ortho-, meta-, or para-position and is a linear or branched C16-C50 alkyl group, and X is hydrogen, an alkali metal, an alkaline earth metal, an ammonium salt or an alkanolamine salt, and a solvent. In one embodiment the flowback aid composition is substantially free of a second anionic surfactant.

[0006] The flowback aid composition may be combined with a water source to form a fracturing fluid. In some embodiments, the flowback aid composition is combined with the water source and subsequently or contemporaneously introduced through a wellbore and into a subterranean formation.

[0007] Thus, according to another embodiment the present disclosure provides a method of fracturing a subterranean formation. The method includes introducing a fracturing fluid through a wellbore into a subterranean formation, where the fracturing fluid comprises the flowback aid composition and a water source, pressurizing the fracturing fluid to fracture thesubterranean formation, and allowing the fracturing fluid to flow back into the well bore from the subterranean formation. In some embodiments, the fracturing fluid may be introduced, for example, by pumping, injecting, pouring or circulating the fracturing fluid through the wellbore.

[0008] The flowback aid composition may substantially increase the yield of fossil fluids obtained from subterranean formations. Thus, in still another embodiment the present disclosure provides a method of increasing recovery of fossil fluids from a subterranean formation including: forming a fracturing fluid containing the flowback aid composition; treating at least a portion of the subterranean formation with the fracturing fluid; and collecting fossil fluids from the subterranean formation.BRIEF DESCRIPTION OF THE DRAWINGS

[0009] Figure 1 is a graph depicting the volume level displacement of flowback aid compositions by crude oil as a function of a time.DETAILED DESCRIPTION

[0010] The present disclosure is generally directed to a flowback aid composition comprising an alkylbenzene sulfonate as defined herein and a solvent. It has been surprisingly found that the flowback aid compositions of the present disclosure, when added to a fracturing fluid that subsequently used in connection with a hydraulic fracturing process, may reduce capillary pressure and water blocks, thereby improving the kinetics of the flowback and preventing or minimizing the leaving-behind of any substantial amount of the fracturing fluid. Additionally, the flowback aid composition may assist in the clean-up of a proppant pack thereby accelerating the flow of fossil fluids through the high permeability proppant pack.

[0011] Unless defined otherwise, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which the present disclosure belongs.

[0012] The phrases "in one embodiment", "according to one embodiment" and the like generally mean the particular feature, structure, or characteristic following the phrase is included in at least one embodiment of the present disclosure and may be included in more than one embodiment of the present disclosure. Importantly, such phrases do not necessarily refer to the same embodiment. If the specification states a component or feature "may", "can", "could", or "might" be included or have a characteristic, that particular component or feature is not required to be included or have the characteristic.

[0013] Where a range of values is provided, it is understood that each intervening value, to the tenth of the unit of the lower limit unless the context clearly dictates otherwise, between the upper and lower limit of that range and any other stated or intervening value in that stated range, is encompassed within the present disclosure. The upper and lower limits of these smaller ranges may independently be included in the smaller ranges and are also encompassed within the present disclosure, subject to any specifically excluded limit in the stated range. Where the stated range includes one or both of the limits, ranges excluding either or both of those included limits are also included in the present disclosure.

[0014] The term “about” used throughout is used to describe and account for small fluctuations. For instance, “about” may mean the numeric value may be modified by ±5%, ±4%, ±3%, ±2%, ±1%, ±0.5%, ±0.4%, ±0.3%, ±0.2%, ±0.1% or ±0.05%. All numeric values are modified by the term “about” whether or not explicitly indicated. Numeric values modified by the term “about” include the specific identified value. For example, “about 5.0” includes 5.0.

[0015] It is noted that, as used herein and in the claims, the singular forms “a,” “an,” and “the” include plural references unless the context clearly dictates otherwise. It is further noted that the claims may be drafted to exclude any optional element.

[0016] The terms “preferred” and “preferably” refer to embodiments that may afford certain benefits, under certain circumstances. However, other embodiments may also be preferred, under the same or other circumstances. Furthermore, the recitation of one or more preferred embodiments does not imply that other embodiments are not useful, and is not intended to exclude other embodiments from the scope of the present disclosure.

