WO2023056002A2 - High temperature well fluid for supercritical operations, methods of making and using, well systems comprising same - Google Patents

Abstract

A well fluid including a resin component, a curing agent, and a nanocomposite filler, wherein the well fluid is stable at a temperature of at least 550°F is provided. A method of using the well fluid in various well operations, and geothermal systems that include the well fluid are also provided.

Description

HIGH TEMPERATURE WELL FLUID FOR SUPERCRITICAL OPERATIONS, METHODS OF MAKING AND USING, WELL SYSTEMS COMPRISING SAME

CROSS REFERENCE TO RELATED APPLICATION(S)

[0001] The present application claims priority to U.S. Provisional Patent Application No. 63/251,059 filed on October 1, 2021, where the entire contents of which are incorporated by reference in its entirety.

FIELD OF THE INVENTION

[0002] The present invention relates to well fluids, to methods of making and using such well fluids, and to subterranean/geothermal systems including such well fluids. In another aspect, the present invention relates to well fluids stable at downhole supercritical conditions, to methods of making and using such well fluids, and to subterranean/geothermal systems including such well fluids within a supercritical subterranean/geothermal zone. Specifically, the present disclosure relates to a well fluid including a resin component, a curing agent, and a nanocomposite filler, wherein the well fluid is stable at a temperature equal to or greater than 550°F and a pressure of at least 2,000 psi. In another aspect, a method of making and/or using the well fluid is also provided.

BACKGROUND

[0003] While the surface of the earth can be cold at times, the area beneath the earth’s crust, i.e. geothermal area, has a relatively stable temperature, which is usually very hot. Thus, geothermal heat that is produced under the earth’s crust is a form of energy. This energy has been utilized to generate electricity and to provide heating for various structures.

[0004] Geothermal energy has a long history of being utilized. However, more recently, geothermal energy is a high demand to be utilized for generation of electricity. To access the geothermal energy, geothermal production sites including geothermal wells have been developed. The geothermal energy production site includes, briefly, a hole drilled into the earth to a depth at which the temperature of the surrounding rock formation is sufficient to heat a working fluid. Pipelines for geothermal systems are generally optimized for closed circulation of a working fluid, commonly by a pipe in a pipe system. A working fluid is pumped down, for example, the outer portion of a pipe in a pipe system to the end of the pipe system, where it is redirected to the, for example, inner portion of a pipe in a pipe system. The pipe system commonly has a vertical element which runs from the surface of the earth to a suitable depth at which the surrounding rock formation is at a desired temperature. A horizontal pipe element is then run roughly horizontally a sufficient length to ensure heating of the working fluid pumped through it.

[0005] A geothermal system operates by extracting heat from the rock formation. Heat is taken up by the working fluid circulated through the pipeline. Geothermal systems can operate at a range of temperatures.

[0006] For example, a geothermal energy system may operate at supercritical temperatures, i.e. at a temperature at or above 550°F. At such temperatures, the working fluid is heated to high enthalpy to extract large amounts of energy at the surface. In order to operate at such supercritical temperatures, at least some of the drilling at the vertical element and/or the horizontal element of the pipe must be undertaken through rock formations at supercritical temperatures. A cement and/or resin may be used in the pipelines of the geothermal system both during installation and after completion.

[0007] It has been found that the cement and/or resin currently used cannot withstand the supercritical temperatures and high pressure for extended periods of time. Thus, there is a need for a well fluid including a cement and/or resin, that can withstand supercritical temperatures of at least 550°F, and high pressures at least about 2,000 psi.

[0008] A number of patents, patent applications and literature are directed to well fluids for use in well operations, the following of which are only a small few, and are herein incorporated by reference in their entirety: U.S. 4,070,865; U.S. 4,154,774; U.S. 4,768,593; AkiraNagai et al. “The Curing Reaction and Glass Transition Temperature of Meleimide Resin containing Epoxy Groups”, Polymer Journal, Vol 20, No 2, pp 125-130 (1988); U.S. 5,151,203; B. G. Min et al., “Cure Kinetics of elementary reactions of aDGEBA/DDS epoxy resin: 1. Glass transition temperature versus conversion”, Polymer, Volume 34, Number 23, 18 January 1993, revised 26 April 1993; U.S. 5,327,969; U.S. 5,343,950; U.S. 5,343,951; U.S. 5,370,185; U.S. 5,829,523; U.S. 6,065,539; U.S. 6,082,456; U.S. 6,244,344; U.S. 6,350,309; U.S. 6,626,991; U.S. 6,776,237; U.S. 6,793,730; U.S. 6,892,814; U.S. 2006/0079408; Fan-Long Jin et al., “Thermal Stability of Trifunctional Epoxy Resins Modified with Nanosized Calcium Carbonate”, Bull. Korean Chem. Soc. 2009, Vol 30, No 2; D Raghavan, “High Temperature Epoxy Nanocomposites for Aerospace Applications”, AFOSR: FA9550-06-1-0266, April 1 2006 to March 31 2009; U.S. 7,748,455; U.S. 8,235,116; Angels Serra et al., “Epoxy Sol-Gel Hybrid Thermosets”, 3 February 2016; U.S. 9,550,933; Yujie Jin et al. 2018 IOP Conf. Ser.: Earth Environ. Sci. 186 012039; Zeyu Sun et al., “Enhancing the Mechanical and Thermal Properties of Epoxy Resin via Blending with Thermoplastic Poly Sulfone”, 11 March 2019; and Samual R Swan et al., “Cure Kenetics and Network Development of a Very High Tg Naphthalene-Based Epoxy Amine Network”, ACS Appl. Polym. Mater. 2021, 3, 5717-5726.

BRIEF SUMMARY

[0009] According to various embodiments, disclosed herein is a well fluid including a resin component, a curing agent, and a nanocomposite filler, wherein the well fluid is stable at a temperature of at least about 550°F or higher and apressure of about 10,000 psi to about 15,000 psi.

[0010] According to another non-limiting embodiment, a method for zone isolation is also provided. The method for zone isolation may include providing a well fluid including a resin component, a curing agent, and a nanocomposite filler; pumping the well fluid into a supercritical temperature section of pipeline; and curing the well fluid in the section to form a zonal isolation structure. The zonal isolation structure may be compressible, wherein the supercritical temperature section is at a temperature of at least 550°F

[0011] In another non-limiting embodiment, there is provided a method of carrying out a well operation in a subterranean/geothermal well having a downhole supercritical temperature zone. The method may include providing a well fluid to the downhole zone. The well fluid may include a resin component, a curing agent and a nanocomposite filler, and may be stable at a temperature of at least about 550°F.

[0012] In yet another non-limiting embodiment, there is provided a subterranean/geothermal well system having a supercritical subterranean/geothermal zone, including a well fluid within the supercritical subterranean/geothermal zone. The well fluid may include a resin component, a curing agent and a nanocomposite filler, wherein the well fluid is stable at a temperature of at least about 550°F.

[0013] According to another non-limiting embodiment, there is provided a method of reducing lost circulation from a lost circulation zone at supercritical temperature within a geothermal wellbore. The method may include providing a well fluid to the lost circulation zone; curing the well fluid to form a plug that seals off the lost circulation zone; and/or drilling through the plug to extend the wellbore through the lost circulation zone. The well fluid may include a resin component, a curing agent, and a nanocomposite filler.

[0014] According to another non-limiting embodiment, there is provided a lost circulation well fluid for use in lost circulation operations to seal off a supercritical temperature lost circulation zone within a geothermal wellbore. The lost circulation well fluid may include a resin component, a curing agent, and/or a nanocomposite filler.

[0015] In another non-limiting embodiment, there is provided a geothermal well system that may include a geothermal wellbore; a supercritical temperature lost circulation zone within the geothermal wellbore; and/or a lost circulation well fluid positioned in the zone that may include a resin, a curing agent and/or a nanocomposite filler. A lost circulation plug may be configured to seal off the supercritical temperature lost circulation zone and to define a passage extending the wellbore through the lost circulation zone.

[0016] According to another non-limiting embodiment, there is provided a method of sealing casing threads of a pipe string, wherein the threads are located in of a supercritical zone of a geothermal wellbore. The method may include providing a well fluid to the casing threads in the wellbore; applying a pressure to squeeze thread the well fluid into the casing threads; and/or maintaining pressure to allow the well fluid to cure and form a seal in the threads. The well fluid may include a resin component, a curing agent, and a nanocomposite filler.

[0017] According to another non-limiting embodiment, there is provided a casing thread well fluid for use with casing threads which are located in a supercritical temperature zone of a pipe string in a geothermal wellbore, wherein the well fluid may include a resin component, a curing agent, and/or a nanocomposite filler. The casing threads may be in a supercritical temperature zone of the geothermal wellbore.

[0018] According to another non-limiting embodiment, there is provided a geothermal well system including a geothermal wellbore having a supercritical temperature lost circulation zone; a pipe string in the geothermal wellbore, wherein the pipe string includes casing threads in the supercritical lost circulation temperature zone; and/or a casing thread well fluid residing in the casing threads. The casing thread well fluid may include a resin component, a curing agent, and a nanocomposite filler.

[0019] According to another non-limiting embodiment, there is provided a method of treating gas migration within a geothermal wellbore having a supercritical temperature gas migration zone, including providing a gas migration well fluid to the gas migration zone; and/or maintaining positive pressure on the gas migration well fluid until the gas migration well fluid cures and hardens. The gas migration well fluid may include a resin component, a curing agent, and a nanocomposite filler.

[0020] According to another non-limiting embodiment, there is provided a gas migration well fluid for use in treating gas migration within a supercritical temperature gas migration zone of a geothermal wellbore, which may include a resin component, a curing agent, and/or a nanocomposite filler.

[0021] According to another non-limiting embodiment, there is provided a geothermal well system including a geothermal wellbore having a supercritical temperature gas migration zone; and/or a gas migration well fluid position in the supercritical temperature gas migration zone. The gas migration well fluid may include a resin component, a curing agent, and a nanocomposite filler.

[0022] In another non-limiting embodiment, there is provided a method of setting a kickoff plug in a geothermal wellbore, including lowering an open ended tubular member into the geothermal wellbore; providing a kickoff plug well fluid through the open ended tubular member and into a supercritical temperature kickoff zone of the wellbore; and/or curing the kickoff plug well fluid into a hardened kickoff plug. The kickoff plug well fluid may include a resin component, a curing agent, and/or a nanocomposite filler.

[0023] According to another non-limiting embodiment, there is provided a kickoff plug well fluid for use in a supercritical temperature zone including a resin component, a curing agent, and/or a nanocomposite filler.

[0024] According to another non-limiting embodiment, there is provided a geothermal well system including a geothermal wellbore having a supercritical temperature kickoff zone; and/or a kickoff plug well fluid configured in the supercritical temperature kickoff zone. The kickoff plug well fluid may include a resin component, a curing agent, and/or a nanocomposite filler.

[0025] According to another non-limiting embodiment, there is provided a method of treating packer leaks from a packer, including: loading a packer leak well fluid into an annulus of a geothermal well; chasing the packer leak well fluid with a liquid; shutting in the well; allowing the packer leak well fluid to fall through the annulus and settle on top of leaking areas of the packer; and/or curing the packer leak well fluid to form a seal on top of the leaking areas of the packer. The packer leak well fluid may include a resin component, a curing agent, and/or a nanocomposite filler.

[0026] According to another non-limiting embodiment, there is provided a packer leak well fluid for use in treating packer leaks from a packer in a supercritical temperature zone within an annulus of a subterranean/geothermal well, that includes a resin component, a curing agent, and/or a nanocomposite filler.

[0027] According to another non-limiting embodiment, there is provided a geothermal well system including a geothermal wellbore having a supercritical temperature zone; a packer configured in the supercritical temperature zone; and/or a packer leak well fluid position on a leak area of the packer. The packer leak well fluid may include a resin component, a curing agent, and/or a nanocomposite filler.

[0028] According to another non-limiting embodiment, there is provided a method of plugging and abandoning a geothermal well, including providing a plugging well fluid in a supercritical temperature zone of the geothermal well; curing the plugging well fluid to form a plug that seals off the geothermal well; and/or abandoning the geothermal well. The plugging well fluid may include a resin component, a curing agent and/or a nanocomposite filler.

