Breaker fluids including a corrosion inhibitor, and related methods

Abstract

A breaker fluid composition includes water, at least one salt, at least of an acid and an acid precursor, and a corrosion inhibitor comprising a heterocyclic diamine. The heterocyclic diamine may include at least one C2-C30 hydrocarbon radical bonded to one of the nitrogen atoms of the heterocyclic diamine. Relative methods of operating a wellbore and breaker fluid compositions are also disclosed.

Description

TITLEBREAKER FLUIDS INCLUDING A CORROSION INHIBITOR, AND RELATED METHODSCROSS-REFERENCE TO RELATED APPLICATIONS

[0001] This patent application claims priority benefit of United States Provisional Patent Application 63 / 593672 filed October 27, 2023, which is entirely incorporated herein by reference.BACKGROUND OF THE DISCLOSURE

[0002] Wellbore drilling operations includes drilling a bore in a formation to access reservoirs of hydrocarbons and other subsurface resources. During drilling of a wellbore, various fluids may be circulated through a drill pipe and drill bit and into the wellbore and may subsequently flow upward through the wellbore to the surface. For example, a drilling fluid (e.g., an aqueous-based fluid, such as drilling mud) may be pumped down the inside of the drill pipe, through the drill bit, and into the wellbore. The drilling fluid returns to the surface through the annulus. The drilling fluid may lubricated and cool the drill bit and remove generated formation cuttings. Maintaining a sufficiently high viscosity of the drilling fluid may facilitate providing sufficient suspension and removal of cuttings by the drilling fluid.

[0003] Conventionally, the viscosity of the drilling fluid may be increased to facilitate providing sufficient suspension and removal of cuttings by the drilling fluid. The higher temperatures encountered downhole and the presence of ions in the drilling fluid may reduce an effectiveness of the viscosifiers. In addition, the drilling fluid may facilitate formation of a filtercake on surfaces of the formation to reduce or prevent permeation of fluids from entering the surrounding formation.

[0004] After the drilling operation is completed, the filtercake on surfaces of the formation in the wellbore is removed. The filtercake may be broken with various chemistries, depending on the chemistry of the viscosifier from which the filtercake is formed. Some viscosifiers and filtercakes are designed for high temperature applicationsand may be difficult to break, requiring acids and other harsh chemicals that may induce corrosion of wellbore piping and equipment.

[0005] Corrosion may include reaction processes that occur over relatively long periods of time when metals and other materials are exposed to corrosive agents in the surrounding environment. Petroleum, acids, caustics, and other compounds present in injected and produced fluids affect metal tool surfaces and tubing in contact with the fluids, which can lead to damage and failure of downhole equipment. Similarly, equipment used to handle and transport corrosive fluids at the surface and within pipelines may be affected by corrosion. Reactive surfaces are often treated with corrosion inhibitors by coating or emplaced within process streams contacting the surfaces.

[0006] A number of chemical and mechanical methods may be used to inhibit metal corrosion and scale formation that may otherwise impact production efficiency and equipment function. One approach to inhibiting corrosion involves the metered injection of corrosion inhibiting chemicals through chemical injection lines extending from the surface. However, dosage schedules are difficult to calculate and the excessive use of corrosion inhibitors can introduce significant material costs and oversaturation of inhibitors in the produced fluids. In addition, many scale inhibitors degrade or become ineffective even at high concentrations, contributing to the continued growth of scale and corrosion, leading to equipment failure.SUMMARY

[0007] In some embodiments, a breaker fluid composition comprises water, at least one salt, at least one of an acid and an acid precursor, and a corrosion inhibitor comprising a heterocyclic diamine having the following structure:At least one of R1 and R2 comprises a C2-C30 hydrocarbon radical, R3 comprise hydrogen or a C1-C30 hydrocarbon radical, and n is an integer between 1 and 4.

[0008] In some embodiments, a breaker fluid composition comprises brine, a breaker fluid, and a corrosion inhibitor comprising a heterocyclic diamine having the following structure:wherein at least one of R1 and R2 comprises a C2-C30 hydrocarbon radical, R3 comprises hydrogen or a C1-C30 hydrocarbon radical, and n is an integer between 1 and 4.

[0009] In some embodiments, a method of operating a wellbore comprises pumping a breaker fluid composition into a wellbore extending through an earth formation. The breaker fluid composition comprises brine, a breaker fluid, and a corrosion inhibitor comprising a heterocyclic diamine. The method further comprises contacting metal surfaces of wellbore equipment with the breaker fluid composition.

[0010] This summary is provided to introduce a selection of concepts that are further described in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter. Additional features and aspects of embodiments of the disclosure will be set forth herein, and in part will be obvious from the description, or may be learned by the practice of such embodiments.BRIEF DESCRIPTION OF THE DRAWINGS

[0011] In order to describe the manner in which the above-recited and other features of the disclosure can be obtained, a more particular description will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. For better understanding, the like elements have been designated by like reference numbers throughout the various accompanying figures. While some of the drawings may be schematic or exaggerated representations of concepts, at least some of the drawings may be drawn to scale. Understanding that the drawings depict some example embodiments,the embodiments will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

[0012] FIG. 1 is a representation of a drilling system for drilling an earth formation to form a wellbore, according to at least one embodiment of the present disclosure;

[0013] FIG. 2 is a simplified flow diagram illustrating a method 200 of drilling a wellbore, according to at least one embodiment of the disclosure; and

[0014] FIG. 3 is a graphical representation of a corrosion rate for samples of various corrosion inhibitors.DETAILED DESCRIPTION

[0015] This disclosure generally relates to including corrosion inhibitors, systems, and methods of using the corrosion inhibitors for downhole applications, such as breaker fluids for removing (e.g., cleaning) a filtercake from formation surfaces within a wellbore. The breaker fluid composition may include aggressive chemicals (e.g., acids, acid precursors) formulated to break (e.g., degrade) the filtercake to facilitate removal thereof. However, the aggressive chemicals that degrade and remove the filtercake may undesirably corrode wellbore components (e.g., piping, tubing, and equipment). The breaker fluid composition may include the corrosion inhibitors described herein to break and remove the filtercake, while substantially reducing (or preventing) corrosion of the wellbore components.

