Substituted alkanolamine scale inhibitors

Abstract

Methods for treating subterranean formations are disclosed. An exemplary method includes introducing a treatment fluid into a wellbore penetrating the subterranean formation. The treatment fluid includes an aqueous base fluid, a cationic or zwitterionic friction reducer, and a substituted alkanolamine scale inhibitor. The method further includes contacting scale deposits on a surface in fluid communication with the wellbore and / or the subterranean formation with the treatment fluid.

Description

BACKGROUND OF THE INVENTION

[0001] During the drilling, completion, and stimulation of a wellbore and subterranean formation, water-based treatment fluids are typically pumped through tubular articles (e.g., pipes, coiled tubing, etc.). A significant amount of energy can be lost due to friction between the water-based treatment fluid in turbulent flow and the formation, wellbore, and / or tubular articles located within the wellbore. Due to these energy losses, additional horsepower may be required to achieve the desired treatment.

[0002] For example, in a fracturing operation, the treatment fluid utilizes an increased viscosity (e.g., a gelled fluid) or a high flow rate (e.g., high-velocity water) to create or extend one or more fractures in the formation. As the treatment fluid flows across the surfaces in the formation, wellbore, and associated tubular articles, the frictional force between the treatment fluid and the surfaces is amplified relative to a non-thickened fluid under normal flow due to the increased viscosity or high flow rate of the treatment fluid. The amplified frictional force translates into a need for increased energy input to achieve the desired pressure and / or flow rate of the treatment fluid. The increased energy input increases the cost of the fracturing operation.

[0003] To reduce these energy losses, friction reducers can be used in water-based treatment fluids. However, most friction reducers are sensitive to the total dissolved solids in the local environment (e.g., the treatment fluid or formation fluid encountered during operation). As used herein, total dissolved solids ("TDS") refers to the sum of all minerals, metals, cations, and anions dissolved in water, which is distinguished from suspended solids and can be separated from suspended solids via filtration. Since most dissolved solids are typically salts, the amount of salt in water is typically described by the concentration of total dissolved solids in the water. When the TDS increases, many friction reducers lose functionality, and in some cases, the situation may be further exacerbated by precipitating out of the fluid.

[0004] In some cases, a scale inhibitor is placed in the formation before, during, or after fracturing the subterranean formation to inhibit the formation of scale deposits in the production conduit. As used herein, the term "scale" refers to a mineral deposit or coating formed on the surface of a metal, rock, or other material, and a "scale inhibitor" refers to a chemical reagent or treatment used to control such deposition or coating. The scale inhibitor treatment fluid can typically be continuously injected into the wellbore through an injection port, for example, during a completion operation. In some cases, the scale inhibitor is included with the treatment fluid used to fracture the subterranean formation such that the scale inhibitor is absorbed into and dissolved in the matrix to prevent or reduce scale deposition. Current methods utilize negatively charged or anionic scale inhibitors, which can have a negative interaction with cationic or zwitterionic friction reducers, thereby having an adverse effect on fluid performance.

[0005] Accordingly, there is a need for a scale inhibitor that is compatible with cationic or zwitterionic friction reducers in high-TDS slickwater fluids. BRIEF DESCRIPTION OF THE DRAWINGS

[0006] The accompanying drawings illustrate certain aspects of the present disclosure and should not be used to limit or define the present disclosure.

[0007] Figure 1 is a schematic diagram showing a system of surface equipment for preparing and delivering a treatment fluid to a wellbore.

[0008] Figure 2 is a schematic diagram showing placing a treatment fluid into a fracture in a subterranean formation.

[0009] Figures 3 to 6 is a graph showing the effect of a scale inhibitor on the performance of a cationic friction reducer.

[0010] Figures 7 to 10 is a graph showing the effect of a scale inhibitor on the performance of an amphoteric friction reducer. Detailed Description

[0011] The compositions, methods, and / or systems disclosed herein may relate to subterranean operations, and in some compositions, methods, and / or systems, relate to introducing a treatment fluid into a subterranean formation penetrated by a wellbore. Any suitable treatment fluid for a given application may be used and should not be limited herein. Suitable treatment fluids may include, but are not limited to, drilling pad fluids, fracturing fluids, post-flush fluids, drilling fluids, completion fluids, acidizing fluids, polymer flood fluids for enhanced oil recovery, fluids for coiled tubing milling, and / or any combination thereof. Formation treatment may be performed in an initial fracturing operation or during a refracturing operation after an initial fracturing operation has been performed on a subterranean area. The treatment fluid may be any suitable aqueous base fluid, which may include a high total dissolved solids concentration. As used herein, the term "high total dissolved solids" or "high TDS" generally refers to the total dissolved solids in the treatment fluid, including salts, which range from about 1 mg / L to 350,000 mg / L, about 500 mg / L to about 350,000 mg / L, about 1,000 mg / L to about 300,000 mg / L, about 1,000 mg / L to 250,000 mg / L, and / or any value or range of values therein. The treatment fluid may comprise an aqueous base fluid, a friction reducer, a substituted alkanolamine scale inhibitor, and / or any combination thereof.

[0012] The treatment fluid may comprise an aqueous base fluid. Any suitable aqueous base fluid may be used and is not to be limited herein. Suitable aqueous base fluids may include fresh water, brackish water, brine, seawater, and / or any other aqueous base fluid that does not undesirably interact with other components used in accordance with the present disclosure or with the subterranean formation. The aqueous base fluid may be present in the treatment fluid in an amount of from about 80% to about 99.95%, or from about 85% to about 95%, or from about 90% to about 99.99% by total weight of the treatment fluid and / or any value or range of values therein.

