BACKOlOt D

The present disclose» relates to compositions for treating a subterranean formation and methods of preparing the same.

Treatment fluids may be used In a variety of subterranean treatment operations. As used herein, the terms ^reill^ ^-attneh ^ere&ttng^ and grammatical equivalents thereof refer to any subterranean operation that uses a flui in conjunction with achieving a desired function and/or for a desired purpose. Use of these terms does not Imply any particular action by the treatment fluid. Illustrative treatment operations may include, for example* fracturing operations, grave! packing operations, acidizing operations, scale dissolution and removal, consolidation operations, and the like. For example, a fluid may be used to drill a well bore in a subterranean formation or to complete a well bore in a subterranean formation, as well as numerous other purposes.

While drilling an oil or gas well, a "drilling fluid (or drilling mud) i typically pumped down to a drill bit during drilling operations an flowed hack to the surface through an annulus defined between a drill string and the walls of the wellbore, Drilling fluid often Include viscosifiers to, for example, I rove the ability of the drilling fluid to remove cuttings from the wellbore and suspend cuttings and weight materials in the drilling fluid, for example, during periods of non-circulation.

BRIEF DESCRIPTION OP TOE DRAWINGS

These dra ings Illustrate certain aspects of some of the embodiments of the present disclosure and should not be used to limit or define the claims.

S Fknre I is a diagram illustrating an example of a drilling assembly that may be used in accordance with certain embodiments of the present disclosure.

While embodiments of this disclosure have been depicted, such embodiments do not imply a limitation on the disclosure, and no such limitation should be inferred. The subject matter disclosed is capable of considerable modification, alteration, and equivalents in form and function,:0 as will occur to those skilled in the pertinent art and having the benefit of this disclosure l re depicted and described embodiments of this disclosure are examples only, and not exhaustive: of the scope of the disclosure.

DESCRIPTION OF CERTAIN EMBODIMENTS

The pr s nt disclosure relates to methods and compositions for treating subte ran an formations _^ More particularly, the present disclosure relates to m ethods arid Oppositions for modifying the rheological properties of non-aqueons fluids for treMing subterranean formations;

Th& presefti disclosure provides methods and compositions tor modifying the viscosity of non-aqueons fluids by including one or more associative polymers In the fluid. As used herein, the term“associative polymer ⁵ refers to one or more polymers that are capable of self-assembling info one or more supramoieciflar assemblies through one or more associative interactions. In particular, associative polymers may be capable of forming such assemblies without the need for (although not excluding the optional presence of) additional molecules of species (eg,, eross!iakers). The compositions of the present disclosure may generally include a noft-aqueous fluid and one or more associative polymers. The methods: of the present disclosure generally include; introducing a treatment fluid including a non-aqueons fluid and one or more associative polymers into a wellbore penetrating at leas a portion of a subterranean formation. In some embodiments, the methods of the present disclosure may also include drilling at least portion of the wellbore penetrating the subterranean formation with the treatment fluid.

Among the many potential advantages to the methods and compositions of the present disclosure, only some of which are alluded to herein, the methods and compositions of the present disclosure may improve properties of non-aqucous fluids by reducing the fluid rheology at high shear conditions while maintaining the fluid rheology at low shear conditions, or by increasing the fluid rheology at low shear conditions while maintaining the fluid rheology at high shear conditions. In certain embodiments, the modification of the fluid rheology may be nearly instantaneous and/or reversable, In one or more embodiments, the desired modification of the fluid rheology may be achieved with a very low concentration of associative polymers in the fluids. such as hundreds to thousands of pasts per million. In one or .more embodiments, the modification of the fluid rheology may fee achieved within the subterranean formation without damaging the surrounding formation.

In one or more embodiments, the treatment fluids of the present disclosure may be used to treat at least a portion of a subterranean formation. Such treatment fluids may include, fiat are not limited to, drilling fluids, completion fluids, gravel pack fluids, loss circulation fluids, pills, fracturing fluids, plugging fluids, cementing fluids, and abandonment fluids. As used herein, the terms“treat,”“treatment” and“beating” refer to any subterranean operation that uses a fluid in conjunction with Achieving a desired function and or for a desired purpose. The use of these terms does not iftiply any particula action by the treatment fluid.

