Method for in-SITU flow control treatment using brines infused with co 2

Abstract

A method for enhancing the production of hydrocarbons such as oil from a wellbore extending into a hydrocarbon reservoir. The method includes identifying a fissure within the hydrocarbon reservoir that is in fluid communication with the wellbore and injecting calcium brine solution and liquid carbon dioxide into the well bore so that the calcium brine solution may react with the carbon dioxide to precipitate calcite and substantially prevent fluid flow through the fissure. The method may enable selected fissures to be sealed thereby enhancing the overall productivity of the well. Other applications of the calcite precipitation method are also disclosed.

Description

METHOD FOR IN-SITU FLOW CONTROL TREATMENT USING BRINES INFUSED WITH CO2CROSS REFERENCE TO RELATED APPLICATIONS

[0001] This application claims the priority benefit under 35 U.S.C. § 119 of U.S. Provisional Application No. 63 / 552,643 filed February 12, 2024, entitled “Method for In-Situ Flow Control Treatment Using Brines Infused with CO2, the entire contents of which are fully incorporated by reference herein for all purposes. This application is also a continuation-in-part application of U. S. Patent Application No. 18 / 763,797 filed July 3, 2024, entitled METHOD FOR ENGINEERED GEOTHERMAL SYSTEM TREATMENT USING BRINES,” which is a continuation application ofU.S. Patent Application No. 18 / 124,074 filed March 21, 2023, now U.S. Patent No. 12,054,666, entitled “METHOD FOR ENGINEERED GEOTHERMAL SYSTEM IN-SITU CONFORMANCE IMPROVEMENT TREATMENT USING BRINES INFUSED WITH CO2,” which is a divisional application of U.S. Patent No. 11,732,178 filed August 4, 2022, entitled “METHOD FOR ENGINEERED GEOTHERMAL SYSTEM IN-SITU CONFORMANCE IMPROVEMENT TREATMENT USING BRINES INFUSED WITH CO2,” which is related to and claims priority under 35 U.S.C. § 119 from U.S. Provisional Application No. 63 / 229,402 filed August 4, 2021, entitled “Apparatus and Method for Engineered Geothermal System in-Situ Conformance Improvement Treatment using Brines Infused with CO2 (In-Situ Conformance Improvement Treatment (ICIT)),” the entire contents of which are fully incorporated by reference herein for all purposes.BACKGROUND

[0002] At least some known subterranean technologies include drilling at least one well into the earth to extract minerals, hydrocarbons (e.g., oil and / or gas), and / or heat from the earth for use on the surface. For example, hydrocarbon, e.g., oil and gas, extraction facilities typically include at least one well that has been drilled into the earth to free and extract the oil and gas from the ground. These methods typically include drilling a deep hole into the hydrocarbon reservoir and the placement of a casing within the hole which is then surrounded by cement to form a wellbore. Perforations are made at various locations along the length of the wellbore to provide fluid access to the surrounding hydrocarbon reservoir. A fluid, e.g., a fracking fluid, is then pumped down thewellbore and enters the reservoir, creating fractures (e.g., fissures) within the reservoir to enhance the flow of oil and / or gas into the wellbore.

[0003] However, during the fracking process, the resultant condition of the reservoir rock may cause unexpected damage to the earth proximate the well and within the hydrocarbon reservoir. Further, some fissures may produce oil at an economically acceptable rate for a period of time, but then the production from that fissure may slow or completely stop. In such instances, it may be desirable to selectively plug that fissure so that resources may be diverted to higher producing fissures in the well.

[0004] Such flow diversions may be accomplished using polymers that are injected into the wellbore. However, such polymers have limited efficacy in many situations. For example, most of these flow diversion polymers degrade under certain conditions of high temperature (e.g., above about 275°F, or 135°C), high pressure and / or a pH that is too acidic or too basic.SUMMARY

[0005] A number of embodiments of a method of repairing or enhancing a well, e.g., the reservoir rock surrounding a wellbore and methods of selectively sealing the reservoir surrounding a wellbore are presented in this application.

[0006] The embodiments described herein include a method of repairing and / or enhancing a well and a method of removing oil, gas and / or other hydrocarbons from rock in a hydrocarbon reservoir. The methods may include injecting a brine solution into the well, injecting carbon dioxide into the well, and reacting the brine solution with the carbon dioxide to form calcite such that calcite precipitates and seals, e.g., repairs, undesirable fissures or short circuits in the reservoir rock in contact with fluids injected for oil and / or gas recovery.

[0007] In one embodiment, a method for enhancing the production of hydrocarbons from a wellbore extending into a hydrocarbon reservoir is disclosed. The method includes the steps of identifying a fissure within the hydrocarbon reservoir that is in fluid communication with the wellbore. Calcium brine solution is injected into the wellbore such that the calcium brine solution penetrates the fissure. Liquid carbon dioxide is also injected into the wellbore such that the liquid carbon dioxide penetrates the fissure. The calcium brine solution and the liquid carbon dioxideare allowed to react within the fissure to precipitate calcite and substantially prevent fluid flow through the fissure.

[0008] In another embodiment, a method for the repair of a subterranean storage reservoir comprising a downhole bore and a plurality of outwardly extending fissures in fluid communication with the downhole bore is disclosed. The method includes the steps of identifying a fissure within the storage reservoir that is in fluid communication with the wellbore. A calcium brine solution is injected into the wellbore such that the calcium brine solution penetrates the fissure. Liquid carbon dioxide is also injected into the wellbore such that the liquid carbon dioxide penetrates the fissure. The calcium brine solution and the liquid carbon dioxide are allowed to react within the fissure to precipitate calcite and substantially prevent fluid flow within the fissure.

[0009] In one characterization, the subterranean storage reservoir is a carbon dioxide storage reservoir, e.g., for use in a carbon capture, utilization and storage (CCUS) facility. In another characterization, the subterranean storage reservoir is a water reservoir, e.g., for the storage of produced water, drilling solutions, and the like.

[0010] In another embodiment, a method for the construction of a wellbore is disclosed. The method includes the steps of drilling a subterranean bore, placing a liner within the subterranean bore, and affixing the liner within the subterranean bore. The step of affixing the liner includes injecting a calcium brine solution into an annular region surrounding the liner and injecting liquid carbon dioxide into the annular region surrounding the liner. The calcium brine solution and the liquid carbon dioxide are allowed to react within the annular region surrounding the liner to precipitate calcite and affix the liner within the subterranean bore, e.g., for subsequent fracking operations.