[0013] In non-limiting examples, the aqueous base fluid may comprise a brine or a combination of brines. Depending on the needs of the particular application, suitable brines may be saturated or unsaturated. One or more salts may be added to water to provide a brine comprising dissolved salt and water. Suitable dissolved salts may include monovalent salts, divalent salts, trivalent salts, and any combination thereof. Mixtures of monovalent, divalent, and trivalent salts may also be used. Suitable brines may include, but are not limited to, saturated or partially saturated aqueous solutions comprising halide salts of Group 1 or alkali metal salts (such as sodium chloride, sodium bromide), halide salts of Group 2 or alkaline earth metal salts (such as calcium chloride, calcium bromide), other divalent metal halide salts (such as zinc bromide), compounds comprising metal formates (such as sodium formate, cesium formate, potassium formate, methyl formate, ethyl formate, methyl chloroformate, triethyl orthoformate, trimethyl orthoformate), derivatives thereof, or combinations thereof.

[0014] The treatment fluid may further comprise a friction reducer. A friction reducer can be added to the treatment fluid to form a slick-water fluid. Any friction reducer capable of reducing the friction generated within the treatment fluid as the treatment fluid flows through the treatment system can be used and is not limited herein. In one embodiment, the friction reducer can be an amphoteric polymer, a cationic polymer, or any combination thereof. In one embodiment, the friction reducer can be a high molecular weight water-soluble polymer. As used herein, "high molecular weight" can refer to a polymer having an average molecular weight of about 14,000,000 Daltons or greater. Optionally, "high molecular weight" can refer to a polymer having a molecular weight of at least about 1,500,000 Daltons or greater. The molecular weight of the polymer can be determined in any suitable manner and is not limited herein. In a non-limiting example, the molecular weight of the water-soluble polymer can be determined by measuring the intrinsic viscosity using a capillary viscometer. First, for polymer concentrations of 0.05 wt%, 0.025 wt%, and 0.01 wt%, the viscosities of the water-soluble polymer in 1M NaCl solution measured at a temperature of about 30 °C and a pH of about 7 can be obtained; then the value corresponding to a polymer concentration of about 0 wt% of the polymer intrinsic viscosity can be extrapolated. Finally, using the measured intrinsic viscosity, the Mark-Houwink equation can provide the average molecular weight of the polymer.

[0015] Suitable friction reducers can include synthetic polymers, amphoteric polymers, cationic polymers, and / or any combination thereof. Additionally, suitable friction reducers can be polymers and / or copolymers. As used herein, the term "copolymer" is not limited to polymers containing two types of monomer units, but includes any combination of monomer units, such as terpolymers and quaternary copolymers. Examples of suitable friction reducers include quaternized aminoalkyl acrylates, such as the copolymer of acrylamide and dimethylaminoethyl acrylate quaternized with benzyl chloride. Another example of a suitable friction reducer includes acrylamide. An example of a suitable friction reducer containing acrylamide is the copolymer of acrylamide and acrylic acid. Such friction reducers can further include additional monomers, such as 2-acrylamido-2-methylpropanesulfonic acid, N,N-dimethylacrylamide, vinylsulfonic acid, N-vinylacetamide, N-vinylformamide, and mixtures thereof. In certain embodiments, suitable friction reducers can include at least one cationic monomer selected from the group consisting of (meth)acrylamidopropyltrimethylammonium halide, (meth)acryloyloxyethyltrimethylammonium halide, (meth)acryloyloxyethyltrimethylmethylsulfate, diallyldimethylammonium halide, diallylamine, methyldiallylamine, dimethylaminoethyl methacrylate, dimethylaminopropylmethacrylamide, and / or any combination thereof. Optionally, suitable friction reducers can include at least one amphoteric polymer selected from the group consisting of acrylamide, acrylic acid, diallyldimethylammonium chloride, vinyl sulfonate / vinyl amide / acrylamide terpolymer, vinyl sulfonate / acrylamide copolymer, acrylamide / acrylamido-methylpropanesulfonic acid copolymer, acrylamide / vinylpyrrolidone copolymer; sodium carboxymethylcellulose, poly[alkylamino acrylate-co-acrylate-grafted poly(ethylene oxide)], acrylamide / octadecyldimethylammonium bromide methyl methacrylate copolymer, dimethylaminoethyl, methacrylate / vinylpyrrolidone / cetyl dimethylammonium bromide ethyl methacrylate terpolymer, acrylamide / 2-acrylamido-2-methylpropanesulfonic acid / 2-ethylhexyl methacrylate terpolymer, and / or any combination thereof. Without limitation, friction reducers can be included in the treatment fluid to provide a desired amount of friction reduction. For example, the friction reducer can be included in the treatment fluid in an amount equal to or less than 2.0 wt% of the aqueous base fluid present in the treatment fluid. In one embodiment, the friction reducer can be included in the treatment fluid in an amount of about 0.02 wt% to about 2.0 wt%, or about 0.025 wt% to about 0.3 wt%, or about 0.2 wt% to about 0.6 wt%, or about 0.6 wt% to about 1.0 wt%, or about 1.0 wt% to about 1.5 wt%, or about 1.5 wt% to about 2.0 wt%, and / or any value or range of values therein of the aqueous base fluid present in the treatment fluid.Without limitation, the friction reducer can be included in the treatment fluid in an amount sufficient to reduce friction upon mixing without forming a gel. For example, a treatment fluid comprising a friction reducer may not exhibit a significant yield point.

[0016] For a given application, the slickwater fluid can have any suitable viscosity and should not be limited herein. The treatment fluid can have a viscosity of from about 0.5 cP to about 20 cP, or from about 1 cP to about 5 cP, or from about 5 cP to about 20 cP, and / or any value or range of values therein. In certain embodiments, the slickwater base fluid can have a density of from about 1.0 g / cc to about 1.1 g / cc, or from about 1.1 g / cc to about 1.3 g / cc, or from about 1.3 g / cc to about 1.5 g / cc, and / or any value or range of values therein. The slickwater base fluid can be used in any suitable treatment fluid and should not be limited herein.

