Exxonmobil Research and Engineering Company

Exxonmobil Upstream Research Company

Exxonmobil Technology and Engineering Company

Vega Grieshaber Kg

Ohio University

Henry Alan Wolf

David Lawrence Chu

Limin Song

Yibing Zhang

Mark M Disko

Scott William Clawson

Katie M Walker

Manuel S Alvarez

Max Deffenbaugh

Timothy I Morrow

Anastasios I Skoulidas

David Samuel Deutsch

James Edward Feather

Brian C Seabrook

Alan M Schliowitz

Josef Fehrenbach

Glen Barry Brons

Mohsen Shahmirzadi Yeganeh

Krishnan Kumaran

Ted Alan Long

Alan Mark Schilowitz

Thomas M Smith

Stuart Ronald Keller

Saul Charles Blum

Martin Mellert

Shiun Ling

Richard John Basile

David A Stiles

Jason B English

James S Burns

George Akehurst

Fang Cao

Timothy R Bragg

Srdjan Nesic

Peng Jin

Gheorghe Bota

Philip J Cacciatore

James Mclaughlin

Anastasios Ioannis Skoulidas

Alan M Schilowitz

Saul C Blum

Ying Zhang

A method of measuring a pressure of a fluid adjacent a wall of a pipe or vessel. A transducer is attached to the wall of the pipe or vessel. A signal is transmitted by the transducer at a characteristic frequency via a plurality of guided wave modes. The characteristic frequency is a frequency at which the guided wave modes are separated in time from each other when received. The signal is received after the plurality of guided wave modes travel in or through the wall a predetermined number of times. The signal has a signal receipt time after the predetermined number of times. The pressure of the fluid is calculated using the signal receipt time.

Apparatus and method for non-intrusive pressure measurement and early identification of solids formation using selected guided ultrasonic wave modes

Methods and systems for measuring pipe parameters using guided acoustic wave modes are provided. The method includes receiving data corresponding to an acoustic signal, wherein the data are obtained by transmitting an excitation pulse at a specified frequency and detecting the resulting acoustic signal using an acoustic transducer attached to the outer surface of the pipe wall. The method includes analyzing the data to identify guided acoustic wave modes including at least two of: a C-SH acoustic wave mode that travels within the pipe wall; a C-LT acoustic wave mode that travels within the near-surface region of the pipe wall; and/or a CA acoustic wave mode that travels within the pipe cavity. The method includes calibrating the parameter measurement using the C-SH acoustic wave mode and determining the parameter measurement based on the phase velocity and/or the amplitude of the C-LT acoustic wave mode and/or the CA acoustic wave mode.

Non-intrusive detection of pipe parameters using selected guided acoustic wave modes

Pet chew

For a monitored corrosion sensor, such as a sensor based on one or more mechanical oscillators disposed in a fluid flow, one or more values are measured over time. The values can be measured at a desired frequency, such as a once per second, once per minute, or another convenient frequency. The measured data can then be analyzed as a time series. The goal of the analysis is to identify variations in the time series data that are sufficiently unexpected relative to the prior behavior of the time series within a given time window. The identified variations can then, for example, be excluded from consideration when determining a corrosion-related value for the sensor.

Detection of corrosion rates in processing pipes and vessels

An electro-acoustic communications node system and method for downhole wireless telemetry, the system including a housing for mounting to or with a tubular body; a receiver transducer positioned within the housing, the receiver transducer structured and arranged to receive acoustic waves that propagate through the tubular member; a transmitter transducer and a processor, positioned within the housing and arranged to retransmit the acoustic waves to another acoustic receiver in a different housing, using the tubular member for the acoustic telemetry. In some embodiments, the transducers may be piezoelectric transducers and/or magnetostrictive transducers. Included in the housing is also a power source comprising one or more batteries. A downhole wireless telemetry system and a method of monitoring a hydrocarbon well are also provided.

Dual transducer communications node for downhole acoustic wireless networks and method employing same

Methods of acoustically communicating and wells that utilize the methods are disclosed herein. The methods generally utilize an acoustic wireless network including a plurality of nodes spaced-apart along a length of a tone transmission medium and include determining a major frequency of a received acoustic tone transmitted via the tone transmission medium.

