Abstract: A method for determining the presence and bonding characteristics of elements which may include cement which may be bonded to a pipe string. The method for determining the presence and bonding may comprise disposing an acoustic logging tool in a wellbore, wherein the acoustic logging tool comprises a transmitter and a receiver, broadcasting a pressure pulse with the transmitter into a first material, wherein the pressure pulse reflects off an interface of the first material and a pipe string as a reflected pressure pulse, recording the reflected pressure pulse with a receiver, and determining an integrity of a material using a Quintero Wellbore Index.

Abstract: A system for near-surface subsurface imaging for detecting and characterizing subsurface heterogeneities comprises a non-contact acoustic source that senses a plurality of acoustic waves that travel through a surface; an instrument that outputs probing electromagnetic signals through the surface that interact and are affected by scattered signals of the acoustic waves and further senses vibrational modes of a subsurface below the surface; an imaging device that dynamically generates a time sequence of images of properties of the acoustic waves and maps elastic wave fields of the acoustic waves; and a processor that analyzes dynamic multi-wave data of the images to quantify spatial variations in the mechanical and viscoelastic properties of the subsurface.

Abstract: Downhole tools and method for a well. At least some of the example embodiments are methods of imaging a formation around a first borehole, including: focusing first outbound acoustic energy, launched from a tool with the first borehole, on a volume within the formation spaced away from the first borehole, the focusing creates a first virtual point source (VPS) that creates a first return acoustic energy; receiving the first return acoustic energy from the first VPS at a plurality of seismic sensors; and determining a parameter of the formation between the first VPS and a location of the seismic sensors using the first return acoustic energy.

Abstract: Some methods of scale and corrosion monitoring of a well include receiving information from a plurality of transducers disposed in a ring on a circumference of a tubing of the well, the received information including frequency domain information representing a first longitudinal ultrasonic wave and a first torsional ultrasonic wave to arrive at the plurality of transducers; determining arrival times for the first longitudinal ultrasonic wave and the first torsional ultrasonic wave to arrive at the plurality of transducers based on the received information; comparing the determined arrival times with a range of predetermined arrival times from a model that accounts for wave refraction using a ray tracing scheme to determine a wall thickness of the tubing, a scale thickness of scale within the tubing, and a scale shear wave velocity of the scale; and identifying a material of the scale based on the determined scale shear wave velocity.

Abstract: A logging tool for performing well logging activities in a geologic formation has one or more transmitters, one or more receivers, and a tool wave propagating factor which differs from a formation wave propagating factor. The one or more transmitters excite a tool wave and formation wave. The tool wave is reduced by the one or more transmitters transmitting an acoustic wave which causes the tool wave to be reduced. Additionally, or alternatively, the tool wave is reduced by generating an inverse estimate of the tool wave based on waveform data associated with the tool wave and formation wave received by each of the one or more receivers.

Abstract: A system can generate and output boundary lines for controlling a drilling operation. The system can receive data, including an offset well surveys, measuring instrument information, and a well casing diameter, about offset wells in a subterranean formation. The system can determine reference well values. The system can generate boundary lines for the offset wells based on the received data and the calculated reference well values. The system can adjust the boundary lines, and can output the adjusted boundary lines for controlling a drilling operation.

Abstract: A vibration-damping sub is provided to mitigate shock and other sources of vibration in a tool string. In examples, a tubular damping body is rigidly coupled between a vibration-sensitive tool and a vibration source. The tubular damping body includes a tubular wall defining a plurality of shaped holes configured to dampen the mechanical vibration to below the design threshold for the vibration-sensitive tool. The tubular damping body may also include different portions having different materials and impedances to further disrupt the propagation of mechanical waveforms.

Abstract: The application discloses an AI real-time microseism monitoring node, which includes a processor and a data acquisition device, an AI calculation device, and a communication device connected to the processor, wherein the AI calculation device is provided with pre-trained microseism data analysis Device, and the processor is configured to perform the following operations: controlling the data acquisition equipment to acquire microseism data; turning on the AI calculation device to calculate the acquired microseism data by means of the microseism data analysis device to determine the valid event data associated with the microseism; and sending the valid event data to the remote data center through the communication device.

Abstract: Systems and methods for picking seismic stacking velocity based on structures in a subterranean formation include: receiving seismic data representing a subterranean formation; generating semblance spectrums from the seismic data representing the subterranean formation; smoothing the semblance spectrums; and picking stacking velocities based on the smoothed semblance spectrums.

