Abstract: Disclosed is a carbon-dioxide-responsive self-thickening intelligent fluid based on supramolecular self-assembly, which comprises a Gemini surfactant, a single-chain amide molecule having a tertiary amine head group and water, wherein the Gemini surfactant and the single-chain amide molecule are self-assembled to form a vesicle structure dispersed in water, with a hydrophilic head group being located outside and a hydrophobic tail group located inside. The method for preparing the carbon-dioxide-responsive self-thickening intelligent fluid of the present invention is simple, the injection viscosity is low, and the fluid is converted into a gel when encountering carbon dioxide, so that the viscosity is greatly increased.

Abstract: Some examples of an emulsion system for treating deep water blockage can be prepared by emulsifying a first aqueous phase in a first organic phase to prepare a first emulsion. A second aqueous phase can be emulsified in a second organic phase to prepare a second emulsion. The first emulsion and the second emulsion can be flowed into a subterranean formation. The first aqueous phase and the second aqueous phase, when mixed, can react to release nitrogen and heat.

Abstract: A method for the fracking or stimulation of a hydrocarbon-bearing formation, said method comprising the steps of: providing a wellbore in need of stimulation; inserting a plug in the wellbore at a predetermined location; inserting a perforating tool and a spearhead or breakdown acid into the wellbore; positioning the tool at said predetermined location; perforating the wellbore with the tool thereby creating a perforated area; allowing the spearhead acid to come into contact with the perforated area for a predetermined period of time sufficient to prepare the formation for fracking or stimulation; removing the tool form the wellbore; and initiating the fracking of the perforated area using a fracking fluid. Also disclosed is a corrosion inhibiting composition for us with the acid composition.

Abstract: A low transition temperature mixture (LTTM) or deep eutectic solvent (DES) useful as a lubricating oil base stock and lubricating oil including a eutectic mixture of at least a first component and at least a second component. The at least first component comprises a hydrogen bond acceptor and the at least second component comprises a hydrogen bond donor. The eutectic mixture includes an equilibrium phase between the at least first component and the at least second component. The equilibrium phase does not exhibit physical characteristics of the at least first component in an unmixed state and the at least second component in an unmixed state. The at least first component and the at least second component form an intermolecular interaction between each other sufficient to prevent crystallization of the at least first component and the at least second component in the eutectic mixture. The eutectic mixture is a liquid at 20° C.

Abstract: The present disclosure discloses an experimental apparatus and method for simulating transport of a sand-carrying fluid in a fracturing fracture. The apparatus may include a spiral proppant transport device, a stirred tank, a screw pump, a liquid transport pump, a pressure gauge, a proppant transport and distribution system, a cyclone desander, a waste liquid recycle container, a proppant recycle container, and a fracturing fluid tank. The spiral proppant transport device may be communicated with the stirred tank. The waste liquid recycle container and the fracturing fluid tank may be communicated with the stirred tank via the liquid transport pump. A bottom end of the stirred tank may be communicated with the proppant transport and distribution system through the screw pump. It is possible to simulate the sand-carrying fluid paved under a closure pressure by setting a computer to precisely control a transparent cuboid fracture member including hydraulic tanks.

Abstract: A corrosion inhibiting composition which is a liquid carrier in which is dissolved or dispersed a corrosion inhibitor compound comprising at least one moiety (A) which is an aliphatic, aromatic or mixed aliphatic/aromatic structure containing one or more hetero atoms which are nitrogen, oxygen, phosphorus or sulphur, and also at least one moiety (B) which contains one or more polymerisable groups containing double or triple bonded carbon, with the moieties (A) and (B) directly or indirectly covalently connected together.

Abstract: The present disclosure relates to compositions and methods for the removal of deposits from oilfield apparatus and wellbore surfaces. In particular, removal of deposits comprising heavy hydrocarbon materials and finely divided inorganic solids. The composition includes a mixture of a corrosion inhibitor component which is morpholine or a morpholine derivative having corrosion inhibitor properties, and a surfactant which is a quaternary ammonium compound having biocidal properties. Methods of removing a deposit from a surface or unplugging an oilwell which has been plugged with a deposit, are also included wherein the method comprising contacting the deposit with a composition as disclosed herein for a selected period of time.