[0017] The term “optional” or “optionally” means that the subsequently described event or circumstance may or may not occur, and that the description includes instances where said event or circumstance occurs and instances where it does not.

[0018] The term “fossil fluids” include oleaginous materials such as those found in oil field deposits, oil shales, tar sands, heavy oil deposits, and the like. The fossil fluids are generally a mixture of naturally occurring hydrocarbons that can be refined into diesel, gasoline, heating oil, jet oil, kerosene and other products called petrochemicals. Fossil fluids derived from subterranean formations may include, but are not limited to, kerogen, bitumen, pyrobitumen, asphaltenes, oils and combinations thereof.

[0019] As used herein, “surfactants” refers to one or more of nonionic, cationic, zwitterionic and anionic surfactants, other than the alkylbenzene sulfonate according to the present disclosure, that lower the interfacial tension between two liquids.

[0020] The term "water source " means water substantially in a liquid state, including, but not limited to, fresh water, tap water, well water, deionized water, distilled water, produced water, municipal water, waste water such as runoff water, gray water, or municipal waste water, treated or partially treated waste water, brackish water, or sea water, or a combination of two or more such water sources. In embodiments, the water source includes one or more salts, ions, buffers, acids, bases, or other dissolved, dispersed, or emulsified compounds, materials, components, or combinations thereof. The term "produced water" refers to a water source that is present within and / or flows from a subterranean formation. Produced water includes connateunless otherwise specified. Generally, the term "water source" includes all of the following unless otherwise specified or determined by context: water, connate, produced water, water having high total dissolved solids, water having high temperature, and water having both high total dissolved solids and high temperature.

[0021] The term "high temperature" refers to a water source, a subterranean formation, or a combination thereof having a temperature of about 140°F to about 250°F.

[0022] The term "high total dissolved solids'" refers to a water source including at least about 4% by weight solids dissolved therein, and in some embodiments up to about 30% by weight solids dissolved therein.

[0023] The term “alkali metal” refers to lithium, sodium or potassium.

[0024] The term “alkaline earth metal” refers to calcium, barium, magnesium or strontium.

[0025] For methods of treating a fossil fluid-bearing subterranean formation, the term “treating” includes placing a chemical within the subterranean formation using any suitable manner known in the art, for example, pumping, injecting, pouring, releasing, displacing, squeezing, spotting, or circulating the chemical into a well, wellbore or subterranean formation.

[0026] The phrase “subterranean formation” encompasses both areas below exposed earth and areas below earth covered by water, such as an ocean or fresh water. Temperatures in a subterranean formation may range from about 25 °F to about 300°F. In some embodiments, the temperature of the formation is at least about 100°F, in other embodiments the temperature of the formation is at least about 125°F, while in other embodiments, temperature of the formation is at least about 150°F.

[0027] In the methods described herein, the steps can be carried out in any order without departing from the principles of the invention, except when a temporal or operational sequence is explicitly recited.

[0028] Furthermore, specified steps can be carried out concurrently unless explicit claim language recites that they be carried out separately. For example, a claimed step of doing X and a claimed step of doing Y can be conducted simultaneously within a single operation, and the resulting method will fall within the literal scope of the claimed process.

[0029] The term “substantially free” refers to a composition in which a particular compound or moiety is present in an amount that has no material effect on the composition. In some embodiments, “substantially free” may refer to a composition in which the particular compound or moiety is present in the composition in an amount of less than 2% by weight, or less than 1% by weight, or less than 0.5% by weight, or less than 0.1% by weight, or less than 0.05% by weight, or even less than 0.01% by weight based on the total weight of the composition, or that no amount of that particular compound or moiety is present in the respective composition.

[0030] The present disclosure generally provides a flowback aid composition and its use in the treatment of a subterranean formation and recovery of fossil fluids from the subterranean formation. According to one embodiment, the flowback aid composition comprises an alkylbenzene sulfonate having a general formula :where R can be in the ortho-, meta-, or para-position and is a linear or branched C16-C50 alkyl group, and X is hydrogen, an alkali metal, an alkaline earth metal, an ammonium salt, or an alkanolamine salt.

