Wellbore fluids including corrosion inhibitor compositions, and related methods

Abstract

A wellbore fluid includes an aqueous base fluid including water, and at least one salt. The wellbore fluid further includes a corrosion inhibitor composition including at least one of morpholine or hydroxyethyl morpholine, and ascorbic acid. The corrosion inhibitor composition includes at least about 0.80 part by weight of the at least one of morpholine or hydroxyethyl morpholine per every about 1.0 part by weight of the ascorbic acid. Related wellbore fluids, corrosion inhibitor compositions, and methods are also disclosed.

Description

Docket No. IS23 1472-WO-PCTWELLBORE FLUIDS INCLUDING CORROSION INHIBITOR COMPOSITIONS, AND RELATED METHODSCROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims priority from, and incorporates US Provisional Application Serial No. 63 / 698855, which bears the same title and was filed on September 25, 2024.BACKGROUND

[0002] Wellbore drilling operations include 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 into the wellbore through a drill pipe and drill bit, and may subsequently flow upward through the wellbore to the surface. For example, a drilling fluid 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 lubricate and cool the drill bit and simultaneously facilitate removal of formation cuttings. In addition to the foregoing, circulation of the drilling fluid may control the subsurface pressure, maintain the integrity of the bore or wellbore until the well section is cased and cemented, and isolate the fluids from the formation by providing sufficient hydrostatic pressure to prevent the ingress of formation fluids into the wellbore.

[0003] Once drilling operations have been completed, the well is prepared for completion operations. Completion operations may include one or more operations to protect the formation, maintain pressure control of the wellbore (e.g., preventing blowouts and other pressure-related issues in the wellbore), displace the drilling fluid from the wellbore, and / or stabilize the wellbore walls to reduce or prevent collapse of the formation into the wellbore. Completion of the wellbore may include preparing the wellbore for production and may include, for example, running casing into the wellbore, cementing the casing, and perforating the casing.BRIEF SUMMARY

[0004] In some embodiments, a wellbore fluid includes an aqueous base fluid including water, and at least one salt. The wellbore fluid further includes a corrosion inhibitor composition including at least one of morpholine or hydroxy ethyl morpholine, and ascorbic acid. The corrosion inhibitor composition includes at least about 0.80 part by weight of the at least one of morpholine or hydroxy ethyl morpholine per every about 1.0 part by weight of the ascorbic acid.Docket No. IS23 1472-WO-PCT

[0005] In some embodiments, a wellbore fluid includes a brine having a density greater than about 1,080 kg / m3, and a corrosion inhibitor composition including greater than about 45.0 weight percent of a first component comprising one or more of morpholine, hydroxyethyl morpholine, or a morpholine derivative, and a second component comprising one or more of ascorbic acid, isoascorbic acid, an ascorbate salt, or an erythorbate salt.

[0006] In some embodiments, a method of operating a wellbore includes performing one or more completion operations with a wellbore fluid, the wellbore fluid including at least one of calcium chloride, calcium bromide, zinc bromide, sodium chloride, sodium bromide, or potassium chloride, and a corrosion inhibitor composition including at least one of morpholine or hydroxyethyl morpholine, and ascorbic acid. The corrosion inhibitor composition includes at least about 0.80 part by weight of the at least one of morpholine or hydroxyethyl morpholine per every about 1.0 part by weight of the ascorbic acid.

[0007] This summary is provided to introduce a selection of concepts that are further described below 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.

[0008] Additional features and advantages of embodiments of the disclosure will be set forth in the description which follows, and in part will be obvious from the description, or may be learned by the practice of such embodiments. The features and advantages of such embodiments may be realized and obtained by means of the instruments and combinations particularly pointed out in the appended claims. These and other features will become more fully apparent from the following description and appended claims, or may be learned by the practice of such embodiments as set forth hereinafter.BRIEF DESCRIPTION OF DRAWINGS

[0009] 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 implementations 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. UnderstandingDocket No. IS23 1472-WO-PCT that the drawings depict some example implementations, the implementations will be described and explained with additional specificity and detail through the use of the accompanying drawings in which:

[0010] 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;

[0011] FIG. 2 is a simplified, partial cross-sectional view of a section of the wellbore system 200, according to at least one embodiment of the disclosure; and

[0012] FIG. 3 is a simplified flow diagram illustrating a method of reducing a rate of corrosion of a wellbore fluid including a high-density brine, according to at least one embodiment of the disclosure.DETAILED DESCRIPTION

[0013] As used herein, a “barrel” means and includes a volume equivalent to 42 gallons. Quantities of various materials (e g., additives) are often quantified in barrels in the oil and gas industry.

[0014] This disclosure generally relates to wellbore fluids including a corrosion inhibitor composition formulated and configured to reduce corrosion of wellbore equipment. When performing various wellbore operations, the wellbore fluid may be configured to provide a desired hydrostatic pressure to the earth formation and reduce and / or minimize damage to the earth formation. The wellbore fluid may include an aqueous base fluid including a high-density brine formulated and configured to exhibit a desired hydrostatic pressure to maintain wellbore integrity. The brine may inhibit the swelling of clays and shales, which may otherwise destabilize the wellbore. In addition, the brine may be substantially unreactive with formation minerals, reducing the risk of formation damage and maintaining the wellbore integrity. Further, the brine may be formed to a relatively high density, which may facilitate balancing formation pressures and prevent wellbore collapse.

[0015] The wellbore fluid may include completion fluid, a packer fluid, a workover fluid, a kill fluid, an acidizing fluid, a fracturing fluid, a perforating fluid, or another fluid used during wellbore operations. Depending on the operation to be performed with the wellbore fluid, the wellbore fluid may include one or more additives and / or other components. While the use of brine in such fluids may be beneficial in terms of wellbore stability, the brine may be corrosive to wellbore equipment,Docket No. IS23 1472-WO-PCT piping, casing, and tubing in the wellbore. According to embodiments described herein, the wellbore fluid includes an aqueous base fluid including a brine (e.g., water and one or more salts) and further including one or more corrosion inhibitor compositions formulated and configured to reduce a rate of corrosion of wellbore equipment, piping, production tubing, casing, or other equipment in contact with the wellbore fluid.

[0016] The corrosion inhibitor composition may include, comprise, consist of, or consist essentially of a first component and a second component. The first component may include morpholine or a morpholine derivative. In some embodiments, the first component includes morpholine. In some embodiments, the first component includes hydroxyethyl morpholine. The second component may include ascorbic acid. In some embodiments, the corrosion inhibitor composition is substantially free of (e.g., does not include) antimony or antimony-containing compounds. Without being bound by any particular theory, the corrosion inhibitor composition reduces the corrosion rate of metals in contact with the wellbore fluid by forming an iron ascorbate layer on the metal due to interaction of the metal with the ascorbic acid, and forming an organic film on the ascorbate layer.

[0017] The corrosion inhibitor composition may reduce the rate of corrosion of metals in contact with the wellbore fluid by at least about 50 percent, at least about 60 percent, at least about 70 percent, at least about 75 percent, at least about 80 percent, or even at least about 85 percent compared to the corrosion rate when the wellbore fluid does not include the corrosion inhibitor composition. In addition, the corrosion inhibitor composition may reduce pitting and cracking (e.g., stress corrosion cracking) in the metals, which may lead to failure of the equipment, piping, and / or tubing. The corrosion inhibitor composition may be effective in high-density brines (e.g., brines having a density greater than about 1,080 kg / m3(about 9.0 ppg), such as greater than about 1,201 kg / m3(about 10.0 ppg), at temperatures greater than about 121.1°C (about 250°F), such as greater than about 148.9°C (about 300°F).