[0029] According to another non-limiting embodiment, there is provided a plug and abandon well fluid for use during plugging and abandoning operations for forming a plug in a supercritical temperature zone, wherein the plug and abandon well fluid may include a resin component, a curing agent, and/or a nanocomposite filler.

[0030] According to another non-limiting embodiment, there is provided plugged and abandoned geothermal well system including a wellbore in a supercritical temperature zone of a geothermal well and a plug configured in the supercritical temperature zone, wherein the plug is formed from a composition comprising a plug and abandon well fluid. The plug and abandon well fluid may include a resin component, a curing agent, and/or a nanocomposite filler.

[0031] According to another non-limiting embodiment, there is provided a method of primary cementing, including providing a primary cementing well fluid to a supercritical temperature zone of an annulus, wherein the annulus is between a casing positioned in the wellbore and the wellbore; and curing the primary cementing well fluid to form a sheath around the casing to fix the casing in the wellbore. The primary cementing well fluid may include a resin component, a curing agent, and/or a nanocomposite filler.

[0032] In another embodiment, a primary cementing well fluid for use carrying out a primary cementing operating in a supercritical temperature annular zone is provided. The primary cementing well fluid may include a resin component, a curing agent, and a nanocomposite filler, wherein the annular zone is defined between a subterranean wellbore and casing therein, and wherein the primary cementing well fluid includes a resin component, a curing agent, and/or a nanocomposite filler.

[0033] In some embodiments, a geothermal well system is also provided. The geothermal well system may include a geothermal wellbore; a casing configured in the geothermal wellbore to define an annulus between the casing and the wellbore, wherein the annulus has a supercritical temperature zone, and a primary cementing well fluid configured in the supercritical temperature zone of the annulus. The primary cementing well fluid may include a resin component, a curing agent, and/or a nanocomposite filler. [0034] According to another non-limiting embodiment, there is provided a water shut off method for a geothermal well, the method including providing a well shut off well fluid to a target zone in the geothermal well outside of a casing positioned in the geothermal well; penetrating a subterranean area of the geothermal well in a radial zone extending radially outside of the casing; and/or curing the well shut off well fluid to form cured and hardened well shut off well fluid, wherein at least one of the target zone or the radial zone is at a supercritical temperature. The well shut off well fluid may include a resin component, a curing agent, and/or a nanocomposite filler.

[0035] According to another non-limiting embodiment, there is provided a water shut off well fluid for use in a supercritical temperature radial zone in the geothermal well outside of a casing positioned in the geothermal well, including a resin component, a curing agent, and/or a nanocomposite filler.

[0036] In another embodiment, a geothermal well system is provided. The geothermal well system may include a geothermal wellbore; a casing configured in the geothermal wellbore; a supercritical temperature radial zone extending radially outside of the casing; and a water shut off well fluid, positioned in the zone. The water shut off well fluid may include a resin component, a curing agent, and a nanocomposite filler.

[0037] According to another non-limiting embodiment, there is provided a method to treat a supercritical conformance zone. The method may include detecting a problem area in the supercritical conformance zone, providing a well fluid to the problem area in the supercritical conformance zone and curing the well fluid to form a cured and hardened plug of the well fluid. The well fluid may include a resin component, a curing agent, and a nanocomposite filler.

[0038] In another embodiment, a well fluid for treating a problem area in a supercritical conformance zone is provided. The well fluid may include a resin component, a curing agent, and a nanocomposite filler.

[0039] In another embodiment, a geothermal well system may include a geothermal wellbore, a casing configured in the geothermal wellbore, a supercritical temperature conformance zone and a well fluid. The well fluid may include a resin component, a curing agent, and a nanocomposite filler.

[0040] According to another non-limiting embodiment, there is provided a method to perform a well kill operations. In one embodiment, a method for performing a well kill operation may include providing a well fluid to a target area, performing a first circulation step and then performing a second circulation step. The first circulation step may include bringing a pump to kill rate, opening a choke and holding the casing pressure constant until the pump reaches the kill rate, switching to drill pipe pressure that is held constant until the influx is removed and shutting down holding the casing pressure constant. The second circulation step may include during the bringing the pump to kill rate, applying the well fluid to a bit towards an annulus and switching to drill pipe pressure when the well fluid enters the annulus, wherein the drill pipe pressure may be held constant and the well fluid reaches a surface. The well fluid may include a resin component, a curing agent, and a nanocomposite filler. In another embodiment, the method for performing a well kill operation may include providing a well fluid to a well kill operation; bringing a pump to kill rate, while holding casing pressure constant; switching to drill pipe pressure when the pump reaches the kill rate, wherein the drill pipe pressure is an initial circulating pressure; allowing the drill pipe pressure to drop to a final circulating pressure, wherein the well fluid fills a drill string; holding the final circulating pressure constant while the well fluid reaches a surface; and shutting down the pump holding casing pressure constant. The well fluid may include a resin component, a curing agent and a nanocomposite filler.

[0041] In another embodiment, a well fluid for performing a well kill operation is provided. The well fluid may include a resin component, a curing agent, and a nanocomposite filler [0042] In another embodiment, a geothermal well system is provided. The geothermal well system may include a geothermal wellbore, a casing configured in the geothermal wellbore, a pump, a drill pipe and a well fluid. The well fluid may include a resin component, a curing agent, and a nanocomposite filler.

BRIEF DESCRIPTION OF THE DRAWINGS

[0043] FIG. 1 illustrates the results of a Static Pot Life Test;

[0044] FIG. 2 illustrates the results of Dynamic testing conducted at 470°F for one embodiment of the present disclosure;

[0045] FIG. 3 illustrates the results of Dynamic testing conducted at 500°F for one embodiment of the present disclosure.

DETAILED DESCRIPTION

[0046] Described herein are various non-limiting embodiments of a well fluid that may include a resin component, a curing agent and a nanocomposite filler. It is to be understood that the invention is not limited to the details of construction or process steps set forth in the following description. The invention is capable of other embodiments and of being practiced or being carried out in a variety of ways that will be clear to those of skill in the art upon review of this specification.

[0047] Reference throughout this specification to “one embodiment,” “certain embodiments,” “one or more embodiments” or “an embodiment” means that a particular feature, structure, material, or characteristic described in connection with the embodiment is included in at least one embodiment of the invention. Thus, the appearances of the phrases such as “in one or more embodiments,” “in certain embodiments,” “in one embodiment” or “in an embodiment” in various places throughout this specification are not necessarily referring to the same embodiment of the invention. Furthermore, the particular features, structures, materials, or characteristics may be combined in any suitable manner in one or more embodiments.

[0048] As used herein, the singular forms “a,” “an,” and “the” include plural references unless the context clearly indicates otherwise. Thus, for example, reference to “a curing agent” includes a single curing agent as well as two or more curing agents.

[0049] As used herein, the term “about” in connection with a measured quantity, refers to the normal variations in that measured quantity as expected by one of ordinary skill in the art in making the measurement and exercising a level of care commensurate with the objective of measurement and the precision of the measuring equipment. In certain embodiments, the term “about” includes the recited number ±10%, such that “about 10” would include from 9 to 11. In other embodiments, the term “about” includes the recited number ±9%, ±8%, ±7%, ±6%, ±5%, ±4%, ±3%, ±2%, ±1%, ±0.5%, or ±0.1%.

[0050] The term “at least about” in connection with a measured quantity refers to the normal variations in the measured quantity, as expected by one of ordinary skill in the art in making the measurement and exercising a level of care commensurate with the objective of measurement and precisions of the measuring equipment and any quantities higher than that. In certain embodiments, the term “at least about” includes the recited number minus 10% and any quantity that is higher such that “at least about 10” would include 9 and anything greater than 9. This term can also be expressed as “about 10 or more.” Similarly, the term “less than about” typically includes the recited number plus 10% and any quantity that is lower such that “less than about 10” would include 11 and anything less than 11. This term can also be expressed as “about 10 or less.”

[0051] Unless otherwise indicated, all parts and percentages are by weight. Weight percent (wt. %), if not otherwise indicated, is based on an entire composition free of any volatiles, that is, based on dry solids content. [0052] As used herein, the term “supercritical temperature” refers to a temperature of about 550°F or greater. In certain embodiments, a “supercritical temperature zone” refers to an area that is a temperature of about 550°F or greater.

[0053] Although the disclosure herein is with reference to particular embodiments, it is to be understood that these embodiments are merely illustrative of the principles and applications of the invention. It will be apparent to those skilled in the art that various modifications and variations can be made to the compositions and methods without departing from the spirit and scope of the invention. Thus, it is intended that the invention include modifications and variations that are within the scope of the appended claims and their equivalents.

[0054] A well fluid as described herein may be utilized in a number of primary, secondary, and remedial hydrocarbon well operations, including but not limited to, lost circulation, casing leaks, conformance, gas migration, kick off plug, packer leak, plug and abandon, primary cement, remedial cement, water shut off, and/or well kill. In a non-limiting embodiment of the present disclosure, the well fluid may also be referred to as a cementing composition or a sealant.

[0055] Disclosed herein is a non-limiting embodiment of a well fluid that may include a resin component, a curing agent and a nanocomposite filler. The well fluid described herein may be stable at any of the following temperatures, of at least any of the following temperatures, above any of the following temperatures, in a range to/from any of two of the following temperatures, or between any two of the following temperatures: about 550°F, about 560°F, about 570°F, about 580°F, about 590°F, about 600°F, about 610°F, about 620°F, about 630°F, about 640°F, about 650°F, about 660°F, about 670°F, about 680°F, about 690°F, about 700°F, about 710°F, about 720°F, about 730°F, about 740°F, about 750°F, about 760°F, about 770°F, about 780°F, about 790°F, about 800°F, about 810°F, about 820°F, about 830°F, about 840°F, about 850°F, about 860°F, about 870°F, about 880°F, about 890°, about 900°F, about 910°F, about 920°F, about 930°F, about 940°F, about 950°F, about 960°F, about 970°F, about 980°, about 990°F, about 1000°F, about 1010°F, or about 1025°C. In another example, the well fluid may be stable at a temperature from about 500°F to about 1025°F, about 550°F to about 1000°F, about 600°F to about 950°F, about 650°F to about 900°F, about 700°F to about 850°F, about 750°F to about 1025°F, about 800°F to about 1000°F, about 825°F to about 975°F, about 850°F to about 950°F, or about 875°F to about 925°F. The well fluid may also be stable at pressures at any of the following pressures, of at least any of the following pressures, above any of the following pressures, in a range to/from any of the following pressures, or between any two of the following pressures: about 2,000 psi, about 3,000 psi, about 5000 psi, about 6000 psi, about 7,500 psi, about 8,000 psi, about 10,000 psi, about 15,000 psi. In another example, the well fluid may be stable at pressures of at least about 2,000 psi, at least about 3,000 psi, at least about 5,000 psi, at least about 7,500 psi, at least about 10,000 psi, or at least about 15,000 psi. In another example, the well fluid may be stable at a pressure from about 2,000 psi to about 15,000 psi, about 3,000 psi to about 12,000 psi, about 5,000 psi to about 10,000, or about 6,000 psi to about 8,000 psi. It has been found that by including a sufficient amount of nanocomposite filler in the composition, the thermal stability of the resin in the composition may be improved. [0056] In an embodiment of the well fluid, the resin component may be an epoxy resin; glycidyl ethers epoxy resin prepared by the reaction of epichlorohydrin with a compound containing a hydroxyl group carried out under alkaline reaction conditions; epoxy resins prepared by the reaction of epichlorohydrin with mononuclear di- and tri-hydroxy phenolic compounds; epoxidized derivatives of natural oils with mixed long-chain saturated and unsaturated acids having between about 14 and 20 carbon atoms; polyepoxides derived from esters of poly carboxylic acids with unsaturated alcohols; poly epoxides derived from esters prepared from unsaturated alcohols and unsaturated carboxylic acids; epoxidized butadiene based polymers; epoxidized derivatives of dimers of dienes, or combinations thereof.