[0017] The treatment fluid can further comprise a clay control agent. Any suitable clay control agent that is chemically compatible with the substituted alkanolamine scale inhibitor can be used and should not be limited herein. In certain embodiments, the clay control agent can be positively charged and incompatible with the anionic friction reducer. Suitable clay control agents can include, but are not limited to, potassium chloride, sodium chloride, ammonium chloride, tetramethylammonium chloride, cationic polymers, cationic surfactants, hydrophobic resins, transition metals, furfuryl alcohol, ethylene glycol, quaternary amines, bisquaternary amines, and / or any combination thereof. The clay control agent can be present in the treatment fluid in any suitable amount and should not be limited herein. In one embodiment, the clay control agent can be present in the treatment fluid in an amount of from about 0.1 wt% to about 10 wt%, or from about 0.1 wt% to about 3 wt%, or from about 0.5 wt% to about 2 wt%, and / or any value or range of values therein.

[0018] The treated fluid may further comprise a substituted alkanolamine scale inhibitor. Any substituted alkanolamine scale inhibitor capable of reducing and / or preventing the formation of mineral scale in the treatment system may be used. As used herein, the term "inhibit" and its derivatives refer to reducing the tendency and / or the degree of occurrence of a phenomenon. The term "inhibit" does not imply any specific degree or amount of inhibition. The substituted alkanolamine scale inhibitor may be compatible with cationic and zwitterionic friction reducers. In other words, the substituted alkanolamine scale inhibitor may not react with the friction reducer and / or may have limited interaction with the friction reducer such that the substituted alkanolamine scale inhibitor does not negatively impact the ability of the friction reducer to reduce the friction of the treated fluid. Optionally, the substituted alkanolamine scale inhibitor may be compatible with a treated fluid having a high total dissolved solids concentration. The substituted alkanolamine scale inhibitor may be present in the treated fluid in any suitable amount and should not be limited herein. In one embodiment, the substituted alkanolamine scale inhibitor may be present in the treated fluid in an amount of from about 5 mg / L to about 1,000 mg / L, or from about 15 mg / L to about 500 mg / L, or from about 50 mg / L to about 200 mg / L, or any value and / or range of values thereof, based on the weight of the treated fluid.

[0019] The substituted alkanolamine scale inhibitor may be any suitable substituted alkanolamine capable of providing scale inhibition performance in the treated fluid. For example, substituted alkanolamines may be used in which at least one substituent is terminated with a phosphonate or phosphonic acid. Suitable substituted alkanolamines may include, but are not limited to, substituted alkanolamines of the following formula (1):

[0020]

[0021] Wherein R1 can be selected from the group consisting of: alkyl, alkenyl, alkynyl, phenyl or phenylene, heteroatom-substituted alkyl, heteroatom-substituted alkenyl, heteroatom-substituted alkynyl or heteroatom-substituted phenyl, wherein R2 and R3 can independently be selected from the group consisting of: hydrogen, alkyl, alkenyl, alkynyl, heteroatom-substituted alkyl, heteroatom-substituted alkenyl, heteroatom-substituted alkynyl, heteroatom-substituted phenyl, alkyl terminated by phosphonate, alkyl terminated by phosphonic acid, alkenyl terminated by phosphonate, alkenyl terminated by phosphonic acid, alkynyl terminated by phosphonate, alkynyl terminated by phosphonic acid, or any combination thereof. Suitable heteroatoms that can be substituted in R1, R2 and / or R3 can include, but are not limited to, nitrogen, oxygen, sulfur, phosphorus, silicon, etc. The alkyl, alkenyl, alkynyl or phenyl or phenylene (or heteroatom-substituted) groups of R1, R2 and R3 can be the same or different, and in some embodiments, include from about 1 carbon atom to about 5 carbon atoms, or more specifically, include from about 1 carbon atom to about 3 carbon atoms. For example, R1 can be a chain of 2 to 5 carbon atoms, R2 can be a chain of 1 to 3 carbon atoms terminated by phosphonate or phosphonic acid, and R3 can be a chain of 1 to 3 carbon atoms terminated by phosphonate or phosphonic acid.

[0022] Examples of suitable substituted alkanolamine scale inhibitors can include, but are not limited to, hydroxyethylamino-di(methylenephosphonic acid) (HADMP or HEMPA) of the following formula (2):

[0023]

[0024] Wherein the hydroxyethylamino-di(methylenephosphonic acid) scale inhibitor can be cationic in nature and thus can have limited (if any) interaction with amphoteric and / or cationic friction reducers present in the treatment fluid. In one embodiment, the substituted alkanolamine scale inhibitor can be cationic in nature. In one embodiment, the substituted alkanolamine scale inhibitor may be incompatible with anionic friction reducers.

[0025] Optionally, the substituted alkanolamine scale inhibitor can be effective in the pH range of about 6 to about 9. In certain embodiments, the treatment fluid can further comprise a pH regulator. If the pH of the substituted alkanolamine scale inhibitor is less than the target or preferred pH of the treatment fluid, the treatment fluid can comprise a pH regulator. In a non-limiting example, if the pH of the substituted alkanolamine scale inhibitor is about 4, a pH regulator can be added to the treatment fluid. The pH regulator can change the pH of the treatment fluid to a range of about 7 to about 8.5. In this non-limiting example, the pH regulator can be an acid neutralizer, such as an alkali solution, a caustic solution, or an alkaline solution. Suitable pH regulators can include, but are not limited to, Group 1 metal hydroxides, bicarbonates, Bronsted bases, and / or any combination thereof. Any suitable pH regulator for a given application can be used and should not be limited herein. The substituted alkanolamine scale inhibitor can be effective at any pH and should not be limited herein.