[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. The wellbore 102 may be used for injecting carbon dioxide into the earth formation 101 to facilitate carbon storage in the earth formation 101. While the disclosureDocket No. IS23 1472-WO-PCT describes that the wellbore 102 is configured for facilitating carbon storage in the earth formation 101, it will be understood that the wellbore 102 may be used to facilitate hydrocarbon recovery from the earth formation 101, injection of carbon dioxide into the earth formation 101, injection of other fluids into the earth formation 101, or combinations thereof.

[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 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 otherDocket No. IS23 1472-WO-PCT 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, after drilling operations are completed, one or more wellbore fluids may be introduced into the wellbore 102. FIG. 2 is a simplified, partial cross-sectional view of a section of the wellbore system 200 including a well 201, according to at least one embodiment of the disclosure. After drilling the wellbore 102 (FIG. 1), the drill string 105 (FIG. 1) may be removed from the wellbore 102 and one or more completion operations may be performed. In some embodiments, various sections of casing may be cemented in place to secure the sections of casing to the wall of the borehole defined by the earth formation 101.

[0024] The wellbore system 200 may include production tubing 202 extending at least partially through a production liner 204 and a production casing 206. Upper sections of the production liner 204 may be fluidly isolated from the production tubing 202 and from the earth formation 101 by a packer 208. The packer 208 may be configured to direct fluid (e.g., from the earth formation 101) entering the production liner 204 to flow through the production tubing 202 and up to a surface 210. The production casing 206 may be cemented to surfaces of the earth formation 101 by cement 212. Apacker 214 may be configured to fluidly isolate the production liner 204 from the production casing 206.

[0025] With continued reference to FIG. 2, the wellbore system 200 may further include a surface casing 216 at an upper portion of the wellbore 102, and intermediate casing 218 extending beyond the surface casing 216. The surface casing 216 may be configured to maintain the integrity of the wellbore 102 and / or prevent (substantially prevent) contamination of groundwater by hydrocarbons, subterranean brines, and drilling fluids. The intermediate casing 218 may be configured to isolate hydrocarbon -bearing portions of the earth formation 101 and fractured and lost circulation zones. In some embodiments, the wellbore system 200 further includes a conductor casing that may be configured to protect shallow portions of the earth formation 101 from contamination, such as contamination by drilling fluids and / or other wellbore fluids. Each of theDocket No. IS23 1472-WO-PCT surface casing 216, the intermediate casing 218, and the conductor casing may be cemented in place by cement 212.

[0026] At a surface 210, the wellbore 102 may be capped by a plurality (e.g., a stack) of fluid flow control system 225, such as a so-called “Christmas tree” or a “frac tree.” The fluid flow control system 225 may include flow control valves (e.g., master valves, wing valves, swab valves, etc.), spools, flow crosses (e.g., goat heads, frac heads, etc.), and fittings individually and / or collectively configured to direct and control (e.g., permit and prevent) flow of the treatment fluid into the wellbore 102 and to direct and control flow of formation fluids out of the wellbore 102.). For example, the fluid flow control system 225 may include at least a first flow control device 222 and a second flow control device 224. The first flow control device 222 and the second flow control device 224 may individually include a valve. The first flow control device 222 and the second flow control device 224 may be configured to close selected tubulars or pipes, such as the production tubing 202 and / or the production casing 206 extending within the wellbore 102, to selectively facilitate the flow of various fluids to or from the wellbore 102. In some embodiments, the fluid flow control system 225 includes a blow-out preventer (BOP) stack configured to selectively prevent the flow of formation fluids out of the wellbore 102. The fluid flow control system 225 may be directly or indirectly coupled to the top of a wellhead 220 (e.g., tubing head adapter) terminating the wellbore 102 at the surface 210.

[0027] The first flow control device 222 may be in fluid communication with first piping 226 via a first valve 228; and the second flow control device 224 may be in fluid communication with second piping 230 via a second valve 232. Different fluids may be provided to the wellbore 102 through the first flow control device 222 and the second flow control device 224. For example, different wellbore fluids may be provided to the wellbore 102 through the flow control device 222 and the second flow control device 224. In some embodiments, the first flow control device 222 and / or the second flow control device 224 is configured to be in fluid communication with one or more of wellbore fluids. In some embodiments, an electric submersible pump (ESP) 240 may be located within the wellbore 102, such as in fluid communication with the production tubing 202, and configured to provide one or more chemicals to the wellbore 102 and / or to facilitate the flow of produced fluids to the surface.

[0028] The wellbore fluid may be provided to different sections of the wellbore 102. For example, a wellbore fluid may be located in the annular region between the production tubing 202Docket No. IS23 1472-WO-PCT and the production casing 206, within the intermediate casing 218, within the surface casing 216, or at other regions of the wellbore 102.

[0029] As described above, the wellbore fluid may include one or more of a completion fluid, a packer fluid, a workover fluid, a kill fluid, an acidizing fluid, a fracturing fluid, a perforating fluid, or another wellbore fluid. The wellbore fluid may be formulated and configured to protect the earth formation, maintain pressure control of the wellbore 102 (e.g., preventing blowouts and other pressure-related issues in the wellbore 102), clean the wellbore 102 (such as by removing residual drilling fluids and debris), stabilize the wellbore walls to reduce or prevent collapse of the wellbore 102, or perform one or more other functions, depending on the composition and purpose of the wellbore fluid.

[0030] The wellbore fluid may include an aqueous base fluid, one or more salts, and a corrosion inhibitor composition. In some embodiments, the aqueous base fluid includes a brine having a relatively high density (a “high-density brine”). The wellbore fluid may further include one or more additives, depending on the application of the wellbore fluids in the wellbore 102. The one or more additives may include, for example, one or more of bridging materials, viscosifiers, fluid loss materials (filtration control agents), sealants, thinners (e.g., dispersion aids), weighting materials, shale stabilizers, shale inhibitors, pH buffers (pH control agents), emulsifiers, emulsion activators, gelling agents, defoamers, surfactants, foaming agents, scale inhibitors, solvents, rheological additives, biocides, oxygen scavengers, or other additives.

[0031] The aqueous base fluid may include water, 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 wellbore fluid, reduce the effect of the wellbore fluid on hydratable clays and shales of the earth formation 101, and / or reduce (e.g., prevent) gas hydrate formation. The salts may include salts of one or more of sodium, calcium, aluminum, magnesium, zinc, potassium, strontium, or lithium, and salts of one or more of chlorides, bromides, carbonates, iodides, chlorates, bromates, formates, nitrates, oxides, phosphates, sulfates, silicates, or fluorides. In some embodiments, the salt comprises a divalent halide, such as an alkaline earth halide (e.g., calcium chloride (CaCh), calcium bromide (CaBr2)), or a zinc halide. The salt may include cesium formate (HCOOCs), sodium bromide (NaBr), potassium bromide (KBr), andDocket No. IS23 1472-WO-PCT 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 a completion fluid.