[0057] In some embodiments, the resin may be a multifunctional epoxidized phenolic novolac resin, such as EPON ™ 162, or EPON ™ 161, an aliphatic triglycidyl ether, such as HELOXY ™ 48, or a combination thereof. In some embodiments, the resin may also be a phenolformaldehyde polymer glycidyl ether, 1,3-propanediol, 2-ethyl-2-(hydromethyl)- polymer with (chloromethyl)oxirane), or a combination thereof.

[0058] The resin component may also include a bisphenol-derived resin. The bisphenolderived resin refers to a resin derived from bisphenols, a group of chemical compounds with two hydroxyphenyl functionalities, and may also include phenolic novalaks. Commonly known bisphenols include Bisphenol A, Bisphenol AP, Bisphenol AF, Bisphenol B, Bisphenol BP, Bisphenol C, Bisphenol C 2, Bisphenol E, Bisphenol F, Bisphenol G, Bisphenol M, Bisphenol S, Bisphenol P, Bisphenol PH, Bisphenol TMC, Bisphenol Z, and combinations of two or more of the foregoing whether physically mixed and/or copolymerized. In some embodiments, the bisphenol-derived resin may include those derived from Bisphenol A&F, F, A&S.

[0059] In some embodiments, the bisphenol-derived resin may be condensation products of the bisphenol with epichlorohydrin to provide a bisphenol diglycidyl ether, with the reaction carried out to provide a low viscosity resin. For example, the condensation reaction of Bisphenol “X” with epichlorohydrin provides Bisphenol “X” diglycidyl ether, wherein “X” is the type of Bisphenol.

[0060] In some embodiments, the bisphenol-derived resin may have a viscosity (at 25°C, and atmospheric) that is at, above or below any one of the following, or that ranges to/from or between any two of the following: about 2,000 cP, about 2,500 cP, about 3,000 cP, about 3,500 cP, about 4,000 cP, about 4,500 cP, about 5,000 cP, about 6,000 cP about 7,000 cP, or about 8,000 cP. Some bisphenol- derived resins may have a viscosity in the range of about 2,500 cP to about 4,500 cP. When the bisphenol-derived resin is used downhole in the geothermal system, it may have a viscosity in the range of about 50 cP to about 2,000 cP, or about 50 cP to about 1,000 cP at downhole pressures and temperatures. Downhole pressures may be about 5,000 psi to about 15,000 psi or higher, and downhole temperatures may be about 550°F to about 1025°C or higher.

[0061] In some embodiments of the well fluid, the resin component may be included in an amount that is at, above or below any one of the following, or that ranges to/from or between any two of the following: about 5 wt%, about 10 wt%, about 15 wt%, about 20 wt%, about 25 wt%, about 30 wt%, about 35 wt%, about 40 wt%, about 45 wt%, about 50 wt%, about 55 wt%, about 60 wt%, about 65 wt%, about 70 wt%, about 75 wt%, about 80 wt%, about 85 wt%, about 90 wt%, or about 95 wt%, based on total weight of the well fluid.

[0062] In some embodiments, the resin component may further include a diluent. The diluent may reduce the viscosity of the resin component for ease of handling, mixing and transferring. In some embodiments, a diluent may not be included because of environmental or safety reasons. Factors that may effect this decision include, but are not limited to, geographic location of the well, the surrounding weather conditions, and the desired long-term stability of the well.

[0063] In an embodiment, the diluent may be reactive, such that they are incorporated into the resin. Diluents that are reactive may include a amine or epoxide functional groups. Suitable diluents may include, but are not limited to, butyl glycidyl ether, Cxi alkyl glycidyl ethers, cyclohexane dimethanol diglycidyl ether, polyethylene glycol, butyl lactate, dipropylene glycol methyl ether, dipropylene glycol dimethyl ether, dimethyl formamide, diethyleneglycol methyl ether, ethyleneglycol butyl ether, diethyleneglycol butyl ether, propylene carbonate, d'limonene, fatty acid methyl esters, or a combination thereof. In some embodiments, the diluent may be included that is at, above or below any one of the following, or that ranges to/from or between any two of the following: about 1 part, about 5 parts, about 10 parts, about 15 parts, about 20 parts, about 25 parts, about 30 parts, about 35 parts, about 40 parts, about 45 parts, about 50 parts, about 55 parts, about 60 parts, about 65 parts, or about 70 parts, by weight per 100 parts of resin component. In some embodiments, about 30 parts, about 35 parts, about 40 parts, about 45 parts, about 50 parts, about 55 parts, about 60 parts, about 65 parts, or about 70 parts by weight diluent per 100 parts of resin component. Some embodiments may include a range of 10-70 parts by weight diluent per 100 parts of resin component. Optionally, the resin component may be heated to reduce its viscosity, in place of, or in addition to, using a diluent.

[0064] In a dual diluent/retardant role, some embodiments may include an aliphatic monoglycidyl ether containing alkyl chains comprising at least 8, 10, 12, 14, 16, 18, or 20 carbons. In some embodiments, an aliphatic monoglycidyl ether may contain chains which are predominately C12 and C14 in length. It should be understood that this reactive diluent serves a dual purpose of reducing the viscosity of the resin and retarding the cure rate of the resin (thus allowing for control of the pot life of the resin).

[0065] In some embodiments, the resin component may have a glass transition temperature (“Tg”) that is at, above or below any one of the following, or that ranges to/from or between any two of the following temperatures: about 570°F, about 580°F, about 590°F, about 600°F, about 610°F, about 620°F, about 630°F, about 640°F, about 650°F, about 660°F, about 670°F, about 680°F, about 690°F, about 700°F, about 710°F, about 720°F, about 730°F, about 740°F, about 750°F, about 760°F, about 770°F, about 780°F, about 790°F, about 800°F, about 810°F, about 820°F, about 830°F, about 840°F, about 850°F, about 860°F, about 870°F, about 880°F, about 890°F, about 900°F, about 910°F, about 920°F or about 930°F, or any value therein. In some embodiments, the resin component glass transition temperature may be at least about 600°F.

[0066] In some embodiments, the well fluid of the present disclosure may be used to modify or replace current well fluids. In particular, the well fluid may be utilized in a number of primary, secondary, and remedial hydrocarbon well operations, including but not limited to, lost circulation, casing leaks, conformance, gas migration, kick off plug, packer leak, plug and abandon, primary cement, remedial cement, water shut off, and/or well kill.

[0067] In some embodiments, the well fluid may further include a cement component. The cement component may be any suitable cement used in geothermal well operations. In some embodiments, the cement component may include a hydraulic cement. The hydraulic cement may include calcium, aluminum, silicon, oxygen, sulfur, or a combination thereof, which is set and hardened by reacting with water. A hydraulic cement may also include Portland cements, pozzolana cements, gypsum cements, high aluminum content cements, silica cements, or high alkalinity cements. In one embodiment, the hydraulic cement may be a Portland cement. The Portland cement of the types defined and described in API Specification For Materials And Testing For Well Cements, API Specification 10, 5th Edition, dated Jul. 1, 1990 of the American Petroleum Institute may be used. In some embodiments, API Portland cements include classes A, B, C, G and H.

[0068] In some embodiments of the well fluid, a curing agent may be included. The curing agent may be an aliphatic amine, an aliphatic tertiary amine, an aromatic amine, a cycloaliphatic amine, a heterocyclic amine, an amido amine, a polyamide, a polyethyl amine, a polyether amine, a polyoxyalkylene amine, a carboxylic anhydride, a triethylenetetraamine, ethylene diamine, N-cocoalkyltrimethylene, isophorone diamine, N-aminophenyl piperazine, imidazoline, 1,2-diaminocyclohexane, polytheramine, di ethyltoluenediamine, 4,4'- di aminodiphenyl methane, methyltetrahydrophthalic anhydride, hexahydrophthalic anhydride, maleic anhydride, polyazelaic polyanhydride, phthalic anhydride, or a combination thereof.

[0069] In some embodiments, the curing agent may be a non-methylene dianiline, aromatic amine, such as Epikure ™ W, an amino silane, such as RSC-4628, or a combination thereof. In some embodiments, the curing agent may also be diethylmethylbenzediamine.

[0070] In some embodiments of the well fluid, the curing agent may be included in an amount that is at, above or below any one of the following, or that ranges to/from or between any two of the following about 5 parts by weight, about 10 parts by weight, about 15 parts by weight, about 20 parts by weight, about 25 parts by weight, about 30 parts by weight, about 35 parts by weight, about 40 parts by weight, or about 45 parts by weight, based on 100 parts of resin component. The amount of curing agent included in the well fluid is included in an amount sufficient to at least partially harden the resin component. The amount of curing agent may also be selected to impart a desired elasticity, compressibility, or a combination thereof. In general, the lower the amount of curing agent, then the greater the elasticity or compressibility of the compound.

[0071] In some embodiments, a mixture of curing agents may be used. In some embodiments, the mixture of curing agents may include a fast-setting curing agent and a slow-setting curing agent. As used herein, the term “fast-setting curing agent” and “slow-setting curing agent” do not imply any specific rate at which the agents set a resin. Rather, the terms merely indicate the relative rates at which the curing agent initiates hardening of the resin. Whether a particular curing agent is considered fast-setting or slow-setting may depend on the other curing agent(s) with which it is used. The ratio of fast-setting curing agent to slow-setting curing agent may be selected to achieve a desired behavior of the curing agent. For example, the fast-setting curing agent may be included in a ratio of approximately 1:5, by volume, with the slow-setting curing agent.

[0072] In some embodiments, the curing agent may be a silane coupling agent. The silane coupling agent may act as a mediator to help bond the resin to the surface of the subterranean formation and/or the surface of the well bore. Examples of suitable silane coupling agents include, but are not limited to, N-2-(aminoethyl)-3-aminopropyltrimethoxysilane; 3- glycidoxypropyltrimethoxysilane; gamma-aminopropyltriethoxysilane; N-beta-(aminoethyl)- gamma-aminopropyltrimethoxysilanes; aminoethyl-N-beta-(aminoethyl)-gamma- aminopropyl-trimethoxysilanes; gamma-ureidopropyl-triethoxysilanes; beta-(3-4 epoxy- cyclohexyl)-ethyl-trimethoxysilane; gamma-glycidoxypropyltrimethoxysilanes; vinyltrichlorosilane; vinyltris (beta-methoxyethoxy) silane; vinyl tri ethoxysilane; vinyltrimethoxysilane; 3-metacryloxypropyltrimethoxysilane; beta-(3,4 epoxycyclohexyl)- ethyltrimethoxysilane; r-glycidoxypropyltrimethoxysilane; r- glycidoxypropylmethylidiethoxysilane; N-beta-(aminoethyl)-r-aminopropyl- trimethoxysilane; N-beta-(aminoethyl)-r-aminopropylmethyldimethoxysilane; 3- aminopropyl-triethoxysilane; N-phenyl-r-aminopropyltrimethoxysilane; r- mercaptopropyltrimethoxysilane; r-chloropropyltrimethoxysilane; vinyltrichlorosilane; vinyltris(beta-methoxyethoxy)silane; vinyltrimethoxysilane; r- metacryloxypropyltrimethoxy silane; beta-(3,4 epoxy cy cl ohexyl)-ethyltrimethoxy sila; r- glycidoxypropyltrimethoxysilane; r-glycidoxypropylmethylidiethoxysilane; N-beta- (aminoethyl)-r-aminopropyltrimethoxysilane; N-beta-(aminoethyl)-r- aminopropylmethyldimethoxysilane; r-aminopropyltriethoxysilane; N-phenyl-r- aminopropyltrimethoxysilane; r-mercaptopropyltrimethoxysilane; r- chloropropyltrimethoxysilane; N[3-(trimethoxysilyl)propyl]-ethylenediamine; substituted silanes where one or more of the substitutions contains a different functional group; or any combinations thereof. In some embodiments, the silane coupling agent may be included in the curing agent in an amount of about 0.1% to about 95% by volume of the curing agent. In some embodiments, the silane coupling agent may be included in an amount that is at, above or below any one of the following, or that ranges to/from or between any two of the following about 0.1%, about 1%, about 5 %, about 10%, about 15%, about 20%, about 25%, about 30%, about 35%, about 40%, about 45%, about 50%, about 55%, about 60%, about 65%, about 70%, about 75%, about 80%, about 85%, about 90%, or about 95%, by volume of the curing agent. [0073] In some embodiments, the curing agent may also be tri ethylenetetramine, aromatic amine, or mixtures thereof. In some embodiments, the aromatic amine may be diethyltoluenediamine.

