Systems and methods for producing coated drill cuttings and wellbore fluids including the same

Abstract

Systems, methods, and apparatus for producing coated drill cuttings and for producing wellbore fluids using coated drill cuttings, and compositions relating to the same are disclosed. The coated drill cuttings may be used to create appropriate wellbore fluids to be used in wellbore fluid supply systems, such as spacer fluids, lead barrier fluids, tail barrier fluids. In one embodiment, the wellbore fluids result in one or more substantially impermeable barrier sheaths within the wellbore, which barrier sheaths may be cementitious or non-cementitious.

Description

Attorney Docket No.: 212276010400 / PCTSYSTEMS AND METHODS FOR PRODUCING COATED DRILL CUTTINGS AND WELLBORE FLUIDS INCLUDING THE SAMECROSS-REFERENCE TO RELATED APPLICATIONS

[0001] The present application claims priority to U.S. Provisional Application No. 63 / 690,835, entitled “SYSTEMS AND METHODS FOR PRODUCING COATED DRILL CUTTINGS AND WELLBORE FLUIDS INCLUDING THE SAME,” filed September 5, 2024, the disclosure of which is incorporated herein by reference in its entirety.BACKGROUND

[0002] In cementing operations, such as well construction and remedial cementing, cement compositions are commonly utilized. Cement compositions may be used in primary cementing operations whereby pipe strings, such as casing and liners, are cemented in wellbores. In a typical primary cementing operation, a cement composition may be pumped into an annulus between the walls of the wellbore and the exterior surface of the pipe string, or casing, disposed therein. The cement composition may set in the annular space, thereby forming an annular sheath of hardened, substantially impermeable material (e.g., a cement sheath) that may support and position the pipe string in the wellbore and may bond the exterior surface of the pipe string to the wellbore walls. The cement sheath surrounding the pipe string generally functions to prevent the migration of fluids in the annulus, as well as protecting the pipe string from corrosion.SUMMARY OF THE DISCLOSURE

[0003] Broadly, the present patent application relates to sy stems, methods, and apparatus for producing coated drill cuttings. The drill cuttings may be used to create appropriate wellbore fluids, such as spacer fluids, barrier fluids (e.g., fluids for producing barriers in a wellbore), and other useful wellbore fluids and compositions relating to the same, as detailed herein.

[0004] As noted above, coated drill cuttings may be used to create one or more wellbore fluids. The coated drill cuttings may be produced, for instance, by coating the drill cuttings using any suitable coating and / or deposition technique. In one embodiment, the coated drill cuttings may be produced locally (e.g., where the drill cuttings are produced). In another embodiment, the coated drill cuttings may be produced remotely (e.g.. remote from where the drill cuttings are produced). Drill cuttings may be obtained from a variety of subterranean drilling, cutting, excavating, and / or mining operations, including hydrocarbon production (e g., oil, natural gas, coal), geothermal energy production, and carbon capture and storage. The drill cuttings that are coated, as described herein, may include one or more particulate and / or fragmented materials inAttorney Docket No.: 212276010400 / PCT addition or alternative to cuttings derived from subterranean or other drilling operations. For example, other cuttings and / or other materials that may be coated and utilized as described herein include mine tailings, geopolymers, fly ash, slug, silica fume, and / or kaolin, among others.

[0005] One non-limiting embodiment of an exemplary' method for creating and using coated drill cuttings is illustrated in FIG. 1. In the illustrated embodiment, the method comprises coating (1000) drill cuttings and creating (2000) a wellbore fluid including the coated drill cuttings. The method may optionally comprise pumping (3000) the wellbore fluid having the coated drill cuttings into a casing (e.g., to facilitate producing barriers in a wellbore) (see, e.g., FIG. 5).

[0006] The coating step (1000) may use any suitable drill cuttings. In one embodiment, the drill cuttings comprise dry drill cuttings, wet drill cuttings, and combinations thereof. In one embodiment, the coating step (1000) may include mixing (e.g., contacting) the drill cuttings with one or more materials. In one embodiment, the liquid is an aqueous solution or an organic solution. In one embodiment, the liquid is an aqueous solution. In one embodiment, the aqueous solution is (or is based on) at least one of fresh water, ground water, deionized water, distilled water, produced water, and combinations thereof.

[0007] In one embodiment, the creating step (2000) may include mixing the drill cuttings with one or more additives to create the wellbore fluid. The one or more additives may include, for example, an emulsifier, a viscosifier, a fluid loss control agent, a surfactant, a retarder, an accelerator, an extender, a densifier. an anti-shrinking agent, a resilient material, and combinations thereof. The created wellbore fluid may be any suitable wellbore fluid, such as any of a spacer fluid, a lead barrier fluid, and a tail barrier fluid. Additional details relating to the creation of wellbore fluids from drill cuttings are provided herein.

[0008] The drill cuttings may be obtained from any suitable source. In one embodiment, and referring now to FIG. 2, a method comprises drilling (800) a wellbore, thereby creating (810) at least some of the drill cuttings. The drill cuttings may be any suitable material or combinations of materials. In one embodiment, the drill cuttings comprise sedimentary materials, igneous materials, metamorphic materials, and combinations thereof. Non-limiting examples of suitable sedimentary materials for use as drill cuttings include dolomite, cherts, siltstone, chalk, shale, limestone, and sandstone, among others. Non-limiting examples of suitable igneous materials for use as drill cuttings include basalt, gabbro, and pumice, among others. Non-limiting examples of suitable metamorphic materials for use as drill cuttings include schist, argillite, and slate, among others.Attorney Docket No.: 212276010400 / PCT

[0009] Once obtained, the drill cuttings may optionally be prepared (900) for the coating step (1000). For instance, the drill cuttings may be wholly or partially washed (910), dried (920) and / or sized (930). In one embodiment, the washing step (910) comprises removing at least some drilling fluid and / or at least some drilling mud from the drill cuttings. In one embodiment, the drying step (920) comprises removing at least some fluid remaining after washing (910) from the drill cuttings via, for example, evaporation. In one embodiment, the sizing step (930) comprises comminuting the drill cuttings. In one embodiment, the comminuting comprises grinding the drill cuttings, pulverizing the drill cuttings, crushing the drill cuttings, and combinations thereof. Prior to, after, or in combination with the comminuting, the drill cuttings may be sorted (e.g., by size). In one embodiment, the sorting comprises sieving the drill cuttings, filtering the drill cuttings, and combinations thereof. In one embodiment, the wellbore fluid is created locally (e g., where the drill cuttings are created). In another embodiment, the drill cuttings may be produced remotely prior to creating the wellbore fluid.

[0010] As noted above, a method may comprise coating (1000) drill cuttings with a coating layer. In one embodiment, and referring now to FIG. 3, a method comprises applying (1010) a liquid layer to at least some of the drill cuttings. The liquid layer applied to the drill cuttings may be solidified to form a coating layer on the drill cuttings. For example, the method may- further comprise curing (1011) and / or drying (1012) the liquid layer to form an at least partially solidified coating layer on the drill cuttings. In some embodiments, the method comprises applying (1020) a powder layer to at least some of the drill cuttings. The powder layer may optionally be further processed by, for example, curing (1021) the powder layer. In some embodiments, heat may be applied prior to and / or during curing to melt particles within the powder. In other embodiments, the method comprises vapor depositing (1030) a solid layer onto surfaces of at least some of the drill cuttings. For example, one or more vapor deposition techniques, such as chemical vapor deposition (CVD) and / or physical vapor deposition (PVD) may be used to deposit one or more layers on the drill cutting surfaces. Although the steps associated with coating (1000) drill cuttings are illustrated as following the preparing (900) of the drill cuttings, in some embodiments, at least some or all of the coating (1000) steps may be carried out during one or more of the preparing (900) steps, e.g., during washing (910), dry ing (920) and / or sizing (930). Additional details relating to the coating of the drill cuttings are provided herein.BRIEF DESCRIPTION OF THE DRAWINGSAttorney Docket No.: 212276010400 / PCT

[0011] FIG. 1 illustrates one embodiment of a method for coating drill cuttings, creating a wellbore fluid, and / or pumping a wellbore into a casing in accordance with embodiments described herein.

[0012] FIG. 2 illustrates one embodiment of a method for creating and / or preparing drill cuttings in accordance with embodiments described herein.

[0013] FIG. 3 illustrates one embodiment of a method for coating drill cuttings and / or creating a wellbore fluid in accordance with embodiments described herein.

[0014] FIG. 4 is a block diagram illustrating one embodiment of a system for preparing a wellbore fluid in accordance with embodiments described herein.

[0015] FIG. 5 is a schematic view of one embodiment of a wellbore fluid supply system for use with wellbore fluids in accordance with embodiments described herein.

[0016] FIG. 6 is a block diagram of one embodiment of a system for coating drill cuttings in accordance with embodiments described herein.

[0017] FIG. 7 is a schematic view of one embodiment of a wellbore drilling system in accordance with embodiments herein.

[0018] FIG. 8 is a block diagram illustrating one embodiment of an off-site preparation system in accordance with embodiments described herein.

[0019] FIG. 9 is a block diagram illustrating one embodiment of a system for preparing a wellbore fluid in accordance with embodiments described herein.

[0020] FIG. 10 illustrates one embodiment of a coated drill cutting in accordance with embodiments described herein.

[0021] FIG. 11 illustrates one embodiment of a coated drill cutting in accordance with embodiments described herein.

[0022] FIG. 12 is a block diagram of one embodiment of a system for coating drill cuttings in accordance with embodiments described herein.

[0023] FIG. 13 is a block diagram of one embodiment of a system for coating drill cuttings in accordance with embodiments described herein.

[0024] FIG. 14 is a block diagram of one embodiment of a system for coating drill cuttings in accordance with embodiments described herein.DETAILED DESCRIPTION

[0025] Reference is now made to the accompanying figures, which illustrate various nonlimiting, pertinent features of embodiments of the present disclosure.Attorney Docket No.: 212276010400 / PCT i. System Overview

[0026] Referring now to FIG. 4, one embodiment of a wellbore fluid preparation system (100) is illustrated. In the illustrated embodiment, the wellbore fluid preparation system (100) may include a primary material source (110). a liquid tank (120). and a secondary material source (130). The primary material source (110) may include, for example, a tank, hopper, or other suitable container holding coated drill cuttings for producing one or more wellbore fluids. The primary material source (110), the liquid tank (120), and the secondary7material source (130) may be fluidly connected to a mixing unit (140) via conduits (115, 125, 135) and / or other suitable conveyance apparatus. The mixing unit (140) may be fluidly connected to a pump (180) (e.g., a slurry pump) via a conduit (146) for provision of wellbore fluids to a wellbore fluid supply system (200), such as that illustrated in FIG. 5. Optionally, the wellbore fluid preparation system (100) may include a supplement unit to facilitate adjustment of one or more properties for a final wellbore fluid, as described in further detail below. As explained below, the wellbore fluid preparation system (100) may be used to create and / or provide tailored wellbore fluids made from drill cuttings to the wellbore fluid supply system (200). In some embodiments, suitable material conveyors (e.g., augers, belts, etc.) may be used in place of or in addition to one or more of the described conduits to move materials between portions of fluid preparation system (100) and / or any other systems described herein. Alternatively or additionally, one or more of the primary material(s), the liquid, and / or the secondary material(s) may be introduced to the mixing unit (140) and / or the wellbore fluid and / or other products may be conveyed from the mixing unit (140) by vehicle, robot, manually, and / or in any other suitable manner. In some examples, as shown in FIG. 9 and described in further detail below, after or concurrent to the mixing in the mixing unit (i.e.. primary mixing unit (140)), one or more wellbore fluids (e.g., the first wellbore fluid (143)) may be further transported to one or more additional mixing units, such as a secondary7mixing unit (660) (e.g., a secondary7mixing tank) for further mixing with one or more additional liquids and / or other materials. The secondary mixing unit (660) may be fluidly connected to a pump (180) (e.g., a slurry pump) via a conduit (668) for provision of wellbore fluids to a wellbore fluid supply system (200), such as that illustrated in FIG. 5.

[0027] Referring now to FIG. 5, a wellbore fluid supply system (200) may include a wellbore head (210) fluidly connected to the wellbore fluid preparation system (100) via a conduit (190). The wellbore head (210) may be fluidly connected to a casing (220) for supply of wellbore fluids to the casing (220) and an annulus (250). The casing (220) extends through a borehole (235) located in a formation (230) and to a wellbore bottom (240). The casing (220) may have aAttorney Docket No.: 212276010400 / PCT smaller diameter than the borehole (235). The space between the casing (220) and the outer circumference of the borehole (235) creates the annulus (250). The wellbore head (210) is positioned at the surface (270), i.e., above the formation (230). As explained in detail below, the wellbore fluid supply system (200) may supply wellbore fluids from the wellbore fluid preparation system (100) to the borehole (235) for use in preparing and / or producing one or more barrier sheaths for a wellbore. A barrier sheath may result from the solidification (e.g., hardening, setting) of a wellbore fluid, such as the solidification of a lead barrier fluid or the solidification of a tail barrier fluid. As disclosed herein, the barrier sheath may include a cement composition and coated drill cuttings dispersed within the cement composition. In some embodiments, the coated drill cuttings each comprise at least one coating layer on a surface of a drill cutting, with the at least one coating layer disposed between the drill cutting and the cement composition.