[0011] In other embodiments, various compositions of a calcium brine solution are disclosed. The calcium brine solutions comprise appreciable concentrations of calcium, e.g., in the form of calcium chloride. The calcium brine solutions may also comprise additional components that facilitate and / or control the precipitation of calcite from the calcium brine solutions when the brine solutions are contacted with carbon dioxide, e.g., with liquid carbon dioxide. These additional components may be added to the calcium brine solution or the calcium brine solution, e.g., anaturally occurring calcium brine solution, may be treated to remove or reduce the concentration of certain naturally occurring components.

[0012] Such components may include one or more pH adjusters, such as ammonium hydroxide, where the pH adjuster is selected to adjust the pH of the calcium hydroxide solution to a pH of at least about 7. The components may also include a reaction inhibitor that is selected to inhibit the reaction of the calcium brine solution with carbon dioxide and provide sufficient time for the brine solution and carbon dioxide to reach the desired fissure(s) before reacting. Such reaction inhibitors may be, for example, copper or zinc. The calcium brine solution may also include a nucleation agent that is selected to facilitate, e.g., to speed up, the crystallization of the calcite from the reactants. Such nucleation agents may include mineral powders or microproppants for example.

[0013] There are other novel aspects and features of this disclosure. They will become apparent as this specification proceeds. Accordingly, this brief summary is provided to introduce a selection of concepts in a simplified form that are further described below in the detailed description. The summary and the background are not intended to identify key concepts or essential aspects of the disclosed subject matter, nor should they be used to constrict or limit the scope of the claims. For example, the scope of the claims should not be limited based on whether the recited subject matter includes any or all aspects noted in the summary and / or addresses any of the issues noted in the background.DRAWINGS

[0014] The preferred and other embodiments are disclosed in association with the accompanying drawings in which:

[0015] FIG. 1 illustrates a flow diagram of a method of repairing a well in accordance with aspects of the present disclosure.

[0016] FIG. 2 illustrates a flow diagram of a method of preparing a brine solution in accordance with aspects of the present disclosure.

[0017] FIG. 3 illustrates a flow diagram of a method of fracturing a well in accordance with aspects of the present disclosure.

[0018] FIG. 4 illustrates a flow diagram of a method of removing oil and other hydrocarbons from rock within a well in accordance with aspects of the present disclosure.DESCRIPTION

[0019] A number of embodiments of a method of repairing a well, a method for preparing a brine solution, a method of fracturing a well, and a method of removing oil and other hydrocarbons from rock in a well are presented in this application. In general, each of the methods described herein use a brine solution to repair a well and / or fracture the rock around a well and remove oil and other hydrocarbons from rock in the well. Specifically, in the illustrated embodiments, the brine solution includes a calcium brine solution. More specifically, in the illustrated embodiments, the brine solution includes a calcium brine solution. The calcium brine solution has several unique properties that enable the solution to repair and / or fracture wells of various types.

[0020] Specifically, in some embodiments, the calcium brine solution may be injected into the wellbore with liquid carbon dioxide (CO2) and a pH adjuster such that the calcium brine solution, the liquid carbon dioxide, and the pH adjuster react to precipitate calcite (CaCO.3) in the flow paths where the injected brine is flowing through the fractures outside the walls of the well casing. The calcite precipitates into undesired fissures or short circuits in the flow paths and plugs the undesired fissures or short circuits in the well. As such, the calcium brine solution may be used to improve the efficiency of the well being treated.

[0021] In some embodiments, the calcium brine solution may have a lower freezing point than fluids typically used to fracture a well. Specifically, in some embodiments, the freezing point of the calcium brine solution may be close to 0°F. Injecting the calcium brine solution into the well at 0°F or other reduced temperatures may rapidly reduce the temperature of the well, causing contraction of the rock proximate to the well and causing the rock to further fracture due to thermal contraction.

[0022] Additionally, in some embodiments, the calcium brine solution may be injected into the well with liquid carbon dioxide (CO2) such that fluid can be transferred from rock to the well. The fluid can be directed to a surface facility to produce oil and other hydrocarbons.

[0023] Thus, the brine solutions described herein may be used to provide one or more of the following improvements / advantages over conventional systems: 1) simpler and easier in-situ repair wells, 2) improved fracturing of rock in contact with wells, 3) increased operating temperature and pressure range for fracturing fluids and / or enhanced oil recovery processes.Calcium Brine Solution

[0024] The calcium brine solution is typically an aqueous solution including calcium chloride. Calcium chloride is an inorganic salt with the chemical formula CaCh. It is a white crystalline solid at room temperature, and it is highly soluble in water. In one characterization, the calcium brine solution includes at least about 5 wt.% calcium chloride and not greater than about 15 wt.% calcium chloride.

[0025] In some embodiments, the calcium brine solution may be characterized as a rich calcium brine solution having an increased amount of calcium chloride, e.g., sourced from a geologic reservoir found by exploration and drilling below the surface. In one characterization, the rich calcium brine solution includes at least about 15 wt.% and not greater than about 25 wt.% calcium chloride.

[0026] In some embodiments, the calcium brine solution may be characterized as a supersaturated calcium brine solution having an increased amount of calcium chloride. In one characterization the supersaturated calcium brine solution includes at least about 25 wt.% and not greater than about 40 wt.% calcium chloride.

[0027] Thus, in certain characterizations, the calcium brine solution may include at least about 5 wt.% calcium chloride, such as at least about 15 wt.% calcium chloride, such as at least about 25 wt.% calcium chloride.

[0028] In some embodiments, the calcium brine solution may be characterized by the relatively low concentrations of other ionic species. In one characterization, the calcium brine solution has a relatively low concentration of magnesium (Mg). The presence of magnesium may lead to the formation of dolomite ((Ca,Mg)(CO3)2), which has a low solubility in most acids and therefore may be difficult to remove after operations are completed. In this regard, it is preferred that thecalcium brine solution have a magnesium concentration of not greater than about 5000 ppm, such as not greater than about 1000 ppm.

[0029] As discussed in greater detail below, the calcium brine solution is used in the methods described herein to react with other inj ectants to repair a downhole well, fracture a well, and / or remove oil from rock in a well. More specifically, with respect to repairing a well, the calcium brine solution is used to react with other inj ectants to form calcite precipitates within fissures and short circuits in the adjacent reservoir rock proximate to the well in need of repair. As such, in alternative embodiments, the calcium brine solution may include, in addition to or in lieu of calcium chloride, any calcium containing ionic or covalent compound that enables calcite to precipitate within fissures and short circuits within the well and / or in the reservoir rock proximate to the primary well or adjacent wells. Examples of such calcium containing compounds include, but are not limited to, calcium bromide and calcium carbonate.