The treatment fiui used in the methods and composi tions of the present disclosure may include a non-atjoeous fluid Noft-aqueoos fluids that may be su itable for use in the method of th present disclosure may include, hut are not limited to, oils, hydrocarbons, orprac liquids, and the like, and any combination thereof. In certain embodiments, the non-aqueons fluid may be the base fluid of the treatment fluid. The term "base fluid” refers to the major component of the fluid fa opposed to components dissolved and/or suspended therein) and does not indicate any particular condition or property of that fluids such as its mass, amount, phi, etc- In other embodiments, the non-aqueous fluid may be an oil phase of water-in-oil (Le. invert) emulsion or an oil phase of an oli-m- water emulsion. In such embodiments, the emulsion may in tarn be the base fluid of the treatment fluid.

The invert emulsions of the present disclose ma include water, e.g., an aqueous phase, in any suitable proportion of the invert emulsion as will be appreciated by one of skill In the art with the benefit of this disclosure. In certain embodiments, the water may be re ent In the invert emulsion in an amount from about 0.01 % to about 50 % b volume of the invert emulsion In other embodiments, the water ay be present in the invert emulsion in an amount from about 10 % to about 40 % by volume of the invert emulsion fn other embodiments, the water may he present in the invert emulsion in an amount from about 20 % to about 3§ % by volume of the invert emulsion.

The oihin-water emulsions of the present disclosure may include oil in any suitable: proportion of the emulsion as will be appreciated by one of skill In the art with the benefit of this disclosure in certain embodiments, the oil ma be present in tbe emulsion in an amount from about 0,01 % to about SO % by volume of the emulsion. In other embodiments, the oil ma be present In the emulsion in an amount from about 10 % to about 40 % by volume of the emulsion. In other embodiments, the oil may be present in the emulsion in an amount from about 20 % to about 30 % by volume of the emulsion.

The treatment fluids used in the methods and compositions of the present disclosure may include one or more associative polymers. In certain embodiments, the associative polymers used in the methods and compositions of the present disclosure may be an associative polymer disclosed in U.S. Patent No, 10,087,310, which Is hereby Incorporated by reference in its entirety for all purposes. In certain embodiments, the associative polymers used in the methods and compositions of the present disclosure may he a linear or branched associative polymer that includes a linear, branched, or hyperbr&nehed polymer backbone having at least two ends: and junctional groups presented at two or more ends of the backbone. In certain em bodiments, at least two ends of the associative polymers may be se rated by a polymer backbone having a length of at least 2,000 bonds and/or a polymer backbone having weight average molar moss of equal to or greater than about 100,000 g/moi In certain embodiments, the polymer backbone may be a nonpolar linear, branched or hyperfaranched polymer or copolymer providing a number of flexible repeat units betwee associative functional end groups. Exemplary architectures of the associative polymers used In the methods and compositions of the present disclosure may include, but are noUlmite to:

ially erossJIhked variants, functional at the chain ends).

( tv) yp ed, functional at chain ends);

< represents & suitable polymer backbone of any length, _: and wherein n, x, y, a, b, e, <1, and e Is each independently an integer greater than 1

Examples of suitable polymer backbones include, but are not limited te, _: substituted or ««substituted polydlenes, such a po!y(botadfene} (PB) and pol Cisoprene), and substituted or ««substituted polyolefins, such as polyisobniylene (PIB) and ethylene-butene copolymers, polyfoorbornene), po!y{oeteneJ, polystyrene (PS), polyfsiloxanes), polyaery lut es with alk l side chains, polyesters, and/or polyurethanes, and any combination thereof. In certain embodiments, the polymer backbone of the associative polymers may be substantially soluble in a non~aqueous composition.