[0016] The corrosion inhibitor may include a heterocyclic diamine. At least one of the nitrogen atoms of the heterocyclic diamine may be bonded a hydrocarbon radical. The hydrocarbon radical may include a C2-C30 saturated or unsaturated hydrocarbon radical. The corrosion inhibitor may include a reaction product (e.g., a reaction product of an annulation reaction) of a diamine (e.g., an alkyl diamine) and an aldehyde. In some embodiments, the breaker fluid composition further comprises a synergist formulated and configured to improve the performance of the corrosion inhibitor.

[0017] The corrosion inhibitor may be stable at high brine concentrations, and at higher temperatures relative to conventional corrosion inhibitors. The corrosion inhibitors may be used with breaker fluid compositions used at the higher temperatures and brine temperatures. In addition, the corrosion inhibitor may facilitate the use of a breaker fluid composition having a lower pH (and a more aggressive breaker fluid) compared toconventional breaker fluids, since the corrosion inhibitor may substantially protect metal surfaces of wellbore equipment for corrosion. Accordingly, the more aggressive breaker fluid may facilitate degradation of fdtercakes formulated and configured to withstand elevated temperatures and other formation conditions, while reducing (e.g., preventing) the corrosion of wellbore equipment.

[0018] FIG. 1 shows one example of a drilling system 100 for drilling an earth formation 101 to form a wellbore 102. The drilling system 100 includes a drill rig 103 used to turn a drilling tool assembly 104 which extends downward into the wellbore 102. The drilling tool assembly 104 may include a drill string 105, a bottomhole assembly (“BHA”) 106, and a bit 110, attached to the downhole end of drill string 105.

[0019] The drill string 105 may include several joints of drill pipe 108 connected end- to-end through tool joints 109. The drill string 105 transmits drilling fluid through a central bore and transmits rotational power from the drill rig 103 to the BHA 106. In some embodiments, the drill string 105 may further include additional components such as subs, pup joints, etc. The drill pipe 108 provides a hydraulic passage through which drilling fluid is pumped from the surface. The drilling fluid discharges through selected size nozzles, jets, or other orifices in the bit 110 for the purposes of cooling the bit 110 and cutting structures thereon, and for lifting cuttings out of the wellbore 102 as it is being drilled.

[0020] The BHA 106 may include the bit 110 or other components. An example BHA 106 may include additional or other components (e.g., coupled between to the drill string 105 and the bit 110). Examples of additional BHA components include drill collars, stabilizers, measurement-while-drilling (“MWD”) tools, logging-while-drilling (“LWD”) tools, downhole motors, underreamers, section mills, hydraulic disconnects, jars, vibration or dampening tools, other components, or combinations of the foregoing. The BHA 106 may further include a rotary steerable system (RSS). The RSS may include directional drilling tools that change a direction of the bit 110, and thereby the trajectory of the wellbore. At least a portion of the RSS may maintain a geostationary position relative to an absolute reference frame, such as gravity, magnetic north, and / or true north. Using measurements obtained with the geostationary position, the RSS may locate the bit 110, change the course of the bit 110, and direct the directional drilling tools on a projected trajectory.

[0021] In general, the drilling system 100 may include other drilling components and accessories, such as special valves (e.g., kelly cocks, blowout preventers, and safety valves). Additional components included in the drilling system 100 may be considered a part of the drilling tool assembly 104, the drill string 105, or a part of the BHA 106 depending on their locations in the drilling system 100.

[0022] The bit 110 in the BHA 106 may be any type of bit suitable for degrading downhole materials. For instance, the bit 110 may be a drill bit suitable for drilling the earth formation 101. Example types of drill bits used for drilling earth formations are fixed- cutter or drag bits. In other embodiments, the bit 110 may be a mill used for removing metal, composite, elastomer, other materials downhole, or combinations thereof. For instance, the bit 110 may be used with a whipstock to mill into casing 107 lining the wellbore 102. The bit 110 may also be a junk mill used to mill away tools, plugs, cement, other materials within the wellbore 102, or combinations thereof. Swarf or other cuttings formed by use of a mill may be lifted to surface, or may be allowed to fall downhole.

[0023] In some embodiments, during drilling operations, a drilling fluid may be used to facilitate lubrication and cooling of the bit 110 and removal of earth formation 101 cuttings. The drilling fluid may include one or more additives to impart one or more properties on the drilling fluid. For example, the drilling fluid may include a viscosifier formulated and configured to increase a viscosity of the drilling fluid and form a filtercake on walls of the earth formation 101 defining the wellbore 102. In some embodiments, after a drilling operation, a completion operation, or a cleaning operation may be performed to prepare the wellbore 102 for a production operation.

[0024] After the drilling, completion, and / or cleaning operations are complete, the filtercake may be broken to facilitate production of hydrocarbon-containing portions of the earth formation 101. The filtercake may be exposed to a breaker fluid composition including a breaker fluid formulated and configured to degrade the filtercake. For example, exposure of the filtercake to the breaker fluid may degrade the constituents of the filtercake. The breaker fluid may be circulated in the wellbore 102 to degrade and remove the filtercake. The breaker fluid may be circulated before, during, or after a completion operation has commenced to destroy the integrity of and clean up residual drilling fluids remaining inside the casing 107 and / or liners. The breaker fluid may contribute to thedegradation and removal of the filtercake deposited on the sidewalls of the wellbore to reduce the likelihood of the filtercake negatively impacting production. After removal of the filtercake and cleaning of the wellbore 102, the wellbore 102 may be converted to production.

[0025] In addition to the breaker fluid, the breaker fluid composition may include one or more corrosion inhibitors formulated to reduce corrosion of wellbore components exposed to the breaker fluid composition. The breaker fluid composition may include a base fluid, a breaker fluid, the one or more corrosion inhibitors, and one or more additives (e.g., surfactants, solvents, chelating agents (e.g., chelating agent solutions (CAS)), and oxidizers). The breaker fluid may be dispersed within the breaker fluid composition (e.g., within the base fluid).

[0026] The base fluid of the breaker fluid composition may include an aqueous material, such as water or brine; or the base fluid may include an oleaginous or oil-based fluid. The brine may include water and at least one of one or more organic salts or one or more inorganic salts dispersed in the water. The salt may be selected based on a desired density of the breaker fluid composition (e.g., to balance downhole formation pressures). The base fluid may include sea water, brine, or a salt-containing aqueous solution. By way of non-limiting example, the base fluid may include a brine including water and one or more salts (e g., one or more organic salts and / or one or more inorganic salts). The one or more salts may provide a desired density to the breaker fluid composition and may also reduce the effect of the breaker fluid composition on hydratable clays and shales of the earth formation 101. In some embodiments, the weight percent of the salt may be greater than the weight percent of the water in the base fluid. In other embodiments, the weight percent of the salt is less than the weight percent of the water in the base fluid.