[0032] In some embodiments, the salt includes a halide and the base fluid includes a halide- based brine. The salt may include one or more of calcium chloride, calcium bromide, zinc bromide, sodium chloride, sodium bromide, potassium chloride, or another salt. In some embodiments, the salt includes calcium chloride, calcium bromide, or a combination thereof.

[0033] The salt may constitute from about 0.0 weight percent (e.g., such as when the base fluid comprises fresh water) to about 55.0 weight percent of the wellbore fluid, such as from about 0.0 weight percent to about 5.0 weight percent, from about 5.0 weight percent to about 10.0 weight percent, from about 10.0 weight percent to about 20.0 weight percent, from about 20.0 weight percent to about 30.0 weight percent, from about 30.0 weight percent to about 40.0 weight percent, from about 40.0 weight percent to about 50.0 weight percent, or from about 50.0 weight percent to about 55.0 weight percent of the wellbore fluid. However, the disclosure is not so limited, and the weight percent of the salt and the water in the drilling fluid may be different than that described.

[0034] As described above, the salt may be provided to the base fluid to increase the density of the base fluid. The wellbore fluid may exhibit a hydrostatic pressure on the wall of the earth formation 101 and balance the formation pressure to prevent blowouts and a loss of wellbore pressure. In addition, the relatively high salt content of the wellbore fluid may reduce and / or prevent swelling of clays and shales of the earth formation 101.

[0035] The density of the wellbore fluid may be within a range of from about 996.7 kg / m3(about 8.3 Ib / gal (ppg)) to about 2,397 kg / m3(about 20.0 ppg), such as from about 996.7 kg / m3(8.3 ppg) to about 1,080 kg / m3(about 9.0 ppg), from about 1,080 kg / m3(about 9.0 ppg) to about 1,201 kg / m3(about 10.0 ppg), from about 1,201 kg / m3(about 10.0 ppg) to about 1,440 kg / m3(about 12.0 ppg), from about 1,440 kg / m3(about 12.0 ppg) to about 1,681 kg / m3(about 14.0 ppg), from about 1,681 kg / m3(about 14.0 ppg) to about 1,921 kg / m3(about 16.0 ppg), from about 1,921 kg / m3(about 16.0 ppg) to about 2,161 kg / m3(about 18.0 ppg), or from about 2,161 kg / m3(about 18.0 ppg) to about 2,397 kg / m3(about 20.0 ppg). In some embodiments, the density of the wellbore fluid may be greater than about 1,080 kg / m3(about 9.0 ppg), such as greater than about 1,201 kg / m3(about 10.0 ppg), greater than about 1,440 kg / m3(about 12.0 ppg), greater than about 1,681 kg / m3(about 14.0 ppg), greater than about 1,921 kg / m3(about 16.0 ppg), or greater than about 2,161 kg / m3(about 18.0 ppg). In some embodiments, the density of the wellbore fluid is within a range of from aboutDocket No. IS23 1472-WO-PCT1 ,080 kg / m3(about 9.0 ppg) to about 1 ,201 kg / m3(about 10.0 ppg), from about 1 ,201 kg / m3(about 10.0 ppg) to about 1,321 kg / m3(about 11.0 ppg), from about 1,321 kg / m3(about 11.0 ppg) to about 1,440 kg / m3(about 12.0 ppg), or from about 1,440 kg / m3(about 12.0 ppg) to about 1,561 kg / m3(about 13.0 ppg). In some embodiments, the wellbore fluid includes a calcium chloride brine having a density of about 1,273 kg / m3(about 10.6 ppg) or about 1,393 kg / m3(about 11.6 ppg). In some embodiments, the wellbore fluid includes a calcium bromide and calcium chloride brine having a density of about 1,393 kg / m3(about 11.6 ppg) or about 1,465 kg / m3(about 12.2 ppg). Of course, the disclosure is not so limited, and the wellbore fluid may be formulated to exhibit a desired density, such as by changing the concentration of the brine and / or including one or more density increasing materials in the wellbore fluid.

[0036] As described above, due to the relatively high concentration of the salts in the wellbore fluid, the wellbore fluid may cause brine corrosion of the wellbore 102, the wellbore equipment (e.g., the electric submersible pump 240), the production tubing 202, the production casing 206, the intermediate casing 218, the surface casing 216, and / or other components of the wellbore system 200. According to embodiments described herein, the wellbore fluid may include the corrosion inhibitor composition formulated and configured to reduce the rate of corrosion caused by the salts (the brine) in the wellbore fluid.

[0037] The corrosion inhibitor composition may include a first component and a second component. In some embodiments, the corrosion inhibitor composition consists essentially or consists of the first component and the second component. The first component may include morpholine or a morpholine derivative, such as a hydroxyalkyl morpholine. In some embodiments, the first component includes morpholine. In some embodiments, the first component includes hydroxyethyl morpholine. In some embodiments, the first component includes a morpholine derivative, such as one or more of 3 -methylmorpholine, 4-(2-chloroethyl)morpholine, 2,6- dimethylmorpholine, N-formylmorpholine, N-methylmorpholine, N-ethylmorpholine, N- phenylmorpholine, N-benzylmorpholine, 2-benzylmorpholine, N-(2-hydroxyethyl)morpholine, N-(2-methoxyethyl)morpholine, 3-methyl-2-phenylmorpholine, another morpholine compound, or combinations thereof.

[0038] The first component may constitute from about 35.0 weight percent to about 65.0 weight percent of the corrosion inhibitor composition, such as from about 35.0 weight percent to about 45.0 weight percent, from about 45.0 weight percent to about 50.0 weight percent, from about 50.0Docket No. IS23 1472-WO-PCT weight percent to about 55.0 weight percent, or from about 55.0 weight percent to about 65.0 weight percent of the corrosion inhibitor composition. The second component may constitute from about 35.0 weight percent to about 65.0 weight percent of the corrosion inhibitor composition, such as from about 35.0 weight percent to about 45.0 weight percent, from about 45.0 weight percent to about 50.0 weight percent, from about 50.0 weight percent to about 55.0 weight percent, or from about 55.0 weight percent to about 65.0 weight percent of the corrosion inhibitor composition.

[0039] In some embodiments, the first component constitutes greater than about 45.0 weight percent of the corrosion inhibitor composition, such as greater than about 47.0 weight percent, greater than about 48.0 weight percent, greater than about 49.0 weight percent, greater than about 50.0 weight percent, greater than about 51.0 weight percent, or greater than about 52.0 weight percent of the corrosion inhibitor composition. In some embodiments, the corrosion inhibitor composition includes a greater weight percent of the first component than of the second component. In some embodiments, the corrosion inhibitor composition includes about a same weight percent of the first component as the second component (e.g., equal parts by weight of the first component as parts by weight of the second component).

[0040] A ratio of the first component to the second component may be within a range of from about 1.0: 1.30 to about 1.0:0.75, such as from about 1.0: 1.3 to about 1.0: 1.2, from about 1.0: 1.2 to about 1.0: 1.1, from about 1.0: 1.1 to about 1.0:1.0, from about 1.0: 1.0 to about 1.0:0.90, from about 1.0:0.90 to about 1.0:0.80, or from about 1.0:0.80 to about 1.0:0.75. In other words, for every about 1.0 part of the first component, the corrosion inhibitor composition may include from about 0.75 part to about 1.3 parts of the second component. In some embodiments, the ratio of the first component to the second component is within a range of from about 1.0: 1.1 to about 1.0:0.90, such as from about 1.0: 1.05 to about 1.0:0.92.