As used herein, the term“functional group’ ⁵ may refer to specific groups of atoms within a molecula structur that are responsible for the characteristic physical and/or chemical reaction s of that structure and in particular to physical and/or ehem teal associative interactions of that structure, in certain embodiments, the functional groups of the associative polymers used in the methods and corn positions of the present disclosure may include, but are no! limited to, carboxylic acids, sulfonic acids, phosphouie acids, amines, alcohols, nucleotides, hydrogen atoms, diaoetamidopyridine, thymine, Hamilton Receptors., cyanurlc acid, ate any combination thereof In certain embodiments, one or more functional groups of an associati ve polymer nm be capable of undergoing an associative Interaction with at least one functional group of another associative polymer, in such embodiments, the associative interaction may have an association constant (k) of from O.T<iog _K! k<lS, and In some embodiments, in the range of 4<legsok<l4, such that the strength of the associative interaction is less than that of a covalent bond between atoms and, in particular, the atoms of the polymer backbone. In certain embodiments, the associative polymers may be tekehelic. In certain embodiments, the functional groups of two or mom associative polymers may undergo associative interactions to se!f-assemble or form into one or mom supramo!ecu!ar assemblies. In such embodiments, the supramolocular assemblies may be linear, branched, cyclic, or combinations thereof

In certain embodiments, the associative interaction between the functional groups may be due to, for example, reversible noneovalent interaction between the associative polymers that enables a discrete number of molecular subunits or components t be assembled, typically with an individual interaction strength less than that of a covalent bond. Examples of such interactions include, but are not limited to, cationic-anionic interactions, self associative hydrogen bonds (H- bonds) (such a homoneelear hydrogen bonding (e.g carboxylic acids, alcohols), heteromsciear hydrogen b n donor-acceptor pairing (e.g, carboxylic aeids-ammes}), donor-aeeep!or M~ onds, Bronsted or Lewis aeid-fause interactions (e.g., transition metal center-electron pair donor ligand such as palladium (II) and pyridine, or iron and tetrascetieaeid, or othe s identifiable to a skilled person as moieties that participate in metal-ligand interactions or mefslwfoelate -interactions), electrostatic interactions (e.g., teiraaikyiammosrinm-teOnalkylboraie}, pi-acid/pi-hase or « admpoiar interactions (e.g , arcne-perfluoroareue), interactions between nucleotides, charge transfer complex _: formation (e.g., carbaaoie-rniroarene), or other supramoieeoiar interactions, and combinations of these interactions (e.g., proteins, biotin-avidin).

in certain embodiments, the functional groups of associative polymer may associate in a donotfoeceptor association. In such embodiment, one functional group of an associative polymer is a donor while another, different functional group of an associative polymer (either the same of different) is the acceptor, such that the donor and acceptor fonctionai groups undergo an associative interaction. In the donor/aceeptor association, the donor and acceptor can be stoichiometric (e.g e ual numbers of doner and acceptor functional gmups) or non-stoiehiometrk (e.g. more d nor groups than acceptor groups or vice versa). In other embodiments, the functional groups of associative polymers may associate in a seSifouseif association. In such e bodiments, one or more functional groups of an assoeiative polymer may interact with identical fonctionai groups _: of an associative polymer (either the same or different),

in certain embodiments, the assoeiative polymer may have, an overall weight average molecular weight (Mw) equal to or less than about 2,000,000 g/mol. In some embodiments, the associative polymer may have an overall weight average molecular weight (Mw) equal to or greater than about 100,000 g/mol In some embodiments, the associative polymer may have an overall weight average molecular weight (Mw) from about 100,000 g/mol to about 1,000,000 g/mol In certain embodiments, the polymer backbone and functional groups can be selected such that the associative polymer has a atio of carbon atoms to heterosioms greater than about 1000: ! , fo certain embodiments, the polymer backbone and functional groups can be selected such that the associative polymer ha a ratio of carbon atoms to heteroatoms greater than about 2,000: 1 , In certain embodiments, the polymer backbone and fonctionai groups can be selected such that the associative polymer has a ratio of carbon atoms to heteroafoms greater than about 10,000:1.