[0028] Referring now to FIG. 6, in one embodiment, a coating system (300) may be used to produce coated drill cuttings. The coating system (300) may include a drill cuttings source (310) (e.g., a tank, hopper, container, or other suitable source) and a coating phase source (320) (e.g., a tank, hopper, container, or other suitable source), which may be connected to a coating unit (330) via conduits (315, 325) for respectively conveying drill cuttings and one or more coating phase compositions, which may include liquid, solid, and or gaseous components utilized for forming coatings on drill cuttings and / or other suitable materials. One or more coating phase compositions may be deposited on external surface portions of the drill cuttings to produce coated drill cuttings as detailed herein. In some embodiments, following deposition of coating phase compositions on the drill cuttings, the coating phase compositions may be further processed (e.g., dried, cured, reacted, melted, at least partially removed, etc.) to, for example, bond the resultant coatings to the drill cuttings, to solidify the coatings, and / or to otherwise modify one or more properties of the coatings. The drill cuttings and / or coatings may be processed during and / or following deposition of the coatings in any suitable manner as described herein. In some embodiments, suitable material conveyors (e.g., augers, belts, etc.) may be used in place of or in addition to one or more of the described conduits to move materials between portions of coating system (300) and / or other systems described herein. Alternatively, or additionally, one or more of the drill cuttings, the coating phase compositions, and / or other suitable materials may be introduced to the coating unit (330) and / or coated cuttings and / or other products may be conveyed from the coating unit (330) by vehicle, robot, manually, and / or in any other suitable manner. In some embodiments, the coating unit (330) may be connected to theAttorney Docket No.: 212276010400 / PCT primary material source (110) (e.g., via conduit (335)). In some embodiments, the coating unit (330) may optionally function as the primary material source (110). The primary material source (110) may be connected to a mixing unit (140), such as that illustrated in FIG. 1, for supply of the coated drill cuttings to the wellbore fluid preparation system (100). Accordingly, the production of coated drill cuttings may be achieved locally. In other embodiments, the production of coated drill cuttings is conducted remotely.

[0029] Referring now to FIG. 7, a wellbore drilling system (400) may be used to prepare a wellbore. In one embodiment, a wellbore drilling system (400) includes a drilling system (410), a primary treatment system (430), and a drill cuttings tank (440). The drilling system (410) may be fluidly connected to a drill string (420). A drill bit (425) may be attached to the end of the drill string (420). The drill bit (425) drills through the formation (230) to the wellbore bottom (240), creating the borehole (235) in the formation (230). A casing is then run through the borehole (235). The casing typically extends through the borehole (235) to the wellbore bottom (240), as shown in FIG. 5.

[0030] The drilling system (410) may be fluidly connected to the primary' treatment system (430) via a conduit (415). In some embodiments, the primary treatment system (430) may be fluidly or otherwise connected via a conduit (435) to a drill cuttings tank (440) or other suitable location (e.g., drill cuttings source (310) in FIG. 6). The primary treatment system (430) may recover drill cuttings (452) from the drilling fluids (426). Optionally, a secondary preparation unit (450) may be used to further process the drill cuttings (452) (e.g., dry ing, sizing, etc.). In some embodiments, the drill cuttings tank (440) may be fluidly or otherwise connected via a conduit (445) to the secondary preparation unit (450). The recovered drill cuttings (452) may be used to produce coated drill cuttings as detailed herein.

[0031] Referring noyv to FIG. 8, in some embodiments, an off-site preparation system (500) may be utilized to process drill cuttings. In one embodiment, drill cuttings (452) may be transported from a yvellbore location (510) to an off-site preparation location (520). Drill cuttings (452) may then be treated at the off-site preparation location (520) to produce treated drill cuttings, as described in further detail beloyv. In one embodiment, the treated drill cuttings may then be transported to the wellbore location (510). In another embodiment, the treated drill cuttings may then be transported to a secondary yvellbore location (515). In yet another embodiment, the treated drill cuttings may then be used to produce coated drill cuttings at the off-site preparation location (520). as described in further detail beloyv. With continued reference to FIG. 8, mine tailings from a mine tailing location (530) may optionally beAttorney Docket No.: 212276010400 / PCT transported to the wellbore location (510) for use in producing coated drill cuttings. In another embodiment, mine tailings from the mine tailing location (530) may be transported to an off-site location, such as a secondary wellbore location (515), or the off-site preparation location (520) for use in producing coated drill cuttings. ii. Processing,

[0032] With reference to FIG. 4, in one embodiment, to produce one or more wellbore fluids, coated drill cuttings (i.e., primary materials) from the primary material source (110) may be transported via the conduit (115) to the mixing unit (140) (e.g., a primary mixing tank). Optionally secondary materials (e.g., cements, additives) from the secondary material source (130) may be transported via the conduit (135) to the mixing unit (140). Optionally, liquid (e.g., water) from the liquid tank (120) may be transported through the conduit (125) to the mixing unit (140). As needed, the coated drill cuttings, secondary materials, and / or liquid may be mixed (e.g., contacted) in the mixing unit (140) to create one or more wellbore fluids, such as a first wellbore fluid (143) as illustrated in FIG. 4. The amounts of coated drill cuttings, secondary materials, and / or liquid supplied to the mixing unit (140) may be controlled (e.g., via valve(s) associated with the conduits (115, 125, 135) and / or associated with the sources (110, 120, 130)) to achieve the desired amount and combination of materials in the mixing unit (140). Accordingly, predetermined ratios of primary materials (coated drill cuttings), secondary materials (e.g., cements, additives), and liquids (e.g., aqueous and / or organic solutions) may be achieved in the mixing unit (140) for preparation of appropriate w ellbore fluid compositions, such as spacer fluid compositions, lead barrier fluid compositions, and / or tail barrier fluid compositions, among others.

[0033] As may be appreciated, the term primary materials is used herein for ease of reference in relation to the use of coated drill cuttings to produce wellbore fluids, and is not intended to imply or require that such materials make up a majority of any wellbore fluid composition. As may be appreciated, the term secondary materials is used herein for ease of reference in relation to secondary materials (e.g., cements, additives) that may be used in combination with the primary materials to produce wellbore fluids, and is not intended to imply or require that such materials make up a minority of any w ellbore fluid composition.

[0034] In one embodiment, a density checker (147) (e.g., a density' measurement and / or density verification apparatus) may be used to measure and / or check the density’ of the one or more wellbore fluids (e.g., the first wellbore fluid (143)) during and / or after its production in the primary mixing unit (140). In one embodiment, the density of the one or more wellbore fluidsAttorney Docket No.: 212276010400 / PCT may be adjusted by changing the amounts of primary materials, secondary' materials, and / or liquid supplied to the mixing unit (140). Accordingly, the ratio of primary materials-to- secondary materials-to-liquid (PM:SM:L ratio) in the mixing unit (140) may be adjusted. In one embodiment, the density7of the one or more wellbore fluids in the mixing unit (140) is adjusted by providing relatively more or less primary materials (drill cuttings, geopolymers, and / or mine tailings) from the primary material source (110) to the mixing unit (140). as needed. In another embodiment, the density of the one or more wellbore fluids in the mixing unit (140) is adjusted by providing relatively more or less liquid from the liquid tank (120) to the mixing unit (140), as needed. In yet another embodiment, the density7of the one or more wellbore fluids in the mixing unit (140) is adjusted by providing relatively more or less secondary materials from the secondary material source (130) to the mixing unit (140). as needed. Accordingly, one or more wellbore fluids having one or more predetermined densities and / or one or more predetermined ratios of primary7materials-to-secondary materials-to-liquid (PM:SM:L ratio) may be realized.

[0035] Referring now to FIG. 9, after or concurrent to the mixing in the mixing unit (i.e., primary mixing unit) (140), one or more wellbore fluids (e.g., the first wellbore fluid (143)) may be further transported to one or more additional mixing units, such as a secondary7mixing unit (660) (e.g., a secondary7mixing tank) via a conduit (645). In one embodiment, the transporting includes an overflow arrangement, wherein the one or more wellbore fluids exit a top or side of the primary7mixing unit (140), after which the wellbore fluids flow into the secondary mixing unit (660). Other manners of transferring wellbore fluids from the primary7mixing unit (140) to the secondary7mixing unit (660) may be used (e.g., gravity7flow, pumping).

[0036] After a wellbore fluid is transported to the secondary7mixing unit (660), it may be further mixed to create a final wellbore fluid (664). Optionally, adjustment material from the supplement unit (650) (e.g., a supplement tank) may be added (e.g., via conduit (655)), to the secondary mixing unit (660) to adjust one or more properties of the one or more wellbore fluids (e.g.. the final wellbore fluid (664)). The adjustment material in the supplement unit (650) may be any suitable material including, for instance, primary materials, secondary materials, and liquid(s), among others. After or concurrent to the mixing of the one or more wellbore fluids, the one or more wellbore fluids are transported to a wellbore head (e.g., the wellbore head (210) of FIG. 5) for use in wellbore fluid supply operations.

[0037] Similar to the mixing unit (140), a density7checker (667) may be used to check the density of the one or more wellbore fluids (e.g., the final wellbore fluid (664)) during and / or after their production in the secondary mixing unit (660). In one embodiment, the density of theAttorney Docket No.: 212276010400 / PCT one or more wellbore fluids may be adjusted by changing the amount of primary materials, secondary materials, and / or liquid supplied to the secondary mixing unit (660). Accordingly, the ratio of primary materials-to-secondary materials-to-liquid (PM:SM:L ratio) in the secondary mixing unit (660) may be adjusted. In one embodiment, the density' of the one or more wellbore fluids in the secondary mixing unit (660) may be adjusted by providing relatively more or less adjustment material from the supplement unit (650) to the secondary mixing unit (660). as needed. In yet another embodiment, the density of the one or more wellbore fluids in the secondary mixing unit (660) may be adjusted by providing relatively more or less wellbore fluid (e.g., the first wellbore fluid (143)) of relatively higher or lower density' from the mixing unit (140) to the secondary mixing unit (660), as needed. Accordingly, one or more wellbore fluids having one or more predetermined densities and / or one or more predetermined ratios of primary materials-to-secondary materials-to-liquid (PM:SM:L ratio) may be realized.

[0038] Returning to FIG. 5, one or more wellbore fluids (e.g., the first wellbore fluid (143), the final wellbore fluid (664)) may be supplied from the wellbore fluid preparation system (100, 600) (see FIGS. 4 and 9) to the wellbore fluid supply system (200) (e.g., via the conduit 190). In one embodiment, the one or more wellbore fluids are pumped through the casing (220) to the wellbore bottom (240), after which the one or more wellbore fluids enter the annulus (250). As additional wellbore fluid is supplied, the one or more wellbore fluids may travel upwards through the annulus (250) towards the surface (270). Multiple wellbore fluids may be pumped down the casing (220) and displaced up the annulus (250). After the one or more wellbore fluids have been supplied, the wellbore fluids may set (harden) in the annulus (250) to create a substantially impermeable barrier sheath (not illustrated) between the formation (230) and the casing (220). Some examples of suitable wellbore fluids, their methods of production, their compositions, and their provision to the wellbore are described below.

[0039] Referring back to FIGS. 4 and 9, as noted above, the primary material source (110) may be used to supply coated dnll cuttings (i.e., primary- materials) to facilitate production of wellbore fluids. Although not illustrated, any number of primary material sources (110) may' be used to facilitate provision of materials for creation of w ellbore fluids. In one embodiment, the primary material source (110) may contain one or more coated drill cuttings. Any suitable drill cuttings may be used to facilitate the production of wellbore fluids. In one embodiment, the drill cuttings comprise sedimentary materials, igneous materials, metamorphic materials, and combinations thereof. In one embodiment, the drill cuttings comprise sedimentary materials. In one embodiment, sedimentary materials may include dolomite, cherts, siltstone, chalk, shale,Attorney Docket No.: 212276010400 / PCT limestone, and sandstone, among others. In one embodiment, the drill cuttings comprise igneous materials. In one embodiment, igneous materials may include basalt, gabbro, and pumice, among others. In one embodiment, the drill cuttings comprise metamorphic materials. In one embodiment, metamorphic materials may include schist, argillite, and slate, among others. In one embodiment, the drill cuttings comprise shale. In another embodiment the drill cuttings comprise limestone. In another embodiment the drill cuttings comprise sandstone.