[0026] The substituted alkanolamine scale inhibitor can be added to the subterranean formation before, after, or during a subterranean operation. In some embodiments, the substituted alkanolamine scale inhibitor can be added to the treatment fluid and carried with the treatment fluid during a subterranean operation. In certain embodiments, the substituted alkanolamine scale inhibitor can be added to the treatment fluid during a remedial operation. In such embodiments, the substituted alkanolamine scale inhibitor can be added to the formation after placement and setting of the particulate fill layer and / or after scale buildup has formed on the surface of the subterranean formation. In such embodiments, a remedial fluid can be used to carry the substituted alkanolamine scale inhibitor into the wellbore and through the particulate fill layer. For example, the particulate fill layer can be contacted with the substituted alkanolamine scale inhibitor. Among other purposes, the technique can also be used as a follow-up treatment method to periodically treat the particulate fill layer over time in order to maintain the permeability of the particulate fill layer.

[0027] Optionally, the treatment fluid can comprise an additive. The additive can be used to adjust the properties of the treatment fluid, such as viscosity, density, etc. Examples of suitable additives can include, but are not limited to, substituted alkanolamine scale inhibitors, corrosion inhibitors, surfactants, gel stabilizers, antioxidants, additives to prevent polymer degradation, relative permeability modifiers, scale inhibitors, foaming agents, defoaming agents, antifoaming agents, iron control agents, particle diverters, salts, fluid loss control additives, gases, clay control agents, dispersants, flocculants, scavengers (e.g., H2S scavengers, CO2 scavengers, or O2 scavengers), gelling agents, lubricants, friction reducers, bridging agents, viscosifiers, weighting agents, solubilizers, paraffin / asphaltene inhibitors, emulsion breakers, hydrate inhibitors, consolidants, biocides, clay stabilizers, demulsifiers, delayed release demulsifiers, or any combination thereof. Benefiting from the present disclosure, those of ordinary skill in the art will be able to formulate a treatment fluid having properties suitable for the desired application.

[0028] The present disclosure provides treatment fluids, methods, and systems for treating subterranean formations. The treatment fluid can include an aqueous base fluid, an amphoteric or cationic friction reducer, and a substituted alkanolamine scale inhibitor. The method can include preparing a treatment fluid that includes a slickwater base fluid, an amphoteric or cationic friction reducer, and a substituted alkanolamine scale inhibitor. The treatment fluid can be prepared on-site directly or at an off-site facility. The treatment fluid can be prepared at any location in any suitable manner as long as there are no destabilizing effects that can cause precipitation or flocculation. The method can include pumping the treatment fluid into a wellbore penetrating a subterranean formation. The method can further include introducing the treatment fluid from the wellbore into a portion of the subterranean formation. The system can include pumping and mixing equipment to deliver the treatment fluid to a wellbore section containing a target subterranean formation.

[0029] System examples can include a pump fluidly connected to a pipe that contains the treatment fluid as described herein. The pump can be a high-pressure pump. As used herein, the term "high-pressure pump" refers to a pump capable of delivering fluid downhole at a pressure of about 1000 psi or greater. A high-pressure pump can be used when it is desired to introduce the treatment fluid into the subterranean formation at or above the fracture gradient of the subterranean formation, but a high-pressure pump can also be used when fracturing is not desired. In some examples, the high-pressure pump is capable of fluidly transporting particulate matter such as proppant particles into the subterranean formation. Suitable high-pressure pumps are known to those of ordinary skill in the art and can include, but are not limited to, floating piston pumps and positive displacement pumps. In other examples, the pump can be a low-pressure pump. As used herein, the term "low-pressure pump" refers to a pump that operates at a pressure of about 1000 psi or less. In some examples, the low-pressure pump can be fluidly coupled to a high-pressure pump that is fluidly coupled to a pipe. That is, the low-pressure pump can be configured to deliver the treatment fluid to the high-pressure pump. In such examples, the low-pressure pump can "boost" the pressure of the treatment fluid before it reaches the high-pressure pump. In any example, the high-pressure pump and / or the low-pressure pump can deliver the treatment fluid to a location in the target subterranean formation. These pumps can supply sufficient pressure to allow the treatment fluid to fracture the subterranean formation. That is, these pumps can reach or exceed the fracture gradient of the subterranean formation.

[0030] In some examples, the systems described herein can further include a mixing tank that is upstream of the pump and is a vessel in which the treatment fluid is formulated. In various examples, the pump (e.g., a low-pressure pump, a high-pressure pump, or a combination thereof) can deliver the treatment fluid from the mixing tank to a transport conduit. In other examples, the treatment fluid can be formulated off-site and transported to the job site, in which case the treatment fluid can be introduced into the transport conduit directly from its shipping container (e.g., a truck, a railcar, or a barge) or from a transport pipeline via a pump. In either case, the treatment fluid can be pumped into the pump, boosted to an appropriate pressure, and then introduced into the transport conduit for downhole delivery.

[0031] When desired for use, the friction reducing agent and the substituted alkanolamine scale inhibitor can be added to the aqueous base fluid and mixed as desired. In alternative instances, the friction reducing agent can be added to the aqueous base fluid, then the substituted alkanolamine scale inhibitor can be added, and then mixed as desired. The components and additives of the treatment fluid can be added or introduced to each other in any order and at any time during the use of the treatment fluid.

