Exxonmobil Research and Engineering Company

Exxon Research and Engineering Company

Exxonmobil Upstream Research Company

Exxonmobil Chemical Patents Inc.

Georgia Tech Research Corporation

Exxonmobil Technology and Engineering Company

Other

Exxon Chemical Patents, Inc.

Exxonmobile Research and Engineering Company

Univation Technologies, LLC

Harry William Deckman

Frank Hershkowitz

Bruce T Kelley

Peter I Ravikovitch

Ronald Richard Chance

Edward William Corcoran, Jr

James Alexander McHenry

Daniel Paul Leta

Paul Scott Northrop

Pavel Kortunov

Robert P Reynolds

Michael Gerard Matturro

Sebastian Carmen Reyes

Preeti Kamakoti

Eugene R Thomas

Robert A Johnson

Charanjit Singh Paur

Leonard Schoenman

Hubert E King

Thomas N Anderson

Wenyih Frank Lai

Gabor Kiss

Ryan Paul Lively

Jack Wayne Johnson

William Anthony Lamberti

John Zengel

Zheng Ni

Karl Gottlieb Strohmaier

John Scott Buchanan

William John Koros

Allan J Jacobson

Edmund John Mozeleski

Ivy Dawn Johnson

Jeffrey William Frederick

Russell H Oelfke

Horst Witzke

Mehmet Deniz Ertas

Benjamin A McCool

Anthony M Dean

Barbara Carstensen

Peter C Rasmussen

Peter A Gordon

Michael Siskin

Richard Henry Schlosberg

Wieslaw J Roth

Ramesh Gupta

Allen David Godwin

John Di-Yi Ou

Tilman W Beutel

Paul Michael Chaikin

Neeraj Srinivas Thirumalai

John William Fulton

Russell J Koveal

Istvan T Horvath

Raymond A Cook

Shiun Ling

Donald J Victory

Eli Yablonovitch

Shwetha Ramkumar

Brent D Wheelock

Christopher R Wronski

Martin N Webster

Philippe Louis Buess

Charles B Roxlo

David Lawrence Stern

Scott Jeffrey Weigel

Richard Alan Huntington

Stephen M Davis

Jean Willem Beeckman

Eric John Markel

Randall David Partridge

Mohsen Shahmirzadi Yeganeh

Robert F Tammera

Johannes Petrus Verduijn

Bhupender S Minhas

Franklin F Mittricker

Christopher W Jones

Yibing Zhang

Ananda K Nagavarapu

Charles John Mart

P Scott Northrop

Jaime A Valencia

Sankar Nair

Randolph John Smiley

David Ritchie Lumgair

LeRoy R Clavenna

Sulabh K Dhanuka

Timothy G Benish

Frank Cheng-Yu Wang

Benjamin Abeles

James H Taylor, Jr

Antonie Jan Bons

Marc L DeChellis

Jennifer Schaefer Feeley

Bennett D Marshall

Chad C Rasmussen

Edward W Corcoran

Lavanga R Veluswamy

Natalie Ann Fassbender

Gary F Janda

A method for determining the pore types of a core sample can include: determining a porosity of a core sample, wherein the core sample has a permeability of 10 mD or less; saturating the core sample with a NMR saturation fluid to achieve a saturated core sample; taking a NMR measurement of fluids in the saturated core sample; and deriving a volume for a pore type based on the porosity based on a correlation between the NMR measurement and a NMR signal to fluid volume calibration, wherein the pore type is selected from the group consisting of a nanopore, a micropore, a macropore, and any combination thereof.

Advanced NMR analysis of pore type and pore connectivity in core samples including diffusional fluid exchange methods

A method for determining the porosity of a core sample can include: saturating a core sample with a nuclear magnetic resonance (NMR) saturation fluid, wherein the core sample has a permeability of 100 milliDarcy (mD) or less, to achieve a saturated core sample; taking a NMR measurement of fluids in the saturated core sample; determining a porosity of the core sample based on a correlation between the NMR measurement and a NMR signal to fluid volume calibration.