[0027] In other embodiments, the base fluid comprises an oleaginous or oil-based fluid and may include a natural or synthetic oil. The oleaginous or oil-based fluid may include salt. In some embodiments the oleaginous fluid is selected from the group consisting of at least one of diesel oil, mineral oil, a synthetic oil, (e.g., hydrogenated and unhydrogenated olefins including polyalpha olefins, linear and branched olefins) polydiorganosiloxanes, siloxanes, organosiloxanes, and esters of fatty acids (e.g., straight chained, branched and cyclical alkyl ethers of fatty acids).

[0028] The salts (of the aqueous material or the oleaginous or oil-based fluid) may include salts of one or more of sodium, calcium, aluminum, magnesium, zinc, potassium, strontium, and lithium, and salts of one or more of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, phosphates, sulfates, silicates, and fluorides. In some embodiments, the salt comprises a divalent halide, such as an alkaline earth halide (e.g., calcium chloride (CaCh), calcium bromide (CaBr?)), zinc bromide (ZnB ), or a zinc halide. The salt may include cesium formate (HCOOR), sodium bromide (NaBr), potassium bromide (KBr), and cesium bromide (CsBr). The particular composition of the salt may be selected based on compatibility with the earth formation 101 and / or to match the brine phase of the completion fluid.

[0029] In some embodiments, the water may constitute from about 5.0 volume percent to about 30.0 volume percent of the breaker fluid composition, such as form about 5.0 volume percent to about 10.0 volume percent, from about 10.0 volume percent to about 20.0 volume percent, or from about 20.0 volume percent to about 30.0 volume percent of the breaker fluid composition. The salt may constitute from about 30.0 volume percent to about 60.0 volume percent of the breaker fluid composition, such as from about 30.0 volume percent to about 40.0 volume percent, from about 40.0 to about 50.0 volume percent, or from about 50.0 volume percent to about 60.0 volume percent of the breaker fluid composition.

[0030] The breaker fluid may be formulated and configured to break long-chain molecules of the filtercake, and to reduce a viscosity of drilling fluids remaining in the wellbore 102. The breaker fluid may include one or more of acids, acid precursors, and enzymes. In some embodiments the breaker fluid comprises an acid. The acid may include one or more of a strong mineral acid (e.g., hydrochloric acid, sulfuric acid), organic acids (e.g., citric acid, salicylic acid, lactic acid, malic acid, maleic acid, acetic acid, formic acid, glycolic acid, fumaric acid, and homo- or copolymers of lactic acid and glycolic acid. In some embodiments, the acid may be circulated with the breaker fluid composition. In some embodiments, an acid wash (including one or more acids) may be circulated within the wellbore 102 to at least partially dissolve some of the filtercake remaining on the wellbore 102 walls. In some embodiments, the breaker fluid comprises an acid precursor. The acid precursors may include hydrolysable esters of one or more organic acids, such as organicacids that may hydrolyze to release an acid (e.g., an organic acid or an inorganic acid), such as one or more of the acids described above. The hydrolysable esters may include a hydrolysable ester of carboxylic acid, a hydrolysable phosphonic ester, or a hydrolysable sulfonic ester. By way of non-limiting example, the hydrolysable esters of carboxylic acid may include one or more of a Ci to a Ce carboxylic acid, a C3 to Cs of a dicarboxylic acid, and a C2 to C30 mono- or poly-alcohol (including alkyl orthoesters). In some embodiments, the hydrolysable esters include about 57 weight percent to about 67 weight percent dimethyl glutarate, about 18 weight percent to about 28 weight percent dimethyl succinate, and 8 weight percent to about 22 weight percent dimethyl adipate. In some embodiments, the breaker fluid includes one or more acids and one or more hydrolysable esters.

[0031] The breaker fluid (e.g., at least one of the acid and the acid precursor) may constitute from about 5.0 volume percent to about 40.0 volume percent of the breaker fluid composition, such as from about 10.0 volume percent to about 20.0 volume percent, from about 20.0 volume percent to about 30.0 volume percent, or from about 30.0 volume percent to about 40.0 volume percent of the breaker fluid composition. In some embodiments, the breaker fluid constitutes within a range of from about 5.0 volume percent to about 20.0 volume percent of the breaker fluid composition, such as from about 5.0 volume percent to about 10.0 volume percent, from about 10.0 volume percent to about 15.0 volume percent, or from about 15.0 volume percent to about 20.0 volume percent of the breaker fluid composition. However, the disclosure is not so limited, and the breaker fluid composition may include a different volume percent of the breaker fluid (e.g., the acid and / or the acid precursor). In some embodiments, the breaker fluid reduces the pH of the breaker fluid composition. For example, the pH of the breaker fluid composition may be less than about 5.0, such as less than about 4.0, less than about 3.0, less than about 2.0, less than about 1.5, or less than about 1.0. In some embodiments, the pH of the breaker fluid composition is less than about 2.0.

[0032] The breaker fluid composition may further comprise an oxidizer (also referred to as an “oxidant”) formulated and configured to react with a polymer and disrupt the filtercake. The oxidizer may include one or more of THBP, bromates, peroxides (including peroxide adducts), other compounds including a peroxy bond such as persulfates (e.g., ammonium persulfate), perborates, percarbonates, perphosphates, and persilicates, andother oxidizers such as hypochlorites. In some embodiments, the oxidizer comprises one or more of R1H2PO3, RJR2HPO3, R^R’PCh, R1HSO3, RJR2SO3, R1H2PO4, R^HPCU, R'R2R3PO4, R1HSO4, or R’R2SO4, where R1, R2, and R3are C2to C3o alkyl-, aryl-, arylalkyl-, or alkylaryl-groups.

[0033] The oxidizer may constitute from about 1.0 volume percent to about 5.0 volume percent of the breaker fluid composition, such as from about 1.0 volume percent to about 3.0 volume percent, or from about 3.0 volume percent to about 5.0 volume percent of the breaker fluid composition. However, the disclosure is not so limited, and the volume percent of the oxidizer in the breaker fluid composition may be different than those described.

