Abstract: A method of inhibiting carbon dioxide (CO2) hydrate formation in a CO2 pipeline is described. The method includes injecting a composition including monoethylene glycol carbon quantum dots (MEG CQDs) into the CO2 pipeline to deposit the MEG CQDs on an inside surface of the CO2 pipeline. The method further includes pressurizing the CO2 pipeline with a gas stream containing CO2 and water vapor at a pressure of 200-2,000 pounds per square inch (psi). The MEG CQDs are present on the inside surface of the CO2 pipeline in an amount effective to reduce the formation of CO2 hydrates in the CO2 pipeline during the pressurizing in comparison to the formation of the CO2 hydrates in the CO2 pipeline under the same conditions but in the absence of the MEG CQDs.

Abstract: A method of drilling is disclosed that includes introducing a water-based drilling fluid into a drill string disposed within a wellbore, circulating the water-based drilling fluid through the drill string and the wellbore, and extending the wellbore using the drill string while circulating the water-based drilling fluid, wherein the water-based drilling fluid includes water and a lubricating additive including a de-oiled cake, wherein the de-oiled cake are residues obtained after extraction of oil from a plant source, wherein the de-oiled cake is in particulate form having a particle size of 100 microns or less. A composition is disclosed that includes water-based drilling fluid including water and a lubricant additive comprising a de-oiled cake, wherein the de-oiled cake are residues obtained after extraction of oil from a plant source and wherein the de-oiled cake has a particle size of 100 microns or less.

Abstract: A method of producing a nanosilica-containing cement formulation, the method comprising the steps of mixing an amount of a determinant nanosilica particle and a functional coating; applying a dynamic initiator to trigger a reversible reaction of the functional coating to produce a reversible cage, where the reversible cage surrounds the determinant nanosilica particle to produce an encapsulated nanosilica; and mixing the encapsulated nanosilica and a cement formulation to produce the nanosilica-containing cement formulation.

Abstract: Methods for reducing scale deposition are provided. An exemplary method for reducing scale in an oilfield facility includes contacting a metallic surface with a production fluid including a film-forming surfactant selected from imidazolines, imidazolidines, amidoamines, isoxazolidines, fatty amines, ?,?-unsaturated aldehydes, salts thereof, and combinations thereof, the production fluid including the film-forming surfactant in a concentration of at least about 200 ppm.

Abstract: A drilling fluid formulation is provided, which includes an aqueous base fluid, a synthetic modified phyllosilicate as an anti-sagging additive, an inorganic base, and a weighting agent (e.g. barite). The synthetic modified phyllosilicate contains a clay material (e.g. smectite) and a metal selected from ruthenium, rhodium, palladium, osmium, iridium, and platinum. The synthetic modified phyllosilicate is effective in preventing barite sagging as demonstrated by low sag factor when drilling at elevated temperatures. Rheology properties of the drilling fluid including gel strength, yield point, plastic viscosity, and storage modulus are also specified.

Abstract: A process for consolidating sand, proppant and other suspended particles present in a subterranean reservoir using an aqueous emulsion particle consolidation system is described. Surfactants with cloud points at or below the reservoir temperature are used to make a low viscosity aqueous external emulsion system with resin and curing agent as the internal phase. As the surfactant reaches its cloud point, it loses its emulsification ability and releases the resin and curing agent to consolidate the sand. The aqueous phase of the system then functions as a spacer to maintain the permeability needed for oil and gas production without additional post flush required.

Abstract: The invention relates to an inverse polymer emulsion having the particular feature of auto-inverting without any need for the use of an inverting agent and containing a polymer of at least one water-soluble monomer and at least one LCST macromonomer. The invention also relates to the use of the inverse emulsion in the fields of the oil and gas industry, water treatment, slurry treatment, paper manufacturing, construction, mining, cosmetics, textiles, detergents or agriculture.

Abstract: A method of incorporating a peroxide source that produces reactive oxygen species and optionally also incorporating steam with the peroxide source (or other source of heat), into soil as a method of soil remediation, i.e., to destroy or remove chemical contaminants that pose a threat to plant or animal life. The invention also relates to the use of the peroxide source along with optional steam (or other heat source) or hot vaporized peroxide solution to treat soils, in particular those intended for agriculture, as a pesticide for controlling nematodes, pathogenic fungi, insect pests and bacteria. The peroxide source may be applied to the soil using soil cultivation equipment to increase contact between the peroxide source and the soil to be treated. The peroxide source and/or steam or other source of heat or hot vaporized peroxide solution can also be applied with injection wells or infiltration galleries, for instance, for the pesticide use and soil remediation.

Abstract: A wellbore fluid may include an oleaginous continuous phase; a non-oleaginous discontinuous phase; an emulsifier stabilizing the non-oleaginous phase within the oleaginous phase; a low density material selected and in an amount to result in a specific gravity of the wellbore fluid that is less than 0.83; and at least one rheology modifier selected to suspend the low density material within the wellbore fluid.