Advanced NMR analysis of porosity and other properties in core samples using hydraulic fluid exchange

Embodiments of an invention disclosed herein relate to methods for performing formation evaluation of a formation or formation's surrounding to identify and characterize the abundance and morphology of non-ionic conductor grains, 'c-grains', within the formations that are evaluated by formation evaluation (FE) tools. The methods and related systems as disclosed herein are directed to correcting any existing FE logs that can be adversely affected by the presence of c-grains in the detection volume of FE tools, and/or obtaining new FE information that is unavailable by the application of existing FE methods.

Methods for performing formation evaluation and related systems

Proppant particulates like sand are commonly used in hydraulic fracturing operations to maintain one or more fractures in an opened state following the release of hydraulic pressure. Fracturing fluids and methods of hydraulic fracturing may also use proppant particulates composed of fluid coke material (also referred to as fluid coke proppant particulates). In some instances, the fluid coke proppant particulates are characterized by a bulk density of less than about 0.9 grams per cubic centimeter.

Proppant particulates formed from fluid coke and methods related thereto

A hydrocarbon well includes a wellbore with a surface casing string that couples the wellbore to a wellhead located at the surface and a production casing string that extends through a reservoir within the subsurface. A fluid column is present within the wellbore. The hydrocarbon well also includes a high-frequency tube wave generator that is hydraulically coupled to the wellbore and is configured to generate high-frequency tube waves that propagate within the fluid column. The high-frequency tube waves include a selected waveform containing a specific bandwidth of high-frequency components. The hydrocarbon well further includes a receiver that is hydraulically coupled to the wellbore and is configured to record data corresponding to the generated and reflected high-frequency tube waves propagating within the fluid column, wherein the recorded data relate to characteristics of the wellbore. Moreover, such techniques may also be applied to a pipeline.

Assessing wellbore characteristics using high frequency tube waves

Proppant particulates like sand are commonly used in hydraulic fracturing operations to maintain one or more fractures in an opened state following the release of hydraulic pressure. Fracturing fluids and methods of hydraulic fracturing may also use proppant particulates composed of flexicoke material. Such proppant particulates may have improved transport into fractures because of lower density than traditional proppants like sand and may produce fewer fines that reduce fluid flow through proppant packs.

Proppant particulates formed from flexicoke and methods related thereto

Disclosed are processes and systems for the removal of water from a feed stream utilizing swing adsorption processes including an adsorbent bed comprising an adsorbent material which is a cationic zeolite RHO. The cationic zeolite RHO comprises at least one, preferably two, metal cations selected from Group 1 and 2 elements (new Group 1-18 IUPAC numbering). The swing adsorption processes and systems utilizing the cationic zeolite RHO have an adsorption selectivity for water and are useful in selective dehydration of commercial feed streams. The cationic zeolite RHO additionally has an exceptionally high water adsorption stability for use in feed streams with wet acid gas environments operating under cyclic swing adsorption conditions.

Dehydration processes utilizing cationic zeolite RHO

The present disclosure describes the use of a specific adsorbent material in a rapid cycle swing adsorption to perform dehydration of a gaseous feed stream. The adsorbent material includes a zeolite 3A that is utilized in the dehydration process to enhance recovery of hydrocarbons.

Swing adsorption processes using zeolite structures

A process for producing polyethylene polymers including contacting ethylene and at least one Cto Calpha-olefin comonomer with a polymerization catalyst on a particulate support in a fluidized bed polymerization reactor under conditions effective to polymerize at least part of the ethylene and comonomer and produce the polyethylene polymers, wherein the support has a dparticle size as measured by laser diffraction of at least 18 microns, is provided.

Process for producing polyethylene polymers

A method for determining the porosity of a core sample can include: submerging a core sample in a NMR saturation fluid, wherein the core sample has a permeability of 10 mD or less; exposing the fluid to a vacuum while the core sample is submerged the NMR saturation fluid for a sufficient period of time to saturate the core sample; removing the vacuum while maintaining the core sample submerged the NMR saturation fluid; taking a NMR measurement of fluids in the core sample; and determining a porosity of the core sample based on a correlation between the NMR measurement and a NMR signal to fluid volume calibration.