[0031] The alkylbenzene sulfonate can include a mixture of linear and / or branched R groups with an array of different lengths (e.g., C16-C20, C20-C24) attached to the alkylbenzene sulfonate molecules at different positions along the benzene ring. Similarly, the alkylbenzene sulfonate can include a mixture of molecules with a uniform length R group (e.g., C24) attached to the alkylbenzene sulfonate. In one embodiment, the R group is a linear or branched C16-C30 alkyl group, or a linear or branched C16-C24 alkyl group or a linear or branched C16-C20 alkyl group. In another embodiment, the R group is a linear or branched C20-C36 alkyl group, or a linear or branched C20-C28 alkyl group or a linear or branched C20-C24 alkyl group. In still another embodiment, the R group is a linear or branched C24-C40 alkyl group, or a linear or branched C24-C34 alkyl group or a linear or branched C24-C28 alkyl group. In another embodiment, the R group is a linear or branched C24-C50 alkyl group, or a linear or branched C34-C50 alkyl group or a linear or branched C40-C50 alkyl group.

[0032] In one embodiment, X is sodium, calcium, lithium, magnesium, potassium, isopropyl ammonium, dimethyl ammonium, triethyl ammonium, monoethanol ammonium, diethanol ammonium, triethanol ammonium, dimethylethanol ammonium, diethyleneglycol ammonium, triisopropanol ammonium, tetramethyl ammonium, tetraethyl ammonium, choline, monoethanolamine salts, diethanolamine salts, triethanolamine salts and isopropylamine salts.

[0033] The alkylbenzene sulfonates according to the present disclosure may be produced by methods known to those skilled in the art. For example, the alkylbenzene sulfonates may be produced by first alkylating benzene in the presence of a catalyst, and then sulfonating the alkylated benzene to produce the sulfonic acid which can be subsequently neutralized with an alkali metal or alkaline earth metal salt or hydroxide, an ammonium salt or an alkanolamine salt.

[0034] The flowback aid composition also includes a solvent. In one embodiment, the solvent comprises water, a glycol, a glycol ether, a derivative of a glycol ether, and mixtures thereof.

[0035] Examples of glycols include, but are not limited to, ethylene glycol, propylene glycol, diethylene glycol, dipropylene glycol, triethylene glycol and tripropylene glycol, hexylene glycol and mixtures thereof.

[0036] According to one embodiment, the glycol ether is a compound having the formulawhere Ra is a Ci-Ce aliphatic group or an aromatic group, Rb is H, CH3, or C2H5, and n is an integer of at least 1. In some embodiments, n can be from 1 to 4, or from 1 to 3 or 1 to 2. Exemplary glycol ethers include, but are not limited to, dipropylene glycol methyl ether where Rais CH3, Rb is CH3, and n has a value of 2. Another exemplary glycol ether is diethylene glycol butyl ether wherein Rais C4H9, Rb is H, and n has a value of 2 that is commercially available from Indorama Ventures of The Woodlands, Texas under the tradename SURFONIC® L4-2 butanol ethoxylate. An exemplary aromatic glycol ether is ethylene glycol phenyl ether where Rais a phenyl group, Rb is H, and n is a value of 1. Other exemplary glycol ethers include, but are not limited to, Ci-Ce alkylene glycol ethers, such as 2-butoxyethanol, propylene glycol butyl ether, dipropylene glycol butyl ether, dipropylene glycol propyl ether, ethylene glycol propyl ether, ethylene glycol butyl ether, diethylene glycol propyl ether and triethylene glycol methyl ether.

[0037] Derivatives of glycol ethers include those glycol ethers modified to include an additional group or functionality such as an ester group. Exemplary derivatives of glycol ethers include those having the formulaR- — (OCHCH2.U-ARdwhere Rcis a Ci-Ce aliphatic group or an aromatic group, Rd is H, CH3, or C2H5, n is an integer of at least 1, and A is an ester group, amide group, or ether group. In some embodiments, n can be from 1 to 4, or from 1 to 3 or from 1 to 2. Exemplary derivatives of a glycol ether include, but are not limited to, ethylene glycol methyl ether acetate, ethylene glycol ethyl ether acetate, diethylene glycol methyl ether acetate, diethylene glycol ethyl ether acetate, ethylene glycol methyl ether acetate, diethylene glycol butyl ether acetate, propylene glycol methyl ether acetate, propylene glycol ethyl ether acetate, propylene glycol propyl ether acetate, dipropylene glycol methyl ether acetate and dipropylene glycol ethyl ether acetate.