[0032] Now referring to Figure 1 an exemplary method of using a substituted alkanolamine scale inhibitor will be described in more detail. Any of the foregoing examples of substituted alkanolamine scale inhibitors can be applied to Figure 1 the context of. Figure 1 A schematic illustration of the surface and near-surface portions of a system that can deliver a treatment fluid described herein to a downhole location in accordance with one or more examples is shown. It should be noted that while Figure 1 a land-based system is generally depicted, it should be appreciated that similar systems can also operate in subsea locations. As Figure 1 depicted, system 100 can include a mixing tank 105 in which a treatment fluid comprising an aqueous base fluid, an amphoteric or cationic friction reducing agent, and a substituted alkanolamine scale inhibitor can be formulated. The treatment fluid can be delivered via line 110 to a wellhead 115 where the treatment fluid enters a tubular 120. The tubular 120 can extend from the wellhead 115 into a wellbore 125 that penetrates a subterranean formation 130. The wellbore 125 can be any type of wellbore, including vertical, horizontal, deviated, etc. The depicted portion of the wellbore 125 is equipped with a casing 135. It should be understood that in some examples, the wellbore 125 can be uncased. When ejected from the tubular 120, the treatment fluid can subsequently enter the subterranean formation 130, as Figure 2 described below. A pump 140 can be configured to raise the pressure of the treatment fluid to a desired level before the treatment fluid is introduced into the tubular 120. Examples of treatment fluids can include, but are not limited to, fracturing fluids, acidizing fluids, fluids for enhanced oil recovery, or any such fluids.

[0033] Although not depicted in Figure 1 in some examples, the treatment fluid can flow back to the wellhead 115 and exit the subterranean formation 130. In some optional examples, the treatment fluid that has flowed back to the wellhead 115 can subsequently be recovered and recycled into the subterranean formation 130.

[0034] Figure 2 A schematic illustration of the downhole portion of the system 100 depicted in Figure 1 is shown in accordance with one or more examples. As Figure 2 depicted, the tubular 120 extends from the wellhead 115 (as Figure 1extends into a wellbore 125 that penetrates a subterranean formation 130. After descending through the heel 145 of the wellbore 125, the tubular member 120 may be coupled to one or more packers 150 that are positioned to isolate sections of the wellbore 125. As described herein, the treatment fluid 155 may exit the tubular member 120 through an opening 160. The treatment fluid 155 may be introduced into the subterranean formation 130 via a native fracture 165 in other such openings that enter the subterranean formation 130. If the treatment fluid 155 is a fracturing fluid, it may have created or enhanced the native fracture 165. If the treatment fluid 155 is an acidizing fluid, it may contact the walls of the subterranean formation 130 and the channels within the native fracture 165 and increase the hydrocarbon permeability therethrough. If the treatment fluid 155 is an enhanced oil recovery fluid, it may be miscible with a portion of the hydrocarbon fluid flowing out of the subterranean formation 130 or otherwise assist in transporting the hydrocarbon fluid flowing out of the subterranean formation, thereby increasing the hydrocarbon recovery from the subterranean formation 130.

[0035] It should be appreciated that the system 100 is merely exemplary in nature and, for clarity, there may be various additional components that are not necessarily depicted in Figure 1 and 2 Non-limiting additional components that may be present include, but are not limited to, supply hoppers, valves, condensers, adapters, connectors, gauges, sensors, compressors, pressure controllers, pressure sensors, flow controllers, flow sensors, and temperature sensors.

[0036] It should be clearly understood that the examples depicted by Figure 1 and 2 are merely general applications of the principles of the present disclosure in practice and that numerous other examples are possible. Accordingly, the scope of the present disclosure is not limited in any way to the details of Figure 1 and 2 described herein.

[0037] The present disclosure provides methods for treating subterranean formations. Exemplary methods include introducing a treatment fluid into a wellbore that penetrates a subterranean formation. The treatment fluid includes an aqueous base fluid, a cationic or zwitterionic friction reducer, and a substituted alkanolamine scale inhibitor. The method further includes contacting scale deposits on a surface in fluid communication with the wellbore and / or the subterranean formation fluid with the treatment fluid.

[0038] Additionally or alternatively, the method may individually or in combination include one or more of the following features. The substituted alkanolamine scale inhibitor may include a molecule having the following molecular formula:

[0039]

[0040] Wherein R1 is selected from the group consisting of: alkyl, alkenyl, alkynyl, phenyl or phenylene, heteroatom-substituted alkyl, heteroatom-substituted alkenyl, heteroatom-substituted alkynyl, heteroatom-substituted phenyl, and any combination thereof. R2 may be selected from the group consisting of: hydrogen, alkyl, alkenyl, alkynyl, heteroatom-substituted alkyl, heteroatom-substituted alkenyl, heteroatom-substituted alkynyl, heteroatom, and any combination thereof. R3 may be selected from the group consisting of: hydrogen, alkyl, alkenyl, alkynyl, heteroatom-substituted alkyl, heteroatom-substituted alkenyl, heteroatom-substituted alkynyl, heteroatom, and any combination thereof. The substituted alkanolamine scale inhibitor may comprise hydroxyethylamino-di(methylenephosphonic acid). The substituted alkanolamine scale inhibitor may be cationic in nature, where the substituted alkanolamine scale inhibitor may not react with or may have limited interaction with cationic or zwitterionic friction reducers. The friction reducer may be cationic, where the cationic friction reducer comprises at least one cation selected from the group consisting of: (meth)acrylamidopropyltrimethylammonium halide, (meth)acryloyloxyethyltrimethylammonium halide, (meth)acryloyloxyethyltrimethylmethylsulfate, diallyldimethylammonium halide, diallylamine, methyldiallylamine, dimethylaminoethyl methacrylate, dimethylaminopropylmethacrylamide, and any combination thereof. The substituted alkanolamine scale inhibitor may be present in the treatment fluid in an amount of from about 5 mg / L to about 1,500 mg / L. The aqueous base fluid may have a total dissolved solids content of from about 10,000 mg / L to about 300,000 mg / L. The method may further comprise forming a proppant pack in the subterranean formation; contacting the formed proppant pack with the substituted alkanolamine scale inhibitor; and preventing mineral scale deposition adjacent to the proppant pack via the substituted alkanolamine scale inhibitor. The treatment fluid may further comprise proppant particles. The treatment fluid may further comprise a positively charged clay control agent. The positively charged clay control agent may be selected from the group consisting of: potassium chloride, sodium chloride, ammonium chloride, tetramethylammonium chloride, cationic polymers, cationic surfactants, hydrophobic resins, transition metals, furfuryl alcohol, ethylene glycol, quaternary amines, bisquaternary amines, and any combination thereof.