[0034] The breaker fluid composition may include one or more chelating agents, such as one or more of polydentate chelating agents. The chelating agents may include one or more of ethylenediaminetetraacetic acid (EDTA), glutamic acid diacetic acid (GLDA) (such as L-glutamic acid, N, N-diacetic acid), iminodiacetic acids, diethylenetriaminepentaacetic acid (DTP A), nitrilotri acetic acid (NTA), ethylene glycol- bis(2-aminoethyl)-N,N,N',N'-tetraacetic acid (EGTA), l,2-bis(o-aminophenoxy)ethane- N,N,N',N'-tetraaceticacid (BAPTA), cyclohexanediamine tetraacetic acid (CDTA), triethylene tetraaminehexaacetic acid (TTHA), N-(2-Hydroxyethyl)ethylenediamine- N,N',N'-triacetic acid (HEDTA), glutamic-N, N-diacetic acid (GLDA), ethylene-diamine tetra-methylene sulfonic acid (EDTMS), diethylene-triamine penta-methylene sulfonic acid (DETPMS), amino tri-methylene sulfonic acid (ATMS), ethylene-diamine tetramethylene phosphonic acid (EDTMP), diethylene-triamine penta-methylene phosphonic acid (DETPMP), amino tri-methylene phosphonic acid (ATMP), potassium and / or sodium salts thereof, and mixtures thereof.

[0035] The chelating agent may constitute from about 5.0 volume percent to about 20.0 volume percent of the breaker fluid composition, such as from about 5.0 volume percent to about 10.0 volume percent, from about 10.0 volume percent to about 15.0 volume percent, or from about 15.0 volume percent to about 20.0 volume percent of the breaker fluid composition.

[0036] In some embodiments, the breaker fluid composition includes one or more solvents. The one or more solvents may include, for example, alcohols, such as linear orbranched alcohols such as isopropanol, methanol, glycerol, or glycols; glycol ethers such as 2-methoxyethanol, 2-propoxyethanol, 2-ethoxyethanol, diethylene glycol monoethyl ether, dipropylene glycol monomethyl ether, tripropylene glycol monomethyl ether, ethylene glycol monobutyl ether, ethylene glycol dibutyl ether, diethylene glycol monoethyl ether, di ethyleneglycol monomethyl ether, tripropylene butyl ether, dipropylene glycol butyl ether, diethylene glycol butyl ether, butylcarbitol, dipropylene glycol methyl ether, propylene glycol n-propyl ether, propylene glycol t-butyl ether, ether; pyrrolidones, and various esters, such as ethyl lactate, propylene carbonate, butylene carbonate.

[0037] The solvent may constitute from about 10.0 volume percent to about 30.0 volume percent of the breaker fluid composition, such as from about 10.0 volume percent to about 20.0 volume percent, or from about 20.0 volume percent to about 30.0 volume percent of the breaker fluid composition.

[0038] As described above, the breaker fluid composition may include one or more corrosion inhibitors dispersed therein. The corrosion inhibitor may include one or more heterocyclic diamines formulated and configured to reduce corrosion of metals at high temperature high pressure (HTHP) conditions, such as metals encountered in the wellbore 102 or in similar environments in which corrosive fluids (e.g., liquids) and gases are present. The corrosion inhibitor may exhibit surfactant and electrostatic properties configured to facilitate film formation on metal surfaces at temperatures encountered in the wellbore 102 (e g., temperatures up to at least about 150°C).

[0039] The corrosion inhibitor may be formulated and configured to form a hydrophobic barrier film on metal surfaces of the wellbore equipment through physisorption and / or chemisorption. The hydrophobic barrier film any isolate metal surfaces from corrosive materials, such as the breaker fluid (e.g., acids, acids formed from hydrolyzed acid precursors), in the wellbore 102.

[0040] The heterocyclic diamine corrosion inhibitor may have a general structure as shown in structure (I) below, wherein R1 and R2 are independently selected from hydrogen and a C2-C30 hydrocarbon radical (e.g., a natural hydrocarbon radical, or an unsaturated hydrocarbon radical), with the proviso that at least one of R1 and R2 is not hydrogen; R3 is hydrogen or a C2-C30 hydrocarbon radical; and n is an integer between 1 and 4. In some embodiments, at least one of R1 and R2 comprises a C1-C30 saturated or unsaturated,aromatic or non-aromatic hydrocarbon radical. In some embodiments, R3 is a saturated hydrocarbon radical and may be aromatic or non-aromatic. In other embodiments, R3 is an unsaturated hydrocarbon radical and may be aromatic or non-aromatic.

[0041] As described above, at least one of R1 and R2 includes a C2-C30 saturated or unsaturated hydrocarbon radical. In some embodiments, one of R1 and R2 comprises a C2- C30 hydrocarbon radical, and the other of R1 and R2 comprises hydrogen. In some embodiments, one of R1 and R2 includes hydrogen. In other embodiments, both of R1 and R2 include a C2-C30 saturated or unsaturated hydrocarbon radical, which may be the same C2-C30 saturated or unsaturated hydrocarbon radical or a different C2-C30 saturated or unsaturated hydrocarbon radical. In some embodiments, n is equal to 1, such that the heterocyclic diamine comprises a six-ringed structure.

[0042] In some embodiments, the heterocyclic diamine corrosion inhibitor comprises a reaction product of at least one alkyl diamine and at least one aldehyde. The heterocyclic diamine corrosion inhibitor may be formed by an annulation reaction of at least one alkyl diamine and at least one aldehyde. The alkyl diamine may have formula (II) below, wherein n is an integer between 3 and 6, and R4 and R5 independently comprise hydrogen (H) or a C2-C30 saturated or unsaturated, aromatic or non-aromatic hydrocarbon radical such as one or more of an alkyl, an alkylene, an alkynyl, or another hydrocarbon radical group. In some embodiments, one or both of R4 and R5 include between 12 carbon atoms and 14 carbon atoms.R4NH(CH2)nNHR5, (II).

[0043] By way of non-limiting example, the reaction of the alkyl diamine and the aldehyde may proceed according to the reaction scheme (III) below for a given alkyl diamine and a given aldehyde. As shown in the reaction scheme, the alkyl diamine and thealdehyde undergo an annulation reaction wherein a new ring structure is formed from the alkyl diamine and the aldehyde group is attached to the new ring structure. In some embodiments, R1 and R2 in structure (I) above correspond to R4 and R5 in formula (II), and R3 in structure (I) corresponds to the aldehyde.