[0038] According to one embodiment, the flowback aid composition includes up to about 99% by weight of the alkylbenzene sulfonate, based on the total weight of the flowback aid composition. In another embodiment, the flowback aid composition includes up to about 95% by weight, or up to about 90% by weight, or up to about 85% by weight, or up to about 80% by weight, or up to about 75% by weight, or up to about 70% by weight, or up to about 65% by weight, or up to about 60% by weight, or up to about 55% by weight or up to about 50% by weight, up to about 45% by weight, or up to about 40% by weight of the alkylbenzene sulfonate, based on the total weight of the flowback aid composition.

[0039] In another embodiment, the flowback aid composition includes at least about 0.5% by weight of the alkylbenzene sulfonate, based on the total weight of the flowback aid composition. In yet another embodiment, the flowback aid composition includes at least about 1% by weight, or at least about 5% by weight, or at least about 10% by weight, or at least about 15% by weight, or at least about 20% by weight, or at least about 25% by weight, or at least about 30% by weight, or at least about 35% by weight, or at least about 40% by weight or at least about 45% by weight, or least about 50% by weight of the alkylbenzene sulfonate, based on the total weight of the flowback aid composition.

[0040] According to yet another embodiment, the flowback aid composition includes about 0.1% by weight to about 99.9% by weight of the alkylbenzene sulfonate, based on the total weight of the flowback aid composition. In still another embodiment, the flowback aid composition includes about 5% by weight to about 95% by weight, or about 10% by weight to about 90% by weight, or about 20% to about 80% by weight, or about 30% by weight to about 70% by weight, or about 40% by weight to about 60%, or about 45% by weight to about 55% by weight of the alkylbenzene sulfonate, based on the total weight of the flowback aid composition.

[0041] According to another embodiment, the flowback aid composition includes up to about 99% by weight of the solvent, based on the total weight of the flowback aid composition. In another embodiment, the flowback aid composition includes up to about 95% by weight, or up to about 90% by weight, or up to about 85% by weight, or up to about 80% by weight, or up to about 75% by weight, or up to about 70% by weight, or up to about 65% by weight, or up to about 60% by weight, or up to about 55% by weight or up to about 50% by weight, up to about 45% by weight, or up to about 40% by weight of the solvent, based on the total weight of the flowback aid composition.

[0042] In another embodiment, the flowback aid composition includes at least about 0.5% by weight of the solvent, based on the total weight of the flowback aid composition. In yet another embodiment, the flowback aid composition includes at least about 1% by weight, or at least about 5% by weight, or at least about 10% by weight, or at least about 15% by weight, or at least about 20% by weight, or at least about 25% by weight, or at least about 30% by weight, or at least about 35% by weight, or at least about 40% by weight or at least about 45% by weight, or least about 50% by weight of the solvent, based on the total weight of the flowback aid composition.

[0043] According to yet another embodiment, the flowback aid composition includes about 0.1% by weight to about 99.9% by weight of the solvent, based on the total weight of the flowback aid composition. In still another embodiment, the flowback aid composition includes about 5% by weight to about 95% by weight, or about 10% by weight to about 90% by weight, or about 20% to about 80% by weight, or about 30% by weight to about 70% by weight, or about 40% by weight to about 60%, or about 45% by weight to about 55% by weight of the solvent, based on the total weight of the flowback aid composition.