[0040] Similarly, in one embodiment, the primary' material source (110) may, in addition to coated drill cuttings, include one or more other coated or uncoated materials, such as one or more geopolymers (e.g., synthesized geopolymers, sourced geopolymers, and combinations thereof), mine tailings, uncoated drill cuttings, etc. In some embodiments, a coated or uncoated geopolymer in the primary' material source (110) may include a synthesized geopolymer (e.g., geopolymers produced from drill cuttings, mine tailings, or combinations thereof) and / or a sourced geopolymer. In one embodiment, synthesized geopolymers are produced from reacting drill cuttings, mine tailings, or combinations thereof with a reactant (e.g., an alkaline activator) to produce a geopolymer. In one embodiment, the compounds that make up the drill cuttings, mine tailings, or combinations thereof, (e.g., aluminum oxide (AI2O3), silicon dioxide (SiCh)) may be dissolved in the reactant to produce, for example, silicon-based and / or aluminum-based monomers (e.g., SiO2(OH)2. A1(OH)4). The silicon-based and / or aluminum-based monomers may then undergo polycondensation to form a polymer (i.e., a synthesized geopolymer). In some embodiments, an atom that is present in the drill cuttings and the synthesized geopolymer produced from the drill cuttings may form bonds with different atoms when in the drill cuttings than when in the synthesized geopolymer. For example, an aluminum atom in an aluminum oxide molecule in a drill cutting may form intermolecular and / or intramolecular bonds with neighboring aluminum, oxygen, silicon, and / or other atoms present in the drill cuttings. However, after the drill cutting is used to produce a synthesized geopolymer, the same aluminum atom may form bonds with different atoms, including different aluminum, oxygen, and / or silicon atoms. In some embodiments, at least some of the atoms in the drill cuttings and / or mine tailings react to form different compounds (e g., create monomers) in the synthesized geopolymer. For example, producing synthesized geopolymers may molecularly rearrange at least some of the atoms and / or molecules of the drill cuttings, and / or mine tailings. Suitable sourced geopolymers may include geopolymers purchased from vendors and / or geopolymers produced from fly ash, slag, silica fume, and kaolin, among other materials. In one embodiment, the geopolymer in the primary material source (110) may include geopolymer produced on-site (e.g., as a result ofAttorney Docket No.: 212276010400 / PCT obtaining drill cuttings from a well drilling operation). In another embodiment, the geopolymer in the primary material source (110) may include geopolymer produced off-site.

[0041] Similarly, any suitable coated and / or uncoated mine tailings may be used to facilitate the production of wellbore fluids. Mine tailings may include any suitable waste from a mining operation. In one embodiment, the mine tailings in the primary material source (110) may include mine tailings from mineral mines (e.g., gypsum, limestone, diatomite, dolomite, barite, silica, pumice, talc, bentonite, kaolin, trona). In another embodiment, the mine tailings in the primary material source (110) may include mine tailings from ore mines (e.g., iron, aluminum, platinum, palladium, titanium, tungsten, lead, copper, zinc, molybdenum, gold, silver, nickel). In another embodiment, the mine tailings in the primary material source (110) may include mine tailings from gem mines (e.g., garnet, sapphire, turquoise, diamond, ruby, opal, emerald). In one embodiment, mine tailings may be prepared prior to use in creating a wellbore fluid and / or prior to conversion to a synthesized geopolymer and / or prior to being coated. In one embodiment, preparing the mine tailings may include separating the mine tailings, drying the mine tailings, sizing the mine tailings, and combinations thereof. Separating the mine tailings may include removing unusable waste from the mine tailings. Suitable methods of separating the mine tailings include froth flotation, pyrometallurgical froth flocculation, hydrometallurgical froth flocculation, biochemical metallurgical processing (e.g., bioleaching, bioreduction, biosorption, biomining), and combinations thereof. In one embodiment, drying the mine tailings may include removing fluid from the mine tailings. In one embodiment, sizing the mine tailings may include sorting mine tailings, comminuting mine tailings, and combinations thereof. Sorting the mine tailings may include sieving the mine tailings, filtering the mine tailings, and combinations thereof. Comminuting the mine tailings may include grinding the mine tailings, pulverizing the mine tailings, crushing the mine tailings, and combinations thereof.

[0042] Referring back to FIGS. 4 and 9. as noted above, a liquid tank (120) may be used to supply one or more liquids to facilitate production of wellbore fluids. Although not illustrated, any number of liquid tanks (120) may be used to facilitate provision of materials for creation of wellbore fluids. Further, any suitable liquids may be used to facilitate production of wellbore fluids, including aqueous and / or organic liquids. In one embodiment, the liquid is aqueous based. In one embodiment, an aqueous based liquid comprises water. Any suitable aqueous based fluids may be used to facilitate production of wellbore fluids, including any type of water, such as fresh water, ground water, deionized water, distilled water, and / or produced water, among others. In another embodiment, the liquid is organic based (e.g., oil).Attorney Docket No.: 212276010400 / PCT

[0043] With continued reference to FIGS. 4 and 9, as noted above, the secondary material source (130) may be used to supply secondary’ materials to facilitate production of wellbore fluids. Although not illustrated, any number of secondary material sources (130) may be used to facilitate provision of secondary materials for creation of wellbore fluids. Further, any suitable secondary materials may be used in the secondary' material source (130) to facilitate production of wellbore fluids. For instance, additives and / or cements may be used in the secondary material source (130). The additives may include, for instance, emulsifiers, viscosifiers, fluid loss control agents, surfactants, retarders, accelerators, extenders, densifiers, anti-shrinking agents, and resilient materials, among other components. Such additives may be used to facilitate the production of wellbore fluids having appropriate properties. The cements may be any cements suited to the production of a yvellbore fluid, such as cements suited for mixing yvith drill cuttings, geopolymers, and / or mine tailings to produce a lead barrier fluid or a tail barrier fluid.A. Spacer Fluid

[0044] As noted above, any suitable wellbore fluids may be produced from the coated drill cuttings (i.e., primary’ materials). In one embodiment, a wellbore fluid is a spacer fluid. In one embodiment, and with reference to FIGS. 4 and 9, a spacer fluid may be produced in the wellbore fluid preparation system (100, 600). Any combination of coated drill cuttings and optional additional materials (e.g., uncoated drill cuttings, coated and / or uncoated mine tailings and / or geopolymers, etc.) from the primary material source (110), liquid from the liquid tank (120), and secondary materials from the secondary material source (130) may be used to produce a spacer fluid. In one embodiment, the primary materials at least include coated drill cuttings, wherein coated drill cuttings from the primary material source (110), liquid (e.g., water) from the liquid tank (120), and optionally secondary materials (e.g., additives) from the secondary material source (130) may be mixed in the mixing unit (140) to create a spacer fluid. In one embodiment, the desired density of the spacer fluid is 0.96 to 3.00 g / ml (8 to 25 pounds per gallon), but any suitable spacer fluid densities may be employed. In one embodiment, the density of the spacer fluid in the mixing unit (140) may be checked with the density’ checker (147). The density’ of the spacer fluid in the mixing unit (140) may be adjusted by changing the ratio of primary materials-to-secondary materials-to-liquid (PM:SM:L ratio) as described previously. In one embodiment, the density of the spacer fluid in the mixing unit (140) is adjusted by changing the ratio of coated and / or uncoated drill cuttings-to-secondary materials-to-liquid (DC:SM:L ratio).Attorney Docket No.: 212276010400 / PCT

[0045] In one embodiment, as shown in FIG. 9, the spacer fluid may be transferred to the secondary mixing unit (660) and optionally mixed. Optionally, adjustment material from the supplement unit (650) may be added to the secondary mixing unit (660) to adjust the spacer fluid composition and / or properties. In one embodiment, the density of the spacer fluid in the secondary mixing unit (660) may be checked with the density checker (667), as described previously. In one embodiment, the density of the spacer fluid in the secondary mixing unit (660) may be adjusted by providing relatively more or less adjustment material from the supplement unit (650) to the secondary mixing unit (660), as needed. In another embodiment, the density of the spacer fluid in the secondary' mixing unit (660) may be adjusted by providing relatively more or less spacer fluid of relatively higher or lower density from the primary mixing unit (140) to the secondary mixing unit (660), as needed. Subsequently, the spacer fluid may be transported to a wellbore fluid supply system (e.g., the wellbore fluid supply system (200) of FIG. 5). The spacer fluid may be pumped into the wellbore fluid supply system (200) for various purposes, such as to remove excess mud from the borehole (235) to enhance the placement of the barrier sheath.

[0046] In one embodiment, and now with reference to FIG. 5, the spacer fluid may be transported to the wellbore head (210) via the conduit (190), as shown in FIGS. 4 and 9. The spacer fluid may then be pumped through the wellbore head (210), down the casing (220), to the wellbore bottom (240). The spacer fluid may then leave the wellbore casing (220) and enter the annulus (250). As more spacer fluid is pumped down the casing (220) the spacer fluid in the annulus (250) may travel up the annulus (250) towards the surface (270). As the spacer fluid moves up the annulus (250), the spacer fluid may remove undesired materials in the annulus (250), such as mud from the edge of the formation (230), to enhance the placement of the barrier sheath. In one embodiment, and as described in further detail below, other wellbore fluids (e.g., lead barrier fluids, tail barrier fluids) may be pumped into the wellbore fluid supply system (200) after the spacer fluid. The other w ellbore fluids may be of higher density than the spacer fluid. In one embodiment, the spacer fluid has a low er density than one or more other wellbore fluids (e.g., from 0.01 to 0.24 g / ml lower density). In one embodiment, the spacer fluid has a density lower than the lead barrier fluid. In another embodiment, the spacer fluid has a density lower than the tail barrier fluid. Thus, as subsequent wellbore fluids are pumped down the wellbore fluid supply system (200), the spacer fluid may be further displaced up the annulus (250) towards the surface (270). In one embodiment, the spacer fluid is displaced up the annulus (250) to theAttorney Docket No.: 212276010400 / PCT wellbore head (210). The spacer fluid may then be transported to a mud pit (290) via a conduit (280). The spacer fluid in the mud pit (290) may then be recycled or disposed of as a waste.B. Lead Barrier Fluid

[0047] As noted above, any suitable wellbore fluids may be produced from the coated drill cuttings (i.e., primary materials). In one embodiment, a wellbore fluid is a lead barrier fluid. In one embodiment, and with reference to FIGS. 4 and 9, a lead barrier fluid may be produced in the wellbore fluid preparation system (100, 600). Any combination of coated drill cuttings and optional additional materials (e.g.. uncoated drill cuttings, coated and / or uncoated mine tailings and / or geopolymers, etc.) from the primary material source (1 10), liquid from the liquid tank (120), and secondary materials from the secondary' material source (130) may be used to produce a lead barrier fluid. In one embodiment, the primary materials at least include coated drill cuttings, wherein coated drill cuttings from the primary material source (110), liquid (e.g.. water) from the liquid tank (120), and optionally secondary materials (e.g., cement and / or additives) from the secondary' material source (130) may' be mixed in the mixing unit (140) to create a lead barrier fluid. In one embodiment, the lead barrier fluid is a lead cement fluid (i.e., a lead barrier fluid including cement). In one embodiment, the desired density of the lead barrier fluid is 0.96 to 3.00 g / ml (8 to 25 pounds per gallon), but any suitable lead barrier fluid densities may be employed. In one embodiment, the density of the lead barrier fluid in the mixing unit (140) may be checked with a density7checker (147). The density' of the lead barrier fluid in the mixing unit (140) may be adjusted by changing the ratio of primary materials-to-secondary materials-to- liquid (PM:SM:L ratio) as described previously. In one embodiment, the density of the lead barrier fluid in the mixing unit (140) may be adjusted by changing the ratio of coated and / or uncoated drill cuttings-to-secondary materials-to-liquid (DC:SM:L ratio).

[0048] In one embodiment, as shown in FIG. 9. the lead barrier fluid may be transferred to the secondary mixing unit (660) and optionally mixed. Optionally, adjustment material from the supplement unit (650) may be added to the secondary mixing unit (660) to adjust the lead barrier fluid composition and / or properties. In one embodiment, the density of the lead barrier fluid in the secondary mixing unit (660) may be checked with the density checker (667), as described previously. In one embodiment, the density of the lead barrier fluid in the secondary mixing unit (660) may be adjusted by providing relatively more or less adjustment material from the supplement unit (650) to the secondary' mixing unit (660), as needed. In another embodiment, the density of the lead barrier fluid in the secondary mixing unit (660) may be adjusted by providing relatively more or less lead barrier fluid of relatively higher or lower density from theAttorney Docket No.: 212276010400 / PCT primary mixing unit (140) to the secondary' mixing unit (660), as needed. Subsequently, the lead barrier fluid may be transported to a wellbore fluid supply system (e.g., the wellbore fluid supply system (200) of FIG. 5). The lead barrier fluid may be pumped into the wellbore fluid supply system (200) for various purposes, such as to create a barrier sheath to provide zonal isolation for the upper sections of the wellbore.