[0041] In some embodiments, for every 1.0 part by weight of the second component, the corrosion inhibitor composition may include at least about 0.80 part by weight of the first component, such as at least about 0.85 part by weight of the first component, at least about 0.90 part by weight of the first component, at least about 0.95 part by weight of the first component, at least about 1.0 part by weight of the first component, at least about 1.05 parts by weight of the first component, or at least about 1.10 parts by weight of the first component.Docket No. IS23 1472-WO-PCT

[0042] The second component may include ascorbic acid, isoascorbic acid (also referred to as “erythorbic acid”), an ascorbate salt (e.g., sodium ascorbate), an erythorbate salt (e.g., sodium erythorbate), or combinations thereof. In some embodiments, the second component includes ascorbic acid.

[0043] The second component may constitute less than about 55.0 weight percent of the corrosion inhibitor composition, such as less than about 53.0 weight percent, less than about 52.0 weight percent, less than about 51.0 weight percent, less than about 50.0 weight percent, less than about 49.0 weight percent, less than about 48.0 weight percent, or less than about 45.0 weight percent of the corrosion inhibitor composition. In some embodiments, a weight percent of the second component in the corrosion inhibitor composition is less than the weight percent of the first component in the corrosion inhibitor composition.

[0044] A concentration of the corrosion inhibitor composition in the wellbore fluid may be within a range of from about 11.4 kg / m3(about 4.0 pounds per barrel (ppb)) to about 28.6 kg / m3(about 10.0 ppb), such as from about 11.4 kg / m3(about 4.0 ppb) to about 17.2 kg / m3(about 6.0 ppb), from about 17.2 kg / m3(about 6.0 ppb) to about 22.9 kg / m3(about 8.0 ppb), or from about22.9 kg / m3(about 8.0 ppb) to about 28.6 kg / m3(about 10.0 ppb). In some embodiments, the concentration of the corrosion inhibitor composition in the wellbore fluid is within a range of from about 11.4 kg / m3(about 4.0 ppb) to about 14.3 kg / m3(about 5.0 ppb). However, the disclosure is not so limited, and the concentration of the corrosion inhibitor composition in the wellbore fluid may be different than that described.

[0045] A concentration of the first component in the wellbore fluid may be within a range of from about 4.0 kg / m3(about 1.4 ppb) to about 18.6 kg / m3(about 6.5 ppb), such as from about 4.0 kg / m3(about 1.4 ppb) to about 6.0 kg / m3(about 2.10 ppb), from about 6.0 kg / m3(about 2.10 ppb) to about 8.0 kg / m3(about 2.80 ppb), from about 8.0 kg / m3(about 2.80 ppb) to about 10.0 kg / m3(about 3.50 ppb), from about 10.0 kg / m3(about 3.50 ppb) to about 12.0 kg / m3(about 4.20 ppb), from about 12.0 kg / m3(about 4.20 ppb) to about 14.0 kg / m3(about 4.90 ppb), from about 14.0 kg / m3(about 4.90 ppb) to about 16.0 kg / m3(about 5.60 ppb), or from about 16.0 kg / m3(about 5.60 ppb) to about 18.6 kg / m3(about 6.5 ppb). In some embodiments, the concentration of the first component in the wellbore fluid is within a range of from about 5.7 kg / m3(about 2.0 ppb) to about6.9 kg / m3(about 2.4 ppb). However, the disclosure is not so limited, and the concentration of the first component in the wellbore fluid may be different than that described.Docket No. IS23 1472-WO-PCT

[0046] A concentration of the second component in the wellbore fluid may be within a range of from about 4.0 kg / m3(about 1.4 ppb) to about 18.6 kg / m3(about 6.5 ppb), such as from about 4.0 kg / m3(about 1.4 ppb) to about 6.0 kg / m3(about 2.10 ppb), from about 6.0 kg / m3(about 2.10 ppb) to about 8.0 kg / m3(about 2.80 ppb), from about 8.0 kg / m3(about 2.80 ppb) to about 10.0 kg / m3(about 3.50 ppb), from about 10.0 kg / m3(about 3.50 ppb) to about 12.0 kg / m3(about 4.20 ppb), from about 12.0 kg / m3(about 4.20 ppb) to about 14.0 kg / m3(about 4.90 ppb), from about 14.0 kg / m3(about 4.90 ppb) to about 16.0 kg / m3(about 5.60 ppb), or from about 16.0 kg / m3(about 5.60 ppb) to about 18.6 kg / m3(about 6.5 ppb). In some embodiments, the concentration of the second component in the wellbore fluid is about 6.3kg / m3(about 2. 2 ppb). However, the disclosure is not so limited, and the concentration of the second component in the wellbore fluid may be different than that described.

[0047] In some embodiments, the corrosion inhibitor composition includes morpholine and ascorbic acid. A concentration of the morpholine in the wellbore fluid may be about 6.9 kg / m3(about 2.4 ppb) and a concentration of the ascorbic acid in the wellbore fluid may be about 6.28 kg / m3(about 2.2 ppb). The wellbore fluid may include calcium chloride, calcium bromide, or a combination thereof and may have a density of about 10.6 ppg, a density of about 11.6 ppg, or a density of about 12.2 ppg.

[0048] In some embodiments, the corrosion inhibitor composition includes hydroxyethyl morpholine and ascorbic acid. A concentration of the hydroxyethyl morpholine in the wellbore fluid may be about 6.9 kg / m3(about 2.4 ppb) or about 5.7 kg / m3(about 2.0 ppb), and the concentration of the ascorbic acid in the wellbore fluid may be about 5.99 kg / m3(about 2.1 ppb). The wellbore fluid may include calcium chloride, calcium bromide, or a combination thereof and may have a density of about 11.6 ppg.

[0049] The corrosion inhibitor composition may include, comprise, consist essentially of, or consist of the first component and the second component. In some embodiments, the corrosion inhibitor composition is substantially free of materials other than the first component and the second component. In some embodiments, the corrosion inhibitor composition does not include and is substantially free of antimony or antimony-containing compounds. The corrosion inhibitor composition may include less than 1,000 ppm of antimony or antimony-containing compounds, such as less than about 500 ppm, less than about 300 ppm, less than about 200 ppm, less than about 150 ppm, less than about 100 ppm, less than about 75 ppm, less than about 50 ppm, less than aboutDocket No. IS23 1472-WO-PCT25 ppm, or less than about 10 ppm of antimony or antimony-containing compounds. In some embodiments, the corrosion inhibitor composition consists essentially or consists of the first component and the second component.

[0050] The corrosion inhibitor composition may reduce the rate of corrosion of metals in contact with the wellbore fluid. The corrosion inhibitor composition may reduce the rate of corrosion of metals in contact with the wellbore fluid by at least about 50 percent, at least about 60 percent, at least about 70 percent, at least about 75 percent, at least about 80 percent, or even at least about 85 percent compared to the corrosion rate when the wellbore fluid does not include the corrosion inhibitor composition. The metals may include wellbore equipment, production tubing (e.g., production tubing 202), liners (e.g., production liner 204), casing (e.g., surface casing 216, intermediate casing 218, production casing 206), or other metals in the wellbore. In addition, the corrosion inhibitor composition may reduce pitting and cracking in the metals, which may lead to failure of the equipment, piping, and / or tubing. Further, the corrosion inhibitor composition may reduce and / or prevent stress corrosion cracking of the metals. In some embodiments, the corrosion inhibitor composition reduces the rate of corrosion of the metals by a factor of at least about 2, at least about 3, at least about 4, at least about 5, at least about 6, or even at least about 8.

