Halliburton Energy Services, Inc.

Other

University of North Carolina at Chapel Hill

Multi-chem Group, LLC

Hallibunon Energy Services, Inc.

Jay Paul Deville

Hui Zhou

William Walter Shumway

Preston Andrew May

Dale E Jamison

Lee Jeremy Hall

Chesnee Lae Davis

Kay Ann Galindo

Philip Wayne Livanec

Cato Russell McDaniel

Charles R Landis

Weibin Zha

Samuel Jason Lewis

Peter James Boul

Catherine Martin Santos

Waseem Abdulrazzaq

Cato Mcdaniel

Philip D Nguyen

B Raghava Reddy

Xiangnan Ye

Xueyu Pang

Jonathan Paul Walker

Vivek S Goel

Nivika Rajendra Gupta

Greg Paul Perez

Orlando J Rojas

Sergey Sheyko

Christopher Michael Jones

Darren George Gascooke

Matthew Lynn Miller

Michael Wayne Sanders

Anthony M Badalamenti

Jeffrey James Miller

Pubudu Gamage

Antonio Recio

Trissa Joseph

Li Guo

Kay A Morris

Jessica Paola Ramirez Angulo

Emily Cummings Hart

John Walter Sherman

Nicholas Charles Braley

Sudarshana Mukherjee

Carlos L Salas

Eliane Padua Oliveira

Miren Aranzazu Castanares

Carlos A Carrillo

Carlos Arturo Carrera

Ayoub Ibrahim Awaji

Siham Kamal Fatani

Zhao Deng

Pubudu H Gamage

Gary P Funkhouser

Enrique Antonio Reyes

Weijun Guo

Anthony Herman Van Zuilekom

Michel Joseph LeBlanc

Kenneth William Pober

Sunita Sameer Kadam

Ronald Oliver Bosch

Brice Aaron Jackson

Kevin Gregory Kleinguetl

Adam Dotson

Gregory Paul Perez

Sherif Eldin

Lawrence Joseph Herskowitz

Kingsley Ihueze Nzeadibe

Alexandra Clare Morrison

Marcus Ray Hudson

Sharad Bhimrao Gotmukle

Zhonghuan Chen

Anthony Herman VanZuilekom

V Ramireddy Devarapalli

Pramod Chamarthy

Michael Rubinstein

Bhau Anantha Kuchik

Azhar Ahmed Alhasawi

Roger L Shelton

Rawan Jawad ALameer

Troy Francis Davis

Frederick Thomas Brown

Xiaobo Hu

Edwin Gnanakumar Solomon Raja

Carlos Luis Salas Araujo

Maria Ina

Phillip Wayne Livanec

Matt Lynn Miller

Mohammad Vatankhah Varnosfaderani

Michele Suzanne Brown

Pubudu Hasanka Gamage

Kay Ann Morris

A method and system for removing a filter cover. A system and method may comprise a downhole fluid sampling tool including a tool body; a flow port disposed on the tool body; a sample chamber disposed within the tool body and fluidly coupled to the flow port; a pump disposed within the tool body. In examples, the pump is configured to pump a fluid through the flow port into the sample chamber; a filter disposed on an inlet of the flow port, wherein the filter is configured to filter the fluid entering the flow port; and a removable filter cover configured to prevent fluid contact with the filter.

Protection of a wellbore tool using fluid medium dependent material

A treatment fluid can include a base fluid and a stabilizing additive. The stabilizing additive can include a plurality of environmentally acceptable nanoparticles. The particle size distribution of the plurality of nanoparticles can be selected such that the nanoparticles stabilize a wellbore wall of a subterranean formation or form a filtercake to inhibit or prevent fluid loss into permeable areas of the formation. The plurality of nanoparticles can have a particle size distribution of a d10 value in the range of 20 to 45 nanometers, a d50 value in the range of 40 to 80 nanometers, and a d90 value in the range of 80 to 140 nanometers. The plurality of nanoparticles can also be coated with a polymeric shell. The treatment fluid can be used in an oil and gas operation.

Environmentally acceptable wellbore stability additive

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

A method may include: introducing a treatment fluid into a production fluid disposed in a surface well system, the treatment fluid comprising: a base fluid; and a supramolecular host guest product comprising: a treatment fluid additive comprising a surfactant; and a supramolecular host molecule, wherein the supramolecular host molecule is not covalently bonded to the treatment fluid additive; introducing the production fluid containing the treatment fluid into a production facility separator; and separating, in the production facility separator, at least a portion of the production fluid to form a water stream.