[0074] In some embodiments, the well fluid may include a nanocomposite filler. The nanocomposite filler may include, but is not limited to, nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability (805 °F) can be used for formulating next generation nanocomposite matrix materials, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof.

[0075] In some embodiments, the nanocomposite filler may be an organic compound, an inorganic compound, a polymer nanofiber, a natural fiber, a natural clay, a nanoclay, a metal oxide, a particle, a carbon nanofiller, or a metallic particle. In some embodiments, the natural fiber may include sisal, cellulose, flax, hemp, kenaf, banana, wood, or pineapple. In some embodiments, the nanoclay may be a layered silicate, or a nonlayered silicate. In some embodiments, the metal oxide may include CU2O, CdO, AI2O3, MgO, CeCh, ZrCL TiCh, ZnO, FesCfi. CuO, NiO, or a combination thereof. In some embodiments, the metallic particles may be Au, Ag, Cu, Pt, Pd, Ru, Re, Zn, Hg, Rh, Co, Ni, Li, Fe, Cr, or a combination thereof. In some embodiments, the carbon nanofiller may be carbon nanotubes, graphene, graphite, flurrenes, carbon fibers, or a combination thereof. In some embodiments, the nanofiller may also be a particle selected from PbS, CdS, CdSe, CdTe, SiCh, CaCCh, CoPt, ZnS, ZrCL. V2O5, M0S2, SnS2, or a combination thereof. In some embodiments, the nanocomposite filler may be a graphene power having a size of about 0.5 pm to about 2 pm.

[0076] The nanocomposite filler may be included in the well fluid in an amount about that is at, above or below any one of the following, or that ranges to/from or between any two of the following: about 0.01%, about 0.1%, about 0.5%, about 1%, about 2%, about 3%, about 4%, about 5%, about 10%, about 15%, about 20%, about 25%, or about 30% based on the weight of the well fluid. In some embodiments, the nanocomposite filler may be included in an amount of about 0.1% to about 20% based on the weight of well fluid.

[0077] In some embodiments, the nanocomposite filler have a particle size that is at, above or below any one of the following, or that ranges to/from or between any two of the following about 0.01 nm, about 0.05 nm, about 1 nm, about 5 nm, about 10 nm, about 25 nm, about 50 nm, about 75 nm, about 100 nm, about 150 nm, about 200 nm, about 250 nm, about 300 nm, about 350 nm, about 400 nm, about 450 nm, about 500 nm, about 550 nm, about 600 nm, about 650 nm, about 700 nm, about 750 nm, about 800 nm, about 850 nm, about 900 nm, about 950 nm, or about 999 nm. In some embodiments, the nanocomposite filler may have a particle size in the range of about 100 nm to about 500 nm.

[0078] In some embodiments, the well fluid may include an additive. The additive may be supplementary settable or cementitious materials, weighting agents, viscosifying agents (e.g., clays, hydratable polymers, diutan, xanthan gum, and cellulose derivatives or any combination thereof), fluid loss control additives, lost circulation materials, filtration control additives, dispersants, foaming additives, defoamers, corrosion inhibitors, scale inhibitors, formation conditioning agents, water- wetting surfactants, or a lightweight additive. Water- wetting surfactants may be used to aid in removal of oil from surfaces in the wellbore (e.g., the casing) to enhance cement and resin bonding. Some example additives may include: organic polymers, biopolymers, latex, ground rubber, surfactants, crystalline silica, amorphous silica, silica flour, fumed silica, nano-clays (e.g., clays having at least one dimension less than 100 nm), salts, fibers, hydratable clays, microspheres, rice husk ash, micro-fine cement (e.g., cement having an average particle size of from about 5 microns to about 10 microns), metakaolin, zeolite, shale, pumice, perlite, barite, slag, lime (e.g., hydrated lime), gypsum, or combinations thereof. [0079] In certain embodiments, the additive may be a weighting agent. A weighting agent are materials that weigh more than water and may be used to increase the density of the resin component and/or the cement composition. In some examples, a weighting agent may have a specific gravity of about 2 or higher (e.g., about 2, about 3, or about 4, etc.). In some embodiments, the weighting agent may behematite, hausmannite, barite, or combinations thereof.

[0080] In certain embodiments, the additive may be a lightweight additive. The lightweight additive may be included in the cement composition to, for example, decrease the density of the cement. Examples of suitable lightweight additives include, but are not limited to, bentonite, coal, diatomaceous earth, expanded perlite, fly ash, gilsonite, hollow microspheres, low-density elastic beads, nitrogen, pozzolan-bentonite, sodium silicate, or combinations thereof. The resin component may generally have lower base densities than the well fluid including the resin component, thus hollow glass beads and/or foam may be suitable lightweight additives for the resin component, dependent upon the base densities of the resin. In certain embodiments, a non-hydrated hydraulic cement may be utilized as a weighting agent. [0081] In certain embodiments, the additive may be a foaming additive. The foaming additive may facilitate foaming and/or stabilize the resultant foam formed therewith. The foaming additive may include a surfactant or combination of surfactants that reduce the surface tension of the water. The foaming additives may be used in conjunction with a gas to produce a foamed resin-cement composite. In some embodiments, the foaming agent may include an anionic, nonionic, amphoteric (including zwitterionic surfactants), cationic surfactant, or mixtures thereof. Examples of suitable foaming additives include, but are not limited to: betaines; anionic surfactants such as hydrolyzed keratin; amine oxides such as alkyl or alkene dimethyl amine oxides; cocoamidopropyl dimethylamine oxide; methyl ester sulfonates; alkyl or alkene amidobetaines such as cocoamidopropyl betaine; alpha-olefin sulfonates; quaternary surfactants such as trimethyltallowammonium chloride and trimethylcocoammonium chloride; Cs to C22 alkylethoxylate sulfates; or combinations thereof. Some examples of suitable foaming additives include, but are not limited to: mixtures of an ammonium salt of an alkyl ether sulfate, a cocoamidopropyl betaine surfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodium chloride, and water; mixtures of an ammonium salt of an alkyl ether sulfate surfactant, a cocoamidopropyl hydroxysultaine surfactant, a cocoamidopropyl dimethylamine oxide surfactant, sodium chloride, and water; hydrolyzed keratin; mixtures of an ethoxylated alcohol ether sulfate surfactant, an alkyl or alkene amidopropyl betaine surfactant, and an alkyl or alkene dimethylamine oxide surfactant; aqueous solutions of an alpha-olefinic sulfonate surfactant and a betaine surfactant; or combinations thereof.

[0082] In some embodiments, the additive may be a strength-retrogression additive. A strength-retrogression additive may prevent the retrogression of strength after the resin-cement composite has been allowed to develop compressive strength. The strength-retrogression additive may prevent cracks and premature failure of the cement. Examples of suitable strength-retrogression additive may include, but are not limited to, amorphous silica, coarse grain crystalline silica, fine grain crystalline silica, or a combination thereof.

[0083] In some embodiments, the additive may be a set accelerator for a cement component. Control of setting time may allow for the ability to adjust to wellbore conditions or customize set times for individual jobs. Examples of set accelerators may include, but are not limited to, aluminum sulfate, alums, calcium chloride, calcium sulfate, gypsum-hemihydrate, sodium aluminate, sodium carbonate, sodium chloride, sodium silicate, sodium sulfate, ferric chloride, or a combination thereof.

[0084] In some embodiments, the additive may be a set accelerator for a resin component to increase the rate of setting reactions. Control of setting time may allow for the ability to adjust to wellbore conditions or customize set times for individual jobs. Examples of a set accelerator may include, but are not limited to, tertiary amines (including 2,4,6- tris(dimethylaminomethyl)phenol, benzyl dimethylamine, and l,4-diazabicyclo[2.2.2]octane), imidazole and its derivatives (e.g., 2-ethyl,-4-methylimidazole, 2-methylimidazole, l-(2- cyanoethyl)-2-ethyl-4-methylimidazole), Lewis acid catalysts (e.g. aluminum chloride, boron trifluoride, boron trifluoride ether complexes, boron trifluoride alcohol complexes, boron trifluoride amine complexes), and metal salts (e.g. ZnC12, Zn (II) acetate, FeC13) or a combination thereof.

[0085] In some embodiments, the additive may be a set retarder to increase the thickening time. Examples of a set retarder include, but are not limited to, ammonium, alkali metals, alkaline earth metals, borax, metal salts of calcium lignosulfonate, carboxymethyl hydroxyethyl cellulose, sulfoalkylated lignins, hydroxycarboxy acids, copolymers of 2-acrylamido-2- methylpropane sulfonic acid salt and acrylic acid or maleic acid, saturated salt, or a combination thereof. In some examples, a sulfoalkylated lignin may include a sulfomethylated lignin.

[0086] In some embodiments, the additive may be a gas generating additive to release gas at a predetermined time, which may be beneficial to prevent gas migration from the formation through the well fluid before it hardens. The generated gas may combine with or inhibit the permeation of the well fluid by formation gas. Examples of gas -generating additives include, but are not limited to, metal particles (e.g., aluminum powder) that react with an alkaline solution to generate a gas.

[0087] In some embodiments, the additive may be a mechanical property enhancing additive. The mechanical property enhancing additive may be included to ensure adequate compressive strength and long-term structural integrity. These properties may be affected by the strains, stresses, temperature, pressure, and impact effects from a subterranean environment. Examples of a mechanical-property-enhancing additive include, but are not limited to, carbon fibers, glass fibers, metal fibers, mineral fibers, silica fibers, polymeric elastomers, latexes, or combinations thereof.

[0088] In some embodiments, the additive may be a lost circulation material. The lost circulation material may help prevent the loss of fluid circulation into the subterranean formation. Examples of a lost-circulation material include, but are not limited to, cedar bark, shredded cane stalks, mineral fiber, mica flakes, cellophane, calcium carbonate, ground rubber, polymeric materials, pieces of plastic, grounded marble, wood, nut hulls, melamine laminates (e.g., Formica® laminate), corncobs, cotton hulls, or combinations thereof.

[0089] In some embodiments, the additive may be a fluid-loss-control additive. The fluid-loss- control additive may be included to decrease the volume of fluid that is lost to the subterranean formation. Properties of the cement may be significantly influenced by their water content. The loss of fluid may subject the compositions to degradation or complete failure of design properties. Examples of a fluid-loss-control additive include, but are not limited to, certain polymers, such as hydroxyethyl cellulose, carboxymethylhydroxyethyl cellulose, copolymers of 2-acrylamido-2 -methylpropanesulfonic acid and acrylamide or N,N-dimethylacrylamide, and graft copolymers comprising a backbone of lignin or lignite and pendant groups comprising at least one member selected from the group consisting of 2-acrylamido-2- methylpropanesulfonic acid, acrylonitrile, and N,N-dimethylacrylamide.

[0090] In some embodiments, the additive may be a defoaming additive. The defoaming additive may be included to reduce the tendency of the modified well fluid to foam during mixing and pumping of the resin-cement composites. Examples of a defoaming additive may include polyol silicone compounds.

[0091] In some embodiments, the additive may be a thixotropic additive. The thixotropic additive may be included to provide a modified well fluid that can be pumpable as a thin or low viscosity fluid, but when allowed to remain quiescent attains a relatively high viscosity. Among other things, thixotropic additives may be used to help control free water, create rapid gelation as the slurry sets, combat lost circulation, prevent “fallback” in annular column, and minimize gas migration. Examples of a thixotropic additive include, but are not limited to, gypsum, water soluble carboxyalkyl, hydroxyalkyl, mixed carboxyalkyl hydroxyalkyl either of cellulose, polyvalent metal salts, zirconium oxychloride with hydroxyethyl cellulose, or a combination thereof.