[0044] The alkyl diamine may include one or more of an N-substituted diamine having a straight chain or a branched alkyl or alkenyl substituent. In some embodiments, at least one of the amine groups is substituted with a group (e.g., other than hydrogen). In some embodiments, both of the amine groups are substituted. The substituent may be a straight chained substituent or a branched alkyl or alkenyl substituent and may include, for example, one or more of n-propyl, n-butyl, n-pentyl, n-hexyl, n-heptyl, n-octyl, 2- ethylhexyl, n- and iso-nonyl, n- and iso-decyl, n-undecyl, n-dodecyl, n-tetradecyl, n- hexadecyl, n-octadecyl, oleyl, linoleyl, and linolenyl groups. In some embodiments, the alkyl diamine includes N-coco-l,3-diaminopropane (e.g., a C12-C14 propylene diamine, coco-propylene diamine, N-oleyl-l,3-propanediamine,). In some embodiments, the alkyl diamine includes tallow diamine (e.g., a Ci8 diamine) (N-tallow-l,3-diaminopropane; also referred to as N-tallowalkyl-l,3-propanediamine). In some such embodiments, the tallow may include a fatty acid complex formed from palmitic acid, stearic acid, myristic acid, oleic acid, linoleic acid, and linolenic acid.

[0045] The aldehyde may include one or more aldehydes that include, for example formaldehyde and C1-C30 saturated or unsaturated, aromatic or non-aromatic hydrocarbon radicals such as 2-hydroxynapthaldehyde, 7-phenyl-2,4,6-heptatrienal, crotonaldehyde, 2-hexenal, 2-heptenal, 2-octenal, 2-nonenal, 2-decenal, 2-undecenal, 2-dodecenal, 2,4- hexadienal, 2,4-heptadienal, 2,4-octadienal, 2,4-nonadienal, 2,4-decadienal, 2,4-undecadienal, 2,4-dodecadienal, 2,6-dodecadienal, 3,7-dimethylocta-2,6-dienal (also referred to as citral), l-formyl-[2-(2-methylvinyl)]-2-n-octylethylene, cinnamaldehyde, dicinnamaldehyde, p-hydroxycinnamaldehyde, p-methyl cinnamaldehyde, p- ethylcinnamaldehyde, p-methoxy cinnamaldehyde, p-dimethylaminocinnamaldehyde, p-diethylaminocinnamaldehyde, p-nitrocinnamaldehyde, o-nitrocinnamaldehyde, o-allyloxycinnamaldehyde, 4-(3-propenal)cinnamaldehyde, p-sodium sulfocinnamaldehyde, p-trimethyl ammoniumcinnamaldehyde sulfate, p-trimethylammoniumcinnamaldehyde o-methyl sulfate, p-thiocyanocinnamaldehyde, p-(S-acetyl)thiocinnamaldehyde, p-(S — N,N-dimethylcarbamoylthio)cinnamaldehyde, p-chlorocinnamaldehyde, 5-phenyl-2,4-pentadienal,5-(p-methoxyphenyl)-2,4-pentadienal, 2,3-diphenylacrolein, 3,3-diphenyl acrolein, a-methyl cinnamaldehyde, P-methylcinnamaldehyde, a-chlorocinnamaldehyde, a-bromocinnamaldehyde, a-butylcinnamaldehyde, a-amylcinnamaldehyde, a-hexylcinnamaldehyde, 2-(p-methylbenzylidine)decanal, a-bromo-p-cyanocinnamaldehyde, a-ethyl-p-methylcinnamaldehyde, p-methyl-a-pentyl cinnamaldehyde, 3, 4-dimethoxy-a-methyl cinnamaldehyde, a-[(4-methylphenyl)methylene]benzeneacetaldehyde, u-(hydroxymethylene)-4-methylbenzylacetaldehyde, 4-chloro-a-(hydroxymethylene)benzeneacetaldehyde, a-nonylidenebenzeneacetaldehyde, or another aldehyde. In some embodiments, the aldehyde includes one or more of citral, cinnamaldehyde, and hexyl cinnamaldehyde.

[0046] The aldehyde may also include heteroaromatic substituted aldehydes such as pyridine-2-carboxaldehyde, pyridine-4-carboxaldehyde, alkylpyridinium aldehyde derivatives, and furfuraldehydes. In some embodiments, the aldehydes include aldoses, glyceraldehydes, pentoses, and / or hexoses. In some embodiments, the aldehyde component may be generated from an aldehyde precursor such as paraformaldehyde, acetal, or another precursor.

[0047] Without being bound by any particular theory, the heterocyclic diamine corrosion inhibitor may undergo ring opening reactions at elevated temperatures, releasing carbon monoxide that reacts with metal surfaces, enhancing the corrosion resistance imparted by the corrosion inhibitor. In some embodiments, the aldehyde component maybe a non-enolizable aldehyde (e.g., an aldehyde that does not include alpha hydrogens), which generates a stable radical following the ring opening and carbon monoxide forming reaction.

[0048] A molar ratio of the alkyl diamine to the aldehyde may be about 1.0: 1.0, since the reaction between the alkyl diamine and the aldehyde may be a condensation reaction to form the heterocyclic diamine corrosion inhibitor.

[0049] In some embodiments, the corrosion inhibitor includes an alkoxylated (e.g., an ethoxylated and / or a propoxylated) heterocyclic diamine, which heterocyclic diamine may comprise a reaction product of at least one alkyl diamine and the at least one aldehyde. In other words, the reaction product of the at least one alkyl diamine and the at least one aldehyde may be ethoxylated, propoxylated, or both. Without being bound by any particular theory, in some embodiments, alkoxylating the heterocyclic diamine may facilitate improved dispersion of the heterocyclic diamine in the breaker fluid composition (e.g., in the base fluid).

