Exxonmobil Upstream Research Company

Exxonmobil Research and Engineering Company

Exxonmobil Technology and Engineering Company

Exxonmobile Research and Engineering Company

Yibing Zhang

Limin Song

Scott William Clawson

Mark M Disko

Henry Alan Wolf

Katie M Walker

Geoff Keiser

Berne K Stober

Peter A Gordon

Michael Louis Hergenrother

Patricia H Kalamaras

Mohsen Shahmirzadi Yeganeh

Benjamin S Umansky

Zhen Li

Brian C Seabrook

Harry William Deckman

Ted Alan Long

Thomas M Smith

Timothy G Benish

David A Howell

Brent D Wheelock

Xiaohua Yi

Daniel Patrick Cherney

H Alan Wolf

Robert P Lucchesi

Mohan G Kulkarni

Richard W Flynn

Kenneth W Desmond

Badrinarayanan Velamur Asokan

James S Burns

Michael G Starkey

Patrick M Moore

David M Chorneyko

Pawel L Peczak

Timothy R Bragg

Methods and systems for measuring cluster efficiency for stages of wellbores are provided herein. One method includes selecting a frequency band for generating broadband tube waves within the fluid column of the wellbore and generating the broadband tube waves within the fluid column of the wellbore using a pressure pulse generator that is hydraulically coupled to the wellbore. The method also includes recording data corresponding to the broadband tube waves and reflected broadband tube waves using pressure receivers that are hydraulically coupled to the wellbore. The pressure receivers are arranged into arrays with two or more pressure receivers in each array. The data recorded by the pressure receivers relate to characteristics of reflectors (including perforation cluster/fracture interfaces) within the wellbore. The method further includes processing the recorded data using interferometry and performing full waveform inversion(s) on the processed data to determine frequency-dependent, complex-valued reflection coefficients at each perforation cluster/fracture interface.

Systems and methods for measuring cluster efficiency using broadband tube waves

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

Communication networks, relay nodes for communication networks, and methods of transmitting data among a plurality of relay nodes utilizing non-dispersive guided acoustic waves are disclosed herein. The communication networks include an elongate tubular body and a wireless data transmission network including a plurality of relay nodes. The relay nodes include an electro-acoustic transmitter array and an electro-acoustic receiver. The methods include inducing a first acoustic wave within the elongate tubular body with a first relay node, conveying the first acoustic wave along the elongate tubular body to a second relay node, and receiving the first acoustic wave with the second relay node. The methods further include inducing a second acoustic wave within the elongate tubular body with the second relay node, conveying the second acoustic wave along the elongate tubular body to a third relay node, and receiving the second acoustic wave with the third relay node.

Communication networks, relay nodes for communication networks, and methods of transmitting data among a plurality of relay nodes

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

A method for collecting data relating to characteristics of a wellbore by generating tube waves within the wellbore using an electro-hydraulic discharge (EHD) source includes generating tube waves that propagate within a fluid column of a wellbore using an EHD source, where the fluid column is defined by a casing string within the wellbore. The method also includes allowing at least a portion of the generated tube waves to interact with acoustic impedance boundaries that act as reflectors within the wellbore, creating reflected tube waves that propagate within the fluid column. The method further includes recording data corresponding to the generated tube waves and the reflected tube waves using a receiver, where the recorded data relate to characteristics of the reflectors within the wellbore.

Generating tube waves within a wellbore using an electrohydraulic discharge source

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

Embodiments described herein include an acoustic telemetry system for use with an apparatus configured to rotate. The acoustic telemetry system includes one or more sensor nodes and at least one receiver node. In at least one embodiment, the telemetry system also includes at least one hub node positioned on the apparatus. Each sensor node is attached to or embedded in the apparatus. Each sensor node obtains data related to one or more operating conditions of the apparatus and the environment surrounding the apparatus. The one or more sensor nodes encode and transmit the data to the hub node or the receiver node using ultrasonic acoustic waves. In at least one embodiment, the hub node transmits the data to the receiver node. The receiver node decodes the data and monitors the one or more operating conditions of the apparatus.

