Shell Oil Comapny

University of Texas System

Vinegar Technologies LLC

Genie IP B.v.

Terrah2 LLC

Other

General Electric Company

Snell Oil Company

Nmr Associates, Ltd. 1983-i

Harold J Vinegar

Scott Lee Wellington

Eric Pierre De Rouffignac

George Leo Stegemeier

Ilya Emil Berchenko

Robert Charles Ryan

Etuan Zhang

John Michael Karanikas

Thomas David Fowler

Gordon Thomas Shahin

Kevin Albert Maher

Frederick Gordon Carl, Jr

William Mountjoy Savage

Robert Rex Burnett

Chester Ledlie Sandberg

Christopher Kelvin Harris

Lanny Gene Schoeling

Robert Martijn Van Hardeveld

John Michele Hirsch

Meliha Deniz Sumnu-Dindoruk

Bruce Gerard Hunsucker

Thomas Mikus

Monroe H Waxman

Fredrick Gordon Carl, Jr

James Louis Menotti

Ronald Marshall Bass

Scott Vinh Nguyen

John Matthew Coles

Dong Sub Kim

Ajay M Madgavkar

John Michael Ward

Pierre Nazareth Tutunjian

Jaime Santos Son

Carlos A Glandt

Lawrence James Bielamowicz

Charles Robert Keedy

Eva Vinegar

Billy John McKinzie

Bruce Roberts

Margaret Ann Messier

Taixu Bai

David Scott Miller

Philip M Singer

Chia-Fu Hsu

George J Hirasaki

James William Hall

Stanley Leroy Mason

Steven Dexter Crane

Xueying Xie

Mark Gregory Picha

Bruce Donald Palfreyman

Phillip Temmons Baxley

Xinglin Wang

Ronnie Wade Watkins

Frederick Henry Kreisler Rambow

Peter Veenstra

Christopher Arnold Pratt

Ralph Sterman Baker

Randy Carl John

Zeliang Chen

Ridvan Akkurt

Vinod Kumar Sikka

Michael Leonard Santella

Charles C Chou

Gary Lee Beer

Dhruv Arora

Steven Paul Giles

Jannetje De Waal

Michael David Fairbanks

Namit Jaiswal

Daniel J O'Meara, Jr

Joachim Hugo Schneibel

Kirk Samuel Hansen

Oluropo Rufus Ayodele

John Paul Shingledecker

Ramesh Raju Mudunuri

Guillermo Pastor Sanz

Rocco DiFoggio

Arthur H Hale

Kenneth M Cowan

William A Edelstein

Otward M Mueller

James J Nahm

Ernest E Carter, Jr

Reece E Wyant

Weijian Mo

Myron Ira Kuhlman

Michael Prats

Anthony Thomas Cole

Peter Van Meurs

Michael F Lucid

Jefferson H Taylor

Jose Luis Bravo

Mark Christopher Haase

Thomas Joseph Keltner

John Andrew Stanecki

Robin Adrianus Hartmann

Cornelis F Van Egmond

Bernard Goldberg

Sau-Wai Wong

A method for operating a kerogen-rich unconventional gas reservoir characterized by there being multiple hydraulically-fractured wells drilled thereinto comprises: recovering a methane-containing gas from a first hydraulically-fractured well drilled into the gas reservoir, steam-methane reforming the recovered methane-containing gas to yield a hydrogen gas and an inorganic carbon-containing gas, injecting at least a portion of the hydrogen gas into a second hydraulically-fractured well drilled into the gas reservoir, and injecting at least a portion of the inorganic carbon-containing gas into a third hydraulically-fractured well drilled into the gas reservoir.

Hydrogen production, storage and recovery

A method for separating liquid-like (T) from solid-like (T)H NMR transverse relaxation times in porous media uses novel pulse sequences together with aH NMR spectrometer optimized for geological core samples. The method is applied to obtain 1D Tdistributions and 2D T-Tmaps in organic-rich chalks for quantification of liquid-like signal (micropore fluids, meso-macropore fluids, fluids dissolved in organic matter, and clay-bound water) and solid-like signal (kerogen, bitumen, and clay hydroxyls). The novel pulse sequences comprise a solid-echo, which detects more solid-like signal than an FID. The method is used for fluid typing in micro/meso-macro pores, clay mineral identification, determination of kerogen content, and quantification of solvent-extracted bitumen versus bitumen expelled from kerogen due to swelling from dissolved hydrocarbons. The method is used to quantify the asphaltene, resin, aromatic, and/or saturate content of bitumen in the rock.

Method of determining solid and liquid components in sedimentary rocks using NMR relaxation

This invention is useful for determining the permeability of a geological formation usingH NMR diffusion measurements acquired in the laboratory and using downholeH NMR well logging. The current technology for obtaining formation permeability downhole using NMR is not adequate for low-permeability, unconventional source rock formations with high organic content. This new method uses laboratoryH NMR diffusion measurements for creating continuous downhole well logs of the mobile-hydrocarbon permeability of the hydrocarbon-filled pore space of downhole geological formations.

Method of estimating permeability using NMR diffusion measurements

The following invention is used for determining the relative permeability of a fluid in a rock for three different phases: water, oil, and gas, in both conventional and unconventional formations. The permeability of a phase describes how much it can flow in porous media given a pressure gradient and is useful in evaluating reservoir quality and productivity. The following invention is a method to determine the three-phase relative permeabilities in both conventional and unconventional formations using NMR restricted diffusion measurements on core with NMR-active nuclei, combined with centrifugation of the core. In addition, the tortuosity, pore size (surface-to-volume ratio), fluid-filled porosity, and permeability is determined for each of the three phases in a rock.

