Halliburton Energy Services, Inc.

Huntsman Petrochemical Corporation

Conocophillips Company

Huntsman Advanced Materials Americas LLC

Hallibunon Energy Services, Inc.

Hui Zhou

Jay Paul Deville

Weibin Zha

William Walter Shumway

Preston Andrew May

Kay Ann Galindo

Chesnee Lae Davis

David C Lewis

Howard P Klein

Wei-Yang Su

Terry L Renken

Cato Russell McDaniel

William Cecil Pearl, Jr

Robert A Grigsby, Jr

Catherine Martin Santos

Timothy Neal Harvey

Alexandra Clare Morrison

Emily Cummings Hart

Eliane Padua Oliveira

Leah Patterson

Philip Wayne Livanec

Donald H Champion

Zhiwei Yue

Sunita Sameer Kadam

Curt E Schneider

Derek Scott Kincaid

Ping Chen

Robert Allison Grigsby

Katty Darragas

Mahesh Vijay Biyani

Benjamin Lascaud

Sudarshana Mukherjee

Casey Timothy Lesar

Sohini Bose

Iman Shahim

Juventino Uriarte

Ke Zhang

Chai Zheng

Ayten Rady

Mohamed Metwally

Emily Hart

Feixia Chen

Curt Schneider

A water-based drilling fluid can include a first and second viscosifier of a cross-linked starch and a cross-linked acrylamide-based polymer. The acrylamide-based polymer can be crosslinked and optionally include hydrophobic monomers. The viscosifiers create a synergistic effect that imparts desirable properties to the drilling fluid compared to using either of the viscosifiers alone. The viscosifiers can be used as an alternative to other types of viscosifiers such as xanthan gum.

Synergistic viscosifiers for clay-free, water-based drilling fluids

Drilling fluids for drilling a wellbore. An example drilling fluid includes an aqueous base fluid, a first fluid loss control additive that comprises a cross-linked polymer comprising N-vinylpyrrolidone as a monomer, and a second fluid loss control additive that comprises a cloud point glycol.

Drilling fluid additives for high-density reservoir drilling fluids

Drilling fluids and methods for drilling a wellbore. An example drilling fluid is a divalent brine aqueous base fluid having at least one dissolved divalent zinc salt and also a polymeric additive that is a cross-linked copolymer comprising a first comonomer of 2-acrylamido-2-methylpropanesulfonic acid in a first comonomer concentration of at least 50 mol % of the copolymer; wherein the polymeric additive additionally comprises a second comonomer comprising a N-vinyl amine-containing monomer, a terminal double bound-containing monomer, or a combination of a N-vinyl amine-containing monomer and a terminal double bound-containing monomer; wherein the second comonomer is present in a total second comonomer concentration of 50 mol % or less of the copolymer. The drilling fluid further includes a zinc solid.

Divalent-brine-based high density drilling fluids

An oil-based treatment fluid for use in subterranean operations may comprise an invert emulsion including an aqueous internal phase and an oil external phase. The aqueous internal phase is solids free and comprises a two-salt brine and a true crystallization temperature reduction additive. The two-salt brine comprises a bromide and a nitrate, wherein the bromide brine has a density of about 14.2 lbs/gal to about 17 lbs/gal. There are no additional salts in the aqueous internal phase; The bromide brine has a first true crystallization temperature without inclusion of a true crystallization temperature reduction additive and a second true crystallization temperature with a true crystallization temperature reduction additive that is lower than the first true crystallization temperature reduction additive.

High density brine internal phase

A curing agent comprising a polyetheramine, a tertiary amine and an alkanolamine. The curing agent may be combined with an epoxy resin to form a curable composition which is capable of being applied to a substrate and cured to form a cured article.

Curing agent for epoxy resins

Methods and compositions for servicing a wellbore and, in certain embodiments, to the use of compositions in a wellbore to mitigate lost circulation. In some embodiments, the methods include providing a treatment fluid that includes an aqueous base fluid, a lost circulation material, and a rheology modifier that includes a nanocellulose material; introducing the treatment fluid into a wellbore penetrating at least a portion of a subterranean formation including a loss zone; and allowing the treatment fluid to rapidly defluidize in the loss zone.

Rheology modifiers for high fluid-loss squeeze lost circulation materials

A curing agent comprising a polyetheramine, a tertiary amine substantially free of an aromatic tertiary amine and glycerin. The curing agent may be combined with an epoxy resin to form a curable composition which is capable of being applied to a substrate and cured to form a cured article.