Ultrasonic telemetry for rotating sensors

In conjunction with a communication network, for example, a downhole wireless network for transmission of data along a tubular body, disclosed herein are: (1) a variety of hardware interfacing methods with sensors and downhole tools; (2) sensing concepts that are enabled by the unique interfaces; (3) physical implementation of the integrated sensor/communication node structures; (4) related software communication protocols. The interfaces may support both data communication and power transfer.

Downhole wireless communication node and sensor/tools interface

A method and system are described for wirelessly communicating within a wellbore. The method includes constructing a communication network (e.g., which uses aliased signals as part of the configuration) for a wellbore accessing a subsurface region and using the communication network in hydrocarbon operations, such as hydrocarbon exploration, hydrocarbon development, and/or hydrocarbon production.

Method and system for performing communications using aliasing

A method and system are described for wirelessly communicating within a wellbore. The method includes constructing a communication network, which communicates during drilling operations along one or more drilling strings. The communication network is used to perform drilling operations for hydrocarbon operations, such as hydrocarbon exploration, hydrocarbon development, and/or hydrocarbon production.

Method and system for performing wireless ultrasonic communications along a drilling string

A method and system are described for communicating within a system, which may be along tubular members. The method includes constructing a communication network for tubular member, such as a wellbore accessing a subsurface region or a pipeline, and using the communication network in hydrocarbon operations, such as hydrocarbon exploration, hydrocarbon development, and/or hydrocarbon production.

Method and system for performing operations using communications

A petroleum desalting process in which the role played by the oil/bulk-resolved-water interface in the dehydration of the stabilized emulsion which forms in the desalter is recognized. The desalting process is improved by introducing the demulsifier and chemical high voltage electrodes. Water droplets in the mixture coalesce and settle towards the bottom of the vessel. A stabilized emulsion layer formed from the oil and the water with additives into the water phase and/or injecting chemical additives directly in the vicinity of the water/oil interface. This improved methodology that makes the rapid and effective delivery of chemical demulsifiers to the rag layer and/or oil/bulk-resolved-water interface possible. In operation, the desalting is carried out by mixing a crude oil to be desalted with water and passing the mixture of oil and water to the desalter vessel. The mixture enters the desalting vessel in the form of an emulsified mixture which is then separated by application of an electric field between emulsion-stabilizing solids from the oil forms above the interface between the denser water layer and the supernatant oil layer. A chemical demulsifier is added to the water layer in the region of the stabilized emulsion layer and/or directly into the emulsion layer itself. The separated water is removed as effluent through a water outlet at the bottom of the vessel and desalted oil is removed from the oil layer through an oil outlet at the top of the vessel.

Desalter operation

A method and system are described for communicating within a system, which may be along tubular members. The method includes constructing a communication network for a hydrocarbon system, which includes one or more wellbores accessing a subsurface region or a pipeline, and using the communication network in hydrocarbon operations, such as hydrocarbon exploration, hydrocarbon development, and/or hydrocarbon production.

Method and system for performing operations using communications for a hydrocarbon system

Systems and methods for detecting a condition of multi-phase flow through a component with a first sensing cable having a first sensor location and aligned with a heating element and a second sensing cable having a second sensing location a predetermined distance from the first sensing location. A heat pulse is propagated through the heating element. A first temperature profile at the first sensing location and a second temperature profile at the second sensing location, each corresponding to the heat pulse, are measured over time. A flow velocity is determined by correlating the first temperature profile with the second temperature profile. A condition of flow of the media is detected by determining a phase of at least one medium exposed to the sensing cable at the first sensing location based on the first temperature profile and the determined flow velocity.

Method and system for multi-phase flow measurement

Provided are systems and methods for in-situ zonal assessment of multiphase fluid flow in one or more production zones of a production well, including for at least one production zone sensing one or more fluid flow parameters via at least one sensor disposed in a production zone; at least one sensor communications node being in electrical communication with an associated sensor, the at least one sensor communications node positioned along a tubular body in the production zone proximate an associated at least one sensor, and receiving signals from the associated at least one sensor; sending the acoustic signals from the at least one sensor communications node to a receiver at a surface via a series of intermediate communications nodes, node-to-node, the signals being indicative of one or more fluid flow parameters, the series of intermediate communications nodes being spaced along the tubular and configured to transmit acoustic waves; assessing one or more fluid flow parameters for the one or more production zones in response to signals received from a topside communications node.

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Annandale, NJ, United States of America

Yibing Zhang