[0050] In some embodiments, the corrosion inhibitor may include a heterocyclic diamine having structure (I) above, and one of R1 and R2 includes hydrogen, such that the heterocyclic diamine includes a secondary amine (e.g., a -NH- bridge). The heterocyclic diamine may be alkoxylated, such as by exposing the heterocyclic diamine to an epoxide, such as ethylene oxide, propylene oxide, 1,2-epoxybutane, or another epoxide. Responsive to exposure to the epoxide, the heterocyclic diamine may be alkoxylated. The secondary amine may group may react with the epoxide to form an alkoxylated heterocyclic diamine. The ethoxylated heterocyclic diamine may have the same structure as structure (I) above, except that at least one of R1 and R2 may include an -(OC2H4)n-OH group bonded to the respective nitrogen atom of the heterocyclic diamine. In some embodiments, one of R1 and R2 includes one or more alkoxy groups (e.g., ethoxy groups, propoxy groups) bonded to the nitrogen atom and the other of R1 and R2 includes an alkyl radical. For example, in some embodiments, R1 comprises an alkyl radical from the alkyl diamine and R2 comprises one or more ethoxy groups (i.e., -(A^F -fOCsF Jn-OH) and / or propoxy (i.e., -C3H6-(OC3He)n-OH groups), wherein n is an integer, such as within a range of 1 to 20, such as from 1 to 4, from 4 to 8, from 8 to 12, or from 12 to 20). As only one non-limiting example, where the heterocyclic diamine comprises a reaction product of an alkyl diamine,and an aldehyde comprising a cinnamaldehyde, and is ethoxylated, the ethoxylated heterocyclic diamine may have the structure illustrated in structure (IV) below. In some embodiments, the alkoxylation of the heterocyclic diamine may facilitate improved dispersion of the corrosion inhibitor in the drilling fluid.

[0051] In some embodiments, the alkoxylated heterocyclic diamine includes an ethoxylated heterocyclic diamine (as illustrated in Structure (IV) above). In some embodiments, the alkoxylated heterocyclic diamine includes a propoxylated heterocyclic diamine.

[0052] In some embodiments, the corrosion inhibitor may further include a synergist formulated and configured to increase the corrosion inhibition of the corrosion inhibitor. The synergist may include one or more of mercaptoethanol, mercaptopropanol, l-mercapto-2-propanol, 2-mercaptobutanol; di- or poly-mercapto organic compounds such as di-mercapto derivatives of thiophene, pyrrole, furane, diazoles, and thiadiazoles; di- and tri-mercapto derivatives of pyridine, diazines, triazines benzimidazole, benzthiazole, thioglycolic acid, and potassium iodide. In some embodiments, the synergist comprises a mercaptan, such as a mercaptanol (e.g., mercaptoethanol).

[0053] The synergist may constitute from about 0.5 weight percent to about 7.5 weight percent of the corrosion inhibitor, such as from about 0.5 weight percent to about 1.0 weight percent, from about 1 .0 weight percent to about 2.0 weight percent, from about 2.0 weight percent to about 4.0 weight percent, or from about 4.0 weight percent to about 7.5 weight percent of the corrosion inhibitor.

[0054] A volume percent of the corrosion inhibitor in the breaker fluid composition may be within a range of from about 0.1 volume percent to about 4.0 volume percent, such as from about 0.1 volume percent to about 0.2 volume percent, from about 0.2 volume percent to about 0.5 volume percent, from about 0.5 volume percent to about 1.0 volume percent, from about 1.0 volume percent to about 2.0 volume percent, or from about 2.0 volume percent to about 4.0 volume percent. However, the disclosure is not so limited, and the volume percent of the corrosion inhibitor in the breaker fluid composition may be different than those described.

[0055] A weight percent of the corrosion inhibitor in the breaker fluid composition may be within a range of from about 0.05 weight percent to about 2.0 weight percent of the breaker fluid composition, such as from about 0.05 weight percent to about 0.1 weight percent, from about 0.1 weight percent to about 0.25 weight percent, from about 0.25 weight percent to about 0.5 weight percent, from about 0.5 weight percent to about 1.0 weight percent, or from about 1.0 weight percent to about 2.0 weight percent. However, the disclosure is not so limited, and the weight percent of the corrosion inhibitor in the breaker fluid composition may be different than those described.

[0056] FIG. 2 is a simplified flow diagram illustrating a method 200 of operating a wellbore, according to at least one embodiment of the disclosure. The method 200 includes pumping a breaker fluid composition comprising a corrosion inhibitor into an earth formation, as shown at act 202. The breaker fluid composition may include one or more of the breaker fluid compositions described above and may include one or more of the corrosion inhibitors described above.

[0057] The method 200 may further include circulating the breaker fluid composition in the wellbore and breaking a filtercake in the wellbore, as shown at act 204. Responsive to exposure to the breaker fluid, the filtercake may be degraded, facilitating removal of the filtercake as the breaker fluid is circulated through the wellbore. For example, acids (and acids formed from acid precursors) may react with calcium carbonate and other components of the filtercake, to facilitate degradation of the filtercake.

[0058] The method 200 may further include contacting metal surfaces within the wellbore with the corrosion inhibitor of the breaker fluid composition, as shown in act 206. Circulating the breaker fluid composition in the wellbore may include coating metalsurfaces within the wellbore with the corrosion inhibitor present in the breaker fluid composition. In some embodiments, the coating comprises a hydrophobic coating configured to repel acids and other hydrophilic components of a breaker fluid, facilitating the corrosion inhibition properties of the corrosion inhibitor.

[0059] In one or more embodiments, the corrosion inhibitor includes organic compounds having a general structure that includes a polar heterocyclic head group containing electron-rich heteroatoms, and a hydrophobic tail group composed of a saturated or unsaturated hydrocarbon chain. Without being bound by any particular theory, it is believed that a polar heterocyclic head group of the corrosion inhibitor interacts with the metal surface, anchoring the corrosion inhibitor molecule to the metal, while a hydrophobic tail forms the hydrophobic film through hydrophobic interactions with neighboring inhibitor molecules.

[0060] The corrosion inhibitors and the breaker fluid compositions including the corrosion inhibitors may be suitable for use in HTHP wellbores. In some embodiments, filtercakes formed for HTHP wellbores may be formulated to remain stable at high temperatures and may be more difficult to break (e.g., remove) than conventional filtercakes. In some embodiments, the corrosion inhibitor of the breaker fluid composition facilitates breaking such filtercakes with breaker fluid compositions having a relatively lower pH (e.g., more acidic breaker fluid compositions (e.g., including at least one of acids and acid precursors)) than conventional breaker fluids while protecting metal surfaces of wellbore equipment in the wellbore from corrosion due to the presence of the corrosion inhibitor in the breaker fluid composition.