Abstract: The invention relates to a method for modifying the water permeability of a subterranean formation, comprising at least the following steps: Preparing an injection fluid from a dispersion of a hydrophilic phase in a lipophilic phase, with water or brine, the dispersion comprising: a hydrophilic phase comprising at least one cross-linked (co)polymer PR, a lipophilic phase, at least one interface polymer composed of at least one monomer of formula (I): Injecting the injection fluid into the subterranean formation, said cross-linked (co)polymer PR forming a hydrogel in the presence of water.

Abstract: Methods of wellbore cementing are provided. A method of designing a cement composition may include: selecting a target heat of hydration for a target time and temperature; selecting one or more cementitious components and a weight percent for each of the one or more cementitious components such that a sum of a heat of hydration of the one or more cementitious components is less than or equal to the target heat of hydration; preparing the cement composition; and allowing the cement composition to set.

Abstract: A foam for hydrocarbon recovery includes a gas phase and a liquid phase. The liquid phase includes a foaming mixture, and the foaming mixture includes an aqueous solution, one or more surfactants, and an oil mixture. At least 2 wt. % of the liquid phase includes the oil mixture. Also described are methods of recovering hydrocarbons from a deposit reservoir using such a foam, as well as a hydrocarbon well including such a foam.

Abstract: A system for use with a subterranean well can include a deployment apparatus configured to deploy one or more plugging devices into a fluid flow. The plugging devices are conveyed into the well by the fluid flow. The deployment apparatus can include multiple queues, different numbers of the plugging devices being contained in respective different ones of the queues. A method of deploying plugging devices can include connecting multiple queues of the plugging devices to a conduit, and deploying the plugging devices from a selected combination of the queues into the conduit. In another system, each of the plugging devices may include a body, and lines or fibers extending outwardly from the body.

Abstract: This disclosure describes the composition and methods of use for a novel delayed polymer gelation system. This polymer gelation system includes a polymer of acrylamide, AMPS and 100-2,000 ppm polyethylene glycol diacrylate in inverse emulsion form, and a polyethyleneimine (PEI) with Mw of 5,000-100,000 Dalton as the crosslinking agent.

Abstract: A method of removing a sulfide-containing scale from a wellbore, pipe, or other metal-containing surface associated with an oil or gas well is provided. The method includes contacting the sulfide-containing scale with a de-scaler solution including an aqueous solvent, an acid and a hydrogen sulfide scavenger. The hydrogen sulfide scavenger includes particles of a manganese oxide supported on a porous support. The particles are suspended in the aqueous solvent. The method includes reacting the acid with the sulfide-containing scale to produce hydrogen sulfide. The method further includes reacting the hydrogen sulfide in the wellbore with the manganese oxide to form a manganese sulfide.

Abstract: Reducing fines from an agricultural spray dispensed from a nozzle is provided in the disclosed methods. The agricultural spray comprises water, an agricultural composition such as a pesticide, at least one oil emulsion drift reduction adjuvant, and at least one spontaneous emulsion drift reduction adjuvant. The agricultural spray exhibits fewer fine droplets having a diameter less than about 105 ?m, about 150 ?m, and/or about 210 ?m compared to an agricultural spray neither or only one of the oil emulsion drift reduction adjuvant and the spontaneous emulsion drift reduction adjuvant.

Abstract: Solvent mixtures for downhole elemental sulfur removal and formation stimulation, and methods for utilizing such solvent mixtures, are described herein. One method includes providing a solvent mixture that includes an elemental sulfur solvent fraction and an odorant fraction that includes a lactate ester solvent. The method also includes injecting the solvent mixture into a hydrocarbon well such that the elemental sulfur solvent fraction of the solvent mixture dissolves elemental sulfur deposited on well components, and contacting the solvent mixture with water such that the lactate ester solvent within the odorant fraction reacts with the water to generate lactic acid. The method further includes stimulating a formation through which the hydrocarbon well extends by flowing the solvent mixture including the lactic acid through the hydrocarbon well and into the formation.

Abstract: A method for generating microfractures in low carbonate mineral content shale reservoirs in which sulfate acid or persulfate compound (such as ammonium persulfate ((NH4)2S2O8)) injected into conventional fracturing fluid can react with shale carbonate components resulting in the precipitation reaction of gypsum crystal (CaSO4·2H2O) to occur.

Abstract: A method of stabilizing sandy soils is provided wherein 0.5 to 5 L·m?2 of an aqueous solution S having less than 2000 ppm of at least one water-soluble polymer is applied to the surface of a sandy soil in order to combat the phenomenon of wind erosion. The polymer may include ethylenically unsaturated monomers having at least one hydroxyalkylated monomer of formula (I) H2C?CR1R2 in which R1 is a hydrogen atom or a methyl group and R2 being a hydrocarbon group containing at least one pendant group OH and optionally at least one N or O heteroatom in the hydrocarbon chain. This method is particularly applicable for the stabilization of mobile dunes and the suppression of sand migration that can impact infrastructure, inhabited areas and agricultural areas in arid, semi-arid and dry sub-humid areas.

Abstract: A fluid control system includes a fluid control device configured to be connected to at least one of two casing elements in a well, for controlling a fluid flow between a bore of the fluid control device and a zone located outside the casing elements; and a tracer material located within an inner chamber of a body of the fluid control device, the tracer material being uniquely associated with the fluid control device. The fluid control device is configured to release, when activated, the tracer material out of the inner chamber.