[0044] According to another embodiment, the flowback aid composition is substantially free of a second anionic surfactants. In one embodiment, the flowback aid composition includes about 10% by weight to about 50% by weight of the alkylbenzene sulfonate and about 50% by weight to about 90% by weight solvent, each based on the total weight of the flowback aid composition, and wherein the flowback aid composition is substantially free of a second anionic surfactant (i.e., the alkylbenzene sulfonate of the present disclosure is the only anionic surfactant present in the flowback aid composition). In other embodiments, the flowback aid composition may include about 20% by weight to about 45% by weight, or about 20% by weight to about 40% by weight, or about 20% by weight to about 35% by weight, or about 20% by weight to about 30% by weight, or about 20 % by weight to about 25% by weight, or about 25% by weight to about 50% by weight, or about 30% by weight to about 50% by weight, or about 35% by weight to about 50% by weight, or about 40% by weight to about 50% by weight, or about 45% by weight to about 50% by weight, based on the total weight of the flowback aid composition, of the alkylbenzene sulfonate and wherein the flowback aid composition is substantially free of a second anionic surfactant.

[0045] In another embodiment, the flowback aid composition includes about 10% by weight to about 50% by weight of the alkylbenzene sulfonate and about 50% by weight to about 90% by weight solvent, each based on the total weight of the flowback aid composition, and whereinthe flowback aid composition is substantially free of a second anionic surfactant. In other embodiments, the flowback aid composition may include about 20% by weight to about 45% by weight, or about 20% by weight to about 40% by weight, or about 20% by weight to about 35% by weight, or about 20% by weight to about 30% by weight, or about 20 % by weight to about 25% by weight, or about 25% by weight to about 50% by weight, or about 30% by weight to about 50% by weight, or about 35% by weight to about 50% by weight, or about 40% by weight to about 50% by weight, or about 45% by weight to about 50% by weight, based on the total weight of the flowback aid composition, of the alkylbenzene sulfonate and wherein the flowback aid composition is substantially free of a second anionic surfactant.

[0046] In a further embodiment, the flowback aid composition may be combined with a water source to form a fracturing fluid. Accordingly, the flowback aid compositions may be suitably prepared for storage and transportation, whereas the fracturing fluid is prepared for subterranean injection by dilution of the flowback aid composition with a water source. Dilution of the flowback aid composition may be suitably carried out using any known technique available to the skilled artisan for diluting compositions prior to or contemporaneously with injection into a subterranean formation using one or more conventional mixing apparatuses; often the mixing apparatuses being in fluid contact with one or more injection apparatuses known to those of skill in the art of subterranean fluid injection. For example, static or dynamic mixers may be employed along with a source of water to combine a flowback concentrate with e.g., connate, surface water, sea water, purified water, or a produced water flowing back from a subterranean formation.

[0047] Accordingly, the flowback aid composition is combined with the water source to form a fracturing fluid and may be subsequently or contemporaneously injected into a subterranean formation. In some embodiments, the fracturing fluid contains the flowback aid compositionin an amount of about 0.1 to about 5 gallons per thousand gallons, based on the volume of the water source.

[0048] In still other embodiments, the total concentration of alkylbenzene sulfonate in the fracturing fluid is referred to as the concentration of "actives" in the fracturing fluid. In some embodiments, the fracturing fluid may include about 0.001% by weight (10 ppm) to about 1% by weight total actives based on the weight of the fracturing fluid. In other embodiments, the fracturing fluid may include about 0.005% by weight to about 1% by weight, or about 0.01% by weight to about 1% by weight, or about 0.02% by weight to about 1% by weight, or about 0.03% by weight to about 1% by weight, or about 0.04% by weight to about 1% by weight, or about 0.05% by weight to about 1% by weight, or about 0.06% by weight to about 1% by weight, or about 0.07% by weight to about 1% by weight, or about 0.08% by weight to about 1% by weight, or about 0.09% by weight to about 1% by weight, or about 0.1% by weight to about 1% by weight, or about 0.001% by weight to about 0.9% by weight, or about 0.001 wt% to about 0.8% by weight, or about 0.001% by weight to about 0.7% by weight, or about 0.001% by weight to about 0.6% by weight, or about 0.001% by weight to about 0.5% by weight, or about 0.001% by weight to about 0.4% by weight, or about 0.001% by weight to about 0.3% by weight, or about 0.001% by weight to about 0.2% by weight, or about 0.001% by weight to about 0.1% by weight, or about 0.005% by weight to about 0.5% by weight, or about 0.005% by weight to about 0.4% by weight, or about 0.005% by weight to about 0.3% by weight, or about 0.005% by weight to about 0.2% by weight, or about 0.005% by weight to about 0.1% by weight, or about 0.01% by weight to about 0.2% by weight, or about 0.01% by weight to about 0.1% by weight actives, based on the total weight of the fracturing fluid.