Abstract: A method and system method for determining motion of a downhole tool and feeding back drilling performance. The method may comprise taking a synchronous tool face measurement of the downhole tool, taking a synchronous pulse-echo acquisition to estimate a shape of a borehole, inputting at least the shape of the borehole, the center trajectory of the downhole tool, the rotational time of the downhole tool, the position of the downhole tool, and the one or more measurements of the downhole tool into an information fusion for drilling dynamics, identifying at least one of a whirl, a vibration, or a stick-slip of the downhole tool, and identifying one or more borehole condition and a drilling efficiency. A system may comprise a downhole tool, at least two transducers, and an information handling system.

Abstract: Apparatus (10) and methods for measurement of pore pressure in rock formations through a metal borehole casing (32) after a well is cased and cemented, are described. Such measurements may be accomplished by using the Dynamic Acoustic Elasticity (DAE) method for characterizing nonlinear parameters by perturbing a selected rock formation region with a High Amplitude, Low Frequency (HALF) acoustic strain wave, and probing this region using a Low Amplitude, High Frequency (LAHF) acoustic wave (18), (22). Time reversal techniques (36) may be employed for focusing acoustic energy into the formation in the vicinity of the pipe or open hole. The change in wave speed of the probe pulses as the HALF induced strain wave oscillation propagates through the formation, as a function of the induced strain, may be used to determine the nonlinear elastic parameters ?, ?, ?, and A of the pore pressure, from which the pore pressure may be determined in the region of the HALF wave.

Abstract: Embodiments of the disclosure can include systems and methods for removing in-situ noise from well logging data. In one embodiment, a method can include acquiring noise-calibration data for a logging tool, (the noise-calibration data including data obtained by the logging tool operating under one or more calibration conditions), generating a noise-signature waveform for the logging tool based at least in part on the noise-calibration data, acquiring logging data from the logging tool (the logging data including data obtained by the logging tool operating in a wellbore under one or more operating conditions), generating, based at least in part on the logging data, an uncorrected logging waveform for the logging tool operating in the wellbore under the one or more operating conditions, and modifying the uncorrected logging waveform based at least in part on the noise-signature waveform to generate a corrected logging waveform for the wellbore.

Abstract: A downhole acoustic tool and method of use are provided. The acoustic tool includes an acoustic tool body. In addition, a transmitter section located along the acoustic tool body, including four or more transmitters to be driven so as to excite multi-mode waveforms. The acoustic tool further includes an array receiver section located along the acoustic tool body, containing a receiver sub-section comprising four or more receivers axially aligned with the four or more transmitters and spaced axially apart from the transmitter section. The acoustic tool also includes a processor configured to drive the transmitter section to excite multi-mode waveforms and to extract the multi-mode waveforms detected by the receiver section for interpretation of formation properties. A method for measuring a formation using the described acoustic tool is also provided.

Abstract: A method for determining properties of rock formations using drill string vibration measurements includes entering into a processor signals corresponding to vibrations detected along a rotating part of a drill string while drilling a borehole. The vibration signals are transformed into transformed signals representing elastic response of the drill string, the rock formations and borehole fluid to a filtered impulse originating at a known location along the drill string. Properties of the rock formations are calculated using the transformed signals.

Abstract: A downhole tool having a transmitter array with azimuthally spaced transmitters and receiver arrays with azimuthally spaced receivers. Methods of operation include transmitting an acoustic signal from an individual one of the transmitters, sensing an attribute of the acoustic signal with the receivers, and evaluating a characteristic of a portion of a downhole feature based on response signals generated by the first and second receivers. Each response signal is indicative of the acoustic signal attribute sensed by the corresponding receivers. This is repeated with different individual ones of the transmitters and receivers until the evaluated portions of the downhole feature collectively extend around a wellbore.

Abstract: Modeling an elastic stiffness tensor in a transverse isotropic subsurface medium acquires well log data for at least one well passing through the transverse isotropic subsurface medium. The transverse isotropic subsurface medium is divided into an effective anisotropic layer and an isotropic layer. The effective anisotropic layer elastic parameters are modeled, and the isotropic layer elastic parameters are modeled using the effective anisotropic layer elastic parameters and the acquired well log data. The modeled effective anisotropic layer elastic parameters and the modeled isotropic layer elastic parameters are used to upscale the effective anisotropic layer and the isotropic layer into the transverse isotropic subsurface medium comprising a single layer and to determine the five members of the elastic stiffness tensor for the transverse isotropic subsurface medium.