In one or more embodiments, the associative polymers used in the methods and compositions of the present disclosure may be present in the treatment fluid in as amount less than 10% by weight of the non-aqueons fluid. In one or more embodiments, the associati ve polymers used In the methods and compositions of the present disclosure may be present in foe treatment fluid in an amount less than 5% by weight of the non-aqueous fluid. In one or more embodiments, the associative polymers use In the methods and compositions: of the present disclosure may be present in the treatment fluid In an amount less than !% by weight of the non-aqueous fluid, in one or more embodiments, the associative polymers used in the methods and compositions of the present disclosure may he present in the treatment fluid in an amount less than 0,75%,by weight of the non-aqueous: fluid, in one or more embodiments, the associative polymers used in the methods and compositions of the present disclosur may be present in the treatment fluid in an amount less than 0.5% by weight of the non-aqueous fluid. Is one or more embodiments, the associative polymer used in the methods and compositions of the present disclosure a be present in the treatment fluid in an amount less than 0.25% hy weight of the «on-aqueous fluid. In one or mote embodiments, the associative polymers used In the methods and compositions of the present disclosure may he present in the treatment fluid In an amount less than 0.1 % by weight of the non-aqueous fluid hi one or mo embodiments, the associative polymers use in the methods and compositions of the present disclosure may be present in the treatment fluid in an amount less than 0.05% by weight of the non-aqueous fluid. In one or more embodiments, the associati ve polymers used in the methods and compositions of the present disclosure may be present in the treatment fluid in an amount less than 0 01% by weight of the noa-aqueous fluid.

In certain embodi ents, one or more of the associative polymers may he capable of undergoing an associative interaction with itself or another associative polymer (e.g, _* via functional groups at one or more ends of the polymer backbone). In certain embodiments, the associative polymers may form one or more snpramoiecylar assemblies within a non-aqueous fluid, which, in turn, may Increase the rheological properties (e.g , viscosity) of the fluid. In some embodiments, the associative polymers may form one or more supramolocuiar assemblies prior to being Introduced to a non-aqueou fluid which, in turn, may increase the rheological properties (e.g,, viscosity) of the fluid after introduction. In certain embodiments, the supramolecular assemblies may form and thereby increase the rheological properties of the fluid at low shear conditions. Examples of low shear conditions include, hat are not limited to, static conditions, pumping at low speeds, and drilling at low speeds.

In certain embodiments, the one or more supraniolecuiar assemblies within the non- aqueous fluid may be broken into one or more polymer strands, which, in turn, may affect the .rheological properties (e.g,, reduce the viscosity) of the fluid. In certain embodiments, the polymer strands may be the associative polymers that formed the supramolecular assemblies in such embodiments, the assembly of the supratnolecnlar assemblies may be reversible in certain embodiments, the suptamolectdar assemblies may be broken by overcom ng the ssociative internet ion between the functional groups of the associative polymers. in certain embodiments, the supramoleeular assemblies may be broken by subjecting the snpra oleeular assemblies to high shear conditions, such as drilling _* In certain embodiments, the suprs olecuiar asse bles ay be broken by Introducing a chemical breaker (e.g , acids, oxidizers, bases, certain ions, enzymes) into the fluid containing the snpra olecalar assemblies. In some embodiments, a combination of breaking methods may he used.

In certain embodiments, the increase of the rheological properties of the fluid (e.g. _* thickening of the fluid) may occur very rapidly upon a transition from a high shear condition to a low shear condi tion in certain embodiments, the reduction of the fluid rheology (e.g., thinning of the fluid) may occur very rapidly upon a transition from a low shear condition to a high shear condition and/or upon breaking of the supramoleeular assemblies through other means fe,g., chemical breaker). In certain embodiments, the modification of the fluid rheology (e,g., increase and/or reduction) may occur nearly instantaneously,