[0092] Various embodiments of the well fluid of the present disclosure may be utilized in a number of well operations, described in the following non-limiting examples. The well fluid of the present disclosure may be mixed with the resin component prior to introduction downhole (i.e., “surface mixed”) into a modified well fluid. Alternatively, the well fluid and resin component may be introduced downhole separately and mixed downhole. Various nonlimiting methods including embodiments of the well fluid, as described herein, are also disclosed.

[0093] A geothermal system may be positioned downhole, where the system is formed including part and/or all of the attendant equipment along with the well fluid of the present disclosure (both in an uncured and cured state). In some embodiments, at least a portion of the geothermal system may be in communication with a subterranean and/or geothermal supercritical temperature zone. In certain embodiments, at least a portion of the well fluid of the present disclosure may be positioned in a supercritical temperature zone. In one embodiment, the well fluid may be used in a subterrain well or geothermal well. In another embodiment, the well fluid may be used in a geothermal system. In yet another embodiment, the well fluid may be used in a geothermal system at a supercritical temperature.

[0094] In general, non-limiting methods of carrying out a well operation in a geothermal well having a geothermal supercritical temperature zone, may include at least positioning, introducing, or circulating at least a portion of the well fluid in, into, or through the supercritical temperature zone.

[0095] Non-limiting methods of the present disclosure for reducing/ eliminating lost circulation may be carried out as follows. In an embodiment, the well fluid may be pumped into a lost circulation zone of a geothermal system, allowing the system to harden to completely plug the lost circulation zone, and then drilling through the lost circulation zone. In one embodiment, the well fluid of the present disclosure may be provided to a lost circulation zone(s) and is allowed to cure/harden to form a plug that seals off the lost circulation zone, thus stopping/reducing the lost circulation. The wellbore may then be extended through the plug by drilling through the plug and continuing through the subterranean as desired. In some embodiments, one may first pull the drill pipe in the area of the lost circulation, and then pump down the well fluid into a well into the lost circulation zone through the drill string. The well fluid will not only form up in the wellbore itself, but some of the well fluid may even go out into a loss zone, taking the path of the lost well fluid and sealing off those paths too. Drilling may then resumed and the plug is drilled through to extend the well bore through the plug.

[0096] Non-limiting methods of the present disclosure for reducing/eliminating leaks from casing threads in a pipe string may be carried out as follows. In another embodiment, the well fluid may reduce and/or eliminate leaks from casing threads in a pipe string. The threads may optionally be pressured and bled of any fluids/materials in the threads. Pressure may then be utilized to squeeze the well fluid of the present disclosure into the threads. In some embodiments, the pressure may be maintained to keep the well fluid in place in the threads until it cures/hardens.

[0097] Non-limiting methods of the present disclosure for reducing/eliminating gas migration may be carried out as follows. In yet another embodiment, the well fluid may be provided to the gas migration zone(s), and is allowed to cure/harden to form a plug that seals off the gas migration zone, to either stop or reduce gas migration. In some embodiments, positive pressure may be provided to physically stop the gas migration with pressure and allow the well fluid to cure/harden. Without the positive pressure, gas may continue to migrate and may channel/migrate through the well fluid before the fluid has cured/hardened. If this occurs, the well fluid will not stop the gas migration. [0098] Non-limiting methods of the present invention for setting a kickoff plug or for directional drilling, may generally be carried out as follows. In another embodiment, the well fluid may be used in methods for setting a kickoff plug or for directional drilling. A kickoff plug may include a well fluid (or components thereof) to be set in the wellbore. The kickoff plug may have a length ranging from about 50 ft to about 500 ft. The kickoff plug may be set in the wellbore by lowering a drillstring or an open-ended tubing string to the desired depth and pumping a well fluid (or components thereof) into the wellbore. The well fluid may be cured/hardened to form a plug, i.e. a kickoff plug. After the kickoff plug has been formed, a drillstring may be used to reinitiate drilling operations. The drillstring and drill bit may be in contact with the plug to deflect the drillstring and change the direction in which subsequent drilling proceeds.

[0099] Non-limiting methods of the present disclosure for reducing/ eliminating packer leaks may be carried out as follows. In other embodiments, the well fluid may used in a method for reducing/eliminating packer leaks. In an embodiment, the well fluid (or components thereof) may be provided in the annulus to the leaking packer and may cure/harden to form a seal to seal off the leaking packer and stop/reduce the packer leak. In some embodiments, the packer sealant system including the well fluid may be loaded into the annulus; the packer sealant system may be chased with a fluid (for example, sea water, aqueous solution, drilling fluid, etc); the packer sealant system may be shut in the well; where the well fluid may fall through the annulus to settle on top of the leaking packer; and may include curing the well fluid into a seal on top of the leaking packer to reduce/ eliminate the packer leak. In another embodiment, the method may include tying a production casing valve to the annulus, and similarly forming a seal on top of the leaking packer to reduce/eliminate the packer leak.

[0100] Non-limiting methods of the present invention for plugging and abandoning a well may be carried out as follows. In yet another embodiment, the well fluid may be used to plug and abandon a well. For example, the method may include removing equipment, structures, debris and any collapsed or broken well casing or well screen. The method may also include plugging and sealing within a certain distance of the ground surface. The method may also include removing the entire casing and well screen during sealing. Thus, the well fluid (or components thereof) may be provided to desired depth and may cure/harden to form a plug that seals off the well.

[0101] Non-limiting methods of the present invention for the primary cementing of a well may be carried out as follows. In another embodiment, the well fluid may be used for the primary cementing of a well. For example, the primary cementing method may be achieved by pumping the well fluid into the annular space between the casing and wellbore wall, and then curing the cement to hold the casing in place.

[0102] In another embodiment, the well fluid may be used for remedial cementing. Remedial cementing may be done to correct problems associated with the primary cement job. The well fluid may be useful in many types of remedial cementing operations, including but not limited to, squeeze cementing and plug cementing. In squeeze cementing, the well fluid may be prepared and pumped down a wellbore to the problem area or squeeze target. The problem area or squeeze target is isolated, and pressure may be applied from the surface to effectively force the well fluid into all voids. The well fluid may fill the type of void in the wellbore, whether it is a small crack or micro-annuli, casing split, formation rock or another kind of cavity.

[0103] Non-limiting methods of the present invention for water shut off may be carried out as follows. In yet another embodiment, the well fluid may be used for water shut off. The well fluid may be provided to a water producing zone(s) and may cure/harden to form a plug that seals off the water producing zone and stops/reduces the water production. For example, the well fluid may penetrate radially into the formation in the zone extending radially around the outside of the casing and into the formation. The penetration depth may be at least about 1, about 2, about 3, about 4, about 5, about 6, about 7, or about 8 feet, or may range to/from or between any two of the foregoing depths. Positive pressure may be provided to assist in the penetration, and/or to allow that cement to harden/cure.

[0104] Non-limiting methods of the present invention for treating conformance zones may be carried out as follows. A geothermal system may have a problematic supercritical temperature conformance zone, as understood by one of skill in the art. The well fluid of the present disclosure may be provided to the problematic supercritical conformance zone. The well fluid may then be cured and/or hardened to form a plug which may seal off a problematic supercritical conformance zone.

[0105] In another embodiment, the well fluid of the present disclosure may be utilized in carrying out a well kill operation. Two of the most common methods to kill a well may include the Driller’s method and the Wait & Weight method. In some embodiments, the Driller’s method may be utilized for well kill operation including a first circulation and a second circulation. The first circulation may include bringing a pump to a kill rate, and then opening a choke and holding casing pressure constant. When the pump is at kill rate, the drill pipe pressure should then be switched. At this stage, the drill pipe pressure may be equal to the initial circulation pressure (ICP), with the pressure being held constant until the influx is removed. Then, the holding casing pressure constant may be shut down. The second circulation may include when pumping to kill rate, holding casing pressure constant until kill mud/well fluid reaches the bit and then once the kill mud/well fluid enters the annulus, switching to drill pipe pressure, which is held constant until kill mud/well fluid reaches the surface. In another embodiment, the Wait & Weight method of killing a well may include the following. First, the pump may be brought to kill rate, casing pressure may be held constant, and then once the pump reaches kill rate, switch to drill pipe pressure. The drill pipe pressure may be equal or close to the calculated ICP. Then, the drill pipe pressure may be allowed to fall from ICP to the final circulating pressure (FCP) as kill mud/well fluid fills the drill string. Next, the FCP may be held constant until the kill mud/well fluid reaches the surface. The pump holding casing pressure constant may then be shut down.

EXAMPLES

[0106] The following examples are provided to merely to illustrate some of the many embodiments of the present disclosure and are not intended to and do not limit the scope of the present disclosure.

Method of Analysis

[0107] Examples investigated the fluid (pumpability) time of a high temperature (HT) resin system as well as the maximum temperature where the HT resin system withstands before thermally breaking down the structural composition of the system to failure. In researching the fluid time of the system, rheological properties were studied as well to determine the recommended mixing temperature to allow a rheological profile that minimizes the stress on mixing equipment. Initial static testing was conducted at 450°F in an intrinsically safe roller oven to test Thermal Stability as well as initial setting of the system to ensure proper reaction at elevated temperature. Upon initial curing of the HT resin system, the samples were then placed in a reactor and subject to various temperature up to 850°F.

Thermal Stability Testing at Circulating Temperature of Geothermal Application

[0108] Initial testing of the HT Resin system was conducted in an Ofite Roller Oven, capable of a maximum temperature of 450°F, where expected circulating temperature during cementing operations in the well are 460°F. Testing was conducted with the following materials: Epon 162, Epon 161, Heloxy 48, Epikure W, EpiSeal 5550, and RSC 4628. The materials were mixed in various slurries and tested to the initial circulating temperature (450°F) and ambient pressure to determine the feasibility of use in the Geothermal application with an ultimate temperature of 815°F to 850°F. The slurries were tested and weighed out to their respective amounts and mixed by hand using a metal stirring rod for 5 minutes until each individual component was homogenously mixed into a solution.

Slurry 1

[0109] A first slurry, Slurry 1 was prepared including the following materials: Epon 162 + Heloxy 48 + Epikure W in the ratio of: 100% by weight Epon 162 (100 grams); 10% by weight of Epon 162:Heloxy48 (10 grams); and 15% by weight Epon 162:Epikure W (15 grams).

[0110] Slurry 1 was tested and it was confirmed that it cured to a solid at 450°F, but the cure time was not determined at this stage in testing. The sample was saved to be utilized in post cure testing up to 850°F in a pressurized reactor.

Slurry 2

[0111] A second slurry, Slurry 2 was prepared including the following materials: Epon 162 + Epikure W in the ratio of: 100% by weight Epon 162 (100 grams); 15% by weight of Epon 162: Epikure W (15 grams).

[0112] Slurry 2 was tested and it was confirmed that it cured to a solid at 450°F, but the cure time was not determined at this stage in testing. The sample was saved to be utilized in post cure testing up to 850°F in a pressurized reactor.

Slurry 3

[0113] A third slurry, Slurry 3 was prepared including the following materials: RSC 5550 + RSC 4628 in the ratio of: 100% by weight RSC 5550 (100 grams); 15% by weight of RSC 5550:RSC 4628 (15 grams).

[0114] Slurry 3 was tested. During testing, aeration of the slurry was caused during the curing process, which was expected as the system is a moisture cured Silane system. This showed that the system would be required to set under pressure to minimize aeration of the slurry. It was decided to conduct no further testing as the moisture cure can cause various issue downhole at maximum temperature by introducing water molecules that can cause degradation of various components being used in the well as well as a possible source to cause failures by the water molecules expanding rapidly to a gas which may cause micro-annuli to form during the curing of the resin system.

Slurry 4 [0115] A fourth slurry, Slurry 4 was prepared including the following materials: Epon 162 + Epon 154 (about 40K cP) + Epikure W in the ratio of: 100% by weight Epon 162 (100 grams); 5% by weight of Epon 162:Epon 154 (5 grams); and 15% by weight Epon 162:Epikure W (15 grams).