Methods for measuring the porosity of core samples using NMR analysis

A method for determining the fluid mobility of a core sample can include: determining a porosity of a core sample having a permeability of 10 mD or less; saturating the core sample with a NMR saturation fluid; taking a first NMR measurement of fluids in the core sample; diffusionally exchanging a hydrophobic fluid or a hydrophilic fluid in the core sample in a hydrophobic NMR exchange fluid or a hydrophilic NMR exchange fluid, respectively; taking a second NMR measurement of the fluid in the core sample after diffusional exchange; and deriving a property of the core sample based on the porosity, a NMR signal to fluid volume calibration, and a comparison between the first and the second NMR measurements, the property being selected from the group consisting of a mobile oil volume, an immobile hydrocarbon volume, a mobile water volume, an immobile water volume, and a combination thereof.

Methods using advanced NMR analysis for core samples

A method for determining a core sample property selected from the group consisting of a recoverable oil volume, an irreducible hydrocarbon volume, a recoverable water volume, an irreducible water volume, and any combination thereof can include: determining a porosity of a core sample, wherein the core sample has a permeability of 100 milliDarcy (mD) or less; saturating the core sample with a NMR saturation fluid; taking a first nuclear magnetic resonance (NMR) measurement of fluids in the core sample; hydraulically exchanging a hydrophobic fluid or a hydrophilic fluid in the core sample in a hydrophilic NMR exchange fluid or a hydrophobic NMR exchange fluid, respectively; taking a second NMR measurement of the fluids in the core sample after hydraulic exchange; and deriving the property of the core sample based on the porosity, a NMR signal to fluid volume calibration, and a comparison between the first and second NMR measurements.

A method determining a volume of a pore type of a core sample can include: determining a porosity of a core sample, wherein the core sample has a permeability of 100 milliDarcy (mD) or less; saturating the core sample with a nuclear magnetic resonance (NMR) saturation fluid to achieve a saturated core sample; taking a NMR measurement of fluids in the saturated core sample; and deriving a volume for a pore type based on the porosity based on a correlation between the NMR measurement and a NMR signal to fluid volume calibration, wherein the pore type is selected from the group consisting of a nanopore, a micropore, a macropore, and any combination thereof.

Advanced NMR analysis of pore type distribution in core samples using hydraulic fluid exchange

For method of utilizing a nondestructive evaluation method to inspect a steel material comprising at least one hysteretic ferromagnetic material and/or at least one nonhysteretic material to identify one or more material conditions and/or one or more inhomogeneities in steel material, the method can comprise the steps of: interrogating the hysteretic ferromagnetic material and/or the nonhysteretic material with an input time varying magnetic field; scanning the steel material and detecting a magnetic response and/or acoustic response over time from the hysteretic ferromagnetic material and/or the nonhysteretic material; determining a time dependent nonlinear characteristic of the received magnetic response and/or acoustic response; and correlating the time dependent nonlinear characteristic of the received magnetic response and/or acoustic response to the one or more material conditions and/or one or more inhomogeneities in steel material.

Methods of using nondestructive material inspection systems

A method for determining one or more material conditions of a hysteretic ferromagnetic material and/or a nonhysteretic material can include interrogating the hysteretic ferromagnetic material and/or the nonhysteretic material with an input time varying magnetic field and detecting a magnetic response and/or acoustic response over time from the hysteretic ferromagnetic material and/or the nonhysteretic material. The method can also include determining a time dependent nonlinear characteristic of the received magnetic response and/or acoustic response and correlating the time dependent nonlinear characteristic of the received magnetic response or acoustic response to one or more material conditions of the material.

Methods and systems for nondestructive material inspection

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Clinton, NJ, United States of America

Harry William Deckman