Determination of fluid-phase-specific petrophysical properties of geological core for oil, water and gas phases

Hydrogen storage and recovery with fracture monitoring

New methods for determining the volumetric composition and saturation of methane and NGLs (natural gas liquids: ethane, propane, butane, and pentane) in a petroleum reservoir combining NMR (nuclear magnetic resonance) logging and NMR core analysis and for determining the mean pore-size and tortuosity of the light hydrocarbon-filled porosity in a petroleum reservoir using NMR core analysis.

Method for determining the composition of natural gas liquids, mean pore-size and tortuosity in a subsurface formation using NMR

A method and system for detecting a subsurface tunnel includes propelling an instrumented pipeline pig through a horizontal detection conduit, acquiring and analyzing magnetometer measurements and VLF EM resistivity measurements to detect distortions and/or anomalies in the Earth's magnetic field and/or VLF electromagnetic field, respectively, and correlating the data with position data of the pipeline pig to compute a parameter of a tunnel such as, for example, location, size and depth.

Tunnel detection using a pipeline pig

Embodiments of the present invention relate to heater patterns and related methods of producing hydrocarbon fluids from a subsurface hydrocarbon-containing formation (for example, an oil shale formation) where a heater cell may be divided into nested inner and outer zones. Production wells may be located within one or both zones. In the smaller inner zone, heaters may be arranged at a relatively high spatial density while in the larger surrounding outer zone, a heater spatial density may be significantly lower. Due to the higher heater density, a rate of temperature increase in the smaller inner zone of the subsurface exceeds that of the larger outer zone, and a rate of hydrocarbon fluid production ramps up faster in the inner zone than in the outer zone. In some embodiments, a ratio between a half-maximum sustained production time and a half-maximum rise time of a hydrocarbon fluid production function is relatively large.

Heater pattern for in situ thermal processing of a subsurface hydrocarbon containing formation

A method is disclosed for generating an areal map of a pre-determined hydrocarbon liquid property of a subsurface kerogen-containing source rock from an electromagnetic resistivity profile. Preferably, the profile is generated by a transient EM method such as a long-offset transient electromagnetic (LOTEM) method. In some embodiments, the areal map is generated by employing resistivity-hydrocarbon liquid-quality relationship data describing a relationship between (i) a property of hydrocarbon liquid generated within the source rock pore space to (ii) an electrical resistivity of the source rock. In some embodiments, it is possible to acquire such data even in the absence of source rock samples where the hydrocarbon liquids within the samples has been preserved. The areal map is useful for determining a target location and/or depth in the source rock to drill for oil. The presently-disclosed techniques are particularly relevant to tight oil formations.

Mapping hydrocarbon liquid properties of a kerogencontaining source rock

A system for treating a subsurface formation includes a plurality of conduits at least partially located in a portion of a hydrocarbon containing formation. At least part of two of the conduits are aligned in relation to each other such that electrical current will flow from a first conduit to a second conduit. The first and second conduits include electrically conductive material and at least one of the first and second conduits is perforated or configured to be perforated. A power supply is coupled to the first and second conduits. The power supply electrically excites at least one of the conductive sections such that current flows between the first conduit and the second conduit in the formation and heats at least a portion of the formation between the two conduits.

Perforated electrical conductors for treating subsurface formations

A system for treating a subsurface formation includes a wellbore at least partially located in a hydrocarbon containing formation. The wellbore includes a substantially vertical portion and at least two substantially horizontal or inclined portions coupled to the vertical portion. A first conductor is at least partially positioned in a first of the two substantially horizontal or inclined portions of the wellbore. At least the first conductor includes electrically conductive material. A power supply electrically excites the electrically conductive materials of the first conductor such that current flows between the electrically conductive materials in the first conductor, through at least a portion of the formation, to a second conductor at least partially positioned in a second of the two substantially horizontal or inclined portions of the wellbore. The current resistively heats at least a portion of the formation between the two substantially horizontally oriented or inclined portions of the wellbore.

Systems and methods for treating a subsurface formation with electrical conductors

An oil shale formation may be treated using an in situ thermal process. Heat may be applied to the formation to raise a temperature of a portion of the formation to a pyrolysis temperature. Heat input into the formation may be controlled to raise the temperature of portion at a selected rate during pyrolysis of hydrocarbons within the formation. A mixture of hydrocarbons, H, and/or other formation fluids may be produced from the formation.

In situ recovery from a hydrocarbon containing formation

A method for treating a tar sands formation includes providing heat to at least part of a hydrocarbon layer in the formation from a plurality of heaters located in the formation. The heat is allowed to transfer from the heaters to at least a portion of the formation. A viscosity of one or more zones of the hydrocarbon layer is assessed. The heating rates in the zones are varied based on the assessed viscosities. The heating rate in a first zone of the formation is greater than the heating rate in a second zone of the formation if the viscosity in the first zone is greater than the viscosity in the second zone. Fluids are produced from the formation through the production wells.

Varying properties of in situ heat treatment of a tar sands formation based on assessed viscosities

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Bellaire, TX, United States of America

Harold J Vinegar