Abstract: Methods for making emulsifiers, emulsified drilling fluids, and methods for using the same are provided. In one or more embodiments, the method for making an emulsifier can include mixing a tall oil and a triamide. The triamide can have the chemical formula: where: x, y, and z are integers independently selected from 1 to 10, R1 is a C8-C20 alkyl, a C8-C20 alkenyl, a C8-C20 dialkenyl, or a C8-C20 alkynyl, R2 is H or ?independently selected for each [(CH2)xNR2(CH2)y] unit, where R4 is a C1-C3 alkylene or a C1-C3 alkylene alcohol, and where at least one R2 is ?and R3 is a C8-C20 alkyl, a C8-C20 alkenyl, a C8-C20 dialkenyl, or a C8-C20 alkynyl.

Abstract: A particle with an environmentally friendly resin coating having very low levels of leachable compounds is disclosed. The water leachable phenolic content of the coated particle is low enough to eliminate problems with leaching of phenol or its derivatives into an aquifer during downhole applications. Processes for fully and partially coating the particle with the resin coating are also disclosed.

Abstract: A method of treating a subterranean formation penetrated by a well comprises combining an aqueous base fluid, a viscoelastic surfactant gelling agent, two or more types of the following nanoparticles: an alkaline earth metal oxide; an alkaline earth metal hydroxide; a transition metal oxide; or a transition metal hydroxide to form a treatment fluid, and pumping the treatment fluid into the well, wherein the weight ratio of the two or more types of the nanoparticles is selected such that the treatment fluid has an improved fluid efficiency as compared to an otherwise identical reference fluid except for comprising only one type of the nanoparticles selected from an alkaline earth metal oxide; an alkaline earth metal hydroxide; a transition metal oxide; and a transition metal hydroxide.

Abstract: Embodiments of the present disclosure include modified nonionic surfactant formulations having a nonionic surfactant and a pour point depressant, where the modified nonionic surfactant formulations have a pour point of ?3° C. to ?54° C. In one or more embodiments, the modified nonionic surfactant formulations can be introduced into a flow of carbon dioxide, where the flow of carbon dioxide and the modified nonionic surfactant formulation are injected into an oil containing reservoir. In one or more embodiments, an emulsion of the carbon dioxide and the nonionic surfactant form in the oil containing reservoir, where the use of the pour point depressant provides minimal interference in forming the emulsion.

Abstract: Disclosed and claimed is a microemulsion-based demulsifier composition and a method of demulsifying an emulsion comprising hydrocarbon and water. The demulsifier composition includes (i) an oil-like phase comprising at least one nonionic surfactant having a hydrophilic-lipophilic balance (HLB) of less than about 9; (ii) a coupling agent capable of stabilizing the demulsifier composition; (iii) at least one water-soluble or dispersible nonionic surfactant that is different from the at least one nonionic surfactant in the oil-like phase; (iv) at least one additional surfactant selected from anionic, cationic, amphoteric, and combinations thereof; (v) at least one nonionic demulsifier; and (vi) water.

Abstract: The present invention concerns the use of a C16-C22-alkyl or C16-C22-alkenyl amido alkyl betaine derivatives as a fabric softener, notably for fabric softening compositions. The invention also concerns a method of treating fabric which comprises the step of contacting said fabric in the rinse cycle of a fabric washing machine with an aqueous medium containing a composition as defined herein.

Abstract: Pitting corrosion of stainless steel occurs in solutions of organic acid, such as tartaric acid, in an electrolyte solution with methanol. However, methanolic solutions containing at least one organic halide and at least one organic hydroxyacid and some water provide reduced pitting corrosion of stainless steel. The organic hydroxyacid may be a hydroxy acid containing 2 to 10 carbon atoms with at least one hydroxyl group and at least one carboxylic acid group, in a non-limiting example, glycolic acid. The pH of the methanolic solution may range from about 3.5 to about 8.

Abstract: Controlling fluid flow in a subterranean formation containing water and hydrocarbons utilizing a Gemini surfactant introduced to the formation via a wellbore. The Gemini surfactant includes a head group having two cationic groups linked by an alkyl spacer, an amide extending from each of the cationic groups, and each amide having a hydrophobic tail extending therefrom.

Abstract: This invention relates generally to novel foamer compositions for treatment of oil and gas wells to enhance production. The invention provides a method of foaming a fluid. The method includes introducing into the fluid a foam-forming amount of a composition comprising at least one long chain fatty acid and at least one organic solvent. An example of the long chain fatty acid is tall oil fatty acid and an example of the organic solvent is ethyleneglycol monobutyl ether.