[0030] Additionally, the calcium brine solution may be used to absorb heat from rock within the well and, as such, has a high heat capacity. Heat capacity is directly related to the specific gravity (S.G.) of the calcium brine solution, i.e., the density of the solution as compared to the density of pure water. In one characterization, the calcium brine solution may have a S.G. of at least about 1.04, such as at least about 1.13, such as at least about 1.23. In another characterization, the calcium brine solution may have a S.G. of not greater than about 1.40.

[0031] Additionally, as discussed in greater detail below, the calcium brine solution may be chilled and used to fracture rock within the well by causing stresses within the rock due to contraction along one or more stress planes in the rock. As such, the calcium brine solutions described herein have a lower freezing point than typical fracking fluids. For example, the freezing point of the calcium brine solution may be not greater than about 28°F (minus 2.2°C), such as not greater than about 12°F (minus 11.1°C) such a not greater than about minus 22°F (minus 30.0°C), or even not greater than about minus 35 °F (minus 37.2°C). Thus, the calcium brine solution may be injected into a downhole well at a temperature below ambient temperature, such as at a temperature of not greater than about 28°F (minus 2.2°C), such as not greater than about 12°F (minus 11.1°C) such a not greater than about minus 22 °F (minus 30.0°C), or even not greater thanabout minus 35°F (minus 37.2°C). In one implementation, the brine solution is chilled before injection, e.g., to cool the brine solution below ambient, e.g., to such reduced temperatures.

[0032] Additionally, as discussed in greater detail below, the calcium brine solution may be used to remove oil and other hydrocarbons from rock in a well.

[0033] In alternative embodiments, the brine solutions described herein may be any type of brine solution that enables the brine solutions to operate as described herein. For example, the calcium brine solution may include any calcium containing ionic or covalent compound that enables calcite to precipitate within fissures and short circuits within the reservoir rock proximate to the well. Additionally, the brine solution may have any freezing point and / or heat capacity that enables brine solution to operate as described herein.Liquid Carbon Dioxide

[0034] As described herein, liquid carbon dioxide (CO2) may be pumped into wells with the calcium brine solution to react with the calcium in the brine solution to precipitate calcite into the fissures and short circuits formed adjacent to the downhole well. In order to pump the carbon dioxide into well in sufficient quantities to precipitate calcite and plug the fissures and short circuits within the well, the carbon dioxide is preferably in liquid form. More specifically, to maintain the liquid state of the carbon dioxide, the liquid carbon dioxide may be under an elevated pressure of at least 75 pounds per square inch (PSI) (about 517 kPa), and at a temperature below the critical point of about 88.0°F (31.1 °C) and above the triple point of about minus 69.9°F (minus 56.6 °C).

[0035] In some embodiments, liquid carbon dioxide (CO2) is pumped into wells with the calcium brine solution to react with the calcium brine solution to move oil and other hydrocarbons out of the rock. The method by which oil is moved out of the rock can be from improving the performance of enhanced oil recovery (EOR) processes such as waterflooding, CO2 flooding, steam flooding, steam-assisted gravity drainage (SAGD) processes, and / or improved oil recovery (IOR) processes used by oil and gas well operators. The common factor in all these processes is that improving the conformance, i.e., the flow uniformity, of the injected fluid or fluids provides better sweep efficiency withing the hydrocarbon reservoir, and this sweep efficiency may be optimized by the methods described herein.

[0036] In alternative embodiments, the liquid carbon dioxide may have any pressure and temperature that enables the methods described herein to operate as described herein. Additionally, in alternative embodiments, rather than carbon dioxide, any chemical may be injected into the well with the calcium brine solution that enables the precipitation of calcite. Examples include, but are not limited to, calcium oxide, hydrated carbon dioxide and carbonic acid. pH Adjuster

[0037] As discussed in greater detail below, the calcium brine solution is used in the methods described herein to react with other inj ectants to repair a well, fracture a well, and / or control the flow of injected fluids within a well or adjacent to a well or wells. Such calcium brine solutions may have a slightly acidic pH, e.g., in the range of about 1.5 to 5. This lower pH may reduce the chance of selectively plugging established and created flow paths. In this regard, a pH adjuster may be used to adjust the pH of the inj ectants to facilitate the precipitation reaction between calcium and carbon dioxide. In one embodiment, the pH adjuster is a base or proton donor that adjusts the pH of the liquid CO2 and calcium chloride brine solution to become more basic, e.g., to have a higher pH. In one implementation, the pH adjuster includes ammonium hydroxide (NH4OH). Ammonium hydroxide adjusts the pH of the inj ectants such that the precipitation reaction to form calcite occurs fast enough to precipitate calcite and plug the fissures and short circuits within the flowpaths encountered by the treatment fluid being pumped, e.g., to repair the downhole well.

[0038] The concentration of the ammonium hydroxide pH adjuster may be determined by lab testing conducted as part of the planned well repair (ICIT) treatment. In one implementation, the pH of the inj ectants after a pH adjuster such as ammonium hydroxide has been added may be from approximately 7.0 to approximately 9.0.

[0039] In alternative embodiments, the pH adjuster may be any solution that adjusts the pH such that the precipitation reactions described herein proceed fast enough to precipitate calcite as described herein. Examples include, but are not limited to, sodium hydroxide (NaOH) and mixed metal hydroxide (MMH). The method of introducing the pH adjuster may include using an encapsulation technique wherein the pH adjuster is sealed with a coating or shell that is activated, e g., is dissolved, by temperature, pH, or contact with a particular type of fluid in the reservoir.Such an encapsulation technique may prevent the pH adjuster from coming into contact with the brine solution until the brine solution reaches the fissures or short circuits of interest.Metals Or Other Reaction Inhibitors Within The Calcium Brine Solution

[0040] In some embodiments, the calcium brine solution may include components that inhibit or retard the precipitation reaction described herein. For example, in some embodiments, the calcium brine solution may include copper (Cu) or zinc (Zn). The copper and / or zinc may inhibit or retard the precipitation reaction such that the reaction does not occur in sufficient precipitation speed or quantities to plug the fissures and / or short circuits within the well. As such, in order to react the inj ectants as described herein, the copper and / or zinc may be removed from the calcium brine solution to sufficiently low concentrations to permit the precipitation reaction to occur as designed.