[0041] The present disclosure provides a treatment fluid for treating a subterranean formation. Treatment fluid examples include an aqueous base fluid, a cationic friction reducer, and a substituted alkanolamine scale inhibitor.

[0042] Additionally or alternatively, the treatment fluid may individually or in combination include one or more of the following features. The substituted alkanolamine scale inhibitor may comprise a molecule having the following molecular formula:

[0043]

[0044] wherein R1 is selected from the group consisting of alkyl, alkenyl, alkynyl, phenyl or phenylene, heteroatom-substituted alkyl, heteroatom-substituted alkenyl, heteroatom-substituted alkynyl, heteroatom-substituted phenyl, and any combination thereof. R2 may be selected from the group consisting of hydrogen, alkyl, alkenyl, alkynyl, heteroatom-substituted alkyl, heteroatom-substituted alkenyl, heteroatom-substituted alkynyl, heteroatom, and any combination thereof. R3 may be selected from the group consisting of hydrogen, alkyl, alkenyl, alkynyl, heteroatom-substituted alkyl, heteroatom-substituted alkenyl, heteroatom-substituted alkynyl, heteroatom, and any combination thereof. The substituted alkanolamine scale inhibitor may comprise hydroxyethylamino-di(methylenephosphonic acid). The substituted alkanolamine scale inhibitor may be cationic in nature, where the substituted alkanolamine scale inhibitor may not react with cationic or zwitterionic friction reducers or may have limited interaction with cationic or zwitterionic friction reducers. The friction reducer may be cationic, where the cationic friction reducer comprises at least one cation selected from the group consisting of (meth)acrylamidopropyltrimethylammonium halide, (meth)acryloyloxyethyltrimethylammonium halide, (meth)acryloyloxyethyltrimethylmethylsulfate, diallyldimethylammonium halide, diallylamine, methyldiallylamine, dimethylaminoethyl methacrylate, dimethylaminopropylmethacrylamide, and any combination thereof. The substituted alkanolamine scale inhibitor may be present in the treatment fluid in an amount of about 5 mg / L to about 1,500 mg / L. The aqueous base fluid may have a total dissolved solids content of about 10,000 mg / L to about 300,000 mg / L. The treatment fluid may further comprise proppant particles. The treatment fluid may further comprise a positively charged clay control agent. The positively charged clay control agent may be selected from the group consisting of potassium chloride, sodium chloride, ammonium chloride, tetramethylammonium chloride, cationic polymers, cationic surfactants, hydrophobic resins, transition metals, furfuryl alcohol, ethylene glycol, quaternary amines, bisquaternary amines, and any combination thereof. The aqueous base fluid may comprise brine having a total dissolved solids content of about 1 mg / L to 350,000 mg / L. The aqueous base fluid may be a slickwater fluid having a viscosity of about 0.5 cP to about 20 cP.

[0045] To facilitate a better understanding of the present disclosure, the following examples of certain aspects of some methods, systems, and compositions are given. The following examples should in no way be construed as limiting or defining the entire scope of the present disclosure.

[0046] Example 1

[0047] A series of friction reduction tests were conducted to determine the effect of four scale inhibitors on the performance of zwitterionic and cationic friction reducers in slickwater treatment fluids. In each of these tests, 1 gallon of friction reducer was used per 1,000 gallons of tap water. The amount of scale inhibitor was varied in each test to illustrate the effect of the scale inhibitor on the performance of the friction reducer. These tests were conducted at room temperature conditions.

[0048] These friction reduction tests are conducted using a friction reducer meter (“FR meter”) according to the procedures listed below. The FR meter is a closed-loop piping device designed to measure the pressure drop across an 8-foot section of a 20-foot long stainless steel pipe. The stainless steel pipe has an inner diameter of 0.5 inches and a smooth wall. The FR meter includes a storage / mixing tank connected to a fixed-speed progressive cavity pump that pumps the test fluid through a magnetic flow meter, then through the test pipe and return line to the storage / mixing tank.

[0049] For each test, approximately 20 liters of tap water are added to the storage / mixing tank. The pump is run to circulate the water for a time period sufficient to fill all the pipes with water. Next, for each test, an appropriate amount of scale inhibitor is added to the storage / mixing tank under mixing. The data acquisition system measures the flow rate, tank temperature, and pressure drop across the 8-foot section of the pipe. At approximately 1 minute into the test, 1 gallon of friction reducer is added to the storage / mixing tank. Each test is run for a total of approximately 20 minutes, recording the flow rate, tank temperature, and pressure drop across the 8-foot section of the pipe at 1-second intervals. The pump speed is approximately 10 gallons per minute. For commercial steel pipes, the flow is fully turbulent at a Reynolds number of approximately 50,000.

[0050] The first minute of data collected before adding the friction reducer is used to verify the instrument readings and provide a data baseline for the known fluid. The pressure drop across the 8-foot section of the pipe for the tap water containing scale inhibitor before adding the friction reducer is calculated based on the flow rate and pipe dimensions according to the following equation:

[0051]

[0052] where ΔP 水 is the calculated pressure drop of deionized water, ρ is the density, V is the velocity, L is the length, gc is the gravitational constant, and d is the pipe diameter. The variable f is calculated according to the following turbulent flow formula.

[0053]

[0054] where ε is the pipe roughness, d is the pipe diameter and NRe is the Reynolds number (Shacham, M., “Science Review Index: Chemical Engineering (Isr. Chem. Eng.)”, 8, 7E (1976)).