[0049] In one embodiment, and now with reference to FIG. 5, the lead barrier fluid may be transported to the wellbore head (210) via the conduit (190), as shown in FIGS. 4 and 9. The lead barrier fluid may then be pumped through the wellbore head (210), down the casing (220), to the wellbore bottom (240). The lead barrier fluid may then leave the wellbore casing (220) and enter the annulus (250). As more lead barner fluid is pumped down the casing (220) the lead barrier fluid in the annulus (250) may travel up the annulus (250) towards the surface (270). In one embodiment, and as described in further detail above, other wellbore fluids (e.g., spacer fluids) may be pumped into the wellbore fluid supply system (200) before the lead barrier fluid. The other wellbore fluids pumped into the wellbore fluid supply system (200) prior to the lead barrier fluid, may be of lower density than the lead barrier fluid. In one embodiment, the lead barrier fluid has a higher density than one or more wellbore fluids pumped into the wellbore fluid supply system (200) before the lead barrier fluid (e.g., from 0.01 to 0.24 g / ml higher density). In one embodiment, the lead barrier fluid has a density higher than the spacer fluid. Thus, as more lead barrier fluid is pumped down the wellbore fluid supply system (200), the wellbore fluids pumped down the wellbore fluid supply system (200) before to the lead barrier fluid may be further displaced up the armulus (250) towards the surface (270). In another embodiment, and as described in further detail below, other wellbore fluids (e.g., tail barrier fluids) may be pumped into the wellbore fluid supply system (200) after the lead barrier fluid. The other wellbore fluids pumped into the wellbore fluid supply system (200) after the lead barrier fluid may be of higher density' than the lead barrier fluid. In one embodiment, the lead barrier fluid has a lower density than one or more other wellbore fluids pumped into the wellbore fluid supply system (200) after the lead barrier fluid (e.g., from 0.01 to 0.24 g / ml lower density). In one embodiment, the lead barrier fluid has a density lower than the tail barrier fluid. Thus, as the subsequent wellbore fluids are pumped down the wellbore fluid supply system (200), the lead barrier fluid may be further displaced up the armulus (250) tow ards the surface (270). The lead barrier fluid may then set (harden) to form a barrier sheath to provide zonal isolation for the upper sections of the wellbore. In one embodiment, the barrier sheath produced from the lead barrier fluid is a cement sheath (i.e., comprises at least some cement). In another embodiment,Attorney Docket No.: 212276010400 / PCT the barrier sheath produced from the lead barrier fluid is a non-cement sheath (i.e., is absent of cement).C. Tail Barrier Fluid

[0050] As noted above, any suitable wellbore fluids may be produced from the coated drill cuttings (i.e., primary materials). In one embodiment, a wellbore fluid is a tail barrier fluid. In one embodiment, and with reference to FIGS. 4 and 9, a tail barrier fluid may be produced in the wellbore fluid preparation system (100, 600). Any combination of coated drill cuttings and optional additional materials (e.g.. uncoated drill cuttings, coated and / or uncoated mine tailings and / or geopolymers, etc.) from the primary material source (1 10), liquid from the liquid tank (120), and secondary materials from the secondary' material source (130) may be used to produce a tail barrier fluid. In one embodiment, the primary materials at least include coated drill cuttings, wherein coated drill cuttings from the primary material source (110), liquid (e.g.. water) from the liquid tank (120), and optionally secondary7materials (e.g., cement, additives) from the secondary material source (130) may be mixed in the mixing unit (140) to create a tail barrier fluid. In one embodiment, the tail barrier fluid is a tail cement fluid (i.e., a tail barrier fluid including cement). In one embodiment, the desired density of the tail barrier fluid is 0.96 to 3.00 g / ml (8 to 25 pounds per gallon), but any suitable tail barrier fluid densities may be employed. In one embodiment, the density of the tail barrier fluid in the mixing unit (140) may be checked with a density checker (147). The density' of the tail barrier fluid in the mixing unit (140) may be adjusted by changing the ratio of primary' materials-to-secondary materials-to-liquid (PM:SM:L ratio) as described previously. In one embodiment, the density of the tail barrier fluid in the mixing unit (140) may be adjusted by changing the ratio of coated and / or uncoated drill cuttings-to-secondary materials-to-liquid (DC:SM:L ratio).

[0051] In one embodiment, and now with reference to FIG. 9, the tail barrier fluid may be transferred to the secondary mixing unit (660) and optionally mixed. Optionally, adjustment material from the supplement unit (650) may be added to the secondary mixing unit (660) to adjust the tail barrier fluid composition and / or properties. In one embodiment, the density' of the tail barrier fluid in the secondary mixing unit (660) may be checked with the density checker (667), as described previously. In one embodiment, the density of the tail barrier fluid in the secondary mixing unit (660) may be adjusted by providing relatively more or less adjustment material from the supplement unit (650) to the secondary' mixing unit (660), as needed. In another embodiment, the density of the tail barrier fluid in the secondary mixing unit (660) may be adjusted by providing relatively more or less tail barrier fluid of relatively higher or lowerAttorney Docket No.: 212276010400 / PCT density from the primary mixing unit (140) to the secondary mixing unit (660), as needed. Subsequently, the tail barrier fluid may be transported to a wellbore fluid supply system (e.g., the wellbore fluid supply system (200) of FIG. 5). The tail barrier fluid may be pumped into the wellbore fluid supply system (200) for various purposes, such as to create a barrier sheath to provide zonal isolation for the lower sections of the wellbore.

[0052] In one embodiment, and now with reference to FIG. 5, the tail barrier fluid may be transported to the wellbore head (210) via the conduit (190). The tail barrier fluid may then be pumped through the wellbore head (210), down the casing (220), to the wellbore bottom (240). The tail barrier fluid may then leave the wellbore casing (220) and enter the annulus (250). As more tail barrier fluid is pumped down the casing (220), the tail barrier fluid in the annulus (250) may travel up the annulus (250) towards the surface (270). In one embodiment, and as described in further detail above, other wellbore fluids (e.g., spacer fluids, lead barrier fluids) may be pumped into the wellbore fluid supply system (200) prior to the tail barrier fluid. The other wellbore fluids may be of lower density than the tail barrier fluid. In one embodiment, the tail barrier fluid has a higher density than one or more other wellbore fluids (e.g., from 0.01 to 0.24 g / ml higher density). In one embodiment, the tail barrier fluid has a density higher than the lead barrier fluid. In another embodiment, the tail barrier fluid has a density higher than the spacer fluid. Thus, as the tail barrier fluid is pumped down the wellbore fluid supply system (200), the other wellbore fluids may be further displaced up the annulus (250) towards the surface (270). The tail barrier fluid may then set (harden) to form a barrier sheath to provide zonal isolation for the lower sections of the wellbore. In one embodiment, the barrier sheath produced from the tail barrier fluid is a cement sheath (i.e.. comprises at least some cement). In another embodiment, the barrier sheath produced from the tail barrier fluid is a non-cement sheath (i.e., is absent of cement).D. Drill Cutting, Preparation

[0053] As noted above, coated drill cuttings for use in wellbore fluids may be produced from drill cuttings and / or other optional materials (e.g., mine tailings, geopolymers, etc ). As it relates to drill cuttings, in one embodiment, and as explained previously with reference to FIG. 7, a drilling system (410) drills the formation (230) to create the borehole (235). In the illustrated embodiment, a water table (260) may be located proximal to the borehole (235) and above the wellbore bottom (240). Typically, as the drill bit (425) drills through the formation (230), drill cuttings (452) are created. A drilling fluid (426) may be pumped down the drill string (420) to the drill bit (425) to cool and lubricate the drill bit (425). The drilling fluid (426) may includeAttorney Docket No.: 212276010400 / PCT oil drilling fluid, water drilling fluid, synthetic drilling fluid, and combinations thereof. After the drilling fluid (426) is pumped out of the drill string (420), the drilling fluid (426) may mix with the drill cuttings (452). The drill cuttings (452) mixed with the drilling fluid (426) are wet drill cuttings (452). The wet drill cuttings (452) may include oil drill cuttings (i.e., drill cuttings mixed with oil drilling fluid), water drill cuttings (i.e., drill cuttings mixed with water drilling fluid), synthetic drill cuttings (i.e., drill cuttings mixed with synthetic drilling fluid), and combinations thereof. As the drilling fluid (426) is used during drilling operations, the wet drill cuttings (452) may move to the surface (270) (e.g., the wet drill cuttings (452) may move to the surface (270) with the drilling fluid (426)).

[0054] In one embodiment, after the wet drill cuttings (452) reach the drilling system (410), the wet drill cuttings (452) are transported to the primary treatment system (430), which acts to remove most or all of the drilling fluid (426) and / or drilling mud from the wet drill cuttings (452). In one embodiment, the primary treatment system (430) is located locally at the drilling location, i.e.. is on-site. The primary treatment system (430) may include equipment such as shale shakers, hydro cyclones, separators, grinders, and centrifuges. In one embodiment, the primary treatment system may size the drill cuttings (452). In one embodiment, sizing the drill cuttings (452) may include sorting the drill cuttings (452). Sorting the drill cuttings may include sieving the drill cuttings (452), filtering the drill cuttings (452), and combinations thereof. In one embodiment, sizing the drill cuttings may include comminuting the drill cuttings (452). Comminuting the drill cuttings may include grinding the drill cuttings (452), pulverizing the drill cuttings (452), crushing the drill cuttings (452), and combinations thereof. The separated and / or sized drill cuttings (452) may then be transported to a drill cuttings source (310) via a conduit (435). The drill cuttings may then be used to produce one or more synthesized geopolymers onsite, such as via use of the coating system (300) of FIG. 6. The separating and sizing steps may occur in any order and may be repeated as needed to achieve drill cuttings of an appropriate size and / or shape.

[0055] In another embodiment, and with reference to FIG. 8 the drill cuttings (452) may be transported from the wellbore location (510) to an off-site preparation location (520) to produce one or more synthesized geopolymers, as described in further detail below.

[0056] Optionally, and with reference to FIG. 7, the drill cuttings (452) may be processed in a secondary' preparation unit (450), which secondary preparation unit (450) may be located onsite or off-site. In the secondary preparation unit (450), the drill cuttings (452) may be further processed, such as to remove additional drilling fluids and / or prepare drill cuttings of anAttorney Docket No.: 212276010400 / PCT appropriate size for coating. In one embodiment, after the drill cuttings (452) have been processed in the secondary preparation unit (450), the drill cuttings (452) may be used to prepare one or more coated drill cutting materials on-site, such as via use of the coating system (300) of FIG. 6. In another embodiment, after the drill cuttings (452) have been processed in the secondary preparation unit (450), the drill cuttings (452) are transported off-site. In yet another embodiment, the drill cuttings (452) are transported from the drill location to a remote (off-site) secondary preparation unit. The off-site secondary preparation unit may be located at the offsite preparation location (520), such as that illustrated in FIG. 8.E. Coated Drill Cuttings

[0057] After any necessary processing (e.g., drying, sizing, etc.), the drill cuttings (452) may be coated to produce coated drill cuttings. For instance, and in reference to FIG. 6, coated drill cuttings may be produced on-site in the coating system (300) and / or one or more alternative coating systems (300a, 300b, 300c) described below in reference to FIGS. 12-14. The coated drill cuttings may also be produced off-site in an off-site coating system (e.g., a system similar to that of FIG. 6, 12, 13, and / or 14, but off-site). In one embodiment, dry drill cuttings (452) from the drill cuttings source (310) may be transported via the conduit (315) to the coating unit (330). In another embodiment, wet drill cuttings from the drill cuttings source (310) may be transported via the conduit (315) to the coating unit (330).

[0058] Referring now to FIGS. 10 and 11, drill cuttings (452) may be at least partially coated with one or more coating layers disposed on surface portions of the drill cuttings (452) to produce coated drill cuttings. For example, as shown in FIG. 10, coated drill cuttings (750) include drill cuttings (452) coated with a coating layer (754). In some embodiments, drill cuttings (452) may be coated with two or more coating layers. For example, as shown in FIG. 11. coated drill cuttings (750a) include a first coating layer (754a) and a second coating layer (754b). Any suitable number of coating layers may be formed on drill cuttings (452). The coating layers may comprise the same or different materials and may be formed to any suitable thicknesses. For example, in one embodiment, the first coating layer (754a) may comprise the same composition as the second coating layer (754b). In another embodiment, the first coating layer (754a) may comprise a different composition than the second coating layer (754b). In one embodiment, the first coating layer (754a) may have the same thickness as the second coating layer (754b). In another embodiment, the first coating layer (754a) may be thicker or thinner than the second coating layer (754b).Attorney Docket No.: 212276010400 / PCT

[0059] Coating layers may be created on drill cuttings and / or on other suitable materials (e.g., geopolymers, mine tailings, etc.) in any suitable manner. In some embodiments, drill cuttings may be coated by applying at least one coating phase composition to the drill cuttings and then processing the coating phase composition to create the coating layer. The coating phase composition may include one or more materials that are applied to the drill cuttings in any suitable manner. In some embodiments, the coating phase composition comprises a liquid composition or semiliquid composition. The liquid / semiliquid coating phase composition may be solidified in any suitable manner. For example, the coating phase composition may include one or more polymer precursors (e.g., monomers, oligomers, etc.) that are further polymerized and / or cured in any suitable manner. Polymerization and / or curing may be carried out by exposing the coating phase composition to heat, actinic radiation (e.g., ultraviolet (UV) light), and / or a suitable initiator compound. In some examples, the coating phase composition includes polymer-based solids dispersed within a solvent and / or oil-based solution and / or emulsion. The polymer-based solids may agglomerate to form a solidified layer when a solvent (e.g., water) is evaporated from the coating phase composition. In one embodiment, two or more coating phase compositions may be combined and reacted together to form a coating layer. For example, the coating phase composition may include a resin (e.g., an epoxy resin) that is mixed with a curing agent (e.g., a thiol-based hardener and / or curative), resulting in hardening of the coating phase to form the coating layer. In some embodiments, the coating phase composition comprises a melted material, such as a thermosetting and / or thermoplastic polymer-based material (e.g., a resin), that is solidified upon cooling. The melted material may, for example, be heated to a temperature above its melting point prior to being applied to surfaces of the drill cuttings. The melted coating phase composition may then be cooled to solidify the material. In one embodiment, the coating phase composition may comprise a thermoplastic or thermosetting material that is deposited on the surfaces of the drill cuttings in a solid state, such as a powder including solid polymer particles. The powder may then be heated to melt the coating phase composition, forming a melted layer, which may then be cooled to form a solidified coating layer.