[0051] Without being bound by any particular theory, the corrosion inhibitor composition reduces the corrosion rate of metals in contact with the wellbore fluid by forming an iron ascorbate layer on the metal due to interaction of the metal with the ascorbic acid, and forming an organic film on the ascorbate layer.

[0052] As described above, the wellbore fluid may include one or more fluids formulated and configured for performing one or more wellbore operations. The wellbore fluid may include one or more additives, such as one or more of bridging materials, viscosifiers, fluid loss materials (filtration control agents), sealants, dispersion aids (e.g., thinners), weighting materials, shale stabilizers, shale inhibitors, pH buffers (pH control agents), emulsifiers, emulsion activators, gelling agents, defoamers, surfactants, foaming agents, scale inhibitors, solvents, rheological additives, biocides, oxygen scavengers, or other additives.

[0053] The bridging material may include particles of at least one of calcium carbonate, zinc carbonate, barium carbonate, a coated metal oxide (e.g., hemalite, ilmenite, magnesium oxide), dolomite (calcium magnesium carbonate), colemanite, ulexite, analcite, apatite, bauxite, brucite, gibbsite, hydrotalcite, galena, hematite, magnetite, iron oxides, siderite, celestite, magnesiumDocket No. IS23 1472-WO-PCT citrate, calcium citrate, calcium succinate, calcium maleate, calcium tartrate, magnesium tartrate, bismuth citrate, other suspended salts, mica, nutshells, or fibers. The bridging materials may be hydrophobically coated with one or more hydrophobic functional groups.

[0054] Viscosifiers of the wellbore fluid may include a material formulated and configured to increase the viscosity of the wellbore fluid. The viscosifier may include, for example, a polymer, a copolymer, a block copolymer, or higher order copolymer (i.e., a terpolymer or quaternary polymer, etc.) composed of monomers that may include 2-acrylamido-2-methylpropanesulfonate, acrylamide, methacrylamide, N,N-dimethyl acrylamide, N,N-dimethyl methacrylamide, tetrafluoroethylene, dimethylaminopropyl methacrylamide, N-vinyl-2-pyrrolidone, N-vinyl-3- methyl-2-pyrrolidone, N-vinyl-4,4-diethyl-2-pyrrolidone, 5-isobutyl-2-pyrrolidone, N-vinyl-3- methyl-2-pyrrolidone, alkyl oxazoline, poly(2-ethyl-2-oxazoline), C2-C12 olefins, ethylene, propylene, butene, butadiene, vinyl aromatics, styrene, alkylstyrene, acrylic acid, methacrylic acid, vinyl alcohol, partially hydrolyzed acrylamide or methacrylamide, derivatives thereof, and / or mixtures thereof. In yet other embodiments, polymeric viscosifiers may include polyalkylene amines and polyethers, such as, for example, polyethylene oxides, polypropylene oxide, and / or mixtures thereof.

[0055] In some embodiments, the viscosifier includes a polymer (e.g., a copolymer) formed from at least one acrylamide monomer and at least one sulfonated anionic monomer. In other words, the viscosifier may include a reaction product of the at least one acrylamide monomer and at least one sulfonated anionic monomer. In other embodiments, the first component comprises a higher order copolymer and / or block copolymers, such as a terpolymer, a quaternary polymer, or another higher order polymer including the at least one acrylamide monomer and the at least one sulfonated anionic monomer.

[0056] The at least one acrylamide monomer may include one or more of acrylamide, unsubstituted acrylamide, methacrylamide, N-substituted acrylamides (e.g., alkylacrylamides, N-methylol acrylamide, N-isopropylacrylamide, diacetone acrylamide, N-alkyl acrylamide (where alkyl is Ci to C14), and N,N-dialkyl acrylamides (where alkyl is Ci (e.g., N,N-dimethylacrylamide) to C14), N-cycloalkane, N-(2-hydroxyethyl) acrylamide, N-isopropyl acrylamide, N-[3- (dimethylamino)propyl] acrylamide, or acryloyl morpholine). In embodiments wherein the at least one acrylamide monomer comprises an N-substituted acrylamide, the N-substituted acrylamide may comprise N,N-dialkyl acrylamides (e.g., N,N-dimethylacrylamide). The alkyl groups of theDocket No. IS23 1472-WO-PCTN,N-dialkyl acrylamides may be linear, branched, or cyclic. In some embodiments, the at least one acrylamide monomer comprises N,N-dimethylacrylamide.

[0057] The at least one sulfonated anionic monomer may include one or more of 2-acrylamido- 2-methyl -propanesulfonic acid (also referred to as acrylamide tertiary butyl sulfonic acid (ATBS)), vinyl sulfonates, styrene sulfonic acid, allyl sulfonates, or styrene sulfonic acid. The at least one sulfonated anionic monomer may facilitate tolerance of the viscosifier to divalent cations in the drilling fluid brine, such as calcium and magnesium. In some embodiments, the at least one sulfonated anionic monomer is provided as a salt, such as an ammonium salt. For example, the at least one sulfonated anionic monomer may be provided as an ammonium salt of 2-acrylamido-2- methyl-propanesulfonic acid or a sodium salt of 2-acrylamido-2-methyl-propanesulfonic acid.

[0058] The viscosifier may constitute from about 0.05 weight percent to about 6.0 weight percent of the wellbore fluid, such as from about 0.05 weight percent to about 0.10 weight percent, from about 0.10 weight percent to about 0.50 weight percent, from about 0.50 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 3.0 weight percent, or from about 3.0 weight percent to about 6.0 weight percent of the wellbore fluid. In some embodiments, the viscosifier may be present in the drilling fluid at a concentration as low as 0.25 ppb. However, the disclosure is not so limited, and the weight percent of the viscosifier in the drilling fluid may be different than that described.

[0059] The fluid loss material may include starch, bentonite, modified starch (e.g., crosslinked starch, carboxymethyl starch, hydroxyethyl starch, hydroxypropyl starch, hydrophobically- modified starch), polyanionic starch, xanthan gum, polyanionic cellulose (PAC), carboxymethylcellulose, carboxymethyl hydroxyethylcellulose, hydroxyalkylcellulose, hydrophobically-modified cellulose (e.g., cellulose modified by lauryl glycidyl ether or cetyl glycidyl ether), glycogen, locust bean gums, wellan gum, scleroglucan gum, guar gum, alginate, carrageenan (e.g., one or more of i-carrageenan, k-carrageenan, 1-carrageenan) (also referred to as carrageenan gum), gellan gum, alginate, synthetic polymers, styrene, styrene-butadiene, a vinyl polymer, or another polymer. In some embodiments, the additional fluid loss material includes starch, such as hydrophobically-modified starch.