Methods of acoustically communicating and wells that utilize the methods

Provided is an acoustic housing including a cover including a first perimeter defining an open cover portion, the cover having a cover length, and a cover height, and a body including a second perimeter defining an open body portion, wherein either the first or second or both perimeters are chamfered, configured to receive one or more electrical components and to sealingly engage with the first chamfered perimeter, the body having a body length, a body height, and an under-surface, and the body including an engagement portion projecting from the under-surface and having an engagement length, an engagement height, and an engagement surface configured to engage an outer surface of a tubular.

Acoustic housing for tubulars

Methods of acoustically communicating acoustically within a wellbore and wells that utilize the methods are disclosed herein. The methods generally utilize an acoustic wireless network including a plurality of nodes spaced-apart along a length of a tone transmission medium. In some embodiments, the disclosure includes methods of conserving power in the acoustic wireless network.

Methods of acoustically communicating and wells that utilize the methods are disclosed herein. The methods generally utilize an acoustic wireless network including a plurality of nodes spaced-apart along a length of a tone transmission medium. In some embodiments, the methods include methods of communicating when the acoustic wireless network is spectrum-constrained.

A system for downhole telemetry is provided herein. The system employs a series of communications nodes spaced along a tubular body either above or below ground, such as in a wellbore. The nodes allow for wireless communication between one or more sensors residing at the level of a subsurface formation or along a pipeline, and a receiver at the surface. The communications nodes employ electro-acoustic transducers that provide for node-to-node communication along the tubular body at high data transmission rates. A method of transmitting data in a wellbore is also provided herein. The method uses a plurality of data transmission nodes situated along a tubular body and a specially configured network to accomplish a wireless transmission of data along the wellbore using acoustic energy.

Telemetry for wireless electro-acoustical transmission of data along a wellbore

A system for downhole telemetry is provided herein. The system employs a series of communications nodes spaced along a tubular body either above or below ground, such as in a wellbore. The nodes allow for wireless communication between one or more sensors residing at the level of a subsurface formation or along a pipeline, and a receiver at the surface. The communications nodes employ electro-acoustic transducers that provide for node-to-node communication along the tubular body at high data transmission rates. A method of transmitting data in a wellbore is also provided herein. The method uses a plurality of data transmission nodes situated along a tubular body to accomplish a wireless transmission of data along the wellbore using acoustic energy.

Telemetry system for wireless electro-acoustical transmission of data along a wellbore

A method for determining the amount and rate of corrosion which has occurred on the surface of a process unit by measuring corrosion with a corrosion sensor and measuring at least one parameter inside the process unit. Corrosion on the internal surfaces of a process unit can then be determined.

Method for quantifying corrosion at a pressure containing boundary

A system and method for optimizing the response of a metal loss sensor which is configured in a way that its insertion depth and orientation in the process fluid are adjustable. These adjustments affect local turbulence and thereby enable achieving a desired corrosion rate at the metal loss sensor. Corrosion rate comparison between the metal loss sensor and pressure containment boundary can be measured directly or indirectly by computing wall shear stresses at the sensor and the pressure containment boundary.

System and method for enhancing corrosion rate determination in process equipment using a telescoping/rotating sensor

A device is coupled to a heat exchanger for mitigating fouling by applying a mechanical force to a fixed heat exchanger to excite a vibration in the heat exchange surface and produce shear waves in the fluid adjacent the heat exchange surface while the heat exchanger is in operation. An electromagnetic driven impulse device induces vibration onto heat exchanger tubes and/or an acoustic wave through the liquid service fluid to reduce fouling. The device can be mounted directly onto the outer part or piping and produces acoustical/vibrational modes onto the tube or near the surface of tubes.

Device for generating acoustic and/or vibration energy for heat exchanger tubes

The present invention is a mechanical oscillator for detection and measurement of corrosive foreign materials. The elements include a mechanical oscillator that is mechanically excited, wherein the mechanical oscillator has a resonant frequency, f, and a quality factor, Q. A fuse fixed to the oscillator to change oscillator amplitude to and from essentially zero to resonance amplitude. In a preferred embodiment, the mechanical oscillator has the shape of a tuning fork where one region is compatible with the service fluid and the other region is incompatible with the service fluid or other contaminant. The sensor alarms when a measured amount of the incompatible material has been removed or the physical strength of the material has been compromised.

Mechanical oscillator activated or deactivated by a predetermined condition

Growing community of inventors

Morris Plains, NJ, United States of America

Henry Alan Wolf