[0061] In some embodiments, the corrosion inhibitor may form a film on metal surface of wellbore equipment and may be configured to inhibit corrosion and scale formation in high temperature applications, such as applications greater than about 150°C. The stability of the corrosion inhibitor in the wellbore may facilitate increasing treatment duration and reducing the effective concentration of the corrosion inhibitor in the breaker fluid composition. The formation of the surface films may facilitate sustained corrosion inhibition and maintenance of active concentration of levels of the corrosion inhibitor during circulation of the breaker fluid composition. By way of comparison, conventional corrosion inhibitors may exhibit a relatively higher solubility in media surrounding thewellbore and are susceptible to various degradation processes, leading to a breakdown of the protective film on metal surfaces. For example, elevated temperatures may cause conventional corrosion inhibitors to be hydrolyzed and may also increase the solubility of the corrosion inhibitor in solution, reducing the effectiveness of the corrosion inhibitor.EXAMPLESExample 1

[0062] A series of diamines were assayed for corrosion inhibition performance by observing corrosion on steel coupons placed in a brine solution with a selected corrosion inhibitor. Acyclic diamine like N-tallowalkyl- 1,3 -propanediamine was assayed alongside various heterocyclic diamines. Heterocyclic diamines in accordance with the present disclosure were prepared from a reaction of a diamine and formaldehyde to generate hexahydropyrimidine with a pendant alkyl chain having the general structure (I) discussed above. El is a diamine in which R1 is a mixture of alkyl chains derived a tallow fatty acid complex containing 26% palmitic acid, 14% stearic acid, 3% myristic, 47% oleic acid, 3% linoleic, and 1% linolenic; and R2 and R3 are hydrogen. For E2-E6, pendant chains R1 were derived from tallow fatty acid, while R2 is independently various lengths of oligomerized ethylene oxide (6-14 repeats), and R3 is hydrogen for all samples.

[0063] Corrosion inhibitor samples were dispersed in a brine medium and steel coupons were submerged therein. The samples were then placed in an autoclave at 150°C for 48 hours. The conditions for autoclave testing of samples are summarized below in Table 1.

[0064] Results are plotted in the bar chart depicted in FIG. 3. The results indicate that samples E2-E6, containing oligomers of ethylene oxide, exhibited higher rates of corrosioncompared to acyclic diamine N-tallowalkyl-l ,3-propanediamineand heterocyclic diamine El. Corrosion was also characterized by the formation of a dark siderite scale.Example 2

[0065] Metal coupons were treated with N-tallowalkyl-l,3-propanediamine and the heterocyclic diamine El of Example 1, but with the introduction of an added oil phase to simulate field conditions. Similar to the results in Example 1, siderite scale was formed on the metal coupons. Samples were formulated as shown in Table 2, where the balance of the inhibitor composition was ethylene glycol monobutyl ether (EGMBE).

[0066] To characterize the durability of the developed scale, sample coupons were treated to remove siderite scale that accumulated during testing. Following aging, samples were removed from the autoclave and treated with Clarke’s solution (e.g., a mixture of hydrochloric acid and di-n-butyl thiourea), to remove surface scaling. Samples were soaked in Clarke’s solution for 75 minutes to remove siderite scale. The results are given in Table 2.

[0067] In all cases, the comparative acyclic amine N-tallowalkyl-l,3-propanediamineexhibited a tendency to form a tightly adhered siderite scale on their surfaces that was extremely difficult to remove. Heterocyclic diamine samples exhibited some siderite scale, but the scale was considerably less dense and easier to remove from the metal surface when compared to the acyclic samples.

[0068] The negative corrosion rates (denoted with *) with N-tallowalkyl-l,3-propanediamineare due to the buildup of siderite corrosion products on the test specimen surfaces, which could not be removed post-processing, resulting in a net weight gain. The performance of heterocyclic diamine El under similar conditions givescorrosion rates <8 mils per year (MPY) with siderite that could be removed by processing with Clarke’s solution.Example 3

[0069] Further testing was performed to confirm the performance of heterocyclic diamine El in a bi-phasic system of 3% sodium chloride brines and an oil phase under substantially the same conditions in Example 1 as applied to coupons prepared from C1018 carbon steel. The results are shown in Table 3.Example 4

[0070] The effect of the brine salinity (total dissolved solids, TDS) on the high temperature performance of heterocyclic diamine in various concentration so sodium chloride brine (10, 15, 25% NaCl) was tested. Testing conditions were substantially the same as those in Example 1 and the results are shown in Table 4.

[0071] It therefore appears that heterocyclic diamine El functions well over wide ranging brine salinities with arguably a slight drop in performance at the higher total dissolved solids (TDS) conditions.Example 5

[0072] El has shown continued performance at 150°C over a range of brine salinities. Testing was performed under the same conditions as Example 1, but the test temperature was increased to 175°C in a bi-phasic system at two different dose rates of 500 ppm and 1000 ppm. Given that siderite scale often exhibits a decreased solubility with increasing temperatures, exposure to Clarke’s solution was recorded at 30 and 60 minutes. Results are shown in Table 5.

[0073] After exposure to Clarke’s solution, it appears from the corrosion rate data that 500 ppm El appears better than 1000 ppm, however this is related to scale formation on the surface. After a 60 minute exposure to Clarke’s solution, the corrosion rates of the 500 ppm and 1000 ppm tests converge and are very similar in magnitude at about 11-12 MPY.

[0074] Heterocyclic diamine corrosion inhibitors in accordance with the present disclosure effectively reduce, prevent, and / or inhibit the formation of corrosion on metal materials and equipment, such as metal piping and flow lines that are used in various wellbore operations. Corrosion inhibitors in accordance with the present disclosure may be applied to metal surfaces by injection downhole, spraying, dipping and the like.

[0075] In some embodiments, corrosion inhibitors may be added to a process stream that contacts a metal surface, covering and maintaining an effective application on the surface. Process streams may include a number of components, including water, petroleum, petroleum products, hydrocarbons, and acidic species such as CO2 and H2S, and salts such as NaCl. Introduction of a corrosion inhibitor to a process stream may include injection of the corrosion inhibitor composition into a process stream at various intervals along a pipeline, well, or other conduit.

[0076] The embodiments of corrosion inhibitors and breaker fluid compositions including the corrosion inhibitors have been primarily described with reference to wellbore operations (e.g., wellbore drilling, completion, cleaning, and production operations); the corrosion inhibitors and breaker fluid compositions including the corrosion inhibitors described herein may be used in applications other than the operation of a wellbore. In other embodiments, corrosion inhibitors and breaker fluid compositions including the corrosion inhibitors according to the present disclosure may be used outside a wellbore or other downhole environment used for the exploration or production of natural resources. For instance, the corrosion inhibitors and breaker fluid compositions including the corrosion inhibitors of the present disclosure may be used in a borehole used for placement of utility lines. Accordingly, the terms “wellbore,” “borehole” and the like should not be interpreted to limit tools, systems, assemblies, or methods of the present disclosure to any particular industry, field, or environment.