[0055] After adding the friction reducer to the tank, the measured 10-minute average pressure drop is compared to the calculated pressure drop of water using the following equation to determine the 10-minute average friction reduction % (“FR %”):

[0056]

[0057] where ΔP 水 is the calculated pressure drop of water, and ΔP测量的 The 10-minute average pressure drop measured after introducing the friction reducer.

[0058] Ramp test conditions can be used to examine the ability of the friction reducer to recover from varying shear and maintain its performance. This can also show the overall degradation of the friction reducer polymer over time. Except for changing the flow rate at specific times, the ramp test conditions are similar to the quantitative flow test conditions. The ramp test conditions are shown in Table 1 below.

[0059] Table 1

[0060]

[0061]

[0062] The compatibility of the scale inhibitor and the friction reducer polymer can be determined by comparing the percentage of friction reduction under ramp-up conditions of the flow rate with that under ramp-down conditions. For a given flow rate, a difference in the percentage of friction reduction greater than 5% between the two conditions indicates a performance decline of the friction reducer polymer. In other words, the friction reducer polymer cannot maintain its performance and recover from varying shear. This decline may be caused by flow-induced shear or by chemical incompatibility with other additives in the fluid. If, for a given flow rate, the difference in the percentage of friction reduction between the two conditions is less than 5%, it can be determined that the scale inhibitor and the friction reducer polymer are chemically compatible because the friction reducer can maintain its performance and recover from varying shear.

[0063] Next, four scale inhibitors were tested with a cationic friction reducer at 1 gallon per thousand gallons sample (gpt) under ramp test conditions. Each tested formulation is shown in Table 2.

[0064] Table 1

[0065]

[0066] The results are plotted in Figures 3 to 6 as shown in. Figures 3 to 5 The results shown in indicate that the conventional scale inhibitor has a significant impact on the performance of the cationic friction reducer. When the amount of the conventional scale inhibitor increases, the percentage of friction reduction decreases. In contrast, Figure 6 it is shown that HADMP does not affect the performance of the cationic friction reducer, so HADMP is compatible with the cationic friction reducer.

[0067] Next, four scale inhibitors were tested with an amphoteric friction reducer sample at 1 gallon per thousand gallons (gpt) under ramp test conditions. Each tested formulation is shown in Table 3.

[0068] Table 3

[0069]

[0070]

[0071] The results of the antifriction test are shown in Figures 7 to 10 . Figures 7 to 9 The results shown in Figure 10 show that the conventional scale inhibitor has a significant impact on the performance of the zwitterionic antifriction agent. When the amount of the conventional scale inhibitor increases, the percentage of antifriction decreases. In contrast,

[0072] It should also be recognized that the disclosed treatment fluid can also directly or indirectly affect various downhole equipment and tools that can come into contact with the disclosed treatment fluid. Such equipment and tools can include, but are not limited to, wellbore casings, wellbore liners, completion strings, insert strings, drilling strings, coiled tubing, slickline, wireline, drill pipe, drill collars, mud motors, downhole motors and / or pumps, surface-mounted motors and / or pumps, centralizers, turbulators, scriber, floats (e.g., slips, collars, valves, etc.), logging tools and associated telemetry equipment, actuators (e.g., electromechanical devices, hydromechanical devices, etc.), sliding sleeves, production sleeves, plugs, screens, filters, flow control devices (e.g., inflow control devices, autonomous inflow control devices, outflow control devices, etc.), connectors (e.g., electrohydraulic wet connections, dry connections, inductive couplers, etc.), control lines (e.g., electrical, fiber optic, hydraulic, etc.), monitoring lines, drill bits and reamers, sensors or distributed sensors, downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers, cement plugs, bridge plugs and other wellbore isolation devices or components. Any of these components can be included in the methods and systems generally described above and depicted in Figures 1 to 10 .

[0073] The foregoing description provides various examples of the systems and methods of use disclosed herein, which can contain alternative combinations of different method steps and components. It should be understood that although individual examples may be discussed herein, the present disclosure encompasses all combinations of the disclosed examples, including but not limited to different component combinations, method step combinations, and system characteristics. It should be understood that the compositions and methods are described in terms of "comprising", "containing", or "including" various components or steps. The systems and methods can also "consist essentially of" or "consist of" various components and steps. In addition, the indefinite articles "a" or "an" used in the claims are defined herein to mean one or more than one of the elements introduced by them.

[0074] For the sake of brevity, only certain ranges are explicitly disclosed in this document. However, ranges from any lower limit can be combined with any upper limit to recite ranges not explicitly recited, and ranges from any lower limit can be combined with any other lower limit to recite ranges not explicitly recited. Similarly, ranges from any upper limit can be combined with any other upper limit to recite ranges not explicitly recited. Additionally, whenever a numerical range with a lower and upper limit is disclosed, any specific numerical value and any included range falling within that range are specifically disclosed. In particular, each value range disclosed herein (in the form of "about a to about b", or equivalently, "from approximately a to b", or equivalently, "from approximately a - b") should be understood to recite every numerical value and range subsumed within the broader value range, even if not explicitly recited. Thus, each point or individual value can serve as its own lower or upper limit in combination with any other point or individual value or any other lower or upper limit to recite ranges not explicitly recited.

[0075] One or more illustrative examples incorporating the examples disclosed herein are presented. For clarity, not all features of the physical embodiments are described or shown in this application. Thus, the disclosed systems and methods are well suited to obtain the recited and those inherent therein purposes and advantages. The specific examples disclosed above are merely illustrative, as the teachings of this disclosure can be modified and practiced in different but equivalent manners, which will be apparent to those skilled in the art benefiting from the teachings herein. Additionally, details of the construction or design shown herein are not intended to be limiting other than as described in the claims below. Thus, it is apparent that the specific illustrative examples disclosed above can be varied, combined, or modified, and all such variations are contemplated within the scope of this disclosure. The systems and methods illustratively disclosed herein can be suitably practiced in the absence of any element not specifically disclosed herein and / or any optional element disclosed herein.