[0060] In some embodiments, applying the coating layer may comprise, for example, at least one of dip coating, brush coating, roll coating, spin coating, and / or spray coating the coating phase onto the drill cuttings. The coating phase composition may. for example, be dried (e.g., via solvent evaporation), cured, reacted, and / or otherwise processed to form a suitable coating layer. In one embodiment, dip coating is used to create a coating layer on the drill cuttings. DipAttorney Docket No.: 212276010400 / PCT coating may include submerging the drill cuttings in a coating phase composition (e.g., a liquid solution, a melted polymer-based material, etc.) and then slowly removing the drill cuttings. In some embodiments, a coating phase solution may be tailored to fit one or more criteria (e.g., one or more desired attributes of a wellbore fluid) using surfactants, solvents, and / or additional additives. Dip coating may allow for a large quantity of cuttings to be coated at a single time. In one embodiment, brush coating is used to create a coating layer on the drill cuttings. Brush coating may include utilizing a brush and / or other suitable distribution tool to physically distribute a liquid coating phase composition onto the drill cuttings. Size, shape, angularity', and bristle ty pe of the brush may be preselected based at least on sizes and / or types of drill cuttings to be coated and / or in accordance with types of coating phase compositions to be distributed. In one embodiment, roller coating of cuttings is used to create a coating layer on the drill cuttings. Roller coating may include utilizing a roller or other suitable distribution device to distribute a liquid coating phase composition onto the drill cutting surfaces. In one embodiment, spin coating of cuttings is used to create a coating layer on the drill cuttings. Drill cuttings can be coated via spin coating, where the drill cuttings are placed into a suitable rotational device (e.g., a rotational drum) and the liquid coating phase composition may be dispensed into the rotational device. The rotational device may then spin the drill cuttings such that the coating phase composition is dispersed over surfaces of the cuttings. In some embodiments, the coated drill cuttings may be heated to ensure the resulting coating layer is hardened and / or adhered to the surface of the cuttings. Dip coating, brush coating, roller coating, spin coating, and / or any other coating techniques or portions thereof, as described herein, may be automated and / or may be performed manually in any suitable manner.

[0061] In some embodiments, the coating phase composition may include one or more powder coating materials. The powder coating material may, for example, include a first powdered material that is applied along with another thermosetting polymer material. In one embodiment, drill cuttings may first be prepared by cleaning and at-least partial drying. The drill cuttings may then be electrically coupled to an electrical power source (e.g., via one or more electrodes) and sprayed with a coating phase composition comprising a powder coating material, and optionally, a thermosetting polymer material. The drill cuttings and applied coating phase composition(s) may then be heated (e.g., within an oven) to form the coating layer bonded to the drill cutting surfaces. The powder coating materials may, for example, include resins (e.g., epoxy resins), urethanes, carbon black, and / or any other suitable materials in powder form.Attorney Docket No.: 212276010400 / PCT

[0062] In some embodiments, the coating phase composition is applied to the drill cutting surfaces by spray coating. For example, thermal spraying may be used to apply the coating phase composition. Thermal spraying may be used to apply various types of coating phase compositions, including metal-based materials (e.g., alloys), polymer-based materials, and / or ceramic coating materials. The coating phase composition may be heated and / or melted prior to spraying. The liquid coating phase composition may then be accelerated via a gas stream onto the drill cuttings in any suitable manner. Examples of thermal spraying techniques include, for instance, plasma spraying, electric arc spraying, detonation gun spraying, flame spraying, high velocity7oxygen fuel spraying, and laser assisted spraying.

[0063] In some embodiments, the coating phase composition is applied to the drill cutting surfaces using one or more thin film deposition techniques. For example, a chemical vapor deposition (CVD) and / or a physical vapor deposition (PVD) technique may be used to form metal-based, ceramic, and / or other suitable coating layers. During CVD, drill cuttings are placed in a CVD reaction chamber and a reactant material in either liquid or gas form is pumped into the reaction chamber. The reactant material may be at a high temperature such that the reactant material undergoes chemical reactions and travels to the surfaces of the cuttings. Deposition of the reactant material then takes place via adsorption and / or diffusion to form the coating layer on the drill cuttings. During PVD, drill cuttings are loaded into a reaction chamber under low pressure such that the drill cuttings are partially ionized. A thin film may then be applied to the ionized surfaces of the cuttings. Suitable PVD techniques may include, for example, sputtering deposition, thermal evaporation deposition, electron beam deposition, and / or pulsed laser deposition. PVD may be utilized to form coating layers from solid materials that are vaporized in a vacuum environment, enabling the formation of layers that include a relatively pure metal, alloy, ceramic, and / or other suitable material coating.

[0064] In some embodiments, a sol-gel composition may be applied as a coating phase composition to form a ceramic coating and / or any other suitable coating. In one embodiment, the sol-gel composition includes a dispersion of particles of at least one coating material and / or precursor. Precursors used in sol-gel compositions include, for example, a metal or metalloid element. Metal alkoxides (e.g., alkoxysilanes), such as aluminates, titanates and zirconates having high reactivity towards water, may be utilized in some embodiments. In some embodiments, metal alkoxides may be used either alone or in combination with non-metal alkoxides (e.g., alkoxyborates, tetraethoxysilane). In one embodiment, the sol-gel may be created by performing hydrolysis and / or condensation reactions on a solution (e.g., an aqueousAttorney Docket No.: 212276010400 / PCT solution, etc.) that includes one or more sol-gel precursors. In one embodiment, the sol-gel may- first be created prior to being applied to the drill cuttings. Once the sol-gel has been formed, the drill cuttings may then be placed into the sol-gel and heated to a temperature sufficient to develop a ceramic coating and / or other suitable coating on the drill cuttings.Hi. CompositionA. Coating Layers

[0065] The coating layers disposed on the drill cuttings may include any suitable materials or combinations of materials. In some embodiments, coating layers may include polymers, ceramics, metals, and combinations thereof. In some embodiments, coating layers include one or more polymer materials. In one embodiment, the polymer comprises a plastic material, including a thermoplastic and / or thermosetting plastic. In one embodiment, the polymer comprises a silicone or silicone-based material. In some embodiments the coating layer comprises a cured resin. In one embodiment, resins may increase one or more properties of a barrier sheath. In one embodiment, resins may increase one or more of the tensile strength, the bond strength, the resiliency, and the durability of the barrier sheath. In one embodiment, resins may be resilient to changes in wellbore conditions (e.g., temperature and pressure changes). In one embodiment, resins may comprise one or more polymers suitable for use in a wellbore. In one embodiment, resins may be derived from a natural material. In one embodiment, resins maybe produced from or derived from a synthetic material. Suitable resins may include epoxy resins (e.g.. napthol-based epoxy resins), poly epoxide resins, furan resins, and polyester resins, among others. In some embodiments, coating layers may include one or more geopolymers, such as silicon-based and / or aluminum-based geopolymers.

[0066] In one embodiment, coating layers include a metal or alloy layer. For example, metals, such as aluminum, copper, tungsten, molybdenum, tantalum, nickel, combinations and / or alloys thereof, may be present in the coating layer. In one embodiment, the coating layer may include one or more ceramics, such as oxides (e.g., alumina, zirconia), carbides (e.g., silicon carbide, tungsten carbide), nitrides (e.g.. aluminum nitride, boron nitride, silicon nitride), and / or composite ceramics. In one embodiment, coating layers include carbon black, such as a layer of carbon black powder and / or carbon black disposed within a mixture, such as a polymer-based coating mixture or matrix.

[0067] In some embodiments, coating layers may include surfactants. In one embodiment, surfactants may decrease the surface tension and / or the interfacial tension between chemicals in the wellbore fluids. In one embodiment, surfactants may include liquid surfactants and / or solidAttorney Docket No.: 212276010400 / PCT surfactants. In one embodiment, surfactants may include wetting agents, anti-foam agents, defoamers, and dispersants. In some embodiments, coating layers may include one or more suitable additives. Additives may include carbon fibers, magnetic particles, carbon black, and combinations thereof. In one embodiment, additives may be disposed within a bulk material, such as a polymer or other suitable material matrix.

[0068] In some embodiments, the coating may include one or more tracer materials. In one embodiment, tracer materials may assist in determining the position of a barrier sheath in a wellbore (e.g., to determine the position of the barrier sheath relative to the surface, to determine the position of a portion of the barrier sheath relative to a different portion of the barrier sheath). In one embodiment, a tracer material may assist in determining the position of a wellbore fluid while the wellbore fluid is being pumped into the wellbore and / or while the wellbore fluid is setting (e.g., to determine if more wellbore fluid may be needed to further displace wellbore fluid up the annulus until the wellbore fluid reaches a desired level). In one embodiment, tracer materials may assist in determining the status of a barrier sheath in a wellbore (e.g., by determining a baseline level of emissions for a barrier sheath and comparing the baseline level of emissions to one or more future levels of emissions to identify if there is a deviation in the levels of emissions, a deviation in the levels of emission may indicate deterioration of the barrier sheath that may require remediation). In one embodiment, a tracer material may emit an indicator that may be detected by one or more devices. Suitable devices for detecting tracer materials may include natural gamma ray spectroscopy logs, neutron logs, and pulsed neutron capture logs, among others. Suitable tracer materials may include radioactive tracers (e.g., iodine-131, tritium, cobalt-60, sodium-22, chlorine-36) and non-radioactive tracers (e.g., gadolinium(III) oxide (Gd20s), samarium(III) oxide (SrmCh). and boron carbide (B4C)). among others.B. Wellbore Fluid

[0069] As noted above, various wellbore fluids (e.g., a spacer fluid, a lead barrier fluid, and / or a tail barrier fluid) may be used to create barrier fluid compositions for use in wellbore fluid supply applications. Any suitable volume of primary materials may be used to create any suitable wellbore fluid composition, optionally with liquid, optionally with secondary materials.

[0070] In one embodiment, the wellbore fluid composition is a spacer fluid composition. Spacer fluid compositions may include any suitable amount of primary materials (coated drill cuttings and optionally additional coated and / or uncoated materials, such as geopolymers, mine tailings, uncoated drill cuttings, etc.), optional liquid (e.g., water), and optional secondaryAttorney Docket No.: 212276010400 / PCT materials (e.g., additives and / or cements). In one approach, a spacer fluid composition is free of secondary materials, i.e., is based on a mixture of primary materials and liquid. In another approach, secondary materials (e.g., additives) may be used with primary materials to produce a spacer fluid.

[0071] In another embodiment, the wellbore fluid composition is a lead barrier fluid composition. Lead barrier fluid compositions may include any suitable amount of primary materials (coated drill cuttings and optional coated and / or uncoated materials), optional liquid (e.g., water), and optional secondary materials (e.g., cement and / or additives).

[0072] In another embodiment, the wellbore fluid composition is a tail barrier fluid composition. Tail barrier fluid compositions may include any suitable amount of primary materials (e.g., coated drill cuttings and optional coated and / or uncoated materials), optional liquid (e.g., water), and optional secondary materials (e.g., cement and / or additives).

[0073] In another embodiment, the wellbore fluid composition is a plugging fluid composition. Plugging fluid may be used in wellbore plugging applications to plug a wellbore. Plugging fluid compositions may include any suitable amount of primary materials (e.g., coated drill cuttings and optional coated and / or uncoated materials), optional liquid (e.g., water), and optional secondary' materials (e.g., cement and / or additives). In one embodiment, the plugging fluid may be a cement plugging fluid (i.e., a plugging fluid with cement).

[0074] In another embodiment, the wellbore fluid composition is a squeeze fluid composition. Squeeze fluid may be used in wellbore squeeze applications, for instance, to repair a barrier sheath in a wellbore. Squeeze fluid compositions may include any suitable amount of primary’ materials (e.g., coated drill cuttings and optional coated and / or uncoated materials), optional liquid (e.g., water), and optional secondary materials (e.g., cement and / or additives). In one embodiment, the squeeze fluid may be a cement squeeze fluid (i.e., a squeeze fluid with cement).