[0049] Optional additives may be included in the fracturing fluid or the flowback aid composition. Such additives can include those oil field additives conventionally used in hydraulic fracturing or post-primary fracturing of subterranean fossil fluid-containingformations. In some embodiments, the additives are added to the flowback aid composition.In other embodiments, the additives are added to the subterranean formation contemporaneously with dilution of the flowback aid composition or are added to the fracturing fluid after the fracturing fluid is formed. The additives may include, but are not limited to, proppants, acids, alcohols or polyols, cellulose, starches, alkalinity control agents, acidity control agents, density control agents, density modifiers, polymeric stabilizers, polyacrylamides, a polymer or combination of polymers, antioxidants, heat stabilizers, foam control agents, plasticizers, fillers or inorganic particles, pigments, dyes, precipitating agents, oil-wetting agents, set retarding additives, gases, weight reducing additives, heavy-weight additives, lost circulation materials, filtration control additives, salts (e.g., any suitable salt, such as potassium salts, such as potassium chloride, potassium bromide, potassium formate; calcium salts, such as calcium chloride, calcium bromide, calcium formate; cesium salts such as cesium chloride, cesium bromide, cesium formate; and the like; and any combination thereof), fibers, thixotropic additives, breakers, crosslinkers, rheology modifiers, curing accelerators, curing retarders, pH modifiers, chelating agents, scale inhibitors, enzymes, resins, water control materials, disproportionate permeability modifiers, relative permeability modifiers, oxidizers, markers, Portland cement, pozzolana cement, gypsum cement, high alumina content cement, slag cement, sorel cement (e.g., Mg-tCbfOH ^Ok), micro matrix cement, silica cement, fly ash, metakaolin, shale, zeolite, a crystalline silica compound, amorphous silica, hydratable clays, microspheres, lime, or any combinations thereof.

[0050] In embodiments of the present invention, the fracturing fluid or the flowback aid composition may include at least one nonionic surfactant. In embodiments of the present invention, the nonionic surfactant may comprise one or more linear and branched alcohol ethoxylates, tallowamine ethoxylates, ditallowamine ethoxylates and / or mixtures thereof.

[0051] In embodiments of the present invention the fracturing fluid or the flowback aid composition are substantially free of any cationic, zwitterionic and amphoteric surfactants.

[0052] Employing the flowback aid composition of the present disclosure may improve penetration into the subterranean formation, allow for better flow-back and drainage, improve load recovery and reduce damage due to phase trapping. The flowback aid composition of the present disclosure may also be used in connection with Enhanced Oil Recovery (EOR), wettability alteration, well cleanout and work-over.

[0053] Thus, according to one embodiment, the present disclosure provides a method of fracturing a subterranean formation. The method includes introducing a fracturing fluid comprising the flowback aid composition through a wellbore into the subterranean formation, pressurizing the fracturing fluid to fracture the subterranean formation, and reducing the pressure to allow the fracturing fluid to flow back into the wellbore from the subterranean formation.

[0054] For applying the method above, the subterranean formation is penetrated by at least one wellbore. The wellbore may be a fresh wellbore drilled into the subterranean formation which needs to become prepared for fossil fluids production. In another embodiment the wellbore may be a production well which already has been used for producing fossil fluids but the production rate has decreased and it is necessary to fracture the subterranean formation again in order to increase production.

[0055] The fracturing fluid is pumped into the wellbore at a rate and pressure sufficient to flow into the formation and to initiate or extend a fracture in the formation. In order to initiate or to extend fractures in the formation, a bottomhole pressure sufficient to open a fracture in the formation is necessary. The bottomhole pressure is determined by the surface pressure produced by the surface pumping equipment and the hydrostatic pressure of the fluid column in the wellbore, less any pressure loss caused by friction. The minimum bottomhole pressurerequired to initiate and / or to extend fractures is determined by formation properties and therefore will vary from application to application. Methods and equipment for fracturing procedures are known to the skilled artisan. In some embodiments, the fracturing fluid will simultaneously transport suspended proppant and the proppant will become deposited into the fractures and hold the fractures open after the pressure exerted on the fracturing fluid has been released.