[0077] One or more specific embodiments of the present disclosure are described herein. These described embodiments are examples of the presently disclosed techniques. Additionally, in an effort to provide a concise description of these embodiments, not all features of an actual embodiment may be described in the specification. It should be appreciated that in the development of any such actual implementation, as in any engineering or design project, numerous embodiment-specific decisions will be made to achieve the developers’ specific goals, such as compliance with system -related and business-related constraints, which may vary from one embodiment to another. Moreover, it should be appreciated that such a development effort might be complex and time consuming, but would nevertheless be a routine undertaking of design, fabrication, and manufacture for those of ordinary skill having the benefit of this disclosure.

[0078] Additionally, it should be understood that references to “one embodiment” or “an embodiment” of the present disclosure are not intended to be interpreted as excluding the existence of additional embodiments that also incorporate the recited features. For example, any element described in relation to an embodiment herein may be combinable with any element of any other embodiment described herein. Numbers, percentages, ratios, or other values stated herein are intended to include that value, and also other values that are “about” or “approximately” the stated value, as would be appreciated by one of ordinaryskill in the art encompassed by embodiments of the present disclosure. A stated value should therefore be interpreted broadly enough to encompass values that are at least close enough to the stated value to perform a desired function or achieve a desired result. The stated values include at least the variation to be expected in a suitable manufacturing or production process, and may include values that are within 5%, within 1%, within 0.1%, or within 0.01% of a stated value.

[0079] A person having ordinary skill in the art should realize in view of the present disclosure that equivalent constructions do not depart from the spirit and scope of the present disclosure, and that various changes, substitutions, and alterations may be made to embodiments disclosed herein without departing from the spirit and scope of the present disclosure. Equivalent constructions, including functional “means-plus-function” clauses are intended to cover the structures described herein as performing the recited function, including both structural equivalents that operate in the same manner, and equivalent structures that provide the same function. It is the express intention of the applicant not to invoke means-plus-function or other functional claiming for any claim except for those in which the words ‘means for’ appear together with an associated function. Each addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.

[0080] The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that is within standard manufacturing or process tolerances, or which still performs a desired function or achieves a desired result. For example, the terms “approximately,” “about,” and “substantially” may refer to an amount that is within less than 5% of, within less than 1% of, within less than 0.1% of, and within less than 0.01% of a stated amount. Further, it should be understood that any directions or reference frames in the preceding description are merely relative directions or movements. For example, any references to “up” and “down” or “above” or “below” are merely descriptive of the relative position or movement of the related elements.

[0081] The present disclosure may be embodied in other specific forms without departing from its spirit or characteristics. The described embodiments are to be considered as illustrative and not restrictive. The scope of the disclosure is, therefore, indicated by theappended claims rather than by the foregoing description. Changes that come within the meaning and range of equivalency of the claims are to be embraced within their scope.

Claims

CLAIMSWhat is claimed is:

1. A breaker fluid composition, comprising: water; at least one salt; at least one of an acid and an acid precursor; and a corrosion inhibitor comprising a heterocyclic diamine having the following structure:wherein at least one of R1 and R2 comprises a C2-C30 hydrocarbon radical, R3 comprises hydrogen or a C1-C30 hydrocarbon radical, and n is an integer between 1 and 4.

2. The breaker fluid composition of claim 1, wherein the other of R1 and R2 is hydrogen.

3. The breaker fluid composition of claim 1, wherein R3 comprises a C1-C30 saturated hydrocarbon radical.

4. The breaker fluid composition of claim 1, wherein the at least one of R1 and R2 comprises one or more ethoxy groups.

5. The breaker fluid composition of claim 1, wherein n is 1.

6. The breaker fluid composition of claim 1, wherein the breaker fluid composition has a pH less than about 3.0.

7. The breaker fluid composition of claim 1, wherein the at least one of the acid and the acid precursor constitutes from about 10 volume percent to about 40 volume percent of the breaker fluid composition.

8. The breaker fluid composition of claim 1, wherein the at least one salt comprises zinc bromide.

9. The breaker fluid composition of claim 1, wherein the corrosion inhibitor constitutes from about 0.1 volume percent to about 4.0 volume percent of the breaker fluid composition.

10. The breaker fluid composition of claim 1, wherein the corrosion inhibitor comprises a reaction product of cinnamaldehyde and coco-propylene diamine.

11. The breaker fluid composition of claim 1, further comprising a synergist.

12. The breaker fluid composition of claim 11, wherein the synergist comprises a mercaptan.

13. A method of operating a wellbore, the method comprising: pumping a breaker fluid composition into a wellbore extending through an earth formation, the breaker fluid composition comprising: brine; a breaker fluid; and a corrosion inhibitor comprising a heterocyclic diamine; and contacting metal surfaces of wellbore equipment with the breaker fluid composition.

14. The method of claim 13, wherein pumping a breaker fluid composition into a wellbore comprises pumping a breaker fluid composition comprising a corrosion inhibitor having the following structure into the wellbore:wherein at least one of R1 and R2 comprises a C2-C30 hydrocarbon radical, R3 comprises hydrogen or a C1-C30 hydrocarbon radical, and n is an integer between 1 and 4.

15. The method of claim 13, further comprising contacting a filtercake with the breaker fluid composition.

16. The method of claim 13, wherein pumping a breaker fluid composition into a wellbore comprises pumping a breaker fluid composition comprising a synergist in the wellbore.

17. The method of claim 13, wherein pumping a breaker fluid composition into a wellbore comprises pumping a breaker fluid composition comprising a corrosion inhibitor comprising an alkoxylated heterocyclic diamine in the wellbore.

18. A breaker fluid composition, comprising: brine; a breaker fluid; and a corrosion inhibitor comprising a heterocyclic diamine having the following structure:wherein at least one of R1 and R2 comprises a C2-C30 hydrocarbon radical, R3 comprises hydrogen or a C1-C30 hydrocarbon radical, and n is an integer between 1 and 4.

19. The breaker fluid composition of claim 18, further comprising at least one of an oxidizer, a chelating agent, and a solvent.

20. The breaker fluid composition of claim 18, further comprising a synergist.

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