Abstract: Improved methods and additives for eliminating or reducing concentrations of hydrogen sulfide or soluble sulfide ions for use in subterranean formations and fluids are provided. In one embodiment, the methods comprise: providing a treatment fluid comprising an oil-based liquid and a sulfide scavenging additive comprising one or more polyaliphatic amines and a catalyst comprising one or more quaternary ammonium salts; introducing the treatment fluid into at least a portion of a subterranean formation; and allowing the sulfide scavenging additive to interact with hydrogen sulfide or sulfide ions present in the treatment fluid.

Abstract: Stabilizing smectite shale may include treating a smectite shale in a subsurface formation with a dewatering fluid so as to yield a stabilized smectite shale, the dewatering fluid comprising an aqueous base fluid and a dewatering additive. In some instances, at least a portion of a highwall in a highwall mine may be formed at a highwall mine site comprising stabilized smectite shale.

Abstract: A composition comprising the following formula and optionally salts thereof is disclosed and claimed.

Abstract: The acid emulsion for acid treatment of oil reservoirs is an emulsion for the acid treatment of the rock reservoir around oil well bores. The acid emulsion includes an oil, such as kerosene, and an emulsifier added to the volume of oil to form an oil-emulsifier mixture. The emulsifier forms about 0.1 wt % of the oil-emulsifier mixture, and is preferably an organically modified montmorillonite clay. Brine is added to the oil-emulsifier mixture to form the acid emulsion. Preferably, the brine has a salt concentration of about 20 kppm, and is added such that the volume ratio of the brine to the oil is about 70 to 30.

Abstract: The invention provides an oilfield suspending friction reducer treatment composition fluid comprising from about 0.001 weight percent to about 0.5 weight percent of a drag reducing surfactant; at least one drag reducing enhancer selected from the group consisting of polymeric drag reduction enhancers, monomeric drag reduction enhancers, and mixtures thereof.

Abstract: Methods for treating a subterranean formation penetrated by a wellbore where shear recovery time of viscoelastic surfactant treatment fluids is shorten by adding an effective amount of an fiber based rheology enhancer. The rheology enhancer also increases fluid viscosity. Further, the rheology enhancer also improves proppant settling. Some examples of surfactants are betaines and quaternary amines, and an example of fiber based rheology enhancer is polylactic acid fiber. The fluids are useful in oilfield treatments, as well as methods of preparing viscoelastic surfactant based fluids.

Abstract: The present disclosure provides a surfactant formulation for use in treating and recovering fossil fluid from a subterranean formation. The surfactant formulation includes a primary surfactant, a formulation stability agent and injection water.

Abstract: Agents, chemicals and particles may be controllably released at remote locations, such as pre-selected or predetermined portions of subterranean formations, by binding or associating or trapping them with an association of micelles formed by a viscoelastic surfactant (VES) in an aqueous base fluid to increase the viscosity of the fluid. An internal breaker within the association of micelles disturbs the association of micelles at some later, predictable or predetermined time thereby reducing the viscosity of the aqueous viscoelastic treating fluid and releasing the agent, chemical or particle at a predetermined or selected location.

Abstract: Methods of drilling wellbores, placing proppant packs in subterranean formations, and placing gravel packs in wellbores may involve fluids, optionally foamed fluids, comprising nanoparticle suspension aids. Methods may be advantageously employed in deviated wellbores. Some methods may involve introducing a treatment fluid into an injection wellbore penetrating a subterranean formation, the treatment fluid comprising a base fluid, a foaming agent, a gas, and a nanoparticle suspension aid; and producing hydrocarbons from the subterranean formation via a production wellbore proximal to the injection wellbore.

Abstract: Synergistic surfactant blends are disclosed. In one aspect, the blend comprises an anionic surfactant and a metathesis-based cationic surfactant comprising a quaternized derivative. The quaternized derivative is a quaternized fatty amine, quaternized fatty amidoamine, imidazoline quat, or esteramine quat made from a metathesis-derived C10-C17 monounsaturated acid or its ester derivative. Also disclosed are synergistic surfactant blends comprising a cationic surfactant and a metathesisbased anionic surfactant comprising a sulfonated derivative. The sulfonated derivative is a fatty ester sulfonate, fatty acid sulfonate, sulfoestolide, fatty amide sulfonate, sulfonated fatty ester alkoxylate, imidazoline quat sulfonate, sulfonated amidoamine oxide, or sulfonated amidoamine betaine. The synergistic blends have a negative value or a reduced interfacial tension (IFT) when compared with an expected IFT value calculated from the individual surfactant components.