[0041] Additionally, the copper and / or zinc may be used to delay, tune, or adjust the precipitation reaction such that the precipitation reaction occurs at a specific location within the well. For example, if a short circuit has been detected within a hydrocarbon reservoir at a specific location within the flow path that the calcium brine solution follows as it exits the wellbore perforations, a predetermined amount of copper and / or zinc may be added to the calcium brine solution to inhibit or retard the precipitation reaction until the calcium brine solution has reached the short circuit. When the calcium brine solution reaches the location of the short circuit within the well, the copper and / or zinc within the calcium brine solution has been reacted or otherwise used such that the precipitation reaction to form calcite is allowed to proceed, and the short circuit is plugged with calcite. As such, the copper and / or zinc in the brine solution enables the inj ectants to target specific regions further outside the well and within the injected brine flow paths that are targeted for repair.

[0042] In one implementation, the calcium brine solution may include approximately 1 mg / L to approximately 5 mg / L of copper, approximately 5 mg / L to approximately 25 mg / L of copper, and / or approximately 25 mg / L to approximately 250 mg / L of copper. Additionally, the calcium brine solution may include approximately 1 mg / L to approximately 5 mg / L of zinc, approximately 5 mg / L to approximately 25 mg / L of zinc, and / or approximately 25 mg / L to approximately 250 mg / L of zinc. In alternative embodiments, the calcium brine solution may include anyconcentration of copper and zinc, e g., as listed above, that enables the calcium brine solution to operate as described herein.

[0043] In alternative embodiments, the calcium brine solution may include any reaction inhibitor and / or any reaction retarding agent that enables the calcium brine solution to operate as described herein.Nucleation Agents

[0044] In some embodiments, nucleation agents may be utilized to provide nucleation sites, e.g., to enhance the precipitation of calcite from the brine solution. In one implementation, the nucleation agent comprises a fine mineral powder such as a fine mineral powder comprising calcite powder. Such mineral powders are readily available in a variety of particle sizes that are suitable for use as a nucleation agent. In one characterization, the mineral powder has a mean average particle size of at least about 25 pm, such as at least about 35 pm. In another characterization, the mineral powder has a mean average particle size of not greater than about 200 pm, such as not greater than about 150 pm.

[0045] In another implementation, the nucleation agent comprises proppants, particularly microproppants. Microproppants are available in a variety of forms and generally are fine-sized particles or beads of relatively inert and strong (e.g., high compressive strength) materials such as sand, e.g., silica, or a ceramic material such as an alumina-based material, clay materials such as kaolin or zirconia. For use as a nucleation site, the microproppants may have a mean average particle size of at least about 25 pm, such as at least about 35 pm. In another characterization, the microproppants may have a mean average particle size of not greater than about 75 pm, such as not greater than about 75 pm. However, it is contemplated that other sizes of microproppants may be effective as well depending on the application.

[0046] Other types of microproppants that may be useful are known to those of skill in the art. Further, it will be appreciated that combinations of two or more types of microproppants may be utilized as the nucleation agent. Further, a combination of fine mineral powder and microproppants may also be utilized.

[0047] The nucleation agents may be added with the brine solution, e.g., by dispersing the microproppants within the brine solution, or may be added prior to injection of the brine solution. In either case, the concentration of the nucleation agents will typically be at least about 0.25 lbs. / gallon and not greater than about 0.5 lbs. / gallon based on the volume of brine solution that is injected into a well, although higher concentrations are contemplated such as up to about 2.0 lbs. / gallon.Method Of Repairing A Well

[0048] FIG. 1 illustrates a flow diagram of a method 100 of repairing a well, e.g., a hydrocarbon well. As shown in FIG. 1, the method 100 includes injecting 102 a calcium brine solution into a well. In some embodiments, the brine solution may include a rich brine solution or may be a supersaturated calcium brine solution, as described above.

[0049] The method 100 may further include injecting 104 carbon dioxide into the well. In the illustrated embodiment, the carbon dioxide includes a liquid carbon dioxide as described above. In alternative embodiments, the carbon dioxide may include a chemical that includes carbon dioxide that disassociates from the chemical to react with the brine solution as described above.

[0050] The method 100 may further include reacting 106 the brine solution with the carbon dioxide to form calcite such that calcite precipitates into fissures surrounding the wellbore and repairs, e.g., seals, the fissures, as shown in EQNS. 1 and 2 below:CO2+ H2O H2CO3 (1)CaCh + H2CO3 + NH4OH CaCCh (2)

[0051] As is known to those of skill in the art, fissures surrounding the wellbore that may need to be sealed can be identified using thermal, acoustic or similar techniques. Packers may then be selectively placed in the wellbore so that the calcium brine and carbon dioxide selectively flow through the wellbore perforation(s) that are fluidly connected to the fissures of interest.

[0052] As shown in EQNS. 1 and 2, carbon dioxide reacts with water to form carbonic acid (H2CO3) which reacts with calcium chloride (CaCh) in the presence of ammonium hydroxide (NH4OH ) to form calcite. The calcite precipitates into a solid within the fissure to plug the fissure and thereby prevent or restrict the flow of fluids in the fissure.

[0053] As shown in EQNS. 1 and 2, the method 100 may include injecting 108 a pH adjuster into the well with the brine solution and the carbon dioxide. The pH adjuster may include a basic solution, and in the illustrated embodiment, the pH adjuster includes ammonium hydroxide. The pH adjuster is configured to adjust the pH of the brine solution and the carbon dioxide such that calcite is precipitated within the fissure or fracture of interest. More specifically, as described above, the pH adjuster may adjust the pH of the inj ectants to a range of from approximately 7.0 to approximately 9.0.

[0054] The method 100 may further include adjusting 110 a concentration of a reaction inhibitor within the calcium brine solution. Specifically, the concentration of the reaction inhibitor may be reduced or increased to a concentration that delays the calcite precipitation reaction described herein, e.g., delays the precipitation reaction until the calcium brine and CO2 are disposed at a desirable location within the fissure. Additionally, the concentration of the reaction inhibitor may be reduced to a concentration that permits the calcite precipitation reaction to occur uninhibited described herein. The presence of metal ions in fairly low concentrations (typically <500 ppm) can inhibit the calcite precipitation process. When the metal ions are naturally present in the brine solution in concentrations greater than the desired concentrations, the metal ions may be selectively removed, e.g., to less than approximately 10 ppm, prior to pumping the calcium brine solution, thereby increasing the speed and efficiency of the calcite precipitation process. This provides an on-site treatment lever that provides unique control over the level of flow re-direction from existing flow paths to new or more effective flow paths within the hydrocarbon reservoir. In this process, the oil and / or gas recovery from the hydrocarbon bearing reservoir targeted by the brine process fluid using ICIT conformance technology may be improved.