[0116] Slurry 4 was tested and it showed that this slurry had an extremely fast curing time at 450°F, less than 2 hours. Further, the addition of Epon 154 increased the viscosity of the resin system because Epon 154 was much more viscous than the Epon 162. With the extremely short fluid time at the circulating temperature, it was deemed that this mixture was not suitable at this time for further analysis.

Static Fluid Time Evaluation with High Temperature Post cure to determine Thermal Stability of HT Resin System

[0117] The second phase of testing the slurries incorporated static fluid time analysis and high temperature thermal stability testing to determine where the slurries’ chemical composition failed to the extent of physical deformation and/or up to complete chemical decomposition of the slurries.

[0118] Slurries 1 and 2 were further tested to determine the fluid time and thermal stability of their respective properties. The samples were weighed according to the recipes for the respective test number and a static fluid time was run and recorded until the unpumpable (to viscous to pump in real work applications) time was observed. The samples were mixed by hand utilizing a metal stirring rod and mixed for 5 minutes until all components of the slurry was fully homogenized. The sample was then placed in a glass jar into the roller oven and preheated oven at 450°F (232.2°C). The samples were checked every 30 minutes to one hour for viscosity decrease, viscosity increase, and pumpability factor according criteria shown in Table 1.

Table 1: Criteria of Thermal Stability of HT Resin System

[0119] When fluid time was determined, the sample was prepared for being placed into a Parr Instruments Series 4575B Bench Top Rector System, which is capable of reaching a temperature of 900°F. The sample was prepared by removing the sample from the glass container which it was being testing in and resized to a smaller sample to be able to test in the reactor chamber. The sample was placed in the cell in a metal, open top cup with the only contact to the sample being the bottom of the cup and the temperature probe in the reactor cell. Once the cell was closed Nitrogen was used to pressurize the cell between 500 PSI - 750 PSI (any higher pressure was allowed to naturally occur through heating of the reactor cell). The samples were tested at multiple temperature for a time of 3.5 - 4 hours at temperature, followed by a slow cooling phase (about!2 hours) before removing the sample to examine for physical changes to the sample or chemical changes to the sample. Any physical or chemical changes were recorded. If the sample had minimal physical change and no observable chemical change (slight discoloration, no signs of melting, no charring/ash of the sample) the same sample was used for subsequent temperature analysis. The temperatures tested were increased by 50°F up to 750°F, at which point an increase of 15°F was utilized to test the remainder of the temperature limit to failure of the sample.

[0120] The test results for slurry 1 are presented in Table 2, while the tests results for slurry 2 are presented in Table 3.

Table 2 - Results of Slurry 1

Table 3 - Results of Slurry 2

[0121] The sample for Slurry 1 was allowed to cure overnight and cool to room temperature, followed by preparing the sample to be placed into the Parr Heated Reactor. The sample was tested at various temperature to failure of the sample, results of which are presented in Table 4. Similar preparation was done for Slurry 2, but testing started at 750°F to ensure the sample was able to withstand at least the maximum temperature from Slurry 1. The results of Slurry 2 is presented in Table 5.

Table 4 - Results of Parr Heated Reactor for Slurry 1

Table 5 - Results of Parr Heated Reactor for Slurry 2

[0122] From this initial testing, it was determined that the Heloxy 48, while decreasing the viscosity of the slurry at surface temperatures, effects the thermal stability of the resin system by lowering the thermal stability by 30°F. It was decided to further test the Epoxy system with a 2-part system from Slurry 2. Static Pot Life Testing (Fluid Time) will be studied to determine a suitable ratio of additives to allow the epoxy to be pumped into the well.

Static Pot Life Analysis

[0123] Static Pot Life Testing of Slurry 2 was performed to determine the ratio of additives to allow for ample fluid time to allow to pump and place the Epoxy system into a Geothermal well. The results are shown in FIG. 1. [0124] The test was conducted by mixing the 2-component epoxy system by weight requirements needed for various recipes. The calculated weights were added to a glass jar and mixed for 5 minutes using a metal stirring rod until the mixture was homogenous. In the following, samples 1 thru 5 were then placed into a Ofite Roller Oven (capable of 450°F) and monitored for fluid time, times and temperature were recorded using the state of sample criteria of Table 1.

Preparation of Samples 1-5

[0125] Sample 1 was prepared including the following materials: Epon 162 + Epikure W in the ratio of: 100% by weight Epon 162 (100 grams); and 10% by weight Epon 162:Epikure W (10 grams).

[0126] Sample 2 was prepared including the following materials: Epon 162 + Epikure W in the ratio of: 100% by weight Epon 162 (100 grams); and 9% by weight Epon 162: Epikure W (9 grams).

[0127] Sample 3 was prepared including the following materials: Epon 162 + Epikure W in the ratio of: 100% by weight Epon 162 (100 grams); and 8.6% by weight Epon 162:Epikure W (8.6 grams).

[0128] Sample 4 was prepared including the following materials: Epon 162 + Epikure W in the ratio of: 100% by weight Epon 162 (100 grams); and 8% by weight Epon 162: Epikure W (8 grams).

[0129] Sample 5 was prepared including the following materials: Epon 162 + Epikure W in the ratio of: 100% by weight Epon 162 (100 grams); and 7% by weight Epon 162: Epikure W (8 grams).

Results of Samples 1 - 5

[0130] The results of Samples 1 -5 are presented below in Tables 6 to 10.

Table 6 - Results of Sample 1

Table 7 - Results of Sample 2

Table 8 - Results of Sample 3

Table 9 - Results of Sample 4

Table 10 - Results of Sample 5

[0131] From the results of this test, Sample 5 was further tested for Dynamic Fluid Time and rheological properties. This further testing was evaluated with the inclusion of particulate materials to determine if the fluid time is affected by the addition of these materials and the effects of glass transition temperature (Tg)Zmelting point of the resin slurry.

Thickening Time Analysis (Dynamic Fluid Time)

[0132] Fluid time analysis was conducted using the Ofite Automated HTHP Consistometer for digital recordings of the fluid time at various temperatures. The Automated HTHP Consistometer was calibrated, with a newly rebuilt rheostat, before the assessment according to outline instructions from the Ofite manual for the consistometer.

Preparation of Potentiometer

[0133] The potentiometer was calibrated according to Table 11.

Table 11 - Calibration Parameters of Potentiometer

HT Resin Slurry Preparation (100-7W)

[0134] The components for the Liquid Bridge Plug Slurry was weighed out as follows: 640.06 grams of Epon 162 and 44.80 grams of Epikure W. The Epon 162 and Epikure W was mixed in a 1000 mL jar using a stand mixer at 150 - 300 RPM to allow the mixture to fully homogenize. Thus, the mixture was mixed for about 10 to 15 minutes to form the slurry.

Slurry Cup Preparation

[0135] A slurry cup assembly was prepared to conduct the dynamic fluid time test. All threads of the slurry cup were cleaned thoroughly. A high temperature grease was applied to all threads of the slurry cup. Enough grease is applied to the threads, so the grease will aide in dismantling the cup once testing is completed. It is recommended to use enough grease that it covers all threads completely because excess grease can be wiped away before placing the cup in the consistometer cell.

[0136] The top cap of the slurry cup was then installed as follows: (1) inserting the diaphragm retaining ring; (2) inserting the diaphragm above the retaining ring; (3) inserting the diaphragm support; and (4) installing the expansion chamber lid and screwing it together tightly. The assembly was then greased and the paddle and paddle shaft was inserted from the bottom of the cup.

[0137] The Drive Bar and the Drive Disk Set Screw was then installed using the potentiometer to gauge the correct placement of the Drive bar, such that the paddle shaft sat flush with the top of the potentiometer.

[0138] The Liquid Bridge Plug Slurry prepared above was poured into the bottom of the cup. The Paddle Shaft was spun intermittently during the pouring process to get any air entrainment out of the slurry, such that the slurry was evenly distributed in the slurry cup. The Liquid Bridge Plug Slurry should be poured to fill the cup just above the base threads at the bottom of the cup.

[0139] After pouring, the gasket and base of the cup was installed. Then the pivot bearing and gasket was installed. Any residue on the outside of the slurry cup was then cleaned.

Consistometer Programming

[0140] The following parameters were used in testing the Liquid Bridge Plug HT System: a. The temperature was ramped at 35 minutes to 105 °F (40.56°C) at a rate of 0.83°F/minute b. The pressure was ramped at 30 minutes to 5,000 PSI. c. The motor speed was 75 RPMS

Testing the Liquid Bridge Plug in the Consistometer

[0141] After preparing the Liquid Bridge Slurry as described above, the mixture is added to the Consistometer within 15 to 25 minutes, such that the slurry cup is placed in the Consistometer. The potentiometer was placed on top of the cup and seated properly. The potentiometer was checked to ensure it was reading correctly and calibrated. The top cap was then placed on the consistometer and the cell was filled with oil. The cap was then checked to ensure there were no leaks.

[0142] The Consistometer was then run to perform the dynamic thickening time test. A dynamic testing was conducted at 470°F for a 6 hour fluid time plus a 30 minute surface mixing time (initial 30 minutes, which can be seen in FIG. 2) The Dynamic test was conducted using the Slurry prepared above, at a pressure of 5,000 PSI and 75 RPM. The results of this test is shown in FIG. 2. From this test, a drastic drop in viscosity of the slurry at 110°F to 120°F occurred. This may indicate that the epoxy system should be preheated in the field for ease of mixing as not to strain mixing equipment in large volumes.

[0143] Another dynamic test was conducted at the same pressure and RPM prepared above, but the temperature was 500°F. The results, which are presented in FIG. 3, show a 3.5 hour fluid time plus a 30 minute surface mixing time (omitted from FIG. 3 due to pressure loss on cell). This test also showed a drastic drop in viscosity of the slurry at 110°F to 120°F. This may indicate that the epoxy system should be preheated in the field for ease of mixing as not to strain mixing equipment in large volumes.

Rheological Profile Analysis

[0144] Rheological properties were studied to determine the viscosity of the resin system. Data from this testing was conducted on an Ofite Model 900 Viscometer. Data was recorded using various RPM readings to build viscosity curves at varying temperatures. The data was recorded using a R1B2 spring and bob. This testing was conducted to determine the recommended mixing temperature of the resin system as well as compiling data to better simulate the rates and friction pressures that will be encountered in field operations.

[0145] Tables 12 to 15 provide the conversion factors used when utilizing the Ofite Model 900 Viscometer when utilizing various springs and bobs during testing.

Table 12

Table 13

Table 14

Table 15

[0146] In testing the rheological properties, initial Shear Rate values were recorded on values from the R1B2 spring and bob and converted to RIB 1 values to better simulate viscosities for evaluation in the needed industries where 300 PRM is equivalent to the cP value used in the Drilling Industry. [0147] Table 16 provides the recorded values of the HT Resin System at 100°F, 120°F, 150°F, and 180°F utilizing the R1B2 spring and bob.

Table 16 - R1B2 Rheological Values

[0148] The values recorded above, were then converted to R1B1 values to calculated and build viscosity models of the resin system to be used in simulations and planning, as shown in Table 17.

Table 17 - R1B1 Rheological Values

[0149] Using the following conversions, the viscosity was calculated using the Bingham Plastic modeling for fluids to determine the centipoise value for the slurry at the tested temperatures. r = YP + PV(y), where r = shear stress y = shear rate

YP = yield point

PV = plastic viscosity

[0150] The viscosities of the slurry are presented in Table 18. Table 18

[0151] Based on the results, the slurry should be mixed at a minimum of 100°F to 120°F to minimize stress on surface equipment.

[0152] The preceding description sets forth numerous specific details such as examples of specific systems, components, methods, and so forth, in order to provide a good understanding of several embodiments of the present invention. It will be apparent to one skilled in the art, however, that at least some embodiments of the present invention may be practiced without these specific details. In other instances, well-known components or methods are not described in detail in order to avoid unnecessarily obscuring the present invention. Thus, the specific details set forth are exemplary. Particular embodiments may vary from these exemplary details and still be contemplated to be within the scope of the present invention.