In certain embodiments, treatment fluids used In the methods and compositions of the present disclosure optionally may include; any number of additives Examples of such additives include, but are not limited to, suits, surfactants, acids, diverting agents, fluid loss control additives, gas, nitrogen, carbon dioxide, surface modifying agents, taekifying agents, fhamers, corrosion inhibitors, scale inhibitors, emulsifiers, catalysts, clay stabilizers, shale inhibitors, biocides, friction reducers, antlfbam agents, bridging agents, floeculants, 1¾S scavengers,€C¾ scavengers, oxygen scavengers, lubricants, hydrocarbons, viscosiiy g/gell g agents, breakers, weighting agents, relative permeability modifiers, resins, wetting agents, coating enhancement agents, filter cake· removal agents, antifreeze agents (e.g _< , ethylene glycol), proppant particles, and the like A person skille in the art, with the benefit of this disclosure, will recognize the types of additives that may be included In the treatment fluids of the present disclosure for a particular application.

In one or more embodiments, the treatment fluids of the present disclosure may include one or more weighting agents. Examples of suitable weighting agents that may fee used in the treatment fluids of the present disclosure include, but are not limited to, barite, hematite, ilmemte, manganese tetraoxide, calcium carbonate, lead sulfide (galena), and any combinations thereof In certain embodiments, the weighting agent may be present In the treatmen fluid in an amount from about 0.001 % to about 40% by volume of the treatment fluid. In other embodiments, the weighting agent may be present In the treatment fluid in an amount from about 5% to about 30% by volume of the treatment fluid, In other embodiments, the weighting agent may he present in the treatment fluid in an amount f om about 10% to about 25% by volume of the treatment fluid.

In one or more embodiments, the treatment fluids of the present disclosure may include one or more bridging agents. Examples of suitable bridging agents that may be used in the treatment fluids of the present disclosure include, but are not limited to, calcium carbonate, magnesium oxide, sodium chloride, and any combinations thereof in certain embodiments, the bridging agent may be present in the treatment fluid in an amount from about 0.001. !b/fibl to about 100 Ih/bb! of the treatment fluid. In other embodiments, the bridging agent may be present in the treatment fluid in an amount front about 5 Ib/bbl to about 80 Ib/bhl of the treatment fluids In other embodiments, the bridging agent may be present in the treatment fluid iu an amount from about HI I b/bbl to about 60 Ib/bbl of the treatment fluid.

In one or more embodiments, the treatment fluids of the present disclosure may include one or more emulsifiers. Examples of suitable emulsifiers that may bo used hr the treatment fluids of the present disclosure include, but are not lim ited to, a idoam ioes, alkyl sulfonates, oxi ize tall oh ethoxy!ated alcohols, fatt acid derivatives, sprbitan esters, and any combination thereof In certain embodiments, the emulsifier ay be present in the treatment fluid in an amount from about 1 ib/bbl t about 30 Ib/bbl of the treatment fluid. In other embodiments, the emulsifier may be present in the treatment fluid in an amount from about 3 Ib/bbl to about 25 Ib/bbl of the treatment fluid, in csther embodiments, the emulsifier may be present in the treatment fluid m an amount from about 5 Ib/bbl to about 20 ib/bbl of the treatment fluid,

in one or more embodiments, the treatment fluids of the present disclosure may include one or more weting agents. Examples of suitable wetting agents that may be used In the treatment fluids of the present disclosure Include, but are no lim ited to, soy lecithin, alky! benzene sulfonic acid salts, and any combination thereof. In certain embodiments, the wetting agent ma be present in the treatment fluid m an amount from about 0 Ib bbl to about 5 Ib/bbl of the treatment fluid. In other embodiments, the wetting agent may be present In the treatment fluid in an amount from 6 Ib/bbl to about 3 Ib/bbl of the treatment .fluid. In other embodiments, the wetting agent may be present in the treatment fluid in an amount from 0 ib/bbl to about 1 ,5 Ib/bbl of the treatment fluid.