[0055] In some applications, the method 100 may further include removing 112 the precipitated calcite from the fissures after other operations have been completed. In one characterization, the precipitated calcite may be removed using an acidic solution. More specifically, if the calcite precipitated in the formation fractures is to be removed in all or part, an acidizing treatment may be used. This type of remedial acidizing treatment has been used to remove calcite scale and similar limestone and dolomite minerals from oil and gas reservoirs. Therefore, the risk of completely “sealing off’ a flow path from injector to producer is mitigated and manageable. Examples of useful acidic solutions for this purpose include, but are not limitedto, hydrochloric acid (HO) and acetic acid (CH3COOH) Further, the introduction of the acid may be in a controlled release fashion such that the acid is not made available until a known period of time has passed. One example of such a method is illustrated in US Patent No. 11,661,545 by Zakaria, which is incorporated herein by reference in its entirety.

[0056] Method 100 includes direct, in-situ flow path intervention placed via the wellbore. A specified thru-wellbore treatment which uses industrial grade fluids including calcium brine, liquid carbon dioxide, and one or more pH adjusters is pumped through the injection well's completed zone(s).

[0057] During some oil and gas well drilling and completion projects at borehole, e.g., at temperatures under about 275 °F, the use of a stable brine solution with similar physical and chemical properties is an accepted and proven method of controlling abnormally high well pressures and mitigating clay swelling and salt zone erosion when drilling and completion fluids contact certain susceptible formations. Polymer additives are often used in these situations; however, they have no applicability above 275 °F as they degrade and lose the viscosity -building properties they are designed to provide and hence are not applicable for use in many drilling and completion projects. This same viscosity degradation is common for all common fracturing (frac) fluids that contain linear gels or crosslinked gel systems as their base fluids. These gelled fluids typically have a S. G. of 8.34 - 9.0 prior to the addition of proppant. This loss of viscosity and proppant carrying capacity can preclude these gel systems for certain well completions. The only viable multi-stage deep stimulation alternative is to use essentially a clean water with near drinking water levels of minerals for the base drilling and fracturing fluid systems. Proppant loads for these clean frac fluid systems would typically be much lower than one using a brine solution for the base fluid because of the ability of this higher S. G. fluid to carry the additional mass of proppant load without the consequences of well bore and / or near wellbore screen-out.

[0058] The method 100 may improve flow path efficiency in oil and gas reservoir systems and the components may be introduced as a separate, planned and monitored “treatment” aimed to redirect fluid flow in-situ to eliminate or correct “short circuits” in a hydrocarbon reservoir. Post treatment, certain reagents can be placed via injection into the wellbore to ensure that a long-lasting calcite mineralization deposit is retained in the hydrocarbon reservoir over the life of the project.

[0059] Hydrocarbon extraction requires the ability to control the flow of fluids through and throughout the hydrocarbon reservoir. Conventional approaches for altering flow through a reservoir are borehole centric where flow control into or out of a well is centrally managed from the wellbore. Aspects of the technology and techniques set out herein can be used to control flow regimes outside of the wellbore and within the reservoir and to mitigate undesirable flow that degrades the extraction efficacy from such reservoirs.Method For Preparing A Brine Solution

[0060] FIG. 2 illustrates a flow diagram of a method 200 of preparing a calcium brine solution. As shown in FIG. 2, the method 200 includes providing 202 a calcium brine solution. In some embodiments, the calcium brine solution may include a rich brine solution as described above or may include a supersaturated brine solution, as described above.

[0061] In the illustrated embodiment, the calcium brine solution may include one or more reaction inhibitor(s) that inhibit or slow the precipitation reaction that forms calcite. As described above, the reaction inhibitors may include metal ions including copper and zinc. In order to enable the precipitation reaction to occur as described herein, the method 200 may further include adjusting 204 a concentration of the reaction inhibitors within the calcium brine solution. More specifically, in some embodiments, adjusting 204 a concentration the reaction inhibitors within the calcium brine solution may include reducing 206 the concentration of the reaction inhibitors within the calcium brine solution. In alternative embodiments, adjusting 204 a concentration of the reaction inhibitors within the calcium brine solution may include increasing 208 the concentration the reaction inhibitors within the calcium brine solution.

[0062] The method 200 may further include adding 210 a pH adjuster to the calcium brine solution to adjust a pH of the calcium brine solution. The pH adjuster is selected to adjust the pH of the calcium brine solution such that calcite is precipitated within a fissure of a reservoir, e.g., a hydrocarbon reservoir. More specifically, as described above, the pH adjuster may adjust the pH of the calcium brine solution to approximately 7.0 to approximately 9.0.Method Of Fracturing A Well

[0063] In some embodiments, the brine solution may be cooled, e.g., super-cooled to below the approximate 32°F freeze point of typical water based drilling and fracturing fluids. For example, a calcium brine solution having a concentration of 38 wt.% calcium chloride will have a freezing point of approximately minus 35°F (about minus 37.2 °C). As such, the costs of heating fracturing fluids on the surface using propane or natural gas fired “hot oilers” may be eliminated in northern climates during the colder months. In certain applications, pre-chilling the calcium brine solution fracturing fluid and circulating through the wellbore to cool the near wellbore region can provide a novel means of ensuring that any number of wireline conveyed electronic instruments that are unreliable at temperatures above about 275 °F (about 135 °C) can function and survive the trip in and out of the wellbore.

[0064] Additionally, the calcium brine solution may be super-cooled and inj ected into the well to further fracture the reservoir rock in contact with the super-cooled injected fluids injected in the wellbore as part of the completion process. More specifically, because the calcium brine solution has a freezing point below the freezing point of water, the calcium brine solution may be injected into the well at temperatures that are below the lower operating temperatures of most fracturing fluids. The super-cooled calcium brine solution thermally contacts the rock within the well, substantially cooling and thermally contracting the rock. The thermal contractions cause the rock to fracture within the well.

[0065] FIG. 3 illustrates a flow diagram of a method 300 of fracturing a well. The method 300 includes drilling 302 at least one well. The method 300 also includes super-cooling 304 a calcium brine solution. The method 300 further includes injecting 306 the calcium brine solution into the well. In some embodiments, the brine solution may include a rich calcium brine solution as described above. In some embodiments, the calcium brine solution may include a supersaturated calcium brine solution as described above. The method 300 also includes transferring heat 308 from the rock to the brine solution. The method 300 further includes thermally contracting and fracturing 310 the rock.Method Of Removing Oil And Other Hydrocarbons From Rock Within A Well

[0066] In some embodiments, the brine solution and liquid carbon dioxide may be injected into a well and utilized to enhance the recovery of hydrocarbons, e.g., oil and / or gas, from the well.In one implementation, the brine solution and liquid carbon dioxide may be injected into a well for the purposes of enhanced oil recovery (“EOR”).

