A device and method used to correct beamforming of an acoustic phased array in cases of eccentricity of the acoustic device in a tubular. A processor calculates the eccentricity from multiple scan lines and create a geometric model of a well or pipe relative to the device. The processor may correct each scan line's focus and/or angle of incidence at a surface of the well or pipe based on the observed eccentricity.

Disclosed are systems and methods for processing broadband acoustic signals acquired by a plurality of acoustic sensors, using an array-signal-processing technique to compute fused-signal maps in the frequency domain for a plurality of frequency bins. In accordance with various embodiments, the fused-signal maps are combined across the frequency bins, with respective weightings that are based on eigenvalues of covariance matrices computed for the plurality of frequency bins. The combined maps can be used to locate an acoustic source in a wellbore.

A technique facilitates the use and application of a distributed vibration sensing system in, for example, a well application. The technique enables selection of a desired gauge length to achieve an optimum trade-off between the spatial resolution of a distributed vibration sensing/distributed acoustic sensing system and signal-to-noise ratio. The optimum gauge length can vary according to specific factors, e.g. depth within a well, and the present technique can be used to account for such factors in selecting an optimal gauge length which facilitates accurate collection of data on dynamic strain.

A system includes a first instrumented bridge plug positionable in a downhole wellbore environment. The first instrumented bridge plug includes an acoustic source for transmitting an acoustic signal. The system also includes a second instrumented bridge plug positionable in the downhole wellbore environment. The second instrumented bridge plug includes an acoustic sensor for receiving a reflected acoustic signal originating from the acoustic signal. The reflected acoustic signal being usable to interpret wellbore formation characteristics of the downhole wellbore environment.

Methods and systems for identifying a pay zone in a subterranean formation can include: logging a well extending into the subterranean formation including measuring bulk density, compressional wave travel time and shear wave travel time at different depths in the subterranean formation; calculating elastic attributes including acoustic impedance and compressional velocity-shear velocity ratio at different depths in the subterranean formation; and displaying and analyzing the calculated elastic attributes to identify the low resistivity pay zones.

Monitoring and diagnosing completion during hydraulic fracturing operations provides insights into the fracture geometry, inter-well frac hits and connectivity. Conventional monitoring methods (microseismic, borehole gauges, tracers, etc.) can provide a range of information about the stimulated rock volume but may often be limited in detail or clouded by uncertainty. Utilization of DAS as a fracture monitoring tool is growing, however most of the applications have been limited to acoustic frequency bands of the DAS recorded signal. In this paper, we demonstrate some examples of using the low-frequency band of Distributed Acoustic Sensing (DAS) signal to constrain hydraulic fracture geometry. DAS data were acquired in both offset horizontal and vertical monitor wells. In horizontal wells, DAS data records formation strain perturbation due to fracture propagation. Events like fracture opening and closing, stress shadow creation and relaxation, ball seat and plug isolation can be clearly identified. In vertical wells, DAS response agrees well with co-located pressure and temperature gauges, and illuminates the vertical extent of hydraulic fractures. DAS data in the low-frequency band is a powerful attribute to monitor small strain and temperature perturbation in or near the monitor wells. With different fibered monitor well design, the far-field fracture length, height, width, and density can be accurately measured using cross-well DAS observations.

A sensor system may be used to measure characteristics of an object in a wellbore. The sensor system may include an ultrasonic transducer that generates an ultrasonic wave in a medium of the wellbore and detects a reflection signal of the ultrasonic wave off the object in the wellbore. The sensor system may also include a processing device and a memory device in which instructions are stored. The memory may include instructions that cause the processing device to receive the reflection signal from the ultrasonic transducer, and to truncate and preprocess the reflection signal to generate a truncated reflection signal. The instructions may also cause the processing device to apply time gain compensation to the truncated reflection signal and determine an echo wavelet from the time gain compensated signal representing an echo of the ultrasonic wave off of a wall of the wellbore.

A method may include obtaining various well logs or various core samples regarding a geological region of interest. The method may further include determining various permeability values, various porosity values, and various dolomite volume fraction values regarding the geological region of interest using the well logs or the core samples. The dolomite volume fraction values may correspond to a percentage of dolomite in a total mineral volume. The method may further include determining, using the porosity values, various permeability thresholds corresponding to various predetermined reservoir qualities. The method may further include generating, using the permeability thresholds, the permeability values, and the dolomite volume fraction values, a reservoir model including various dolomite boundaries defining the predetermined reservoir qualities. The method may further include determining a hydrocarbon trap prediction using the reservoir model.

This disclosure describes systems, methods, and apparatuses for preventing wireline sticking during hydraulic fracturing operations, the system comprising: a sensor coupled to a fracking wellhead, circulating fluid line, or standpipe of a well and configured to convert acoustic vibrations measured in fracking fluid in the wellhead, fluid line, or standpipe into an electrical signal in a time domain; a memory configured to store the electrical signal; a converter configured to access the electrical signal from the memory and convert the time domain electrical signal into a frequency domain spectrum; a machine-learning system configured to classify the current frequency domain spectrum as associated with increasing wireline friction, the machine-learning system trained on previous frequency domain spectra measured during previous wireline operations and previously classified by the machine-learning system; and a user interface configured to return an indication of the increasing wireline friction to an operator of the hydraulic fracturing operations.

An active fiber stretcher assembly can be used for data acquisition systems. A time-break signal can be detected that coincides with a seismic event emitted from a seismic controller. A predetermined waveform can be generated in response to detecting the time-break signal. The predetermined waveform may be encoded onto a fiber optic cable using a fiber stretcher. A data acquisition system connected to the fiber optic cable may detect the predetermined waveform on the fiber optic cable and initiate acquisition operations including: receiving, during the seismic event, light signals returning from a portion of the fiber optic cable in a subterranean environment; determining one or more characteristics of the subterranean environment from the light signals; and storing the one or more characteristics.