In one or more embodiments, the associative polymers used in the methods and compositions of the present disclosure may be added to the non-aqueous fluid along with any other additives at a well site where the operation or treatment is conducted, either by batch mixing or continuous (“on-the-fly”) mixing. The term“on-the-fiy” is used herein to include methods of combining two or more components wherein a flowing stream of one element is continuously introduced into a flowing stream of another component so that the streams are combined and mi ed wh le continuing to Bow as a single stream as part of the on-going treatment. Socb mixing can also be described as“real-time’' mixing, In other embodiments. the treatment fluids of the present disclosure may be prepared, either in whole or in part, at an offsite location and transported to the site where the treatment or operation is conducted. In introducing a treatment fluid into a portion of a subterranean formation, the components of the treatment fluid may be mixed together at the surface and introduced into the formation together, or one or more components may be introduced into th formation at the surface separately from other components such that the components mix or Intermingle in a portion of the formation to form a treatment fluid. In either suc case, the treatment fluid Is deemed to be introduced into at least: a portion of the safoem ean formation for purposes of the presen t disclosure.

Some embodiments of the present disclosure provide methods for using the disclosed compositions and treatment fluids to cany out a variety of subterranean treatments, including but not limited to, drilling, lire drilling fluids disclosed hereto may directly or indirectly affect one or more components or pieces of equipment associated wit the preparation, delivery, recapture, recycling, reuse, and/or disposal of the drilling fluids, For example, an with reference to Figure 1, the drilling fluids disclosed herein may directly or indirectly affect one or more components or pieces of equipment associated with a wellbore drilling assembly 100, according to one or more embodiments. It should be noted that while Figure I generally depicts a land-based drilling assembly, those skilled in the art will readily recognize that the principles _: described herein are equally applicable: to subsea drilling operations that employ floating or sea-based platforms and rigs, without departing from the scope of the disclosure.

A illustrated, the drilling assembly 100 may Include a drilling platform 102 that supports a derrick 104 having a traveling block 106 for raising and lowering a drill string 108. The drill siring 108 may include, but Is not limited to, drill pipe and colled tubing, as generally known to those skilled in the art, A kelly 110 supports the drill string 108 as it i lowered through a rotary table 112, A drill bit 1 14 is attached to the distal end of the drill string IdSand Is driven either by a downhole motor and/or via rotation of the drill string 1 8 from the well surface, A the bit 1 14 rotates, it creates a borehole 3 16 that penetrates various subterranean formations 1 18.

A pump 120 (e.g., a mud pump) circulates a drilling fluid 122 prepared with the compositions disclosed herein through a feed pipe 124 and to the kelly 110, which conveys the drilling fluid 122 downhole through the interior of the drill string 108 and through one or more orifices In the drill bit 1 14, The drilling fluid 122 is then circulated back to the surface via an

1 ! annulus 126 defined between the drill string 108 and the walls of the borehole 1 16, At the surface, the recirculated or spent drilling fluid 122 exits the annulus 126 and may be conveyed to otic of more fluid processing unli(s) 128 via an interconnecting flow line 130. After passing through the fluid processing imit(s) 128, a“cleaned” drilling fluid 122 is deposite into a nearby retention pit 132 (Le,, a mud pit). While illustrated as being arranged at the outlet of the wellbore 1.16 via the annulus 126, those skilled in the art will readily appreciate that, the fluid· processing umi(s) 128 may be arranged at any other location in the drilling assembly 100 to facilitate its proper function, without departing from the cope of the disclosure.

The associative polymers used in the methods and compositions of the present disclosure may be added to the drilling fluid 12 via a mixing hopper .134 eommUnicably coupled to or otherwise in fluid communication with the retention p¾ 132, The mixing hopper 134 may include, hut Is not limited to, mixers an related mixin equipment known to those skilled in the art. other embodiments, however, the associative polymers used in the methods and compositions of the present disclosure may be added to the drilling fluid 122 at any other location in the drilling assembly 100. in at least one embodiment, for example, there could be more than one retention pit 132, such as multiple retention pits 132 in series. Moreover, the retention pit 132 may be representative of one or more fluid storage facilities and/or units where the associative polymers used io the methods and compositions of the present disclosure thereof may be stored, reconditioned, and/or regulated until added to tfs drilling fluid 122,

As mentioned above, the drilling fluid 122 prepared with a composition disclosed herein may directly or indirectly affect the components and equipment of th drilling assembly 100. For example, the disclosed drilling fluid 122 may directly or indirectly affect the fluid processing unit(s) 1 8 which may include, but Is not limited to, one or more of a shaker (e,g., shale shaker), a centrifuge, a hydroeyeloue, a separator (including magnetic a i electrical separators), a desilter, a desander, a filter (e.g„ dlatomaceous earth Alters), a hea exchanger, any fluid reclamation equipment. The fluid processing urilt(s) 1.28 may further include one or more sensors, gauges, pumps, compressors, and the like used to store, .monitor, regulate, and/or recondition the drilling fluid 1 2.