[0060] In some embodiments, the wellbore fluid includes a packer fluid and includes, for example, one or more of the viscosifiers, the biocides, the scale inhibitors, the surfactants, the pH control agents, the weighting materials, or other additives.Docket No. IS23 1472-WO-PCT

[0061] Fluid dispersion aids may include lignosulfates, lignitic materials, modified lignosulfonates, polyphosphates, tannin, and polyacrylates. The dispersion aids may facilitate improved rheological properties of the drilling fluid (e.g., a reduction in flow resistance) and a reduction in gel development. In addition, the dispersion aids may reduce a thickness of filtercakes formed by the drilling fluid, counteract the effects of salts, and reduce the effects of water on the earth formation 101.

[0062] Weighting materials (also referred to as “weighting agents”) may include one or more of barite (BaSO4), iron oxide (e.g., Fe2Os, FeaCE), calcium carbonate (CaCCh), magnesium carbonate (MgCCh), manganese oxide (M Ch), or combinations thereof. The weighting material may be present in the wellbore fluid and facilitate increasing the density of the drilling fluid up to about 2.88 g / cm3(about 24 pounds per gallon (ppg)).

[0063] The shale stabilizer and / or shale inhibitor may include one or more of potassium chloride, calcium chloride, a polyamine, polyacrylamide (PAM), a silicate, glycol, a glycol-based material, polyethylene glycol (PEG), lignosulfate, or another material. The pH buffer may include an amine stabilizer, such as one or more of triethanolamine (CeHisNCh) (TEOA), methyl di ethanol amine (C5H13NO2) (MDEA), dimethylethanol amine (C4H11NO) (DMEA), diethanol amine (C4H11NO2) (DEA), monoethanol amine (MEA), cyclic organic amines, sterically hindered amines, amides of fatty acid, or other suitable tertiary, secondary, or primary amines and ammonia. In some embodiments, the pH buffer includes magnesium oxide.

[0064] The emulsifiers may include calcium polyvalent metal soaps, phosphate esters, fatty acids, fatty acid soaps, alkylbenzene sulfonate, lime, amidoamines, and imidazolines. The corrosion inhibitor may include iron oxide, aluminum bisulfate, zinc carbonate, zinc chromate, an amine, or another material. The gelling agent may include one or more of a clay and a crosslinked polyvinylpyrrolidone, an acrylamide copolymer, guar, sodium bentonite, or another material. The shale inhibitor may include one or more of hexamethylenediamine (HMD), bis(hexamethylene)triamine (BHMT), amine tartaric salt, ammonium lauric salt, polyammonium, alkyl diammonium, an amphoteric polymer, an organosilicate polymer, a silicone polymer, or another material. Defoamers may include one or more of 2-octanol, oleic acid, paraffinic waxes, amide waxes, sulfonated oils, organic phosphates, silicone oils, mineral oils, or dimethylpolysiloxane.Docket No. IS23 1472-WO-PCT

[0065] The defoamer may include a silicone defoamer, an alcohol-based defoamer, a polyether defoamer, or another material. The surfactant may include anionic surfactants, cationic surfactants, and / or non-ionic surfactants. The foaming agents may include a nonionic surfactant including polymeric materials. The scale inhibitors may include an acrylic acid polymer, a maleic acid polymer, or a phosphonate. The solvents may include hydrocarbon solvents.

[0066] The biocide may include one or more of glutaraldehyde, tetrakis-hydroxy methyl - phosphonium sulfate (THPS), quaternary ammonium compounds (quats), sodium hypochlorite, chlorine dioxide, hydrogen peroxide, methyl isothiocyanate (MITC), triazine (e.g., hexahydro- 1,3, 5-tris-(-2-hydroxyethyl)-s-triazine), ozone, bromous acid, perchloric acid, bronopol (e.g., 2- bromo-2-nitropropane-l,3-diol), isothiazoline(s) (e.g., alkyl isothiazonlin-3-ones), tributyl tetradecyl phosphonium chloride (TTPC), another material, or combinations thereof.

[0067] The oxygen scavenger may include one or more of a sulfite-based scavenger, a hydrazinebased scavenger, an organic-based scavenger, or combinations thereof.

[0068] In some embodiments, the wellbore fluid includes a completion fluid, which may be a substantially solids-free fluid (liquid) that is used, in part, to control well pressure during completion of the well 201. The completion fluid may be placed into the wellbore 102 after drilling operations and before production to facilitate completion of the well 201. Completion of the well 201 may include preparing the bottom of the wellbore 102 to desired specifications, running the production tubing 202 and associated downhole equipment, and optionally performing one or more production enhancement operations. The completion fluid may be compatible (chemically compatible) with the earth formation 101 and reservoirs of the earth formation 101 and should not damage the permeability of the earth formation 101 or other equipment in the wellbore 102 (such as production screens). By way of non-limiting example, the completion fluid may include the aqueous base fluid including water, the salt, and the corrosion inhibitor composition. The completion fluid may further include one or more additives, such as one or more of the weighting material, the viscosifiers, the fluid loss materials, the shale inhibitors, the pH buffers, or other additives described above.

[0069] In some embodiments, the wellbore fluid includes a packer fluid and includes the aqueous base fluid including water, the salt, and the corrosion inhibitor composition. The packer fluid may further include one or more additives, such as one or more of the scale inhibitors, the biocides, pH buffers, or other additives described above.Docket No. IS23 1472-WO-PCT

[0070] In some embodiments, the wellbore fluid includes a workover fluid and includes the aqueous base fluid including water, the salt, and the corrosion inhibitor composition. The workover fluid includes one or more of the viscosifiers, the fluid loss materials, the shale inhibitors, the pH buffers, the biocides, or other additives described above.

[0071] In some embodiments, the wellbore fluid includes a kill fluid and includes the aqueous base fluid including water, the salt, and the corrosion inhibitor composition. The kill fluid may further include a weighting material, such as one or more of the weighting materials described above. In some embodiments, the kill fluid includes barite. The kill fluid may be formulated and configured to control the pressure of the wellbore 102 and stop the flow of reservoir fluids into the wellbore 102.

[0072] In some embodiments, the wellbore fluid includes an acidizing fluid and includes the aqueous base fluid including water, the salt, and the corrosion inhibitor composition. The acidizing fluid may further include an acid, a chelating agent, and one or more of the additives described above.

[0073] In some embodiments, the wellbore fluid includes a perforating fluid and includes the aqueous base fluid including water, the salt, and the corrosion inhibitor composition. The perforating fluid may further include one or more acids and one or more of the additives described above. For example, the perforating fluid may include one or more of the surfactants, biocides, scale inhibitors, and scale stabilizers described above.

[0074] In some embodiments, the wellbore fluid incudes a fracturing fluid and includes the aqueous base fluid including water, the salt, and the corrosion inhibitor composition. The fracturing fluid may include one or more proppants and one or more of the additives described above. For example, the fracturing fluid may include one or more of the viscosifiers, surfactants, biocides, pH buffers, and scale inhibitors described above.

[0075] FIG. 3 is a simplified flow diagram illustrating a method of operating a wellbore, according to at least one embodiment of the disclosure. The method 300 includes drilling a borehole, as shown in act 302. The borehole may be formed by circulating a drilling fluid through a drill string, out of a drill bit, and through an annulus between the drill string and the surfaces of the earth formation defining the borehole.

[0076] After drilling the borehole, the method 300 may further include performing one or more completion operations to form a wellbore, as shown in act 304. The one or more completionDocket No. IS23 1472-WO-PCT operations may include cementing one or more sections of casing in the borehole to form a wellbore, performing one or more of acidizing, perforation, fracturing, stimulation, or another wellbore operation.