[0075] In another embodiment, the wellbore fluid composition is a grouting fluid composition. Grouting fluid may be used in wellbore grouting applications, for instance, to repair a barrier sheath in a wellbore. Grouting fluid compositions may include any suitable amount of primary' materials (e.g., coated drill cuttings and optional coated and / or uncoated materials), optional liquid (e.g., water), and optional secondary materials (e.g., cement and / or additives). In one embodiment, the grouting fluid may be a cement grouting fluid (i. e. , a grouting fluid with cement).Attorney Docket No.: 212276010400 / PCT

[0076] As noted above secondary' materials may be used in producing wellbore fluids. Secondary materials may include additives and / or cement. In some embodiments, one or more additives, as described below, may be included in coating layers on coated drill cuttings. Additives may include one or more additives suited for production of wellbore fluids. In one embodiment, additives may include, emulsifiers, viscosifiers, fluid loss control agents, surfactants, retarders, accelerators, extenders, densifiers, anti-shrinking agents, resilient materials, and combinations thereof. In one embodiment, emulsifiers may promote the separation of mud in a wellbore. Suitable emulsifiers may include amides (e.g., acetomide), amines, and amidoamines, among others. In one embodiment, viscosifiers may increase the viscosity of a wellbore fluid. Suitable viscosifiers may include clay-based viscosifiers (e.g., bentonite) and polymer-based viscosifiers (e.g., hydroxyethylcellulose, xantham gum, polyanionic cellulose), among others. In one embodiment, a fluid loss control agent may control the loss of aqueous phase cement system to the formation. Suitable fluid loss control agents include chemicals such as, water soluble polymers (e.g., hydroxyethylcellulose), cellulose derivatives (e.g., polypeptide, ethylenediaminecarboxymethylcellulose), and finely divided particulates (e.g., bentonite, carbonate powder, asphaltenes, thermoplastic resins), among others. In one embodiment, fluid loss control agents may include gas migration control agents. In one embodiment, gas migration control agents may prevent and / or control the flow of gases though the wellbore fluid and / or barrier sheath. Suitable gas migration control agents include latexes (e.g.. polymer latexes) and silica fume, among others. In one embodiment, surfactants may decrease the surface tension and / or the interfacial tension between chemicals in the wellbore fluids. In one embodiment, surfactants may include liquid surfactants and / or solid surfactants. In one embodiment, surfactants may include wetting agents, anti-foam agents, defoamers, and dispersants. In one embodiment, a dispersant may reduce agglomeration of particles in a wellbore fluid. Suitable dispersants include chemicals such as sulfonates (e.g., polymelamine sulfonate, polynaphthalene sulfonate, polystyrene sulfonate), polysaccharides (e.g., cellulose derivatives, ethylene oxide polymers, polyglycol), silicas (e.g., microsilica, silica fume), and non-polymeric chemicals (e.g., hydroxycarboxylic acids), among others. In one embodiment, wetting agents may lower surface tension of the wellbore fluids. Suitable wetting agents include alkyl-based surfactants, peptides, lipids, and polymers, among others. In one embodiment, antifoam agents may prevent or reduce the foaming of a wellbore fluid during mixing (e.g., by adding an anti-foaming agent to a liquid or wellbore fluid prior to mixing). Suitable anti-foam agents include poly glycol ethers (e.g.. polypropylene glyocol) and silicons, among others. Conversely, defoamers may reduce or eliminate foam that has formed due to mixing. SuitableAttorney Docket No.: 212276010400 / PCT defoamers include insoluble oils, polyethers (e.g., alkyl polyethers, silicone polyethers), and phosphates (e.g.. tributyl phosphate), among others. In one embodiment, retarders may extend the setting time of a wellbore fluid. Suitable retarders include lignosulfonates, saccharide compounds, hydroxycarboxylic acid, cellulose derivatives, organophosphonates, and inorganic compounds, among others. In one embodiment, an accelerator may reduce the setting time of a cement system and / or may increase the rate of compressive strength development of the wellbore fluid. Suitable accelerators include chemicals such as inorganic salts such as chlorides (e.g., calcium chloride), carbonates, and silicates (e.g., sodium silicate), among others. In one embodiment, extenders may lower the density' of a cement system, and / or reduce the quantity' of cement per unit volume. Suitable extenders include clays, sodium silicates, pozzolans, fly ashes, hollow spheres, other lightweight materials, and diatomaceous earth, among others. In one embodiment, densifiers may include weighting agents. In one embodiment, weighting agents may increase the density' of a cement system. Suitable weighting agents include chemicals that have a higher density than the wellbore fluid such as ilmenite, hematite, and barite, among others. In one embodiment, anti-shrinking agents may reduce and / or control the shrinking of a barrier sheath in a wellbore (e.g., to maintain the connection between the casing, the barrier sheath, and the formation). Suitable anti-shrinking agents include magnesium oxide, aluminum powder, and ethylene glycol derivatives, among others. In one embodiment, resilient materials may make barrier sheaths more resilient to changes in the wellbore conditions (e.g., temperature and pressure changes). Suitable resilient materials may include asphaltenes, rubbers, silica fume, and microspheres, among others.

[0077] As noted above, pozzolans may be used as one or more additives in a wellbore fluid. Suitable pozzolans include fly ash, silica fume, metakaohn, limestone, kaolinite, blast furnace slag, and diatomaceous earth, among others.

[0078] As noted above, suitable additives may include one or more additives suited for use in the production of wellbore fluids. In one embodiment, suitable additives may include calcite precipitation agents, resins, tracer materials, nanoparticles, and smart materials, among others.

[0079] In one embodiment, calcite precipitation agents may promote calcite precipitation (e.g.. to facilitate the conversion of calcium into calcite). In one embodiment, calcite produced from calcite precipitation agents may plug and / or fill small voids in the barrier sheath. In one embodiment, calcite produced from calcite precipitation agents may decrease the porosity' of the barrier sheath. In one embodiment, calcite precipitation agents may promote microbial inducedAttorney Docket No.: 212276010400 / PCT or ureolysis induced calcite precipitation. In one embodiment, calcite precipitation agents may comprise a ureolytic bacteria such as Bacillus sphaericus and / or Bacillus pasteurii. among others.

[0080] In one embodiment, resins may increase one or more properties of a barrier sheath. In one embodiment, resins may increase one or more of the tensile strength, the bond strength, the resiliency, and the durability of the barrier sheath. In one embodiment, resins may be resilient to changes in wellbore conditions (e.g., temperature and pressure changes). In one embodiment, resins may comprise one or more polymers suitable for use in a wellbore. In one embodiment, resins may be derived from a natural material. In one embodiment, resins may be produced from or derived from a synthetic material. Suitable resins may include epoxy resins (e.g., napthol- based epoxy resins), polyepoxide resins, furan resins, and polyester resins, among others.

[0081] In one embodiment, tracer materials may assist in determining the position of a barrier sheath in a wellbore (e.g., to determine the position of the barrier sheath relative to the surface, to determine the position of a portion of the barrier sheath relative to a different portion of the barrier sheath). In one embodiment, a tracer material may assist in determining the position of a wellbore fluid while the wellbore fluid is being pumped into the wellbore and / or while the wellbore fluid is setting (e.g., to determine if more wellbore fluid may be needed to further displace wellbore fluid up the annulus until the wellbore fluid reaches a desired level). In one embodiment, tracer materials may assist in determining the status of a barrier sheath in a wellbore (e.g., by determining a baseline level of emissions for a barrier sheath and comparing the baseline level of emissions to one or more future levels of emissions to identify if there is a deviation in the levels of emissions, a deviation in the levels of emission may indicate deterioration of the barrier sheath that may require remediation). In one embodiment, a tracer material may emit an indicator that may be detected by one or more devices. Suitable devices for detecting tracer materials may include natural gamma ray spectroscopy logs, neutron logs, and pulsed neutron capture logs, among others. Suitable tracer materials may include radioactive tracers (e.g., isotopes, such as iodine-131. tritium, cobalt-60, sodium-22. chlorine-36) and nonradioactive tracers (e.g., Gd2Ch, SrmCh, B4C), among others.

[0082] Nanoparticles may be used as one or more additives in a wellbore fluid. In one embodiment, nanoparticles may be used as a filler (e.g., to reduce porosity). In one embodiment, nanoparticles may be used as ahydrating agent (e.g., to increase or decrease the rate ofhydration of wellbore fluids). In one embodiment, nanoparticles may be used as a densifier. In one embodiment, nanoparticles may be used to increase the surface area of the wellbore fluid.Attorney Docket No.: 212276010400 / PCTSuitable nanoparticles may include synthetic nanofiber, SiCh, MgO, TiCh, FezOs, AI2O3, and graphene oxide (GO), among others.

[0083] In one embodiment, smart materials may include expandable materials. In one embodiment, expandable materials may expand while a wellbore fluid is setting (e.g., hardening). In one embodiment, expandable materials may reduce the bulk shrinkage of the wellbore fluid. Suitable expandable materials may include MgO and CaO, among others.

[0084] In one embodiment, smart materials may include shape memory materials. In one embodiment, shape memory materials may change from a temporary shape to a permanent shape once a condition is met (e.g., at a certain temperature, moisture content, or pressure). In one embodiment, shape memory’ materials may include shape memory polymers. Suitable shape memory' polymers may include polymethacrylic acids, polyactide, polyaryletherketones, polyurethane, polytetrafluoroethylene, and ethylene-vinyl acetate, among others.

[0085] As noted above, the secondary materials may include cements. The cements may be any cements suited to the production of a wellbore fluid, such as cements suited for mixing w ith coated drill cuttings and other optional materials, such as geopolymers, mine tailings, uncoated drill cuttings to produce a lead barrier fluid or a tail barrier fluid. Examples of suitable cements include any class (e.g., class A-H) of Ordinary Portland cement (OPC), Portland pozzolana cement (PPC), ASTM standard cements, Portland limestone cements (IL cements), calcium sulfoaluminate cements (CSA), slag cement, and rapid hardening cement, among others. iv. Properties

[0086] As noted above, primary materials may be used to produce any appropriate wellbore fluid. The coating layers on drill cuttings and / or other coated primary materials may be selected to achieve one or more preselected wellbore properties, including one or more of strength, bonding, hydration, ductility7, and / or traceability7of a wellbore fluid and / or barrier sheath. Additionally, the amount of primary materials used in those wellbore fluids, as well as the amount of optional liquid and the amount of optional secondary materials used in those wellbore fluids, may be selected to achieve one or more preselected wellbore properties. The wellbore properties may be, for instance w ellbore fluid properties or barrier sheath properties. Wellbore fluid properties may be one or more of density, rheology, and set time, among others. Barrier sheath properties may be one or more of tensile strength, compressive strength, shear strength, bonding strength, and ductility among others. In one embodiment, a traceability property7of the wellbore fluid comprises traceability of the at least one material in at least one of the barrier sheath and an environment around the barrier sheath. In one embodiment, one or more wellboreAttorney Docket No.: 212276010400 / PCT properties are derived from a suitable computer program, such as the software program CEMLAB made by Pegasus Vertex. Inc. located at 6100 Corporate Dr.. Suite 448, Houston, TX 77036, USA. To achieve the one or more wellbore properties, the ratio of primary materials-to- secondary materials-to-liquid (PM:SM:L ratio) may be preselected. After or concomitant to the preselecting, the selected ratio of primary materials-to-secondary materials-to-liquid (PM:SM:L ratio) may be mixed to produce the wellbore fluid.

[0087] In one embodiment, the preselected ratio of primary materials-to-secondary materials-to-liquid (PM:SM:L ratio) may be achieved in near real-time by (a) appropriate realtime provision of primary materials, liquid, and / or secondary materials to a primary mixing unit and / or (b) provision of adjustment materials from a supplement unit. For instance, flow rates of materials may be adjusted in real-time to achieve the desired primary materials-to-secondary materials-to-liquid (PM:SM:L ratio). In one embodiment, one or more flow rates of primary materials from a primary materials source to a mixing destination are controlled. In one embodiment, one or more flow rates of a liquid from a liquid source to a mixing destination are controlled. In one embodiment, one or more flow rates of secondary materials from a secondary materials source to a mixing destination are controlled. In one embodiment, one or more flow rates of an adjustment material from a supplement unit are controlled. Any of the primary materials, liquids, secondary materials, and adjustment material flow rates may be controlled to achieve the desired ratio of primary materials-to-secondary materials-to-liquid (PM:SM:L ratio) and, if desired, in near real-time. The flow rate adjustments may be made individually or jointly, and in succession or contemporaneously.

[0088] In one embodiment, a first wellbore property may be selected for a spacer fluid. Accordingly, a first ratio of primary materials-to-secondary materials-to-liquid (PM:SM:L ratio) may be selected to achieve the first wellbore property. The spacer fluid may then be produced in accordance with the first ratio. The spacer fluid may then be used in the wellbore fluid supply system as described above. For instance, a spacer fluid density of from 0.96 to 3.00 g / ml (8 to 25 pounds per gallon) may be selected as the first wellbore property. Correspondingly, a first ratio of primary7materials-to-secondary materials-to-liquid (PM:SM:L ratio) may be selected to achieve the spacer fluid density of from 0.96 to 3.00 g / ml (8 to 25 pounds per gallon), after which the spacer fluid may be used in the wellbore fluid supply system as described above. The same methodology may be used for other wellbore properties (e g., tensile strength, set time, compressive strength), alone or in combination with other wellbore properties.Attorney Docket No.: 212276010400 / PCT

[0089] In one embodiment, a second wellbore property may be selected for a lead barrier fluid. Accordingly, a second ratio of primary materials-to-secondary materials-to-liquid (PM: SM:L ratio) may be selected to achieve the second wellbore property. The lead barrier fluid may then be produced in accordance with the second ratio. The lead barrier fluid may then be used in the wellbore fluid supply system as described above. For instance, a lead barrier fluid density of from 0.96 to 3.00 g / ml (8 to 25 pounds per gallon) may be selected as the second wellbore property. Correspondingly, a second ratio of primary materials-to-secondary materials- to-liquid (PM:SM:L ratio) may be selected to achieve the lead barrier fluid density of from 0.96 to 3.00 g / ml (8 to 25 pounds per gallon), after which the lead barrier fluid may be used in the wellbore fluid supply system as described above. The same methodology may be used for other wellbore properties (e.g., tensile strength, set time, compressive strength), alone or in combination with other wellbore properties.