[0067] EOR, also known as tertiary recovery, encompasses a group of techniques that are used to extract more oil from an oil reservoir than would otherwise be possible using conventional techniques. That is, EOR typically includes the extraction of oil from a reservoir, e.g., an oil field, that would be difficult to extract by conventional methods. When a well is first produced, the pressure in the subsurface provides the energy for moving the oil, gas and water that is in the rock to the surface. The pressure dissipates over time. While pumps may be used to remove additional oil, a considerable amount of the oil may be left behind. Common EOR techniques include, but are not limited to, water flooding, gas flooding such as with CO2 and steam injection.

[0068] In the illustrated embodiment, the calcium brine solution is selectively injected into the well, e.g., to target selected fissures, and the operator may then resume production from the well with increased production efficiency. In the illustrated embodiment, the brine solution includes a calcium brine solution. CO2 is miscible with oil and is therefore used for injection with the calcium brine solution into the reservoir, e.g., into the pore spaces of the rock to displace oil from the rock pores. Alternatively, where CO2 flooding is utilized, a sufficient amount of CO2 may be available such that the injected CO2 may be eliminated or the amount injected may be reduced. The oil can be swept towards producing wells and pumped to the surface, e.g., where it can flow to a collection facility.

[0069] In alternative embodiments, the brine solution may be any type of brine solution. This method may be used in diversion of injected fluids in EOR fields and in fracturing of hydrocarbon wells, including shale wells. Additionally, this method is capable of operating at all temperatures (e.g., in excess of 250 °F) and pressures, not just above typical oil and gas field temperatures, allowing the application in higher temperature hydrocarbon reservoirs in sedimentary basins settings, as well as granitic hot dry rock applications than can typically be achieved using polymer diversion materials. This method is also reversible by using an acid (e.g., hydrochloric acid) to dissolve the calcite at a later time, the method reduces costs as compared to polymer diversion materials, and is a carbon negative process, as the CO2 is converted chemically through a mineral carbonation process to form calcite.

[0070] Additionally, in some embodiments, the brine treatment includes injecting the calcium brine solution into the wellbore with liquid CO2 and other chemicals and remains in the well for a predetermined amount of time. During the predetermined amount of time, the brine provides additional calcium ions that react with the carbonic acid formed in the well as part of the disclosed brine treatment, allowing flow of oil and gas from less drained areas of the rock. An acid may be injected into the well during the treatment or at any time after the treatment if it is desired to remove the calcite formed by the brine treatment from the well, e.g., to restore all or part of the wells’ flow capacity. In the illustrated embodiment, the acid includes hydrochloric acid. In alternative embodiments, the calcite may be removed by any chemical and the acid may include any acid or any other chemical that is capable of solubilizing calcite, e.g., acetic acid. In the illustrated embodiment, removal of the calcite re-establishes flow paths that may become desirable for the efficient operation of a well or system of wells in contact with a hydrocarbon reservoir. After the brine treatment, the well may resume production, e.g., with increased production of oil or other hydrocarbons as a desired result.

[0071] In some embodiments, the disclosed brine solution may be injected into a well to improve conformance of an injected EOR drive fluid to improve the uniformity of the flood front of the injected drive fluid within the well. Additionally, in some embodiments, the brine solution may be injected into the well multiple times. For example, the well may be treated with the brine solution multiple times over a period of time to achieve the desired result in terms of flow control and re-direction, or to shut off flow from a portion of the well completion, such as in a horizontal shale well that has been completed with a large number of fracturing stages with several subordinate perforation clusters within each stage.

[0072] As described above, the brine solution flows through the well, and the brine solution may absorb oil and gas from the well. More specifically, residual oil and gas within the well may be absorbed into the brine solution and may be recovered at the surface facility. As such, the method described herein may be used to recover oil and gas as the brine solution is being used for other purposes such as those described herein.

[0073] FIG. 4 illustrates a flow diagram of a method 400 of removing oil from rock within a well using a brine solution of the disclosed technology. The method 400 includes drilling 402 atleast one well. The method 400 further includes injecting 404 a calcium brine and liquid CO2 into the well, where it moves to rock, and through fractures and smaller pore spaces of the rock. In some embodiments, the brine solution may include a rich brine solution as described above. In some embodiments, the brine solution may include a supersaturated brine solution as described above. The method 400 also includes transferring fluid 406, including oil displaced by the brine solution, from the rock to the well. The method 400 may further include flowing 408 the fluid 406 to a surface facility. The fluid may be separated using oil and gas processes known to one of ordinary skill in the art. The method 400 may include producing oil 410 at the surface facility as a result of using the brine solution. Producing oil 410 at the surface facility using the brine solution may include producing oil using an artificial lift system.

[0074] A number of embodiments of a method of repairing a well, a method for preparing a brine solution, and a method of fracturing a well are presented in this application. In general, each of the methods described herein use a brine solution to repair a well, absorb heat from a well, and / or fracture the rock around a well. Specifically, in the illustrated embodiments, the brine solution includes a calcium brine solution. More specifically, in the illustrated embodiments, the brine solution includes a calcium rich brine solution. The calcium brine solution has several unique properties that enable the solution to repair and / or fracture wells and absorb heat from the rock within a well.

[0075] Specifically, in some embodiments, the calcium brine solution may be injected into the well with liquid carbon dioxide (CO2) and pH adjuster such that the calcium brine solution, the liquid carbon dioxide, and the pH adjuster react to precipitate calcite (CaCCh) on the walls (casing interior and / or near wellbore flow channels) within the well. Additionally, if desired, calcite may precipitate into undesired fissures or short circuits in the well and plugs the undesired fissures or short circuits in the well. As such, the calcium brine solution may be used to repair wells and ensure that the wells are in compliance with all applicable regulations, including injection fluid containment within a prescribed reservoir rock volume, such as in the case of a Class VI injection well that is drilled for use in a carbon capture, utilization and storage (CCUS) project.

[0076] The techniques disclosed herein may be utilized in many different far-field wellbore applications, e.g., to control fluid flow beyond the immediate perimeter of the well bore. In oneembodiment, the calcium brine solutions may be used for the hydraulic fracturing and / or refracturing of existing shale wells. In this embodiment, a reversible and / or temporary flow diverter composed of calcite, e.g., formed in accordance with the present disclosure, may be utilized to control the length of the hydraulic fracture such that the breakthrough of fracturing fluid into nearby wellbores is mitigated or eliminated.

