Halliburton Energy Services, Inc.

Chetan Prakash

Sairam Eluru

Ravikant S Belakshe

Lalit Pandurang Salgaonkar

Pratiksha Shivaji Meher

Anant Kanhoba Ghumare

Shreya Mohan

Sandeep Kumar Borra

Enrique Antonio Reyes

Mallikarjuna Shroff Rama

Sumit Ramesh Songire

Amit Chandrakant Agrawal

Achala Vasudev Danait

Julio Estuardo Vasquez Estrada

Sunil Narsingrao Garaje

Monalisa Mallick

Umesh Namdeo Nehete

Marisol Mendez

Tzoni Trifonov Raykov

Amar Deep Pathak

Sarai Santos

Nurpasha Hipparge

Breaker fluids for removing polyolefin agglomerations from wellbore equipment and subterranean formations. An example breaker fluid includes an acid, at least one oxidizer, a corrosion inhibitor, a surfactant, an asphaltene remover, a sludging inhibitor, and an aqueous base fluid. The breaker fluid is introduced to wellbore equipment and subterranean formations and breaks down polyolefin agglomerations present therein.

Breaker fluids for removal of polyolefin residue

Methods and system for using salting out inhibitors in subterranean formations are provided. In some embodiments, the methods comprise introducing a treatment fluid comprising an aqueous base fluid, a salting out inhibitor, a gelling agent, and one or more salts into at least a portion of a subterranean formation, wherein the salting out inhibitor is selected from the group consisting of: an oligomer comprising one or more quaternary ammonium cations, a polymer comprising one or more quaternary ammonium cations, a source of one or more phosphate anions, and any combination thereof.

Salting out inhibitors for use in treatment fluids

A well treatment fluid comprising an aqueous base fluid and a sugar-based surfactant is provided. The sugar-based surfactant includes at least one betaine functionalized alkyl polyglucoside. Also provided is a method of treating an oil and gas well.

Sugar-based surfactant for well treatment fluids

A method of treating a well comprising introducing an aqueous-based well treatment fluid into the well and treating the well with the well treatment fluid is provided. The well treatment fluid comprises an aqueous base fluid, and a treating agent. The treating agent comprises fulvic acid. In one embodiment, the treating agent functions as a scale inhibitor. In another embodiment, the treating agent functions as a gel stabilizer. For example, the method can be a method of fracturing a subterranean formation. For example, the method can be a method of forming a gravel pack in a well. An aqueous-based well treatment fluid is also provided.

Fulvic acid well treatment fluid

Systems and methods for using gellable gravel packing fluids that may comprise polysaccharide gelling agents and gel stabilizers to extend the working temperature range for the polysaccharide gelling agents. A method for placing a gravel pack in a subterranean formation comprising: providing a gravel packing fluid in the form of a linear gel and comprising an aqueous base fluid, a polysaccharide gelling agent, a thermal stabilizer, and a gravel; placing the gravel packing fluid into the subterranean formation; and allowing the gravel packing fluid to form a gravel pack in the subterranean formation.

Gravel packing fluids with enhanced thermal stability

A composition and method for treating a subterranean formation that includes preparing a treatment gel of aqueous fluid, a thickening agent soluble in the aqueous fluid, sand/gravel, and micro fibrous cellulose. Placing the treatment gel in at least a portion of a subterranean formation.

High temperature gravel packing fluid system

An invert emulsion composition which includes a base fluid having an oleaginous phase and a non-oleaginous phase, an emulsifier, and wherein the oleaginous phase includes a mixture of vegetable oil and an oil other than vegetable oil. The composition may also include particles such as proppants or gravel, which may be coated prior to introduction to the composition to assist in stabilization the emulsion. The invert emulsion composition can be employed in fracturing, gravel packing, and diversion operations, and the like.

Invert emulsion containing vegetable oil

A wellbore treatment fluid comprising: a base fluid; a viscosifier, wherein the viscosifier is a synthetic, cross-linked polymer having a thermal stability greater than 275&#xb0; F.; a breaker, wherein the breaker decreases the viscosity of the treatment fluid at or above a breaker-activation temperature; and an activator, wherein the activator is a chelate complex, and wherein the activator activates the breaker to reduce the viscosity of the treatment fluid at a temperature less than the breaker-activation temperature. A method of treating a subterranean formation comprising: introducing the treatment fluid into the subterranean formation.

Activator for breaking system in high-temperature fracturing fluids

A persulfate compound activated by a strong base is used for low-temperature breaking of fluids viscosified with one or more water-soluble synthetic polymers, wherein the water-soluble synthetic polymers are selected from the group consisting of polyacrylamides, copolymers of polyacrylamide, derivatives of polyacrylamide or of copolymers of polyacrylamide, and any combination thereof. The breaker system can be used in an oilfield or pipeline application where such a synthetic polymer, a multi-chain polysaccharide, or combination thereof may be present in a fluid. It is particularly useful at low temperatures of less than 100&#xb0; F.

Alkaline persulfate for low-temperature breaking of polymer viscosified fluid

Low residue, high salinity fracturing fluids may be produced by hydrating a gelling agent comprising carboxymethyl hydroxypropyl guar (CMHPG) in an aqueous fluid having a total dissolved solids concentration of about 30,000 ppm or greater and a pH of about 5 to about 8; adjusting the pH of the aqueous fluid to about 9 to about 10; and then, adding a zirconate crosslinker to the aqueous fluid to yield a crosslinked-CMHPG.

Low residue, high salinity fracturing fluids

A process for chemically removing cured resin product from subterranean formations in case of inappropriate consolidation, plugging of screens or tubing, and equipment damage. A chemical solvent is introduced to a wellbore where a resin has cured. The resin is contacted with the chemical solvent until the resin at least partially dissolves. The dissolved resin is then removed from the wellbore. The process may also be used to remove consolidated packs consisting of cured resin and particulate materials.

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Pune, India

Chetan Prakash