[0076] Although the present disclosure has been described in detail along with its advantages, it should be understood that various changes, substitutions, and alterations can be made without departing from the spirit and scope of the present disclosure as defined by the appended claims.

Claims

1. A method for treating a subterranean formation, the method comprising: introducing a treatment fluid into a wellbore penetrating the subterranean formation, the treatment fluid comprising: an aqueous base fluid; a cationic friction reducer; and a substituted alkanolamine scale inhibitor; contacting scale deposits on a surface in fluid communication with the wellbore and / or the subterranean formation fluid with the treatment fluid, wherein the cationic friction reducer comprises at least one cation selected from the group consisting of (meth)acrylamidopropyltrimethylammonium halide, (meth)acryloyloxyethyltrimethylammonium halide, (meth)acryloyloxyethyltrimethylmethylsulfate, diallyldimethylammonium halide, diallylamine, methyldiallylamine, dimethylaminoethyl methacrylate, dimethylaminopropylmethacrylamide, and any combination thereof.

2. The method according to claim 1, wherein the substituted alkanolamine scale inhibitor comprises a molecule having the following molecular formula: wherein R1 is selected from the group consisting of alkyl, alkenyl, alkynyl, phenyl or phenylene, heteroatom-substituted alkyl, heteroatom-substituted alkenyl, heteroatom-substituted alkynyl, heteroatom-substituted phenyl, and any combination thereof.

3. The method according to claim 2, wherein R2 is selected from the group consisting of hydrogen, alkyl, alkenyl, alkynyl, heteroatom-substituted alkyl, heteroatom-substituted alkenyl, heteroatom-substituted alkynyl, heteroatom, and any combination thereof.

4. The method according to claim 3, wherein R3 is selected from the group consisting of hydrogen, alkyl, alkenyl, alkynyl, heteroatom-substituted alkyl, heteroatom-substituted alkenyl, heteroatom-substituted alkynyl, heteroatom, and any combination thereof.

5. The method according to claim 1, wherein the substituted alkanolamine scale inhibitor comprises hydroxyethylamino-di(methylenephosphonic acid).

6. The method according to claim 1, wherein the substituted alkanolamine scale inhibitor is essentially cationic and does not react with the cationic friction reducer.

7. The method according to claim 1, wherein the substituted alkanolamine scale inhibitor is present in the treatment fluid in an amount of 5 mg / L to 1,500 mg / L.

8. The method according to claim 1, wherein the aqueous base fluid has a total dissolved solids content of 10,000 mg / L to 300,000 mg / L.

9. The method according to claim 1, wherein the treatment fluid further comprises proppant particles.

10. The method according to claim 9, further comprising: forming a proppant pack in the subterranean formation; contacting the formed proppant pack with the substituted alkanolamine scale inhibitor; and preventing mineral scale accumulation adjacent to the proppant pack via the substituted alkanolamine scale inhibitor.

11. The method according to claim 1, wherein the treatment fluid further comprises a positively charged clay stabilizer.

12. The method according to claim 11, wherein the positively charged clay control agent is selected from the group consisting of potassium chloride, sodium chloride, ammonium chloride, tetramethylammonium chloride, cationic polymers, cationic surfactants, hydrophobic resins, furfuryl alcohol, ethylene glycol, bisquaternary ammonium, and any combination thereof.

13. The method according to claim 11, wherein the positively charged clay control agent is selected from the group consisting of quaternary ammonium.

14. A treatment fluid, the treatment fluid comprising: an aqueous base fluid; a cationic friction reducer; and a substituted alkanolamine scale inhibitor, wherein the cationic friction reducer comprises at least one cation selected from the group consisting of (meth)acrylamidopropyltrimethylammonium halide, (meth)acryloyloxyethyltrimethylammonium halide, (meth)acryloyloxyethyltrimethylmethylsulfate, diallyldimethylammonium halide, diallylamine, methyldiallylamine, dimethylaminoethyl methacrylate, dimethylaminopropylmethacrylamide, and any combination thereof.

15. The treatment fluid according to claim 14, wherein the substituted alkanolamine scale inhibitor comprises a molecule having the following molecular formula: wherein R1 is selected from the group consisting of alkyl, alkenyl, alkynyl, phenyl or phenylene, heteroatom-substituted alkyl, heteroatom-substituted alkenyl, heteroatom-substituted alkynyl, heteroatom-substituted phenyl, and any combination thereof, wherein R2 is selected from the group consisting of hydrogen, alkyl, alkenyl, alkynyl, heteroatom-substituted alkyl, heteroatom-substituted alkenyl, heteroatom-substituted alkynyl, heteroatom, and any combination thereof, and wherein R3 is selected from the group consisting of hydrogen, alkyl, alkenyl, alkynyl, heteroatom-substituted alkyl, heteroatom-substituted alkenyl, heteroatom-substituted alkynyl, heteroatom, and any combination thereof.

16. The treatment fluid according to claim 14, wherein the substituted alkanolamine scale inhibitor comprises hydroxyethylamino-di(methylenephosphonic acid).

17. The treatment fluid according to claim 14, wherein the aqueous base fluid comprises brine, and the brine has a total dissolved solids content of 1 mg / L to 350,000 mg / L.

18. The treatment fluid according to claim 14, wherein the aqueous base fluid is a slickwater fluid, and the aqueous base fluid has a viscosity of 0.5 cP to 20 cP.

19. The treatment fluid according to claim 14, wherein the treatment fluid further comprises a positively charged clay control agent.

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