Schlumberger Technology Corporation

Cameron International Corporation

Prad Research and Development Nv

Services Petroliers Schlumberger

Schlumberger Holdings Limited

Prad Research and Development Limited

Yiyan Chen

Carlos Abad

Jesse Lee

Philip F Sullivan

Lijun Lin

Dimitri M Khramov

Belgin Baser

Timothy L Pope

Anthony Loiseau

Michael D Parris

Mohan K R Panga

Gregory Kubala

Andrey Mirakyan

Oscar Bustos

Bruno Drochon

Gary John Tustin

Eric L Hanson

Mehmet Parlar

Christopher N Fredd

Paul R Howard

Reda Karoum

Hemant K Ladva

Erik B Nelson

Xiaowei Weng

Mathew M Samuel

Marie Noelle Dessinges

Yenny Christanti

Hongren Gu

Alyn Jenkins

Richard Marcinew

William Brett Cardwell

Manilal S Dahanayake

Diankui Fu

Curtis L Boney

Emanuel Stamatakis

Mohan Kanaka Raju Panga

William Troy Huey

Steven Philip Young

Dean M Willberg

Golchehreh Salamat

Allwyn Colaco

Z Frank Zheng

Marina Nikolaevna Bulova

Bernhard Lungwitz

John Lassek

Sylvie Daniel

Fang Li

Changping Sui

Stephen Cliffe

Zhijun Xiao

Ann M W Hoefer

Moin Muhammad

Hemant K J Ladva

Albert Okhrimenko

Mohan Panga

Jean-Philippe Bedel

Abbas Mahdi

Liz Morris

Michaela Nagl

Robert J Tillotson

Paul A Price

Yan Gao

Taner Batmaz

Alex Ahrenst

Glynda A Addicks

Samuel Cozzens

Yang He

Keyur Pandya

Nihat Gurmen

Zakir Azmi

Donald Hodgson, Iii

Meghan Ruth Riley

Jean-Phi Bedel

Matt Graham

Goke Adeogun

Robert Tillotson

Jesse C Lee

A system for recovering carbon dioxide from a carbon dioxide-containing gas includes an absorber configured to absorb carbon dioxide from the carbon dioxide-containing gas with a non-aqueous solvent to form a carbon dioxide-lean gas, the non-aqueous solvent comprising a nitrogenous base, regenerator configured to remove the carbon dioxide from the non-aqueous solvent after the non-aqueous solvent is loaded with carbon dioxide, and an acid wash column configured to remove a second portion of the nitrogenous base from the carbon dioxide-lean gas with a buffered acid solution. Related systems and methods of removing carbon dioxide from a carbon dioxide-containing gas are also disclosed.

Systems for removing carbon dioxide from a carbon dioxide containing gas, and related methods

Production chemicals and methods of selecting the production chemicals based on Hansen Solubility Parameters (HSP) are disclosed. The production chemicals selected by the methods mitigate or reduce one or more issues or problems associated with oil and gas productions and transportations. The methods measure HSP values for the production chemicals and/or crude oil and select at least one production chemical for at least one application on the crude oil based on the HSP values of the production chemicals and the crude oil.

Production chemicals and methods of selecting the production chemicals based on Hansen solubility parameters

Corrosion inhibition compositions and methods useful for inhibiting corrosion are provided. The corrosion inhibition compositions comprise at least one coupling agent and at least one corrosion inhibitor, wherein the at least one coupling agent is at least one of one or more ether amines, one or more ether amine oxides, and at least one combination thereof, and the at least one corrosion inhibitor is at least one selected from one or more thiophosphates, one or more polyphosphate esters, one or more imidazolines, one or more quinolines, one or more alkynols, one or more alkynol derivatives, and at least one combination thereof. The methods for inhibiting corrosion on metal surfaces utilize the disclosed corrosion inhibiting compositions.

Coupling agents for use in corrosion inhibiting compositions

Corrosion inhibition compositions and methods useful for inhibiting corrosion are provided. The corrosion inhibition compositions comprise at least one filming agent and at least one promoting agent and the methods for inhibiting corrosion on metal surfaces utilize the disclosed corrosion inhibiting compositions.

Corrosion inhibitor

Methods may include quantifying the concentration of residual free amine and/or free carboxylic acid in a product mixture prepared from a reaction of a multireactive species and a fatty reagent; verifying that the concentration for the free amine and/or free acid in the product mixture is within an acceptable threshold for a given application; and combining the product mixture with one or more wellbore fluid components to generate the wellbore fluid. In another aspect, methods may include including reacting the multireactive species and a fatty reactant to generate a product mixture; quantifying the concentration of residual free amine and/or free carboxylic acid in the product mixture; verifying that the concentration for the free amine and/or free acid in the product mixture is within an acceptable threshold for a given application; and collecting the product mixture.