[0056] The applied pressure is then reduced thereby allowing at least a portion of the injected fracturing fluid to flow back from the subterranean formation into the wellbore. Reducing the pressure allows the fractures to close whereas proppant transported by the fracturing fluid “props” fractures open. Therefore, the fracturing fluid is shut in or allowed to flow back. At the surface, chokes may be used to generate a pressure differential to allow fracturing fluid to begin to flow from the subterranean formation into the wellbore.

[0057] In another embodiment, there is provided a method for enhancing the recovery of fossil fluids from a subterranean formation. The method includes forming the fracturing fluid comprising the flowback aid composition, treating the subterranean formation with the fracturing fluid and collecting fossil fluids the subterranean formation. In some embodiments, the fracturing fluid may be combined with any desired additive(s) to produce the fracturing fluid contemporaneously with one or more subterranean formation treatment processes; in other embodiments the combining is prior to treatment. Treatment of the subterranean formation by the fracturing fluid results in increased recovery of fossil fluids from the subterranean formation. In embodiments, the subterranean formation is characterized by one or more of low permeability, low porosity, high temperature, high total dissolved solids, and high divalent cation content of an ambient water source (present naturally in the reservoir or produced water within the formation). Treatment is carried out contemporaneously with hydraulic fracturing of the subterranean formation, or after the fracturing is complete. In someembodiments, the treatment is into a first wellbore connected to the subterranean formation, and the collecting is from a second wellbore that is connected to the subterranean formation. In other embodiments, the treatment and the collecting are carried out in the same wellbore.EXAMPLES

[0058] Sand column test - A glass tube having an inner diameter of 1” and a length of 12”, with 1-ml graduations beginning with zero positioned 1” above the bottom of the tube and ending with 100 near the top of the tube, was equipped with a screw cap fitting and adapter connecting to a stoppered 3” length of tubing having an inner diameter of 1 / 4” at the bottom of the tube. Successive 325- and 40-mesh screens were seated into the adapter. Various flowback aid compositions containing 200 ppm of an alkylbenzene sulfonate according to the present disclosure or 200 ppm of a surfactant, each in 2% by weight KC1, were prepared with deionized water as the solvent. Examples 1 thru 7 below were the flowback aid compositions that were tested.Comparative Example 1 - a sodium salt of a C11-C13 alkylbenzene sulfonate in water.Example 2 - a sodium salt of a C16-C20 alkylbenzene sulfonate, water, SURFONIC® L4- 2 butanol ethoxylate (diethylene glycol butyl ether). Example 2 is an alkylbenzene sulfonate of the general formula wherein R is a mixture linear and branched C16-C20 alkyl chains located predominantly in the para position (with some in the ortho position) and X is sodium. The sodium salt of C16-C20 alkylbenzene sulfonate was mixed in water and SURFONIC® L4-2 butanol ethoxylate to form a clear liquid. This liquid was then added to a 2% KC1 solution to give 200 ppm concentrations of the sulfonates for Example 2.Example 3 - a sodium salt of a C20-C24 alkylbenzene sulfonate, water, SURFONIC® L4- 2 butanol ethoxylate (diethylene glycol butyl ether). Example 3 is an alkylbenzene sulfonate of the general formula wherein R is a mixture of linear and branced C20-C24 alkyl chain located predominantly in the para position (with some in the ortho position) and X is sodium. The sodium salt of C20-C24 alkylbenzene sulfonate was mixed in water and SURFONIC® L4-2 butanolethoxylate to form a clear liquid. This liquid was then added to a 2% KC1 solution to give 200 ppm concentrations of the sulfonates for Example 3.Comparative Example 4 -a 7 mole ethoxylate of a linear C12-C14 alcohol in water. Comparative Example 5 -a 9 mole ethoxylate of a linear C12-C14 alcohol in water. Comparative Example 6 -a 5.5 mole ethoxylate of tetraethyl ene triamine in water Comparative Example 7 -a short chain alcohol ethoxylate in water.