Abstract: Methods and compositions of treating formations using viscoelastic treatment fluids are provided that reduce the amount of fluid loss to the formations due to the lack of polymer backbone in the viscoelastic treatment fluids. The methods and compositions of treating formations include a fluid loss additive that includes a copolymer that includes a hydrophilic monomeric unit and a first anchoring monomeric unit.

Abstract: The present invention provides aqueous viscoelastic compositions comprising a cleavable surfactant and possibly also an electrolyte. The cleavable surfactants useful in the present invention comprise at least one weak chemical bond, which is capable of being broken under appropriate conditions, to produce oil soluble and water soluble products typically having no interfacial properties and surface activity compared with the original surfactant molecule. Further, the rheological properties of the aqueous viscoelastic composition are usually altered upon cleavage of the cleavable surfactant generally resulting in the elimination of the viscosifying, viscoelastic and surfactant properties of the composition. Aqueous viscoelastic compositions in accordance with the present invention are suitable for use in oil-field applications, particularly for hydraulic fracturing of subterranean formations.

Abstract: A composition for enhancing fluid viscosity including a mixture of at least one cationic or cationizable polymer and at least one anionic or anionizable (hydrolysable) polymer. The composition has a zeta potential at 25° C. in the range of 0.5 to 100 mV or ?0.5 to ?100 mV, typically 1 to 60 mV or ?1 to ?60 mV, or is a precursor convertible at a temperature of 100 to 250° C. to the composition having a zeta potential at 25° C. of 0.5 to 100 mV or ?0.5 to ?100 mV, typically 1 to 60 mV or ?1 to ?60 mV. Typically the compositions exhibit salt tolerance and interaction of both polymers at very high temperatures (>300° F.) such that the system exhibits an increase of viscosity at extreme temperatures. The compositions are useful for hydraulic fracturing, enhanced oil recovery, subterranean acidization, personal care as well as home and industrial cleaners.

Abstract: The present invention discloses liquid quaternary ammonium salts that can be used to treat and coat the surfaces of the proppant sand or inorganic particles that are used in down-hole oil well fracturing operations as well as the containment structure and that these treated surfaces will cause water and oils to flow faster through the porous structure. These liquid quaternary ammonium salts can be chosen from a list that includes but is not limited to cocobis(2-hydroxyethyl)ethylammonium ethyl sulfate, benzylcocobis(hydroxyethyl)ammonium 2-ethyl-hexylsulfate, dibenzylcocobishydroxyethyl ammonium phenolsulfonate, didecyldimethyl-ammonium dodecylbenzenesulfonate and tallow-bis(2-hydroxyethyl)ethylammonium ethyl sulfate.

Abstract: A wellbore fluid that includes an aqueous based fluid; an amphoteric, viscoelastic surfactant; and a modified starch is disclosed. Methods of drilling subterranean wells, methods of reducing the loss of fluid out of subterranean wells, and methods of completing wellbores using aqueous-based fluids having an ampoteric, viscoelastic surfactant and a modified starch are also disclosed.

Abstract: Fluids viscosified with viscoelastic surfactants (VESs) may have their fluid loss properties improved with the presence of at least one mineral oil slurried together in combination with at least one particulate fluid loss control agent that may be an alkaline earth metal oxides, alkaline earth metal hydroxides, transition metal oxides, transition metal hydroxides, and mixtures thereof. The mineral oil having the particulate fluid loss control agents slurried within it may initially be dispersed oil droplets in an internal, discontinuous phase of the fluid. In one non-limiting embodiment, the slurry is added to the fluid after it has been substantially gelled. The mineral oil/particulate slurry may enhance the ability of a particulate fluid loss control agent to reduce fluid loss. The presence of the mineral oil may also eventually reduce the viscosity of the VES-gelled aqueous fluid.

Abstract: An oil recovery method by the modification of the rock wettability from hydrophilic to oleophilic using hydrophobic compounds. Specifically, the method relates to the application of oil-type emulsions in water based on hydrophobic compounds free of silicon and fluorine to increase the oil recovery in mature sandstone-type reservoirs after the injection of water.