[0153] Although the operations of the methods herein are described in a particular order, the order of the operations of each method may be altered so that certain operations may be performed in an inverse order or so that certain operation may be performed, at least in part, concurrently with other operations. In another embodiment, instructions or sub-operations of distinct operations may be in an intermittent and/or alternating manner.

[0154] It is to be understood that the above description is intended to be illustrative, and not restrictive. Many other embodiments will be apparent to those of skill in the art upon reading and understanding the above description. The scope of the invention should, therefore, be determined with reference to the appended claims, along with the full scope of equivalents to which such claims are entitled.

Claims

WHAT IS CLAIMED IS:

1. A well fluid comprising: a resin component; a curing agent; and a nanocomposite filler, wherein the well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi.

2. The well fluid of claim 1, wherein the resin component comprises a bisphenol resin, glycidyl ethers epoxy resin prepared by the reaction of epichlorohydrin with a compound containing a hydroxyl group carried out under alkaline reaction conditions; epoxy resins prepared by the reaction of epichlorohydrin with mononuclear di- and trihydroxy phenolic compounds; epoxidized derivatives of natural oils with mixed long- chain saturated and unsaturated acids having between about 14 and 20 carbon atoms; polyepoxides derived from esters of polycarboxylic acids with unsaturated alcohols; polyepoxides derived from esters prepared from unsaturated alcohols and unsaturated carboxylic acids; epoxidized butadiene based polymers; epoxidized derivatives of dimers of dienes, or combinations thereof.

3. The well fluid of claim 1, wherein the resin component comprises a bisphenol resin.

4. The well fluid of claim 3, wherein the bisphenol resin comprises Bisphenol A, Bisphenol AP, Bisphenol AF, Bisphenol B, Bisphenol BP, Bisphenol C, Bisphenol C 2, Bisphenol E, Bisphenol F, Bisphenol G, Bisphenol M, Bisphenol S, Bisphenol P, Bisphenol PH, Bisphenol TMC, Bisphenol Z, or combinations thereof.

5. The well fluid of claim 1, wherein the curing agent comprises an amine compound.

6. The well fluid of claim 1, wherein the curing agent comprises N-2-(aminoethyl)-3- aminopropyltrimethoxy silane; 3 -glycidoxypropyltrimethoxy silane; gammaaminopropyltriethoxysilane; N-beta-(aminoethyl)-gamma- aminopropyltrimethoxysilanes; aminoethyl-N-beta-(aminoethyl)-gamma-

- 39 - aminopropyl-trimethoxysilanes; gamma-ureidopropyl-triethoxysilanes; beta-(3-4 epoxy-cyclohexyl)-ethyl-trimethoxysilane; gamma- glycidoxypropyltrimethoxysilanes; vinyltrichlorosilane; vinyltris (betamethoxyethoxy) silane; vinyl tri ethoxysilane; vinyltrimethoxysilane; 3- metacryloxypropyltrimethoxysilane; beta-(3,4 epoxycyclohexyl)- ethyltrimethoxysilane; r-glycidoxypropyltrimethoxysilane; r- glycidoxypropylmethylidiethoxysilane; N-beta-(aminoethyl)-r-aminopropyl- trimethoxysilane; N-beta-(aminoethyl)-r-aminopropylmethyldimethoxysilane; 3- aminopropyl-triethoxysilane; N-phenyl-r-aminopropyltrimethoxysilane; r- mercaptopropyltrimethoxysilane; r-chloropropyltrimethoxysilane; vinyltrichlorosilane; vinyltris(beta-methoxyethoxy)silane; vinyltrimethoxysilane; r- metacryloxypropyltrimethoxysilane; beta-(3,4 epoxy cyclohexyl)-ethyltrimethoxysila; r-glycidoxypropyltrimethoxysilane; r-glycidoxypropylmethylidiethoxysilane; N-beta- (aminoethyl)-r-aminopropyltrimethoxysilane; N-beta-(aminoethyl)-r- aminopropylmethyldimethoxysilane; r-aminopropyltri ethoxysilane; N-phenyl-r- aminopropyltrimethoxysilane; r-mercaptopropyltrimethoxysilane; r- chloropropyltrimethoxysilane; N[3-(trimethoxysilyl)propyl]-ethylenediamine; substituted silanes where one or more of the substitutions contains a different functional group; or a combination thereof. The well fluid of claim 1, wherein the curing agent is diethyltoluenediamine. The well fluid of claim 1, wherein the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrill omite, metal oxides, metallic particles, or a combination thereof. The well fluid of claim 1, wherein the resin component comprises bisphenol resin, and the curing agent comprises an amine compound. . The well fluid of claim 1, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises

- 40 - nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy- apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrill omite, metal oxides, metallic particles, or a combination thereof. . The well fluid of claim 1, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. . The well fluid of claim 1, wherein the resin component has a viscosity at 25 °C of about 2,500 cP to about 4,500 cP. . The well fluid of claim 1, wherein the nanocomposite filler has a particle size in a range of about 100 nm to about 500 nm. . The well fluid of claim 1, wherein the resin component is included in an amount of about 20% to about 95%, based on total weight of the well fluid. . The well fluid of claim 1, wherein the curing agent is included in about 5 parts by weight to about 45 parts by weight, per 100 parts of resin component. . The well fluid of claim 1, wherein the resin component comprises a diluent. . The well fluid of claim 16, wherein the diluent comprises butyl glycidyl ether, Cxi alkyl glycidyl ethers, cyclohexane dimethanol diglycidyl ether, polyethylene glycol, butyl lactate, dipropylene glycol methyl ether, dipropylene glycol dimethyl ether, dimethyl formamide, diethyleneglycol methyl ether, ethyleneglycol butyl ether, diethyleneglycol butyl ether, propylene carbonate, d'limonene, fatty acid methyl esters, or a combination thereof. . The well fluid of claims 16 or 17, wherein the diluent is included in an amount of about 10 to 70 parts by weight of diluent per 100 parts of the resin component.

- 41 -

. The well fluid of any of the preceding claims, further comprising a cement component. . The well fluid of claim 19, wherein the cement component comprises a hydraulic cement. . The well fluid of claim 20, wherein the hydraulic cement includes calcium, aluminum, silicon, oxygen, sulfur, or a combination thereof. . The well fluid of claim 20, wherein the hydraulic cement comprises Portland cements, pozzolana cements, gypsum cements, high aluminum content cements, silica cements, or high alkalinity cements. 3. The well fluid of claim 22, wherein the Portland cement comprises classes A, B, C, G and H. 4. The well fluid of claim 1, further comprising an additive. 5. The well fluid of claim 24, wherein the additive is at least one of a weight agent, a viscofying agent, fluid loss control additive, a lost circulation material, a filtration control additive, a dispersant, a foaming additive, a defoamer, a corrosion inhibitor, a scale inhibitor, a formation conditioning agent, or a water-wetting surfactant. 6. The well fluid of claim 1, wherein the composition is cured to form a cured composition having at least about 90% seal integrity after compression compared to seal integrity before compression. 7. A method for zone isolation comprising: providing a well fluid including a resin component, a curing agent, and a nanocomposite filler; pumping the cement composition into a supercritical temperature section of pipeline; and curing the cement composition in the section to form a zonal isolation structure, wherein the zonal isolation structure is compressible, and wherein the supercritical temperature section is at a temperature of at least 550°F

8. The method of claim 27, wherein the section of pipeline includes an annulus or borehole. 9. The method of claim 27, wherein the well fluid includes the resin component in an amount of about 20% to about 95%, based on total weight of the well fluid 0. The method of claim 27, wherein the well fluid has a viscosity at 25°C at about 1,000 cP to about 2,100 cP. 1. The method of claim 27, wherein during the providing the well fluid, the well fluid is mixed. 2. The method of claim 31, wherein the composition is mixed at a temperature of about 100°F to about 120°F. . The method of claim 27, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy- apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrill omite, metal oxides, metallic particles, or a combination thereof. . The method of claim 27, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. 5. A method of carrying out a well operation in a subterranean well having a downhole supercritical temperature zone, comprising: providing a well fluid to the downhole zone, wherein the well fluid comprises a resin component, a curing agent and a nanocomposite filler, wherein the well fluid is stable at a temperature of at least about 550°F.

6. The method of claim 35, wherein the well operation includes lost circulation, casing leaks, gas migration, kick off plug, packer leak, plug and abandon, primary cement, remedial cement, or water shut off. . The method of claim 35, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy- apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrill omite, metal oxides, metallic particles, or a combination thereof. . The method of claim 35, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. 9. A subterranean/geothermal well system having a supercritical subterranean zone, comprising a well fluid within the supercritical subterranean zone, wherein the well fluid comprises a resin component, a curing agent and a nanocomposite filler, wherein the well fluid is stable at a temperature of at least about 550°F. . The subterranean/geothermal well system of claim 39, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. . The subterranean/geothermal well system of claim 39, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene.

- 44 -

42. A method of reducing lost circulation from a lost circulation zone at supercritical temperature within a geothermal wellbore, the method comprising: providing a well fluid to the lost circulation zone; curing the well fluid to form a plug that seals off the lost circulation zone; and drilling through the plug to extend the wellbore through the lost circulation zone, wherein the well fluid comprises a resin component, a curing agent, and a nanocomposite filler.

43. The method of claim 42, wherein the well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi.

44. The method of claim 42, wherein the well fluid is cured to form a cured composition having at least about 90% seal integrity after compression compared to seal integrity before compression.

45. The method of claim 42, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy- apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof.

46. The method of claim 42, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene.

47. A lost circulation well fluid for use in lost circulation operations to seal off a supercritical temperature lost circulation zone within a geothermal wellbore, comprising a resin component, a curing agent, and a nanocomposite filler.

- 45 -

. The lost circulation well fluid of claim 47, wherein the lost circulation well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. . The lost circulation well fluid of claim 47, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. . The lost circulation well fluid of claim 47, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. . A geothermal well system comprising: a geothermal wellbore; a supercritical temperature lost circulation zone within the geothermal wellbore; and a lost circulation plug comprising a cured lost circulation well fluid comprising a resin, a curing agent and a nanocomposite filler, wherein the lost circulation plug is configured to seal off the supercritical temperature lost circulation zone and to define a passage extending the wellbore through the lost circulation zone. . The geothermal well system of claim 51, wherein the cured lost circulation well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. . The geothermal well system of claim 51, wherein the lost circulation well fluid is cured to form a cured composition having at least about 90% seal integrity after compression compared to seal integrity before compression.

- 46 -

. The geothermal well system of claim 51, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. . The geothermal well system of claim 51, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene.

56. A method of sealing casing threads of a pipe string, wherein the threads are located in a supercritical zone of a geothermal wellbore, the method comprising: providing a well fluid to the casing threads in the wellbore; applying a pressure to squeeze thread the well fluid into the casing threads; and maintaining pressure to allow the well fluid to cure and form a seal in the threads, wherein the well fluid comprises a resin component, a curing agent, and a nano composite filler. . The method of claim 56, wherein the well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. . The method of claim 56, wherein the well fluid is cured to form a cured composition having at least about 90% seal integrity after compression compared to seal integrity before compression . The method of claim 56, wherein the wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate,

- 47 - graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. . The method of claim 56, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. . A casing thread well fluid for use with casing threads which are located in a supercritical temperature zone of a pipe string in a geothermal wellbore, comprising a resin component, a curing agent, and a nano composite filler. The casing thread well fluid of claim 61, wherein the casing thread well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The casing thread well fluid of claim 61, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The casing thread well fluid of claim 61, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A geothermal well system comprising: a geothermal wellbore having a supercritical temperature zone; a pipe string in the geothermal wellbore, wherein the pipe string includes casing threads in the supercritical temperature zone; and a casing thread well fluid residing in the casing threads, wherein the casing thread well fluid comprises a resin component, a curing agent, and a nanocomposite filler.