[0059] The glass tubes were then packed up to the 50 -ml mark with a slurry of 40-100 mesh sand and one of the above flowback aid compositions. Additional flowback aid composition was then added up to the 55-ml mark. An Oman oil, obtained from Medco, having an API of 26.1 was chosen for this example and was added to each glass tube up to the 100-ml mark. The stoppers were then removed from the bottom of the glass tubes and a timer was started. The time required for the oil to displace the flowback aid composition to the 45-, 40-, 35-, 30-, 25-, 20-, 15-, 10-, 5- and 0-ml marks was then measured. A blank with only sand was also tested. The results for each are shown in Figure 1.

[0060] Depending on the flowback aid composition, the oil front can travel through the sand pack at a uniform height from one position within the glass tube to another position, or ‘fingering’ can be observed where the oil penetrates deeper into the sand pack at one position rather than another position. In general, smoother curves were observed for the flowback aid compositions which indicated occurrence of the former case rather than the latter case. This was particularly observed for the blank example.

[0061] The total time required for the oil to displace the flowback aid composition to the 0-ml mark is shown below in Table 1.Table 1From the results, it can be seen that Ex. 2 and Ex. 3 were much more effective as flowback aids than each of the comparative examples. In addition, it was unexpected that Comp. Ex. 1 (C11-C13 alkylbenzene sulfonate) performed the worst and that increasing the length of the alkyl chain to 16-20 carbons improved performance significantly.

[0062] While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.

Claims

CLAIMSWhat is claimed is:

1. A flowback aid composition comprising an alkylbenzene sulfonate having a formulawhere R can be in the ortho-, meta-, or para-position and is a linear or branched C16-C50 alkyl group, and X is hydrogen, an alkali metal, an alkaline earth metal, an ammonium salt or an alkanolamine salt and a solvent and wherein the flowback aid composition is substantially free of a second anionic surfactant.

2. The flowback aid composition of claim 1, wherein R is a linear or branched C16-C30 alkyl group.The flowback aid composition of claim 2, wherein R is a linear or branched C16-C20 alkyl group.

4. The flowback aid composition of claim 2, wherein R is a linear or branched C20-C24 alkyl group.The flowback aid composition of claim 1, wherein X is sodium, calcium, lithium, magnesium, potassium, isopropyl ammonium, dimethyl ammonium, triethyl ammonium,monoethanol ammonium, diethanol ammonium, triethanol ammonium, dimethylethanol ammonium, diethyleneglycol ammonium, triisopropanol ammonium, tetramethyl ammonium, tetraethyl ammonium, choline, a monoethanolamine salt, a diethanolamine salt, a triethanolamine salt, or an isopropylamine salt.

6. The flowback aid composition of claim 1, wherein the solvent comprises water, a glycol, a glycol ether, a derivative of a glycol ether, or mixtures thereof.

7. The flowback aid composition of claim 6, wherein the solvent comprises a glycol ether having a formulawhere Ra is a Ci-Ce aliphatic group or an aromatic group, Rb is H, CH3, or C2H5, and n is an integer of at least 1.

8. The flowback aid composition of claim 1, further comprising an additive.

9. The flowback aid composition of claim 1, further comprising a nonionic surfactant.

10. A fracturing fluid comprising a water source and the flowback aid composition of claim 1.

11. The fracturing fluid of claim 10, wherein the fracturing fluid comprises about 0.001% by weight to about 1% by weight total actives based on the weight of the fracturing fluid.

12. The fracturing fluid of claim 10, further comprising an additive.

13. A method for enhancing the recovery of fossil fluids from a subterranean formation comprising: forming a fracturing fluid comprising a water source and the flowback aid composition of claim 1; treating the subterranean formation with the fracturing fluid; and collecting fossil fuels from the subterranean formation.

14. The method of claim 13, wherein the flowback aid composition is combined with the water source to form the fracturing fluid and the fracturing fluid is subsequently injected into a first wellbore connected to the subterranean formation, and the fossil fluids are collected from a second wellbore that is connected to the subterranean formation.

15. The method of claim 13, wherein the flowback aid composition is combined with the water source to form the fracturing fluid and the fracturing fluid is subsequently injected into a first wellbore connected to the subterranean formation, and the fossil fluids are collected from the first wellbore.

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