[0090] In one embodiment, a third wellbore property may be selected for a tail barrier fluid. Accordingly, a third ratio of primary materials-to-secondary materials-to-liquid (PM:SM:L ratio) may be selected to achieve the third wellbore property. The tail barrier fluid may then be produced in accordance with the third ratio. The tail barrier fluid may then be used in the wellbore fluid supply system as described above. For instance, a tail barrier fluid density of from 0.96 to 3.00 g / ml (8 to 25 pounds per gallon) may be selected as the third wellbore property’. Correspondingly, a third ratio of primary materials-to-secondary materials-to-liquid (PM:SM:L ratio) may be selected to achieve the tail barrier fluid density of from 0.96 to 3.00 g / ml (8 to 25 pounds per gallon), after which the tail barrier fluid may be used in the wellbore fluid supply system as described above. The same methodology’ may be used for other wellbore properties (e.g.. tensile strength, set time, compressive strength), alone or in combination with other wellbore properties.

[0091] In one embodiment the first, second, and third wellbore property’ may be the same wellbore property. For instance, the first, second, and third wellbore property may all relate to density’. In one embodiment, the first density may be different than the second and / or third densities (e.g., when successive spacer fluid, lead barrier fluid, and tail barrier fluid wellbore fluids are used). In another embodiment, the first density may be the same as the second density and / or third density (e.g., when a single wellbore fluid is used, but with different additives to achieve different wellbore properties.) The same principles apply to the second and third wellbore properties.Attorney Docket No.: 212276010400 / PCT

[0092] In another embodiment, the first and second wellbore property may be the same wellbore property, and the third wellbore property may be a different wellbore property. For instance, the first and second wellbore property may relate to density, and the third wellbore property may relate to tensile strength. In yet another embodiment, the first and third wellbore property may be the same wellbore property, and the second wellbore property may be a different wellbore property. In yet another embodiment, the second and third wellbore property may be the same wellbore property, and the first wellbore property may be a different wellbore property. In yet another embodiment, the first, second, and third wellbore property may all be different wellbore properties. For instance, the first wellbore property' may relate to density', the second wellbore property may relate to tensile strength, and the third wellbore property may relate to set time.

[0093] In one embodiment, a first w ellbore fluid is produced with a first ratio of primary' materials-to-secondary materials-to-liquid (PM:SM:L ratio) to achieve a first wellbore property’. After or concomitant to the production of the first wellbore fluid, the first wellbore property of the first wellbore fluid may be verified. For instance, when the first wellbore property is density', a density' checker, such as those described above, may be used to check whether the density' of the wellbore fluid corresponds to the selected density. If the density' corresponds to the selected density, then the wellbore fluid may be deemed suitable for use and may be used in the wellbore fluid supply system as described above. If the density does not correspond to the selected density7, then the wellbore fluid may be adjusted by adding appropriate materials (e.g., primary materials, secondary materials, liquid, adjustment materials) as appropriate to achieve the selected density.

[0094] In one embodiment, multiple different w ellbore fluids are created in succession. For instance, a first w ellbore fluid and a second wellbore fluid may be produced in succession. The first wellbore fluid may have a first wellbore property and the second wellbore fluid may have a second wellbore property. After production of the first wellbore fluid having the first wellbore property, the production of the second wellbore fluid having the second wellbore property’ may commence, either immediately or after a delay. In one embodiment, the production of the second wellbore fluid occurs wherein the ratio of primary materials-to-secondary materials-to-liquid (PM:SM:L ratio) of the first wellbore fluid is adjusted to achieve the wellbore property of the second wellbore fluid, thus creating the second wellbore fluid.

[0095] In one embodiment, the first wellbore fluid is a spacer fluid, and the second wellbore fluid is a lead barrier fluid. In another embodiment, the first wellbore fluid is a spacer fluid, andAttorney Docket No.: 212276010400 / PCT the second wellbore fluid is a tail barrier fluid. In yet another embodiment, the first wellbore fluid is a lead barrier fluid, and the second wellbore fluid is a tail barrier fluid. In yet another embodiment, the first wellbore fluid is a spacer fluid, the second wellbore fluid is a lead barrier fluid, and the third wellbore fluid is a tail barrier fluid. v. System ApDlications

[0096] As may be appreciated, primary materials may be used to produce a single wellbore fluid or to produce multiple wellbore fluids in a single wellbore fluid supply system. For instance, as described above, a wellbore fluid supply system (e.g., a wellbore fluid supply system (200) of FIG. 5), may require multiple wellbore fluids (e.g., a spacer fluid, a lead barrier fluid, a tail barrier fluid). It is anticipated that more than one wellbore fluid in the wellbore fluid supply system may use primary materials. For example, in one embodiment, primary materials may be used in a spacer fluid, a lead barrier fluid, and a tail barrier fluid in the same wellbore fluid supply system. In another embodiment, primary materials may be used in a spacer fluid and tail barrier fluid in the same wellbore fluid supply system. In yet another embodiment, primary materials may be used in the spacer fluid and the lead barrier fluid in the same wellbore fluid supply system. In yet another embodiment, primary materials may be used in the lead barrier fluid and the tail barrier fluid in the same wellbore fluid supply system.

[0097] As noted above, the wellbore fluid supply system may supply one or more wellbore fluids to the wellbore. In one embodiment, the one or more wellbore fluids supplied to the wellbore may include one or more barrier fluids (e.g.. a lead barrier fluid, a tail barrier fluid). In one embodiment, the one or more barrier fluids may then be pumped into the annulus of the wellbore. The one or more barrier fluids in the annulus may then set (e.g., harden, solidify) in the annulus of the wellbore to create one or more substantially impermeable barrier sheaths (e.g., lead barrier sheath, tail barrier sheath). In one embodiment, the one or more barrier sheaths may be cement barrier sheaths (i.e., a barrier sheath comprising at least some cement). The cement for the cement barrier sheaths may be supplied as a secondary material for mixing with primary materials (if needed and as needed), as described above. In another embodiment, the one or more barrier sheaths may be non-cement barrier sheaths (i.e., barrier sheaths comprising no cement).

[0098] While prior embodiments were described in which a wellbore fluid supply system (e.g., a wellbore fluid supply system (200) of FIG. 5) used three wellbore fluids (e.g., a spacer fluid, a lead barrier fluid, and a tail barrier fluid), it is also anticipated that wellbore fluid supply systems may require more or less wellbore fluids. For instance, in one embodiment, a wellboreAttorney Docket No.: 212276010400 / PCT fluid supply system (e.g., a wellbore fluid supply system (200) of FIG. 5) may only require a single wellbore fluid (e.g.. a tail barrier fluid) or only two wellbore fluids (e.g., a spacer fluid). It is anticipated that primary materials may be used in one or both of the wellbore fluids required by the wellbore fluid supply system, using any of previous embodiments described above. Similarly, a wellbore fluid supply system may require additional wellbore fluids (e.g., wellbore fluids in addition to a spacer fluid, a lead barrier fluid, and a tail barrier fluid). It is also anticipated that primary materials may be used in any additional wellbore fluids that may be used in such wellbore fluid supply systems.

[0099] As noted above, primary materials may be used in one or more wellbore fluids in a single wellbore fluid supply system. Additionally, as noted above, in one embodiment, resins may be used as an additive in a wellbore fluid. In another embodiment, the wellbore fluid may be resin-based, i.e., a wellbore fluid that primarily comprises resin. In one embodiment, a resinbased fluid consists essentially of, or consists of, one or more resins. In one embodiment, a resin-based fluid may comprise one or more additives. In one embodiment, a resin-based fluid may be used in a wellbore fluid supply system (e.g., a wellbore fluid supply system (200) of FIG. 5). In one embodiment, a resin-based fluid may set (e.g., harden) to create a substantially impermeable resin barrier sheath (i.e., a barrier sheath primarily comprising resin). In one embodiment, a resin-based fluid may be used in the same wellbore fluid supply system as a wellbore fluid comprising primary materials and / or cements (e.g., a wellbore fluid comprising primary materials and / or cements may be used as a tail and a resin-based fluid may be used as a lead).

[0100] As noted above, drill cuttings may be processed on-site to produce one or more synthesized geopolymers. For instance, drill cuttings from the wellbore location may be used to produce synthesized geopolymers on-site. In other embodiments, it is anticipated that drill cuttings from the wellbore location (510) may be used to produce synthesized geopolymers offsite, such as in the off-site preparation system (500) illustrated in FIG. 8. For instance, in one embodiment and with continued reference to FIG. 8, drill cuttings from the wellbore location (510) are transported to an off-site coating system (e.g., a system similar to that of FIG. 6, but off-site). In one embodiment, the off-site coating system may be at the off-site preparation location (520). In another embodiment, the off-site coating system may be at the secondary wellbore location (515). The drill cuttings at the off-site coating system may then be used toAttorney Docket No.: 212276010400 / PCT produce coated drill cuttings. In one embodiment, the coated drill cuttings made at the off-site coating system, may then be transported to the wellbore location (510). In another embodiment, the coated drill cuttings made at the off-site coating system may be transported to the secondary wellbore location (515). In yet another embodiment, the coated drill cuttings made at the offsite coating system may be further mixed with liquids (e.g., water) and / or secondary materials (e.g., cements, additives) at the off-site preparation location (520) as described in further detail below. The coated drill cuttings may then be used in one or more wellbore fluids, as described above. These wellbore fluids may be any of the wellbore fluids previously described, such as any of the spacer fluid, lead barrier fluid, and tail barrier fluid.

[0101] As noted above, and with continued reference to FIG. 8, mine tailings may be coated in the coating process. It is anticipated that mine tailings may be transported from the mine tailing location (530) to the wellbore location (510) to be used in the coating process. In another embodiment, the mine tailings may be transported from the mine tailing location (530) to the off-site preparation location (520). In yet another embodiment, the mine tailings may be transported from the mine tailing location (530) to the secondary wellbore location (515). The mine tailings may then be used in the on-site and / or off-site coating process. In one embodiment, the transported mine tailings may be substituted for drill cuttings or used in addition to drill cuttings in the coating process as described above.

[0102] As noted above, prior embodiments described mixing primary materials, optional liquid, and optional secondary materials in a wellbore fluid preparation system, such as that illustrated in FIGS. 4 and 9. It is also anticipated that the primary materials (coated drill cuttings and optionally additional coated and / or uncoated materials, such as geopolymers, mine tailings, uncoated drill cuttings, etc.) and secondary materials (e.g., cements, additives) may be mixed prior to the production of one or more wellbore fluids. In one embodiment, and with reference to FIG. 8, the primary materials and secondary’ materials may be mixed at the wellbore location (510), to create a precursor mixture, for subsequent use in the production of one or more wellbore fluids. In another embodiment, the primary materials and secondary materials may be mixed at an off-site preparation location (520), to create the precursor mixture. The precursor mixture at the off-site preparation location (520) may then be transported from the off-site preparation location (520) to the wellbore location (510) or to the secondary wellbore location (515). Accordingly, the precursor mixture may' then be used to create one or more wellbore fluids in a wellbore fluid preparation system (e.g., a system similar to FIGS. 4 and 9), such as by addingAttorney Docket No.: 212276010400 / PCT liquid and / or additives thereto. These wellbore fluids may be any of the wellbore fluids previously described, such as any of the spacer fluid, lead barrier fluid, and tail barrier fluid.B. Alternative Drill Cutting Coating Systems

[0103] Refernng now to FIGS. 12-14. alternative embodiments of coating systems for coating drill cuttings are described. In reference to FIG. 12, an alternative embodiment of the coating system (see, e.g., FIG. 6) is illustrated. In the embodiment of FIG. 12, a coating system (300a) may include a coating unit (330) that includes coating phase composition(s) loaded within the coating unit (330) prior to introduction of drill cuttings and / or other suitable materials (e.g., mine tailings, geopolymers, fly ash, slug, silica fume, and / or kaolin) from drill cuttings source (310), which may be connected to coating unit (330) via a conduit (315) or other suitable conveyance apparatus. For example, coating unit (330) may comprise a physical vapor deposition (PVD) reaction chamber that includes a solid source target disposed within a deposition chamber. The solid target, which may be changed infrequently, may act as the source of the coating phase composition. Accordingly, coating unit (330) of coating system (300a) may not require a separate coating phase source since the target may be changed only infrequently or as needed. The coating unit (330) may be connected to the primary material source (110) (e.g., via conduit (335) or other suitable conveyance apparatus).

[0104] Referring now to FIG. 13, an alternative embodiment of the coating system (see, e.g., FIG. 6) is illustrated. In the embodiment of FIG. 14, a coating system (300b) may include an additional processing unit (340) for further processing drill cuttings that are at least partially coated with a coating phase composition and / or a coating layer. For example, the processing unit (340) may comprise a heating chamber for applying heat to a coating phase composition applied to drill cuttings. In one embodiment, processing unit (340) may comprise a UV light chamber that exposes a coating phase composition on drill cuttings to UV light to cure the coating phase composition. In one embodiment, processing unit (340) may comprise a convection chamber that circulates air or other gasses, which may be heated, to facilitate dry ing of a coating phase composition to form coating layers on drill cuttings. As shown in FIG. 13, prepared drill cuttings and / or other materials to be coated may be received by coating unit (330) from drill cuttings source (310) and one or more coating phase compositions may be received by coating unit (330) from coating phase source (320). Drill cuttings and / or other materials at least partially covered by one or more coating phase compositions may be transferred to processing unit (340), where additional processing is carried out to create coating layers on the drill cuttings and / or other materials. The coated drill cuttings and / or other materials may thenAttorney Docket No.: 212276010400 / PCT be transferred to the primary' material source (110). Materials may be respectively conveyed between drill cuttings source (310), coating phase source (320), coating unit (330), processing unit (340), and primary materials source (1 10) via conduits (315, 325, 335, 345) and / or other suitable conveyance apparatus.