- 48 - The geothermal well system of claim 65, wherein the casing thread well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The geothermal well system of claim 65, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The geothermal well system of claim 65, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. method of treating gas migration within a geothermal wellbore having a supercritical temperature gas migration zone, comprising: providing a gas migration well fluid to the gas migration zone; and maintaining positive pressure on the gas migration well fluid until the gas migration well fluid cures and hardens, wherein the gas migration well fluid comprises a resin component, a curing agent, and a nanocomposite filler. he method of claim 69, wherein the gas migration well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The method of claim 69, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy- apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof.

- 49 - The method of claim 69, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A gas migration well fluid for use in treating gas migration within a supercritical temperature gas migration zone of a geothermal wellbore, comprising a resin component, a curing agent, and a nanocomposite filler. The gas migration well fluid of claim 73, wherein the gas migration well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The gas migration well fluid of claim 73, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The gas migration well fluid of claim 73, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A geothermal well system comprising: a geothermal wellbore having a supercritical temperature gas migration zone; and a gas migration well fluid position in the supercritical temperature gas migration zone, wherein the gas migration well fluid comprises a resin component, a curing agent, and a nanocomposite filler. The geothermal well system of claim 77, wherein the gas migration well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi.

- 50 - The geothermal well system of claim 77, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The geothermal well system of claim 77, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A method of setting a kickoff plug in a geothermal wellbore, comprising: lowering an open ended tubular member into the geothermal wellbore; providing a kickoff plug well fluid through the open ended tubular member and into a supercritical temperature kickoff zone of the wellbore; and curing the kickoff plug well fluid into a hardened kickoff plug, wherein the kickoff plug well fluid comprises a resin component, a curing agent, and a nanocomposite filler. The method of claim 81, wherein the kickoff plug well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The method of claim 81, wherein the kickoff plug well fluid is cured to form a cured composition having at least about 90% seal integrity after compression compared to seal integrity before compression. The method of claim 81, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy- apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay

- 51 - tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The method of claim 81, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A kickoff plug well fluid for use in a supercritical temperature zone comprising a resin component, a curing agent, and a nanocomposite filler. The kickoff plug well fluid of claim 86, wherein the kickoff plug well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The kickoff plug well fluid of claim 86, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The kickoff plug well fluid of claim 86, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A geothermal well system comprising: a geothermal wellbore having a supercritical temperature kickoff zone; and a kickoff plug well fluid configured in the supercritical temperature kickoff zone, wherein the kickoff plug well fluid comprises a resin component, a curing agent, and a nanocomposite filler.

- 52 - he geothermal well system of claim 90, wherein the kickoff plug well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The geothermal well system of claim 90, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The geothermal well system of claim 90, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A method of treating packer leaks from a packer, comprising: loading a packer leak well fluid into an annulus of a geothermal well; chasing the packer leak well fluid with a liquid; shutting in the well; allowing the packer leak well fluid to fall through the annulus and settle on top of leaking areas of the packer; and curing the packer leak well fluid to form a seal on top of the leaking areas of the packer, wherein the packer leak well fluid comprises a resin component, a curing agent, and a nanocomposite filler. he method of claim 94, wherein the packer leak well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The method of claim 94, wherein the packer leak well fluid is cured to form a cured composition having at least about 90% seal integrity after compression compared to seal integrity before compression.

- 53 - The method of claim 94, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy- apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrill omite, metal oxides, metallic particles, or a combination thereof. he well fluid of claim 94, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. packer leak well fluid for use in treating packer leaks from a packer in a supercritical temperature zone within an annulus of a subterranean well, comprising a resin component, a curing agent, and a nanocomposite filler. The packer leak well fluid of claim 99, wherein the packer leak well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The packer leak well fluid of claim 99, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The packer leak well fluid of claim 99, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A geothermal well system comprising: a geothermal wellbore having a supercritical temperature zone;

- 54 - a packer configured in the supercritical temperature zone; and a packer leak well fluid position on a leak area of the packer, wherein the packer leak well fluid comprises a resin component, a curing agent, and a nanocomposite filler. The geothermal well system of claim 103, wherein the packer leak well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The geothermal well system of claim 103, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The geothermal well system of claim 103, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A method of plugging and abandoning a geothermal well, comprising: providing a plugging well fluid in a supercritical temperature zone of the geothermal well; curing the plugging well fluid to form a plug that seals off the geothermal well; and abandoning the geothermal well, wherein the plugging well fluid comprises a resin component, a curing agent and a nanocomposite filler. The method of claim 107, wherein the plugging well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi.

- 55 - The method of claim 107, wherein the plugging well fluid is cured to form a cured composition having at least about 90% seal integrity after compression compared to seal integrity before compression. The method of claim 107, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy- apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrill omite, metal oxides, metallic particles, or a combination thereof. The method of claim 107, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A plug and abandon well fluid for use during plugging and abandoning operations for forming a plug in a supercritical temperature zone, wherein the plug and abandon well fluid comprises a resin component, a curing agent, and a nanocomposite filler. The plug and abandon well fluid of claim 112, wherein the plug and abandon well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The plug and abandon well fluid of claim 112, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof.

- 56 - The plug and abandon well fluid of claim 112, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A plugged and abandoned geothermal well system comprising: a wellbore in a supercritical temperature zone of a geothermal well; a plug configured in the supercritical temperature zone, wherein the plug is formed from a composition comprising a plug and abandon well fluid, wherein the plug and abandon well fluid comprises a resin component, a curing agent, and a nanocomposite filler. The plugged and abandoned geothermal well system of claim 116, wherein the plug and abandon well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The plugged and abandoned geothermal well system of claim 116, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrill omite, metal oxides, metallic particles, or a combination thereof. The plugged and abandoned geothermal well system of claim 116, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A method of primary cementing, comprising: providing a primary cementing well fluid to a supercritical temperature zone of an annulus, wherein the annulus is between a casing positioned in the wellbore and the wellbore; curing the primary cementing well fluid to form a sheath around the casing to fix the casing in the wellbore,

- 57 - wherein the primary cementing well fluid comprises a resin component, a curing agent, and a nanocomposite filler. The method of primary cementing of claim 120, wherein the primary cementing well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The method of primary cementing of claim 120, wherein the primary cementing well fluid is cured to form a cured composition having at least about 90% seal integrity after compression compared to seal integrity before compression. The method of primary cementing of claim 120, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The method of claim 120, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A primary cementing well fluid for use carrying out a primary cementing operating in a supercritical temperature annular zone, comprising a resin component, a curing agent, and a nanocomposite filler, wherein the annular zone is defined between a subterranean wellbore and casing therein. The primary cementing well fluid of claim 125, wherein the primary cementing well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The primary cementing well fluid of claim 125, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the

- 58 - nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof.

128. The primary cementing well fluid of claim 125, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene.

129. A geothermal well system comprising: a geothermal wellbore; a casing configured in the geothermal wellbore to define an annulus between the casing and the wellbore, wherein the annulus has a supercritical temperature zone, and a primary cementing well fluid configured in the supercritical temperature zone of the annulus, wherein the primary cementing well fluid comprises a resin component, a curing agent, and a nanocomposite filler.

130. The geothermal well system of claim 129, wherein the primary cementing well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi.

131. The geothermal well system of claim 129, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof.

132. The well fluid of claim 129, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene.

- 59 - A water shut off method for a geothermal well, the method comprising: providing a well shut off well fluid to a target zone in the geothermal well outside of a casing positioned in the geothermal well; penetrating a subterranean area of the geothermal well in a radial zone extending radially outside of the casing; and curing the well shut off well fluid to form cured and hardened well shut off well fluid, wherein at least one of the target zone or the radial zone is at a supercritical temperature, and wherein the well shut off well fluid comprises a resin component, a curing agent, and a nanocomposite filler. The water shut off method of claim 133, wherein the well shut off well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The water shut off method of claim 133, wherein the well shut off well fluid is cured to form a cured composition having at least about 90% seal integrity after compression compared to seal integrity before compression. The water shut off method of claim 133, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The water shut off method of claim 133, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene.

- 60 - A water shut off well fluid for use in a supercritical temperature radial zone in the geothermal well outside of a casing positioned in the geothermal well, comprising a resin component, a curing agent, and a nanocomposite filler. The water shut off well fluid of claim 138, wherein the water shut off well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The water shut off well fluid of claim 138, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The water shut off well fluid of claim 140, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A geothermal well system comprising: a geothermal wellbore; a casing configured in the geothermal wellbore; a supercritical temperature radial zone extending radially outside of the casing; and a water shut off well fluid, wherein the water shut off well fluid comprises a resin component, a curing agent, and a nanocomposite filler. The geothermal well system of claim 142, wherein the water shut off well fluid is stable at a temperature of at least about 550°F or higher and a pressure of about 10,000 psi to about 15,000 psi. The geothermal well system of claim 142, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the

- 61 - nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The geothermal well system of claim 142, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A method for treating a supercritical conformance zone, comprising: detecting a problem area in the supercritical conformance zone; providing a well fluid to the problem area in the supercritical conformance zone; curing the well fluid to form a cured and hardened plug of the well fluid, wherein the well fluid comprises a resin component, a curing agent, and a nanocomposite filler. The method of claim 146, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy- apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The method of claim 146, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A well fluid for treating a problem area in a supercritical conformance zone comprising: a resin component; a curing agent; and a nanocomposite filler.

- 62 - The well fluid of claim 149, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3- cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The well fluid of claim 149, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A geothermal well system comprising: a geothermal wellbore; a casing configured in the geothermal wellbore; a supercritical temperature conformance zone; and a well fluid, wherein the well fluid comprises a resin component, a curing agent, and a nanocomposite filler. The geothermal well system of claim 152, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The geothermal well system of claim 152, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A method for performing a well kill operation, comprising: providing a well fluid to a target area;

- 63 - performing a first circulation step; and performing a second circulation step.

156. The method of claim 155, wherein the first circulation step comprises: bringing a pump to kill rate, opening a choke and holding the casing pressure constant until the pump reaches the kill rate; switching to drill pipe pressure, wherein the drill pipe pressure is held constant until the influx is removed, and shutting down holding the casing pressure constant.

157. The method of claim 156, wherein the second circulation step comprises: during the bringing the pump to kill rate, applying the well fluid to a bit towards an annulus; and switching to drill pipe pressure when the well fluid enters the annulus, wherein the drill pipe pressure is held constant and the well fluid reaches a surface, wherein the well fluid comprises a resin component, a curing agent, and a nanocomposite filler.

158. The method of claim 155, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy- apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof.

159. The method of claim 155, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene.

160. A method for performing a well kill operation, comprising: providing a well fluid to a well kill operation;

- 64 - bringing a pump to kill rate, while holding casing pressure constant; switching to drill pipe pressure when the pump reaches the kill rate, wherein the drill pipe pressure is an initial circulating pressure; allowing the drill pipe pressure to drop to a final circulating pressure, wherein the well fluid fills a drill string; holding the final circulating pressure constant while the well fluid reaches a surface; and shutting down the pump holding casing pressure constant, wherein the well fluid comprises a resin component, a curing agent and a nanocomposite filler.

161. The method of claim 160, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy- apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrill omite, metal oxides, metallic particles, or a combination thereof.

162. The method of claim 160, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene.

163. A well fluid for performing a well kill operation, comprising a resin component, a curing agent and a nanocomposite filler.

164. The well fluid of claim 163, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3- cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof.

- 65 - The method of claim 164, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene. A geothermal well system comprising: a geothermal wellbore; a casing configured in the geothermal wellbore; a pump; a drill pipe; and a well fluid, wherein the well fluid comprises a resin component, a curing agent, and a nanocomposite filler. The geothermal well system of claim 166, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises nano calcium carbonate, nano clays, NLDH nanofillers, 3-cyanopropyldimethylsiloxy-apophllite with Epon 862 at a concentration, organic layered-silicate with high thermal stability, nano- graphene, silica, calcium carbonate, graphite, cellulose fibers, clay tubes, sepiolite, carbon fibers, copper oxide, graphene oxide, montrillomite, metal oxides, metallic particles, or a combination thereof. The method of claim 166, wherein the resin component comprises bisphenol resin, the curing agent comprises diethyltoluenediamine, and the nanocomposite filler comprises graphene.

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