[0077] In another embodiment, the techniques disclosed herein may be used to affix a wellbore liner into place with calcite that is formed in-situ. Advantageously, the calcium brine solution and liquid CO2 has a lower viscosity than wet cement or wet concrete that is typically used to surround a liner in a wellbore, thereby enabling the brine solution and liquid CO2 to easily flow within the space between the liner and the surrounding casing or rock. Further, after the project is completed, the calcite that is sealing the wellbore liner in place for purposes of fracture treatment may then be treated, e.g., with an acidic solution, to dissolve the calcite such that the wellbore liner may be removed and reused or otherwise recycled.

[0078] In another embodiment, the calcium brine solutions may be used to enhance the integrity of a depleted hydrocarbon reservoir, e.g., so that the hydrocarbon reservoir may be utilized as a carbon sequestration reservoir. In this embodiment, the precipitated calcite may be utilized to ensure that any leaks or potential leaks along or at the end of a fracture within the depleted reservoir are sealed, e.g., before the sequestration of CO2. For example, seismic techniques may be used to identify potential leak zones which can then be selectively targeted by the calcium brine solution and liquid CO2 to seal the leaks. In this regard, the amount of calcium brine and liquid CO2 may be carefully selected based upon the size, e.g., the average diameter and length of the fracture, so that the precipitated calcite only seals the portion of the fracture where the leak exists. In this manner, the remainder of the fracture and the associated pore space volume is available for sequestration. Similar techniques may be applied to water disposal wells, e.g., for the permanent storage of produced water, drilling solutions, etc.

[0079] In summary the brine solutions described herein may be used to provide one or more of the following improvements / advantages over conventional systems: 1) simpler and easier in- situ repair of wells, 2) improved fracturing of rock within wells, 3) improved control of injectedfluids in EOR floods not compatible with polymer diverters or other flow control systems, and / or 4) increased operating range for fracking fluids.Terminology and Interpretative Conventions

[0080] Any methods described in the claims or specification should not be interpreted to require the steps to be performed in a specific order unless stated otherwise. Also, the methods should be interpreted to provide support to perform the recited steps in any order unless stated otherwise.

[0081] Spatial or directional terms, such as “left,” “right,” “front,” “back,” and the like, relate to the subject matter as it is shown in the drawings. However, it is to be understood that the described subject matter may assume various alternative orientations and, accordingly, such terms are not to be considered as limiting.

[0082] Articles such as “the,” “a,” and “an” can connote the singular or plural. Also, the word “or” when used without a preceding “either” (or other similar language indicating that “or” is unequivocally meant to be exclusive - e.g., only one of x or y, etc.) shall be interpreted to be inclusive (e.g., “x or y” means one or both x or y).

[0083] The term “and / or” shall also be interpreted to be inclusive (e.g., “x and / or y” means one or both x or y). In situations where “and / or” or “or” are used as a conjunction for a group of three or more items, the group should be interpreted to include one item alone, all the items together, or any combination or number of the items.

[0084] The terms have, having, include, and including should be interpreted to be synonymous with the terms comprise and comprising. The use of these terms should also be understood as disclosing and providing support for narrower alternative embodiments where these terms are replaced by “consisting” or “consisting essentially of.”

[0085] Unless otherwise indicated, all numbers or expressions, such as those expressing dimensions, physical characteristics, and the like, used in the specification (other than the claims) are understood to be modified in all instances by the term “approximately.” At the very least, and not as an attempt to limit the application of the doctrine of equivalents to the claims, each numerical parameter recited in the specification or claims which is modified by the term “approximately”should be construed in light of the number of recited significant digits and by applying ordinary rounding techniques.

[0086] All disclosed ranges are to be understood to encompass and provide support for claims that recite any and all subranges or any and all individual values subsumed by each range. For example, a stated range of 1 to 10 should be considered to include and provide support for claims that recite any and all subranges or individual values that are between and / or inclusive of the minimum value of 1 and the maximum value of 10; that is, all subranges beginning with a minimum value of 1 or more and ending with a maximum value of 10 or less (e.g., 5.5 to 10, 2.34 to 3.56, and so forth) or any values from 1 to 10 (e.g., 3, 5.8, 9.9994, and so forth).

[0087] All disclosed numerical values are to be understood as being variable from 0-100% in either direction and thus provide support for claims that recite such values or any and all ranges or subranges that can be formed by such values. For example, a stated numerical value of 8 should be understood to vary from 0 to 16 (100% in either direction) and provide support for claims that recite the range itself (e.g., 0 to 16), any subrange within the range (e.g., 2 to 12.5) or any individual value within that range (e.g., 15.2).

[0088] The terms recited in the claims should be given their ordinary and customary meaning as determined by reference to relevant entries in widely used general dictionaries and / or relevant technical dictionaries, commonly understood meanings by those in the art, etc., with the understanding that the broadest meaning imparted by any one or combination of these sources should be given to the claim terms (e.g., two or more relevant dictionary entries should be combined to provide the broadest meaning of the combination of entries, etc.) subject only to the following exceptions: (a) if a term is used in a manner that is more expansive than its ordinary and customary meaning, the term should be given its ordinary and customary meaning plus the additional expansive meaning, or (b) if a term has been explicitly defined to have a different meaning by reciting the term followed by the phrase “as used in this document shall mean” or similar language (e.g., “this term means,” “this term is defined as,” “for the purposes of this disclosure this term shall mean,” etc.). References to specific examples, use of “i.e.,” use of the word “invention,” etc., are not meant to invoke exception (b) or otherwise restrict the scope of therecited claim terms. Other than situations where exception (b) applies, nothing contained in this document should be considered a disclaimer or disavowal of claim scope.

[0089] The subject matter recited in the claims is not coextensive with and should not be interpreted to be coextensive with any embodiment, feature, or combination of features described or illustrated in this document. This is true even if only a single embodiment of the feature or combination of features is illustrated and described in this document.Incorporation by Reference

[0090] The entire content of each of the documents listed below are incorporated by reference into this document. If the same term is used in both this document and one or more of the incorporated documents, then it should be interpreted to have the broadest meaning imparted by any one or combination of these sources unless the term has been explicitly defined to have a different meaning in this document. If there is an inconsistency between any of the following documents and this document, then this document shall govern. The incorporated subject matter should not be used to limit or narrow the scope of the explicitly recited or depicted subject matter.