The drilling fluid 122 prepared as disclosed herein may directly or indirectly affect the pump 120, which representatively Includes any conduits, pipelines, trucks, tubulars, arid/or pipes used to fiuidieally convey the drilling fluid 122 downhole, any pumps, compressors, or motors (e,g., topside or downhole) used to drive the drilling fluid 122 into motion, any valves or related joints used to regulate the pressure or flow rate of the drilling fluid 122, and any sensors (ie.. pressure, temperature, flow rale, etc,), gauges, and/or combinations thereof, and the like. The disclosed drilling fluid 122 may also directly or indirectly affect the mixing hopper 134 and the retention pit ! 32 and their assorted variations.

The drilling fluid 122 prepared as disclosed herein may also directly or indirectly affect the various downhole equipment and tools that may come into contact with the drilling fluid 1,22 such as, but not limited to, the drill string 108, any floats, drill collars, mud motors, downhole motors and/or pumps associated with the drill string: 108, and any MWD/LWD tools and related telemetry equipment, sensors or distributed sensors associated with the drill string 108. The disclosed drilling fluid 122 may also directly or indirectly affect any downhole heat exchangers, valves and corresponding actuation devices, tool seals, packers and other wellbore isolation devices or components, and the like associated with the wellbore 116, The disclosed drilling fluid 122 may also directly or Indirectl affect the drill hit 114, which may include, but is not limited to, roller cone hits, PDC bits, natural diamond bits, any hole openers, reamers, coring bits, etc.

While not specifically illustrated herein, the drilling fluid 122 prepared: as disclosed herein may also directly or indirectly affect any transport or delivery equipment used to convey the drilling: fluid 122 to the drilltng assembly 100 such as, for example, any transport vessels, conduits, pipelines, trucks, tubulars, and/or pipes used to fhddicai!y move the drilling fluid 1.22 from one location to another, any pumps, compressors, or motors used to drive the drilling fluid 1 into motion, any valves or related joints used to regulate the pressure or flow rate of the drilling fluid 122, and any sensors (he. _» pressure and te erature}, gauges, and/or combinations thereof/ and the like.

An embodiment of the present disclosure Is a method Including: introducing a treatment fluid into a wellbore penetrating at least a portion of a subterranean formation, wherein the treatment fluid comprises a noiwaqueous fluid and one or more associative polymers,

In one or more embodiments described in the preceding paragraph, the associative polymer is present in the treatment fluid in an amount less than 10% by weight of the neai-aqueous fluid. In one or more embodiments described in the preceding paragraph, the one or more associative polymers each comprises a polymer backbone and one or more functional groups on at least two ends ofthe polymer backbone. In one or more embodiments described in the preceding paragraph, the polymer backbone comprises a polymer selected from the group consisting oil a substituted or uosubsihufed potydiene, poly(bntadlene}, poiy(jsoprene), a substituted or uosnbsiitu!ed polyolefin, an ethylene-butene copolymer, poiyisobuty!ene, paly(nofbornene), poiy(oetene), polystyrene, a poly(siioxane), a polyacrylate with one or more alky! side chains, a polyester, polyurethane, and any combination thereof, In one or more embodiments described in. the preceding: paragraph, the one or more functional groups are selected ten the group consisting oh a carboxylic add, a sulfonic acid, a phospho e add, an amine, an alcohol, nucleotide, a hydrogen atom, dlaceiamidopyridine, thymine, a Hamilton Receptor, cyanuric acid, and any combination thereof. In one or more embodiments described in the preceding paragraph _* allowing the one or more associative polymers to form one or more supramoleeular assemblies thereby increasing the viscosity of the treatment fluid. In one or more embodiments: described in the preceding paragraph, the one or om associative polymers each has a molecular weight from about 100,00:0 g/mol to about ! , 000,000 g/mol

L nether embodiment ofthe present disclosure is a method including; providing a drilling fluid comprising a non-aqaeons fluid and arte or more associative polymers; an drilling at least a portion of a wellbore in a subterranean formation using at least the drilling fluid.