Abstract: A composition in the form of an emulsion is provided, the composition including: (i) a continuous oil phase; (ii) an internal aqueous acid phase adjacent the continuous oil phase; and (iii) a source of ammonium ion, wherein the ammonium ion has: (a) at least one ammonium ion; (b) an organic group with at least 40 carbon atoms; (c) at least 40 carbon atoms per ammonium ion; (d) a carbon to nitrogen ratio of at least 20 carbon atoms per nitrogen atom; and (e) at least one alkyl branch on the organic group. In addition, a method of acidizing a subterranean formation is provided, the method including the steps of: (A) forming a treatment fluid comprising a composition according to the invention; and (B) introducing the treatment fluid into the well.

Abstract: Acidizing operations in subterranean formations that contain both a siliceous material and a source of calcium ions can often be problematic due to the generation of calcium-containing precipitates, particularly calcium fluoride. Methods for treating a subterranean formation can comprise: providing a treatment fluid having a pH ranging between about 1 and about 4.5 and comprising a chelating agent, hydrofluoric acid or a hydrofluoric acid-generating compound, and a compound having two or more quaternized amine groups; introducing the treatment fluid into a subterranean formation containing a siliceous material and a source of calcium ions; dissolving at least a portion of the siliceous material in the subterranean formation with the hydrofluoric acid or the hydrofluoric acid-generating compound; and complexing at least a portion of the calcium ions in the subterranean formation with the chelating agent.

Abstract: Compositions of and methods of using a fluid formulation for increasing flow, production, and/or recovery of oil and gas hydrocarbons from a subterranean formation.

Abstract: Reduction of the water permeability within a subterranean formation, particularly within a proppant pack or a gravel pack, can be achieved through the use of a relative permeability modifier (RPM) coated on a particulate material. Methods for reducing the water permeability include providing RPM-coated particulates that contain a RPM coating on the particulates, and placing a treatment fluid containing a base fluid and the RPM-coated particulates in at least a portion of a subterranean formation. The treatment fluid can also contain a companion polymer that serves to further reduce the water permeability compared to that achievable when using the RPM alone.

Abstract: Nanoemulsions, miniemulsions, microemulsion systems with excess oil or water or both (Winsor III) or single phase microemulsions (Winsor IV) may be formed in situ during hydrocarbon recovery operations after drilling with OBM or SBM using one or more fluid pills. The nanoemulsions, miniemulsions, microemulsion systems with excess oil or water or both or single phase microemulsions remove oil and solids from the well and wellbore surfaces. In one non-limiting embodiment, a single phase microemulsion (SPME) or other in situ-formed fluid may be created from a polar phase, a nonpolar phase, at least one viscosifier, and at least one surfactant.

Abstract: Methods of stimulating a well comprising providing a stimulation fluid comprising at least one surfactant and submicron particles, the submicron particles having a particle size between about 200 nm and about 800 nm and a specific surface area greater than about 5 square meters per gram; and introducing the stimulation fluid into a wellbore. Additional methods to enhance oil recovery from subterranean reservoirs accessible via a well are described.

Abstract: Proppants for use in fractured or gravel packed/frac packed oil and gas wells are provided with a contaminant removal component to remove one or more of the contaminants found in subterranean water/hydrocarbon from a production well. The water/hydrocarbon cleaning proppant solids may be used as discrete particles in a proppant formulation, as a coating on proppant solids in pores of a porous proppant solid or as part of the proppant's internal structure. The contaminant removal component removes contaminants, especially dissolved contaminants, in the subterranean water or hydrocarbon before the water/hydrocarbon leaves the well. For those contaminant removal components that can be regenerated, such as ion exchange resins, a measured quantity of an acidic regeneration solution can be injected into the fractured stratum for regeneration and recovered when the well resumes production.

Abstract: Disclosed are compositions derived of mixtures of choline ion salts (typically choline chloride) in aqueous solution with suspended particulates of sparingly soluble borate minerals or with alkali or alkaline earth borate salts, boric acid and its ester derivatives and salts, or other aqueous soluble borate forms. These compositions are useful as cross-linkers for polysaccharides and other biopolymers and particularly as used in subterranean treatment fluids for completion and stimulation of oil and gas wells. Advantages of the compositions are the combination into a single package of the properties of clay stabilizing actives (choline ion) and crosslinking actives (borates, etc.), in relatively high concentrations, and these compositions are easy to handle, being stable and pumpable at low temperatures, and with attractive environmental profiles. Also disclosed are the analogous choline solutions mixed with metallic cross-linking ions know in the art such as Zr+, Ti4+, Al3+, & Fe3+.