The present disclosure provides a quaternary ammonium hydroxide solution comprising a reaction product of a polyamine and an organic oxirane. The quaternary ammonium hydroxide solution may be used in various applications, such as in removing chemical residue from a metal or dielectric surface.

Quaternary ammonium hydroxides of polyamines

A method for creating a field development plan, comprising initializing, by a specially programmed computing system, a connectivity model, calibrating, by a specially programmed computing system, the connectivity model based on a plurality of reservoir simulation results, determining, by a specially programmed computing system, a travel time between wells and reservoir cells using a fast marching method, determining, by the specially programmed computing system, a hydrocarbon saturation based on the travel time to construct a model prediction, optimizing, by the specially programmed computing system, the connectivity model using a global optimization and a local optimization, and constructing, by the specially programmed computing system, at least one well file using the optimized connectivity model.

Connectivity based approach for field development optimization

A method may include providing a single-phase cleanout fluid comprising a first nonionic surfactant with a hydrophilic-lipophilic balance (HLB) greater than 10, a second nonionic surfactant with an HLB greater than 10, a third nonionic surfactant with an HLB of less than 10, and a solvent; preparing a cleanout pill by mixing the single-phase cleanout fluid with a brine; and displacing a fluid in a wellbore using the cleanout pill.

Wellbore cleaner for use in displacement trains

A method of drilling a wellbore penetrating a subterranean formation, the method includes: during drilling operations, circulating in the wellbore a first aqueous drilling fluid composition including a modified starch and a calcium carbonate wherein the calcium carbonate has a first predetermined particle size; during the circulating, measuring one or more parameters to create a set of measured parameters; and during the circulating, responsive to one or more parameters of the set of measured parameters, changing the calcium carbonate with another calcium carbonate of a different particle size to obtain a second aqueous drilling fluid composition, wherein the first and second predetermined particle sizes are, independently, a dparticle size of about 1.0 &#x3bc;m to about 150 &#x3bc;m.

Changing calcium carbonate particle size with starch for reservoir fluids

Implementations described and claimed herein provide systems and methods for developing resources from an unconventional reservoir. In one implementation, raw reservoir data for the unconventional reservoir is obtained. The raw reservoir data includes geology data, completion data, development data, and production data. The raw reservoir data is transformed to transformed data. The raw reservoir data is transformed to the transformed data based on a transformation from a set of one or more raw variable to a set of one or more transformed variables. The set of one or more transformed variables is statistically uncorrelated. Resource development data is extracted from the transformed data. Performance analytics are generated for the unconventional reservoir using the resource development data. The performance analytics are generated through ensemble machine learning. The unconventional reservoir is developed based on the performance analytics.

Integrated machine learning framework for optimizing unconventional resource development

Compositions and methods involving polyvalent cation reactive polymers for use as lost circulation materials in subterranean treatment operations are provided. In some embodiments, the methods include forming a treatment fluid including a base fluid, a source of a polyvalent cation, a polyvalent cation reactive polymer, and an acid precursor; introducing the treatment fluid into a wellbore penetrating at least a portion of a subterranean formation; and allowing the treatment fluid to at least partially set.

Reactive polymeric lost circulation materials

A method includes providing a treatment fluid including a strong acid precursor defined by the structure: where X is independently selected from fluorine, chlorine, bromine, and iodine; where each of R, R, and Ris independently selected from a hydrogen, X, and a Cto Chydrocarbon chain; and where the electron withdrawing group (EWG) is independently selected from a carboxylic acid, carboxylate salt, or carboxylate ester, an orthoester, a sulfonic acid, sulfonate salt, or ester, a phosphonic acid, phosphonate salt, or phosphonate ester, a nitrate, or a cyanide; where Y is hydrogen, a cation, or a Cto Chydrocarbon chain; and wherein each R' is independently is independently selected from a hydrogen, X, and a Cto Chydrocarbon chain. The method also includes introducing the treatment fluid into a wellbore penetrating a subterranean formation.

Acid precursor treatment fluid generating and/or releasing acid for use downhole in a subterranean formation

Provided are compositions and methods that use a true crystallization temperature reduction additive in the aqueous internal phase. An example method may comprise providing an oil-based treatment fluid in the form of an invert emulsion comprising an aqueous internal phase and an oil external phase. The aqueous internal phase may include a bromide brine and a true crystallization temperature reduction additive, wherein the bromide brine has a density of about 14.2 lbs/gal or greater. The method may further include placing the oil-based treatment fluid into a wellbore.

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The Woodlands, TX, United States of America

Hui Zhou