[0105] Referring now to FIG. 14, an alternative embodiment of the coating system (see. e.g., FIG. 6) is illustrated. In the embodiment of FIG. 14, a coating system (300c) may include multiple coating units, such as a first coating unit (330a) and a second coating unit (330b). The first coating unit (330a) and the second coating unit (330b) may each be configured to create a coating layer such that multiple coating layers are formed on surfaces of drill cuttings (see. e.g., FIG. 11). In one embodiment, the first coating unit (330a) may utilize one or more coating phases from a first coating phase source (320a) to create a first coating layer on the drill cuttings and / or other suitable materials received from a drill cuttings source (310a). The second coating unit (330b) may then utilize one or more coating phases from a second coating phase source (320b) to create a second coating layer on the coated dnll cuttings and / or other suitable materials received from the first coating unit (330a). The first coating unit (330a) and the second coating unit (330b) may form the same or different coating layers on the drill cutting surfaces. Additionally, the first coating unit (330a) and the second coating unit (330b) may use the same coating process or different coating processes to create the coating layers. While two coating units are illustrated in FIG. 14, additional coating units may be utilized in some embodiments to form one or more additional coating layers. The coated drill cuttings and / or other materials may then be transferred to the primary material source (110). Materials may be respectively conveyed between drill cuttings source (310a), first coating phase source (320a), first coating unit (330a), second coating phase source (320b), second coating unit (330b). and primary materials source (110) via conduits (315a, 325a, 335a, 325b, 335b) and / or other suitable conveyance apparatus.C. Remediation

[0106] As noted above, wellbore fluids may be used to create one or more substantially impermeable barrier sheaths. It is anticipated that remedial operations may be performed on one or more substantially impermeable barrier sheaths. Remedial operations may include utilizing a remedial fluid to repair, reinforce, and / or supplement a portion of a substantially impermeable barrier sheath. In one embodiment, a remedial fluid may be one of the wellbore fluids described previously, such as a squeeze fluid and / or a grouting fluid.

[0107] In another embodiment, a remedial fluid may be a non-wellbore fluid, such as a calcite precipitation fluid or a resin-based fluid, among others. In one embodiment, calciteAttorney Docket No.: 212276010400 / PCT precipitation fluids may be aqueous based. In one embodiment, calcite precipitation fluids may comprise a calcite precipitation agent.

[0108] In another embodiment, a remedial fluid may be resin-based, i.e., a wellbore fluid that primarily comprises resin. In one embodiment, a resin-based fluid consists essentially of, or consists of, one or more resins. In one embodiment, a resin-based fluid may comprise one or more additives.

[0109] As noted above, remedial fluids may be used to repair a portion of a barrier sheath. In one embodiment, a remedial fluid may be pumped into a wellbore to repair a portion of a barrier sheath. In one embodiment, the remedial fluid may solidify, set, and / or harden onto the wellbore barrier sheath to repair the barrier sheath. In one embodiment, the remedial fluid may promote solidification of other materials (e.g.. calcite) onto the barrier sheath to repair a barrier sheath.

[0110] As noted above, remedial operations may be used to repair a portion of the barrier sheath. It is also anticipated that sensors may be used to detect one or more properties of the barrier sheath (e.g., to aid in determining if a barrier sheath may require remediation, to determine if a wellbore fluid has set). In one embodiment, a sensor may be an embedded sensor. In one embodiment, one or more embedded sensors may be added to a wellbore fluid before the wellbore fluid is pumped into a casing. In one embodiment, one or more embedded sensors may be added to the wellbore fluid while the wellbore fluid is setting (e.g., hardening). In one embodiment, one or more embedded sensors may be added to the barrier sheath after the wellbore fluid is set. In one embodiment, embedded sensors may sense one or more of pH, temperature, pressure, and humidify, among others. Suitable embedded sensors include, for example, optical fibers, micro-chips, surface acoustic wave devices, and silicon integrated circuit devices, among others. vii. Definitions

[0111] As used herein, “cement” means any cementitious composition suited for use in its intended end-use application, optionally with any suitable additives. Examples of cement may include any class (e.g., class A-H) of Ordinary Portland cement (OPC), Portland pozzolana cement (PPC), ASTM standard cements, Portland limestone cements (IL cements), calcium sulfoaluminate cements (CSA), slag cement, and rapid hardening cement, among others. In one embodiment, a cement is a wellbore cement, suited for use in a wellbore cementing application.

[0112] As used herein, “tank” means any receptacle suited to hold (e.g., contain) a fluid. In one embodiment, a tank is a fixed structure (e.g.. permanently mounted at a location). In anotherAttorney Docket No.: 212276010400 / PCT embodiment, a tank is a moveable structure (e.g., located on a moveable vehicle). Examples of suitable tanks for use herein include in-ground tanks, tractor trailer tanks, and bulk truck tanks, among others. viii. Miscellaneous

[0113] These and other aspects, advantages, and novel features of this new technology are set forth in part in the preceding description that and will become apparent to those skilled in the art upon examination of the preceding description and figures, or may be learned by practicing one or more embodiments of the technology provided for by the present disclosure.

[0114] Among those benefits and improvements that have been disclosed, other objects and advantages of this disclosure will become apparent from the preceding description taken in conjunction with the accompanying figures. Detailed embodiments of the present disclosure are disclosed herein; however, it is to be understood that the disclosed embodiments are merely illustrative of the disclosure that may be embodied in various forms. In addition, each of the examples given in connection with the various embodiments of the disclosure is intended to be illustrative, and not restrictive.

[0115] Throughout the specification and claims, the following terms take the meanings explicitly associated herein, unless the context clearly dictates otherwise. The phrases “in one embodiment’" and “in some embodiments” as used herein do not necessarily refer to the same embodiment(s), though they may. Furthermore, the phrases “in another embodiment” and “in some other embodiments” as used herein do not necessarily refer to a different embodiment, although they may. Thus, various embodiments of the disclosure may be readily combined, without departing from the scope or spirit of the disclosure.

[0116] In addition, as used herein, the term “or” is an inclusive “or” operator, and is equivalent to the term “and / or,” unless the context clearly dictates otherwise. The term “based on” is not exclusive and allows for being based on additional factors not described, unless the context clearly dictates otherwise. In addition, throughout the specification, the meaning of “a.” “an,” and “the” include plural references, unless the context clearly dictates otherwise. The meaning of “in” includes “in” and “on”, unless the context clearly dictates otherwise.

[0117] While a number of embodiments of the present disclosure have been described, it is understood that these embodiments are illustrative only, and not restrictive, and that many modifications may become apparent to those of ordinary skill in the art. However, it is to be expressly understood that such modifications and adaptations are within the spirit and scope of the present disclosure. Further still, unless the context clearly requires otherwise, the variousAttorney Docket No.: 212276010400 / PCT steps may be carried out in any desired order, and any applicable steps may be added and / or eliminated.

Claims

Attorney Docket No.: 212276010400 / PCTCLAIMSWhat is claimed is:

1. A method comprising:(a) coating drill cuttings with a coating layer, thereby creating coated drill cuttings; and(b) creating a wellbore fluid, wherein the creating comprises mixing the coated drill cuttings with a liquid.

2. The method of claim 1, wherein the coating layer comprises at least one of a ceramic, a polymer, a metal, and a surfactant.

3. The method of claim 2, wherein the polymer comprises a plastic material.

4. The method of claim 2 or 3, wherein the polymer comprises a silicone-based material.

5. The method of any of claims 1 to 4, wherein the coating layer comprises additives selected from the group consisting of carbon fibers, magnetic particles, carbon black, and combinations thereof.

6. The method of any of claims 1 to 5, wherein the coating step (a) comprises: applying a coating phase composition to the drill cuttings; and processing the coating phase composition, thereby creating the coating layer.

7. The method of claim 6, wherein the coating phase composition comprises a liquid composition or semiliquid composition.

8. The method of claim 7. wherein the processing step comprises solidifying the liquid or semiliquid composition.

9. The method of claim 8, wherein the solidify ing step comprises at least one of curing the liquid or semiliquid composition and evaporating a solvent from the liquid or semiliquid composition.

10. The method of any of claims 6 to 9. wherein the coating phase composition comprises a resin, wherein the processing step comprises curing the resin.Attorney Docket No.: 212276010400 / PCT11. The method of any of claims 6 to 9, wherein the coating phase composition comprises a solgel, wherein the processing step comprises heating the sol-gel to create a ceramic coating.

12. The method of claim 6, wherein the coating phase composition comprises a powder.

13. The method of claim 12, wherein the powder comprises polymer particles, wherein the processing step comprises at least one of melting and curing the polymer particles.

14. The method of claim 12 or 13, wherein the powder comprises carbon black.

15. The method of any of claims 6 to 14, wherein the applying step comprises at least one of dip coating, brush coating, roll coating, spin coating, and spray coating the coating phase composition onto the drill cuttings.

16. The method of claim 1 or 2, wherein the coating step (a) comprises applying the coating layer by thin film deposition.

17. The method of claim 16, wherein the thin film deposition comprises at least one of chemical vapor deposition and physical vapor deposition.

18. The method of any of claims 1 to 17, wherein the coating layer comprises at least one tracer material.

19. The method of claim 18. wherein the tracer material comprises at least one radioactive tracer compound.

20. The method of claim 19, wherein the at least one radioactive tracer compound comprises at least one isotope selected from the group consisting of tritium, iodine-131, cobalt-60, sodium- 22, and chlorine-36.

21. The method of any of claims 18 to 20, wherein the tracer material comprises at least one of gadolinium(III) oxide, samarium(III) oxide, and boron carbide.Attorney Docket No.: 212276010400 / PCT22. The method of any of claims 1 to 21, wherein the liquid comprises at least one of an aqueous solution and an organic solution.

23. The method of any of claims 1 to 22, wherein the wellbore fluid is selected from the group consisting of a spacer fluid, a lead barrier fluid, and a tail barrier fluid.

24. The method of any of claims 1 to 23, wherein the creating step (b) further comprises mixing the coated drill cuttings and the liquid with at least one material selected from the group consisting of cements, additives, and combinations thereof.

25. The method of any of claims 1 to 24, comprising, after the creating step (b): pumping the wellbore fluid into a casing of a wellbore; and allowing the wellbore fluid to set, thereby creating a barrier sheath within the wellbore.

26. The method of claim 25, comprising, prior to the coating step (a): preselecting a wellbore property of the barrier sheath; and selecting at least one material for the coating layer to achieve the wellbore property.

27. The method of claim 26, wherein the wellbore property comprises at least one of strength, bonding, hydration, and ductility.

28. The method of claim 27, wherein the strength comprises at least one of tensile strength, compressive strength, shear strength, and bonding strength.

29. The method of any of claims 26 to 28, wherein the wellbore property comprises traceability of the at least one material in at least one of the barrier sheath and an environment around the barrier sheath.

30. The method of any of claims 1 to 29, comprising, prior to the coating step (a), obtaining the drill cuttings from a wellbore at a wellbore location.

31. The method of claim 30, wherein at least one of the coating step (a) and the creating step (b) is performed at the wellbore location.Attorney Docket No.: 212276010400 / PCT32. The method of claim 30 or 31, comprising, after the creating step (b), pumping, at the wellbore location, the wellbore fluid into a casing of a wellbore.

33. The method of any of claims 1 to 32, comprising, prior to the coating step (a), separating the drill cuttings from a drilling mud comprising the drill cuttings.

34. The method of claim 33, comprising, after the separating step, at least one of washing the drill cuttings and drying the drill cuttings.

35. The method of any of claims 1 to 34, comprising, prior to the coating step (a), sizing the drill cuttings for use in the wellbore fluid.

36. The method of claim 35, wherein the sizing comprises comminuting the drill cuttings.

37. The method of claim 36, wherein the comminuting comprises grinding the drill cuttings, pulverizing the drill cuttings, crushing the drill cuttings, and combinations thereof.

38. A barrier sheath for a wellbore comprising:(a) a cement composition; and(b) coated drill cuttings dispersed within the cement composition, wherein the coated drill cuttings each comprise a coating layer on a surface of a drill cutting.

39. The barrier sheath of claim 38. wherein the coating layer comprises at least one of a ceramic, a polymer, a metal, and a surfactant.

40. The barrier sheath of claim 39, wherein the polymer comprises a plastic material.

41. The barrier sheath of claim 39 or 40, wherein the polymer comprises a silicone-based material.

42. The barrier sheath of any of claims 38 to 41, wherein the coating layer comprises additives selected from the group consisting of carbon fibers, magnetic particles, carbon black, and combinations thereof.Attorney Docket No.: 212276010400 / PCT43. The barrier sheath of any of claims 38 to 42, wherein the coating layer comprises at least one tracer material.

44. The barrier sheath of any of claims 38 to 43, wherein at least one of the coated drill cuttings comprises at least two coating layers.

45. The barrier sheath of claim 44, wherein the at least two coating layers comprise different materials.

46. The barrier sheath of any of claims 38 to 45, wherein the coating layer of each coated drill cutting is disposed between the drill cutting of the coated drill cutting and the cement composition.

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