Abstract: Systems and methods for controlling microbial growth and/or activity in a gas field fluid or oil field fluid are provided, comprising: a) adding a first biocide component to the gas field fluid or oil field fluid in an amount effective to control microbial growth and/or activity; and b) after a delay, adding a second biocide component to the gas field fluid or oil field fluid.

Abstract: Novel slick water fracturing fluid compositions are disclosed, where the compositions including with slick water fracturing compositions including a partially hydrolyzed polyacrylamide polymer system within invert emulsion and an effective amount of a friction reducer booster system, where the effective amount is sufficient to reduce a drag friction of the composition by an additional amount of at least 5% in the first 30 seconds of evaluation in high salinity and low temperature environments.

Abstract: The present disclosure provides chemical compositions useful for minimizing or preventing the precipitation of sludge, such as asphaltenes, maltenes, or similar asphaltic components, during an acidizing treatment. Methods for preventing or minimizing sludge formation are also disclosed. The anti-sludge compositions can be added to an aqueous acidic solution before injecting the solution into a well for treatment. The compositions can include a formulated dodecylbenzene sulfonic acid, a cationic surfactant, a corrosion inhibitor, and an iron reducing agent, in addition to other additives.

Abstract: New classes of temporary and/or permanent clay stabilization compositions including at least one quaternary salt of polyamines or a reaction product of at least one polyamine having an NH moiety with an aldehyde, and to methods for making and using same, where the quaternary salts of polyamines have reduced toxicity.

Abstract: A treatment fluid and method treating a zone of a subterranean formation penetrated by a wellbore. The treatment fluid includes: (i) water; (ii) a strong acid; (iii) a cationic viscoelastic surfactant; (iv) an anionic organic component having at least 4 carbon atoms; and (v) a non-cationic corrosion inhibitor; wherein the pH of the treatment fluid is less than 0.5. Preferably, the viscosity of the treatment fluid is less than 5 cP at 40 sec-1. The method includes the steps of: (A) forming the treatment fluid; (B) introducing the treatment fluid through the wellbore into the zone; and (C) allowing time for the strong acid in the treatment fluid to spend in the formation. Preferably, as the acid spends in the subterranean formation, the viscosity of the treatment fluid increases in the well to above 5 cP. Such a treatment fluid shows good rheological properties at temperatures above 93° C. (200° F.).

Abstract: A treatment fluid for use in a subterranean formation penetrated by the wellbore of a well includes: (i) water; (ii) a strong acid; and (iii) a branched viscoelastic surfactant having a hydrophobic portion with a total of 16 to 20 carbons; wherein the pH of the treatment fluid is less than 0.5; and wherein the viscosity of the treatment fluid is less than 5 cP at 40 sec-1. A method of treating a zone of a subterranean formation penetrated by a wellbore includes the steps of forming the treatment; (B) introducing the treatment fluid through the wellbore into the zone; and (C) allowing time for the strong acid in the treatment fluid to spend in the formation. Such a treatment fluid shows good rheological properties at temperatures above 93° C. (200° F.).

Abstract: A method for improving the performance of fracturing processes in oil production fields may rely on polymer coated particles carried in the fracturing fluid. The particles may include heavy substrates, such as sand, ceramic sand, or the like coated with polymers selected to absorb water, increasing the area and volume to travel more readily with the flow of fluid without settling out, or allowing the substrate to settle out. Ultimately, the substrate may become lodged in the fissures formed by the pressure or hydraulic fracturing, resulting in propping open of the fissures for improved productivity.

Abstract: A method of converting an inactive biocide into an active biocide comprises: contacting the inactive biocide with an activating agent, wherein the activating agent is capable of chemically reacting with the inactive biocide; and causing or allowing a chemical reaction to take place between the inactive biocide and the activating agent, wherein the chemical reaction produces the active biocide. The methods can also include deactivating the active biocide via a chemical reaction between the active biocide and a deactivating agent.

Abstract: Breaker nanoparticles may be added to gelled aqueous fluids where the gelled aqueous fluid may include an aqueous base fluid, e.g. a drilling fluid, gelled with at least one viscoelastic surfactant (VES) in an amount to increase the viscosity of the aqueous base fluid. The addition of the breaker nanoparticles may reduce the viscosity, or break the gel, of the gelled aqueous fluid by the direct or indirect action of the breaker nanoparticles. The breaker nanoparticles may be or include, but are not limited to inorganic semiconductor particles, organic semiconductor particles, and combinations thereof.