Natural Gas Solutions North America, LLC

Baker Hughes, a Ge Compnay, LLC

Baker Hughes Corporation

Baker Hughes Oilfield Operations LLC

Richard Jin Yao

Eric Charles Sullivan

Navish Makkar

R Keith Glasgow, Jr

Priscila Farias Ronqui

Otto N Fanini

Chaitanya K Vempati

Kenneth R Evans

Jeff Thomas Martin

Roman Leon Artiuch

Jason R Habernal

Robert Erling Fowler

Albert A Alexy

Paul Lowson

Thomas Nguyen

Ludger E Heuermann-Kuehn

Jeffrey Raynal

Ronald Lewis Strong

Amit Anand Kale

Troy A Falgout

David Burhoe

A sensor unit that is configured to improve the non-contact, magnetic interface on a gas meter. The configurations may include a pair of magnets that co-rotate in response to a magnet internal to the gas meter. At least one of the magnets may also move longitudinally in proximity to the internal magnet. This feature aligns the magnets with one another to ensure proper magnetic coupling with the internal magnet.

Self-locating mechanical interface for a sensor on a gas meter

A manifold assembly configured to measure differential pressure of fluid. The manifold assembly may have a monolithic body with an internally drilled fluid pathway. The body supports a differential pressure transducer that communicates, on either end, with the internally drilled fluid pathway. This configuration can generate data that defines pressure drop across impellers or other mechanisms on metrology hardware (or 'gas meters'). Utilities can use this data to diagnose health or other conditions on the gas meter in the field.

Manifold for measuring differential pressure on a gas meter

A method of determining a rate of penetration of a downhole tool. The method comprises introducing a downhole tool including a drill bit configured to drill through a subterranean formation in a wellbore, the downhole tool comprising at least one reader configured to communicate with identification tags using electromagnetic radiation. The method includes advancing the wellbore with the drill bit and placing, with a component of a bottomhole assembly of the downhole tool, a first identification tag at a first location proximate the wellbore and at least a second identification tag at a second location proximate the wellbore and separated from the first location by a distance. An interrogation signal is transmitting from the at least one reader toward a wall of the wellbore and response signals from the identification tags are received by the at least one reader to determine proximity of the identification tags to the reader. A rate of penetration of the downhole tool is determined, using a processor and associated memory, based at least in part on a distance between identification tags and an amount of time between receiving response signals from a first identification tag and at least a second identification tag. Downhole systems for determining a rate of penetration and other methods are also disclosed.

Downhole system for determining a rate of penetration of a downhole tool and related methods

An earth-boring tool includes a shank. The shank may include a central bore extending partially through the shank. An end-cap may be disposed within the central bore, and the end-cap may include a first flange, a second flange, and a body portion extending between the first flange and the second flange. An annular chamber may be defined between the body portion of the end-cap and an interior wall of the central bore of the shank. At least one strain gauge may be secured to an outer surface of the body portion of the end-cap. At least one stain gauge may be secured to a cap portion welded over a recess formed in the earth-boring tool.

Sensors in earth-boring tools, related systems, and related methods

A gas meter () and like metering systems that are configured for use underwater. The gas meter may embody a positive displacement rotary gas meter having a meter body with impellers that counter-rotate in response to material flow. The gas meter can also comprise an index unit having an electronics assembly to generate a value that equates rotation of impellers with a parameter of the material flow. The gas meter can further comprise a connective interface having a first part and a second part, one each disposed on the meter unit and the index unit, respectively, the first part and the second part coupling with one another to provide data to the electronics assembly, the data corresponding with operating conditions on the meter unit and rotation of the impellers. In one example, the first part and the second part are configured so that the meter unit and the index unit are operable underwater to generate the value.

Gas meter for submerged use

A power generator for use to generate power for metrology hardware like gas meters and flow measuring devices. The power generator may use flame-less combustion that creates heat from fuel gas. The heat causes a temperature differential. The power generator may include a thermal electric generator that generates an electrical signal in response to the temperature differential.

Using flameless combustion of fuel gas to generate power for a gas meter

An energy harvester for use to provide power to metrology hardware like gas meters and flow measuring devices. The energy harvester may include an actuator that mounts to a substrate found in the gas meter or in an adjacent, collateral device like a pressure regulator. The substrate may embody a diaphragm or membrane, possibly a thin, flexible or semi-rigid member. The actuator may include piezoelectric transducers that mount to this member. In operation, the piezoelectric transducers can generate an electrical signal in response to mechanical activity (or energy) from the thin member. The electrical signal can be directed to the flow device to replace, supplement, or recharge a power source that powers electronics necessary to expand functions on the flow meter.

Generating power for electronics on a gas meter

Wellbore sensor systems and related methods are disclosed. A wellbore sensor system includes a first sensor node and a second sensor node. The first sensor node is operably coupled to a drill string at a first location. The second sensor node is operably coupled to the drill string at a second location. A method includes taking first sensor readings from the first sensor node relative to a first spatial frame of reference, and taking second sensor readings from the second sensor node relative to a second spatial frame of reference, and using the first sensor readings and the second sensor readings to estimate parameters of a mathematical transform configured to transform the second sensor readings into the first spatial frame of reference. The method also includes transforming the second sensor readings into the first spatial frame of reference with the estimated mathematical transform.

Multiple downhole sensor digital alignment using spatial transforms

A system and method to determine health prognostics for selection and management of a tool for deployment in a downhole environment are described. The system includes a database to store life cycle information of the tool, the life cycle information including environmental and operational parameters associated with use of the tool. The system also includes a memory device to store statistical equations to determine the health prognostics of the tool, and a processor to calibrate the statistical equations and build a time-to-failure model of the tool based on a first portion of the life cycle information in the database.

Probabilistic determination of health prognostics for selection and management of tools in a downhole environment

A drill bit is disclosed that in one embodiment includes a bit body having a cutting section, a shank attached to the cutting section and a neck section and at least one sensor in contact with a surface of the shank and wherein the at least one sensor provides a signal in response to a bending moment.

Growing community of inventors

The Woodlands, TX, United States of America

Richard Jin Yao