[0091] U.S. Prov. App. No. 63 / 229,402, titled “Apparatus and Method for Engineered Geothermal System in-Situ Conformance Improvement Treatment using Brines Infused with CO2 (In-Situ Conformance Improvement Treatment (ICIT)),” filed on August 4, 2022.

[0092] While various embodiments of calcium brine solutions and methods for the use of such brine solutions have been described in detail, it is apparent that modifications and adaptations of those embodiments will occur to those skilled in the art. However, it is to be expressly understood that such modifications and adaptations are within the spirit and scope of the present disclosure.

Claims

What is claimed is:

1. A method for enhancing the production of hydrocarbons from a wellbore extending into a hydrocarbon reservoir, comprising the steps of: identifying a fissure within the hydrocarbon reservoir that is in fluid communication with the wellbore; injecting a calcium brine solution into the wellbore such that the calcium brine solution penetrates the fissure; injecting liquid carbon dioxide into the wellbore such that the liquid carbon dioxide penetrates the fissure; and allowing the calcium brine solution and the liquid carbon dioxide to react within the fissure to precipitate calcite and substantially prevent fluid flow through the fissure.

2. The method recited in Claim 1, wherein the calcium brine solution and the liquid carbon dioxide are injected into the wellbore simultaneously.

3. The method recited in Claim 2, further comprising the step of injecting a pH adjuster into the wellbore.

4. The method recited in any one of Claims 1 to 3, wherein the pH adjuster is injected into the wellbore with the calcium brine solution.

5. The method recited in Claim 4, wherein the pH adjuster is selected to modify the pH of the calcium brine solution to a pH of at least about 7.

6. The method recited in Claim 5, wherein the pH adjuster is selected to modify the pH of the calcium brine solution to a pH of not greater than about 9.

7. The method recited in Claim 4, wherein the pH adjuster comprises ammonium hydroxide.

8. The method recited in Claim 4, further comprising injecting a reaction inhibitor into the wellbore.

9. The method recited in Claim 8, wherein the reaction inhibitor is selected from the group consisting of copper, zinc and combinations thereof.

10. The method recited in Claim 9, wherein the reaction inhibitor is injected into the wellbore with the calcium brine solution.11 . The method recited in Claim 10, wherein the concentration of the reaction inhibitor is at least about 25 milligrams per liter (mg / L) of calcium brine solution.

12. The method recited in Claim 1, wherein the concentration of the reaction inhibitor is not greater than about 250 milligrams per liter (mg / L) of calcium brine solution.

13. The method recited in Claim 4, further comprising inj ecting a nucleation agent into the wellbore.

14. The method recited in Claim 4, wherein the nucleation agent is selected from the group consisting of a mineral powder, proppants and combinations thereof.

15. The method recited in Claim 14, wherein the nucleation agent has a mean average size of at least about 25 pm.

16. The method recited in Claim 15, wherein the nucleation agent has a mean average size of not greater than about 200 pm.

17. The method recited in Claim 4, wherein the calcium brine solution comprises calcium chloride.

18. The method recited in Claim 17, wherein the calcium brine solution has a calcium chloride concentration of at least about 15 wt.%.

19. The method recited in Claim 18, wherein the calcium brine solution has a calcium chloride concentration of at least about 25 wt.%.

20. The method recited in Claim 4, further comprising, after allowing the calcium brine solution and the liquid carbon dioxide to react within the fissure, resuming the production of hydrocarbons from the wellbore.

21. The method recited in Claim 4, further comprising the step of removing the precipitated calcite from the fissure.

22. The method recited in Claim 21, wherein the step of removing the precipitated calcite comprises contacting the precipitated calcite with an acid.

23. A method for the repair of a subterranean storage reservoir comprising a downhole bore and a plurality of outwardly extending fissures in fluid communication with the downhole bore, comprising the steps of: identifying a fissure within the storage reservoir that is in fluid communication with the wellbore; injecting a calcium brine solution into the wellbore such that the calcium brine solution penetrates the fissure; injecting liquid carbon dioxide into the wellbore such that the liquid carbon dioxide penetrates the fissure; and allowing the calcium brine solution and the liquid carbon dioxide to react within the fissure to precipitate calcite and substantially prevent fluid flow within the fissure.

24. The method recited in Claim 23, wherein the storage reservoir is a carbon dioxide storage reservoir.

25. The method recited in Claim 23, wherein the storage reservoir is a water storage reservoir.

26. A method for the construction of a wellbore, comprising the steps of: drilling a subterranean bore; placing a liner within the subterranean bore; and affixing the liner within the subterranean bore, the affixing comprising the steps of: injecting a calcium brine solution into an annular region surrounding the liner; injecting liquid carbon dioxide into the annular region surrounding the liner; and allowing the calcium brine solution and the liquid carbon dioxide to react within the annular region surrounding the liner to precipitate calcite and affix the liner within the subterranean bore.

27. The method recited in Claim 26, wherein the calcium brine solution and the liquid carbon dioxide are injected into the annular region simultaneously.

28. The method recited in Claim 27, further comprising the step of injecting a pH adjuster into the annular region.

29. The method recited in any one of Claims 26 to 28, wherein the pH adjuster is injected into the annular region with the calcium brine solution.

30. The method recited in Claim 29, wherein the pH adjuster is selected to modify the pH of the calcium brine solution to a pH of at least about 7.

31. The method recited in Claim 30, wherein the pH adjuster is selected to modify the pH of the calcium brine solution to a pH of not greater than about 9.

32. The method recited in Claim 28, wherein the pH adjuster comprises ammonium hydroxide.

33. The method recited in Claim 29, further comprising injecting a nucleation agent into the annular region.

34. The method recited in Claim 33, wherein the nucleation agent is selected from the group consisting of a mineral powder, proppants and combinations thereof.

35. The method recited in Claim 34, wherein the nucleation agent has a mean average size of at least about 25 pm.

36. The method recited in Claim 35, wherein the nucleation agent has a mean average size of not greater than about 200 gm.

37. The method recited in Claim 29, wherein the calcium brine solution comprises calcium chloride.

38. The method recited in Claim 37, wherein the calcium brine solution has a calcium chloride concentration of at least about 15 wt.%.

39. The method recited in Claim 38, wherein the calcium brine solution has a calcium chloride concentration of at least about 25 wt.%.

40. The method recited in Claim 39, further comprising the step of removing the precipitated calcite from the annular region.

41. The method recited in Claim 40, wherein the step of removing the precipitated calcite comprises contacting the precipitated calcite with an acid.

42. The method recited in Claim 41, further comprising the step of removing the liner from the wellbore after the precipitated calcite has been removed from the annular region.

Images