Amidoamine synthesis, methods to track the reaction process

Wellbore fluid compositions may include an oleaginous base fluid; and a polymeric rheology modifier incorporating a polar comonomer at a percent by weight (wt %) in the range of 1 wt % to 20 wt %; wherein the low shear rate viscosity (LSRV) of the wellbore fluid measured by FANN 35 rheometer at 3 rpm and 150° F. is in the range of 8 to 12. Methods may include emplacing a wellbore fluid in a wellbore, wherein the wellbore fluid comprises an oleaginous base fluid and a polymeric rheology modifier incorporating a polar comonomer at a percent by weight (wt %) in the range of 1 wt % to 50 wt %; wherein the low shear rate viscosity (LSRV) of the wellbore fluid is in the range of 8 to 12.

Polymeric rheology modifiers

Systems and methods measure one or more rheological properties and/or parameters of a fluid and establish at least one correlation between the measured one or more rheological properties and/or parameters. The systems and methods may correlate the measured one or more rheological properties and/or parameters to static aging results to establish the at least one correlation between the one or more rheological properties and/or parameters of the fluid. The systems and methods may predict at least one sagging tendency of the fluid based on the established at least one correlation and may measure and/or monitor static sagging of the fluid based on the predicted at least one sagging tendency of the fluid. The systems and methods may guide fluid treatment of the fluid or produce a mud system based on the predicted at least one sagging tendency of the fluid.

Systems and methods for monitoring and/or predicting sagging tendencies of fluids

Compositions may contain an oleaginous base fluid, and a branched amidoamine surfactant prepared from the reaction of an alkylene amine or an oligoalkylene amine and a branched acid having a C4 to C24 primary hydrocarbon chain, and having one or more C1 to C24 branches. Methods may include emplacing a wellbore fluid into a wellbore, wherein the wellbore fluid contains an oleaginous base fluid; and a branched amidoamine surfactant prepared from the reaction of an alkylene amine or an oligoalkylene amine and a branched acid having a C4 to C24 primary hydrocarbon chain, and having one or more C1 to C24 branches.

Branched acid emulsifier compositions and methods of use

Wellbore fluids may include an oleaginous continuous phase; a non-oleaginous discontinuous phase; and an emulsifier stabilizing the non-oleaginous discontinuous phase in the oleaginous continuous phase, wherein the emulsifier is the product of a reaction between an alkyl cyclic anhydride and a polar reactant, wherein the polar reactant is one or more selected from a group containing alkyl amine, alkanolamine, and polyamine. Methods may include drilling a wellbore with an oil-based mud, wherein the oil-based mud is an invert emulsion containing an emulsifier stabilizing the invert emulsion, wherein the emulsifier is the product of a reaction between an alkyl cyclic anhydride and a polar reactant, wherein the polar reactant is one or more selected from the group of alkyl amine, alkanolamine, and polyamine.

Alkyl cyclic anhydride based emulsifiers for oil based mud

A fluid may include an aqueous based continuous phase, a pH adjusting additive, wherein the pH adjusting additive is formic acid, and a clay hydration suppressant agent having the formula HNCH(CH)CH(OCH(CH)CH)NH, wherein x is a value less than 15.

High performance water based fluid

A composition comprising an oleaginous base fluid, an emulsifier and a liquid tertiary amide is disclosed. A wellbore fluid may include an oleaginous continuous phase, a non-oleaginous discontinuous phase and the composition to stabilize the non-oleaginous discontinuous phase within the oleaginous continuous phase. A method comprising adding the composition to a wellbore fluid and emplacing the wellbore fluid mixed with the composition into a wellbore is also provided.

Effective pour point depressants for amidoamine emulsifiers

Wellbore fluids and methods of drilling with the wellbore fluids are provided. One wellbore fluid may include an oleaginous continuous phase, a non-oleaginous discontinuous phase, and a polymer having a polycyclic backbone. One method may include pumping the wellbore fluid into a wellbore through an earthen formation.

Invert emulsifiers from DCPD copolymers and their derivatives for drilling applications

A composition, treatment fluid and method using hydrolyzable fines. A treatment fluid, which may optionally include a high solids content fluid (HSCF) and/or an Apollonianistic solids mixture, includes a fluid loss control agent comprising a dispersion of hydrolyzable fines, optionally with one or more of a surfactant, plasticizer, dispersant, degradable particles, reactive particles and/or submicron particles selected from silicates, &#x3b3;-alumina, MgO, &#x3b3;-Fe2O3, TiO2, and combinations thereof.

Hydrolyzable particle compositions, treatment fluids and methods

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Sugar Land, TX, United States of America

Yiyan Chen