[0077] The method 300 may further include introducing a wellbore fluid including a brine and a corrosion inhibitor composition to the wellbore, as shown in act 306. In some embodiments, the wellbore fluid is introduced to the wellbore with one or more fluids for performing the one or more completion operations of act 304. The wellbore fluid may include one or more of the wellbore fluids described above. By way of non-limiting example, the one or more wellbore fluids may include one or more of a completion fluid, a packer fluid, a workover fluid, a kill fluid, an acidizing fluid, a fracturing fluid, a perforating fluid, or another wellbore fluid.

[0078] The corrosion inhibitor composition may include one or more of the corrosion inhibitor compositions described above. For example, the corrosion inhibitor composition may include, comprise, consist essentially of, or consist of ascorbic acid and one of both of morpholine and hydroxyethyl morpholine.

[0079] Providing the corrosion inhibitor composition in the wellbore fluid including a brine may reduce the rate of corrosion (on wellbore equipment, piping, tubing, etc.) caused by the brine. In some embodiments, the corrosion inhibitor composition reduces the rate of corrosion by at least a factor of 2, at least a factor of 3, at least a factor of 4, at least a factor of 5, at least a factor of 6, or even at least a factor of 8. In other words, the corrosion inhibitor composition may reduce the rate of corrosion by at least about 50 percent, at least about 66 percent, at least about 75 percent, at least about 80 percent, at least about 83 percent, or even at least about 87.5 percent. Accordingly, wellbore fluids including the brines and the corrosion inhibitor compositions described herein may be in contact with wellbore equipment, production tubing, production casing, other sections of casing, and other components of a wellbore for an extended period of time since the rate of corrosion is substantially reduced by the corrosion inhibitor composition. In addition, the wellbore fluid may exhibit a relatively high temperature and a high brine concentration. For example, the corrosion inhibitor compositions may reduce a rate of corrosion at temperatures greater than about 93.3°C (about 200°F), greater than about 121.1°C (about 250°F), greater than about 148.9°C (about 300°F), or even greater than about 176.7°C (about 350°F).Docket No. IS23 1472-WO-PCTEXAMPLESExample 1

[0080] A plurality of high-density brines including calcium chloride, calcium bromide, or a combination thereof were prepared. Different corrosion inhibitor compositions were provided to the high-density brines and the corrosion rate was measured. In addition, some of the high-density brines did not include a corrosion inhibitor composition. The effectiveness of the corrosion inhibitor compositions at reducing the rate of corrosion was compared. Table 1 below lists the different fluids that were prepared including the density of the brine, the composition of the brine, and the composition of the corrosion inhibitor composition (if any) in the various fluids. In Table 1, “ppg” means pounds per gallon and “ppb” means pounds per barrel, wherein 1.0 ppb is equivalent to about 2.85 kg / m3. Table 1

[0081] The corrosion rate of different metal coupons exposed to the different fluids of Table 1 was measured to compare the effectiveness of the corrosion inhibitor compositions. C4130 carbon steel (also known as “Chromoly steel,” a low-alloy, carbon steel including chromium and molybdenum) coupons were exposed to the different fluids and the weight loss was measured to quantify the effectiveness of the corrosion inhibitor compositions. Table 2 below shows the results of testing of Fluid 1 through Fluid 7 when a C4130 metal coupon was exposed to the fluids under 200 psi nitrogen (N2) at the noted temperature, and pH. In Table 2, “mpy” refers to the corrosionDocket No. IS23 1472-WO-PCT rate in units of mils per year, wherein 1 .0 mpy is equal to one thousandth of an inch per year and about 0.0254 mm per year (mmy).Table 2

[0082] With reference to Table 2, the fluids that included the corrosion inhibitor compositions (Fluids 2, 4, 5, and 7) exhibited substantially less than corresponding fluids that did not include corrosion inhibitor compositions. For example, Fluid 2 was the same composition and density as Fluid 1, except Fluid 2 included a corrosion inhibitor composition including ascorbic acid and morpholine. The coupon exposed to Fluid 1 exhibited a corrosion rate of about 5.9 mpy, whereas the coupon exposed to Fluid 2 exhibited a corrosion rate of about 2.0 mpy, about one-third the corrosion rate of the coupon exposed to Fluid 1. Similarly, Fluids 4 and 5 included the same composition as Fluid 3, but included a corrosion inhibitor composition. The corrosion inhibitor compositions of Fluids 4 and 5 reduced the rate of corrosion of the coupon by more than about 66 percent. For example, Fluid 4 reduced the rate of corrosion to about 2.2 mpy and Fluid 5 reduced the rate of corrosion to about 2.4 mpy compared to about 7.2 mpy for Fluid 3 which did not include a corrosion inhibitor composition. Fluid 7, which included a corrosion inhibitor composition, similarly reduced the rate of corrosion by about 66 percent compared to Fluid 6, which included the same composition as Fluid 6, but without a corrosion inhibitor composition. With reference to Table 2, the corrosion inhibitor compositions were effective at reducing the rate of corrosion even at relatively high temperatures of about 149.9°C (about 300°F) and about 121.1°C (about 250°F).

[0083] Table 3 below compares the rate of corrosion of a C4130 coupon when exposed to Fluid 8 and Fluid 9 at about 500 psi nitrogen and about 5 volume percent of carbon dioxide at about 146.1°C (about 295°F). With reference to Table 3, when exposed to carbon dioxide, the coupon exhibited substantially higher corrosion without the corrosion inhibitor than with the corrosionDocket No. IS23 1472-WO-PCT inhibitor. The coupon exposed to Fluid 8 exhibited a corrosion rate of about 17.7 mpy and experienced pitting, whereas the coupon exposed to Fluid 9 exhibited a corrosion rate of about 2.1 mpy and did not experience pitting. The rate of corrosion of the coupon exposed to Fluid 9 was about 11.9 percent the rate of corrosion of the coupon exposed to Fluid 8.Table 3

[0084] The effect of the corrosion inhibitor composition on stress corrosion cracking (SCC) was tested. A 13Cr-HPl-110 C-ring coupon was exposed to Fluid 8 and Fluid 9. The 13Cr-HPl-110 coupon included a martensitic stainless steel material comprising a modified 13 chrome alloy formulated for corrosion resistance. 13Cr-HPl-110 materials are quenched and tempered materials intended for corrosion resistance in carbon dioxide environments including chlorides at temperatures up to about 176.7°C (about 35O°F). A coupon was exposed to Fluid 8 at about 500 psi nitrogen and about 5 volume percent of carbon dioxide at about 146.1°C (about 295°F) and another coupon was exposed to Fluid 9 at the same conditions. Each coupon was exposed to the respective fluid for about 28 days. Table 4 below shows the results of the testing. With reference to Table 4, the coupon exposed to Fluid 8 exhibited a deep, wide crack and the coupon exposed to Fluid 9 did not experience any cracking or pitting, indicating that the corrosion inhibitor composition of Fluid 9 successfully prevented stress corrosion cracking of the coupon.Table 4

[0085] The embodiments of wellbore fluids including the corrosion inhibitor composition have been primarily described with reference to completion operations; the corrosion inhibitor composition described herein may be used in other wellbore operations. The corrosion inhibitor composition may be provided to a fluid that is in contact with wellbore equipment, piping, and tubing for an extended period of time; exhibits a corrosivity; is exposed to corrosive conditions (e.g., carbon dioxide in the presence of water, which may form carbonic acid and cause corrosion); or otherwise exposed to conditions that may increase corrosiveness (e.g., high temperatures, highDocket No. IS23 1472-WO-PCT pressures). 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. In addition, the wellbore fluids may be used in cased completion wellbores and in open hole completion wellbores.