Supramolecular host guest product concentrators for production fluids

A treatment fluid can include a base fluid and a lost-circulation package. The lost-circulation package can include plurality of pieces of a first lost-circulation material and a second lost-circulation material. The plurality of pieces can be an open-cell, natural or biodegradable material, for example natural sponges such as loofah. The plurality of pieces can enter permeable areas of a subterranean formation and form a mesh-like matrix that the second lost-circulation material can be retained within. The second lost-circulation material can be insoluble particles such as ground walnut shells or include ingredients that form a cementitious substance. The first and second lost-circulation materials can form a plug and provide adequate fluid loss control. The treatment fluid can be used in an oil and gas operation.

Open-cell, natural materials as lost-circulation material

A variety of methods and systems are disclosed, including, in one embodiment, a method for emulsion breaking including: applying a trigger to an oilfield emulsion to facilitate breaking of the oilfield emulsion, wherein the oilfield emulsion includes an oleaginous phase, a non-oleaginous phase, and a breakable emulsifier, wherein the trigger breaks the breakable emulsifier into non-emulsifying byproducts; and separating at least a portion of the oleaginous phase from the non-oleaginous phase.

Breakable emulsifiers

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

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

In general, in one aspect, embodiments relate to a method that includes circulating a water-based drilling fluid though a drill string to extend a wellbore through a subterranean formation, separating at least a portion of the water-based drilling fluid from the circulated water-based drilling fluid to form a separated portion of water-based drilling fluid, mixing a metal salt and a metal oxide into the separated portion of water-based drilling fluid to form a mixture and shearing the mixture to form a chemical sealing pill, where the chemical sealing pill includes the portion of the water-based drilling fluid, the metal salt, and the metal oxide, and after mixing and shearing, introducing the chemical sealing pill into the drill string as a single mixture and flowing the chemical sealing pill into a lost circulation zone in the subterranean formation.

Curing lost circulation of water-based drilling muds

A solids-control fluid for controlling flow of solids in a subterranean formation is disclosed herein. The solids-control fluid can include a diluent and a curable resin. The diluent can include a glycol ether. The curable resin can be dispersed within the diluent for controlling flow of solids in the subterranean formation.

Diluent with glycol ether for solids-control fluid in a wellbore

Methods and compositions for use in the inhibition of the formation of gas hydrate agglomerates are provided. In some embodiments, a method is provided that includes: providing an emulsion drilling fluid including: a continuous phase including a non-oleaginous fluid; an internal phase including an oleaginous fluid; and a thermodynamic hydrate inhibitor; and drilling at least a portion of a wellbore penetrating a subterranean formation.

Low density hydrate inhibitive fluids

In one embodiment, the methods include introducing a treatment fluid including an aqueous base fluid, at least one viscoelastic surfactant, a divalent salt, a metal salt; and a metal oxide into a wellbore penetrating at least a portion of a subterranean formation; and allowing the treatment fluid to at least partially set in the subterranean formation.

Viscoelastic surfactant-based treatment fluids for use with metal oxide-based cements

Particulate additives that may be useful in mitigating fluid loss and/or as bridging agents or diverting agents in subterranean treatment fluids such as drilling fluids. In some embodiments, the particulate additives include a polymeric material and calcium carbonate disposed on at least a portion of the outer surface of the polymer core wherein the particulates have a particle size (d50) of from about 2 μm to about 1600 μm in diameter. In some embodiments, the methods include providing a treatment fluid that includes the base fluid and the particulate additives and introducing the treatment fluid into at least a portion of a subterranean formation.

Calcium carbonate/polymer particulate additives for use in subterranean operations

A method may include: circulating an oil-based drilling fluid though a drill string to extend a wellbore through a subterranean formation, wherein the oil-based drilling fluid comprises an invert emulsion; separating at least a portion of the oil-based drilling fluid from the circulated oil-based drilling fluid to form a separated portion of oil-based drilling fluid; mixing a metal salt and a metal oxide into the separated portion of the oil-based drilling fluid to form a chemical sealing pill; introducing the chemical sealing pill into the drill string and flowing the chemical sealing pill into a lost circulation zone in the subterranean formation; allowing at least a portion of the chemical sealing pill to set in the lost circulation zone to form a set plug, wherein the set plug seals the lost circulation zone and reduces loss of fluid into the lost circulation zone from subsequently introduced fluids; and preventing loss of fluid into the lost circulation zone from subsequently introduced fluids with the set plug.

Curing lost circulation of oil-based drilling muds

Growing community of inventors

Spring, TX, United States of America

Jay Paul Deville