In one or more embodiments described in the preceding paragraph, the associative polymer is present in the drilling fluid in an amount less than about 10% by weight of the non- aqueous fluid. In one or more embodiments described In the preceding paragraph, the one or more associative polymers each comprise a polymer backbone and one or more functional groups on at least two ends of the polymer backbone. In one or more embodiments described in the preceding paragraph, the polymer backbone comprises at least one polymer selected from the group consisting of: a substituted or ««substituted polydiene, polyfbntadiene), poly(isoprene), a substituted: or ««substituted polyolefin, an ethylene-butene copolymer, po!yisobulykme, pol Cnorbomene), poiy(octene), polystyrene, pol Csiloxanes), polyaery laics with alkyl side chains, polyesters, polyurethane, and any combination thereof. In one or more embodiments described in the preceding paragraph, the one or more functional groups are selected from the group consisting of: a carboxylic add, a sulfonic acid, a phosphonic add, an amine, an alcohol, a nucleotide, a hydrogen atom, diacetamldopyridine, thymine, a Hamilton Receptor, cyanuric acid, and any combination thereof in one or snore embo iments described in the preceding paragraph, allowing the one or more associative polymers to form one or more supramoleeular assemblies thereby increasing the viscosity of the drilling fluid: and breaking the one or more supramoleeular assemblies into one or more polymeric strands thereby reducing the viscosity of the treatment fluid, in one or more embodiments described in the preceding paragraph, the one or more associative polymers each has a molecular weight from about 100,000 g/mol to about 1,000,000 g/mol. Another embodiment of the present disclosure is a composition including: a non-aqueous fluid; a weighting agent; and one or more associative polymers that are capable of associating to form one or mo supramokenlar assemblies.

!.o one or more embodiments described in the preceding paragraph, the associative polymer is present in the composition In an amount less than 10% by weight of the non-aqucous fluid. In one or more embodiments described in the preceding paragraph, the one or more associative polymers each comprise a polymer backbone and one or more functional groups on si least two ends of the polymer backbone.. In one or more embodiments described in the precedin paragraph, the noiMigueous fluid comprises at least one fluid selecte from the group consisting of: an oik a hydrocarbon, a organic Ikpfid, and any combination thereof! In one or more embodiments described in the preceding paragraph, the non-aqueoos fluid Is an oil phase of an emulsion. In one or more embodiments described in the preceding paragraph, the composition further comprising one or more additives .selected from the group consisting of: a. bridging agent, an emulsifier, a wetting agent, and any combination thereof,

Therefore, the present disclosure is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein, The particular embodiments disclosed above are illustrative only, as the present disclosure may be modified and practice in different but equivalent manners apparent to those skilled In the art having the benefit of the teachings herein. While numerous changes may be made by those skilled In the art, such changes are encompassed within the spirit of the subject matter defined by the appended claims. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below, ft is therefore evident that the particular Illustrative embodiments disclosed above ma be altered or modified arid all such variations are considered within the scope and spirit of the present disclosure. In particular, every range of v lues (e.g. ,“from about a t about h,” or, equivalently,“from approximately a to b,” or, equivalently,“from approximately a b”) disclosed herein Is to be understood as referring to the power set (the set of all subsets) of the respective range of values. The terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly define by the patentee. Any definitions or disclaimers in the references Incorporated herein by reference should not be interpreted as limiting the present claims. If there is any conflict in the usage of a word, term, or phrase in the present specification and the references incorporated herein by reference, then the usage in present specification controls.