[0086] In some embodiments, the wellbore fluids may be used in wellbores to be used for hydrocarbon recovery, for carbon capture, utilization, and storage (CCUS), and / or for recovery and use of geothermal energy. Geothermal energy is a promising source of renewable energy that captures energy from heat generated within the earth. For example, geothermal energy may be used to heat structures (e.g., buildings) and / or to generate electricity (e.g., by heating water to generate steam and drive a turbine with the steam). The wellbore fluids described herein may be used in wellbores used to circulate a fluid that is heated within the earth formation through which the wellbore extends. The heated fluid may be circulated to the surface where the captured heat may be recovered to heat a structure and / or generate electricity, followed by recirculation of the fluid to the earth formation to continue the cycle.

[0087] CCUS facilitates the capture, use, and / or storage of carbon (e.g., carbon dioxide), which has a goal of achieving carbon neutrality and / or net zero carbon emissions (NZE). CCUS may facilitate the capture of carbon dioxide from large point sources (e.g., power plants, refineries, cement plants, other industrial processing plants, or other industrial facilities that use fossil fuels, biomass fuels, or other fuels that generate carbon dioxide). The captured carbon dioxide may be converted into valuable products such as, for example, ethanol, sustainable aviation fuel, chemicals, and mineral aggregates. Alternatively, the carbon dioxide may be stored in geologic formations, such as in depleted hydrocarbon reservoirs. The carbon dioxide may be introduced into the earth formation through a wellbore. In the earth formation, the carbon dioxide may be dispersed in an aqueous phase and stored as carbon dioxide, in mineral form (e.g., as a carbonate, such as calcium carbonate, magnesium carbonate, iron(II) carbonate), or as another form of carbon. The corrosion inhibitor composition may be provided to such wellbores, such as with the carbon dioxide or another wellbore fluid.

[0088] 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 developmentDocket No. IS23 1472-WO-PCT of any such actual implementation, as in any engineering or design project, numerous embodimentspecific 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.

[0089] The articles “a,” “an,” and “the” are intended to mean that there are one or more of the elements in the preceding descriptions. The terms “comprising,” “including,” and “having” are intended to be inclusive and mean that there may be additional elements other than the listed elements. 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 ordinary skill 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.

[0090] 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. EachDocket No. IS23 1472-WO-PCT addition, deletion, and modification to the embodiments that falls within the meaning and scope of the claims is to be embraced by the claims.

[0091] The terms “approximately,” “about,” and “substantially” as used herein represent an amount close to the stated amount that 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.

[0092] 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 the appended 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

Docket No. IS23 1472-WO-PCTCLAIMSWhat is claimed is:

1. A wellbore fluid, comprising. an aqueous base fluid comprising: water; and at least one salt; and a corrosion inhibitor composition comprising: at least one of morpholine or hydroxy ethyl morpholine; and ascorbic acid, the corrosion inhibitor composition including at least about 0.80 part by weight of the at least one of morpholine or hydroxyethyl morpholine per every about 1.0 part by weight of the ascorbic acid.

2. The wellbore fluid of claim 1 , wherein the corrosion inhibitor composition includes a greater weight percent of the at least one of morpholine or hydroxyethyl morpholine than of the ascorbic acid.

3. The wellbore fluid of any preceding claim, wherein the corrosion inhibitor composition consists essentially of the ascorbic acid and the at least one of morpholine or hydroxyethyl morpholine.

4. The wellbore fluid of any preceding claim, wherein the corrosion inhibitor composition includes at least about 0.90 part by weight of the at least one of morpholine or hydroxyethyl morpholine per every about 1.0 part by weight of the ascorbic acid.

5. The wellbore fluid of any preceding claim, wherein the corrosion inhibitor composition is free of antimony or antimony-containing compounds.

6. The wellbore fluid of any preceding claim, wherein the corrosion inhibitor composition includes hydroxy ethyl morpholine.Docket No. IS23 1472-WO-PCT7. The wellbore fluid of any preceding claim, wherein the at least one salt includes at least one of calcium chloride or calcium bromide.

8. The wellbore fluid of any of claims 1-6, wherein the at least one salt includes at least one of zinc bromide, sodium chloride, sodium bromide, or potassium chloride.

9. The wellbore fluid of any preceding claim, wherein the aqueous base fluid has a density greater than about 1,080 kg / m3.

10. The wellbore fluid of any preceding claim, further comprising one or more of a bridging material, a viscosifiers, a fluid loss materials, a sealant, a dispersion aid), a weighting material, a shale stabilizer, a shale inhibitor, a pH buffer, an emulsifier, an emulsion activator, a gelling agent, a defoamer, a surfactant, a foaming agent, a scale inhibitor, a biocides, or an oxygen scavenger.

11. The wellbore fluid of any preceding claim, wherein the wellbore fluid includes a completion fluid, a packer fluid, a workover fluid, or a kill fluid.

12. The wellbore fluid of any preceding claim, wherein the corrosion inhibitor composition constitutes from about 11.4 kg / m3to about 28.6 kg / m3.

13. A wellbore fluid, comprising: a brine having a density greater than about 1,080 kg / m3; and a corrosion inhibitor composition comprising: greater than about 45.0 weight percent of a first component comprising one or more of morpholine, hydroxy ethyl morpholine, or a morpholine derivative; and a second component comprising one or more of ascorbic acid, isoascorbic acid, an ascorbate salt, or an erythorbate salt.Docket No. IS23 1472-WO-PCT14. The wellbore fluid of claim 13, wherein the corrosion inhibitor composition is free of antimony or antimony-containing compounds.

15. The wellbore fluid of claims 13 or 14, wherein the corrosion inhibitor composition includes hydroxyethyl morpholine.

16. The wellbore fluid of any of claims 13-15, wherein the corrosion inhibitor composition includes a greater weight percent of the first component than of the second component.

17. The wellbore fluid of any of claims 13-15, wherein a ratio of the first component to the second component is within a range of from about 1.0: 1 1 to about 1.0:0.90.

18. The wellbore fluid of any of claims 13-17, wherein the corrosion inhibitor composition consists essentially of the ascorbic acid and the at least one of morpholine or hydroxyethyl morpholine.

19. The wellbore fluid of any of claims 13-18, wherein the brine includes calcium chloride, calcium bromide, zinc bromide, or combinations thereof.

20. A method of operating a wellbore, the method comprising: performing one or more completion operations with a wellbore fluid, the wellbore fluid comprising: water; at least one of calcium chloride, calcium bromide, zinc bromide, sodium chloride, sodium bromide, or potassium chloride; and a corrosion inhibitor composition comprising: at least one of morpholine or hydroxy ethyl morpholine; and ascorbic acid,Docket No. IS23 1472-WO-PCT the corrosion inhibitor composition including at least about 0.80 part by weight of the at least one of morpholine or hydroxy ethyl morpholine per every about 1.0 part by weight of the ascorbic acid.

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