Abstract: Examples of techniques for deployment risk management are disclosed. In one example implementation according to aspects of the present disclosure, a computer-implemented method may include: receiving, by a processing device, operating parameters for simulating a well operation job; simulating, by the processing device, the well operation job based on the operating parameters to generate a script for performing the well operation job, wherein the script comprises an ordered plurality of tasks and corresponding task parameters; and performing the well operation job based on the script generated by the simulation.

Abstract: Method and system of estimating a shape of a borehole include receiving data points associated with a standoff measurement for the borehole, wherein each data point includes a radial distance value and an azimuthal value corresponding to the radial distance value. The method and system determine point-to-point angles for the data points based on at least the azimuthal value associated with each data point, wherein each point-to-point angle spans between two adjacent data points. The method and system select a geometric shape from a plurality of geometric shapes to fit to the data points based on the point-to-point angles, the plurality of geometric shapes including a circle and an ellipse. A shape of the borehole is estimated at a location of the standoff measurement based on the selected geometric shape.

Abstract: Embodiments of a method for detecting well integrity failure are disclosed herein. In general, embodiments of the method utilize seismic signals for detection. In particular, embodiments of the method may use recording of passive or active seismic signals. Further details and advantages of various embodiments of the method are described in more detail in the application.

Abstract: The processing of multicomponent induction (“MCI”) data in non-circular, or elliptical, boreholes is achieved through the use of borehole formation models generated using elliptical borehole characteristics.

Abstract: In some embodiments, an apparatus, method, and a system may operate to include an AEM sensor configured to generate an electromagnetic wave into a geologic formation. The AEM sensor is further configured to receive a reflected electromagnetic wave from the formation. The reflected electromagnetic wave is representative of a velocity of an acoustic wave traveling through the geologic formation.

Abstract: A downhole tool for real-time caliper measurements is provided. The downhole tool comprises multiple acoustic transducers mounted at different positions of the tool, and a control system. The control system drives the multiple transducers, receives pressure echo signals from the transducers, records the pressure echo signals in the memory, extracts data of two-way transit time and echo amplitude from the echo signals, and computes at least one of a borehole diameter, a tool center position, and an acoustic slowness or velocity of downhole fluid, based on the data of transit time and echo amplitude.

Abstract: The present invention proposes a method and apparatus of determining stiffness coefficients of formation, wherein the method comprising: setting up a relation of stiffness coefficients of formation C11 and C33, C44, C66 based on stiffness coefficients of a formation core sample; computing clay content of formation along depth continuously based on formation logging information; computing the stiffness coefficient of formation C33 along depth continuously based on a P-wave velocity and a volume density of the formation; computing the stiffness coefficient of formation C44 along depth continuously based on a S-wave velocity and a volume density of the formation; and then computing the stiffness coefficients of formation C11 and C66 along depth continuously based on the calculations above, the relation of stiffness coefficients of formation C11 and C33, C44, C66, and a relation of an anisotropy coefficient of the P-wave of the formation and its clay content or a relation of an anisotropy coefficient of the S-wav

Abstract: An acoustic tool for evaluating a geologic formation includes a housing member disposed between transmitter and receiver sections of the acoustic tool. The housing member defines a change in direction in an acoustic path extending therethrough such that acoustic signals traveling through the housing member are delayed and disrupted. The delay and disruption may isolate the acoustic signals traveling through the housing member from acoustic signals traveling through the geologic formation. Thus, the acoustic tool may facilitate identification and evaluation of acoustic signals traveling through the geologic formation.

Abstract: Embodiments relate to calculating a journey time for a planned journey between a chosen origin and a chosen destination over a network of roads in a region. A first journey time for the journey is estimated using a route scheduling algorithm and a second journey time for the journey is estimated using selected historical journeys characterized by journey origins and destinations. The historical journeys are selected based on their vicinity to the planned journey. An error in the second journey time is calculated based on the standard deviation in the selected historical journeys. The second journey time is selected as the estimated journey time from the planned journey if this error is below a defined threshold, otherwise the first journey time is selected as the estimated journey time for the planned journey.

Abstract: A method can include receiving data that characterizes anisotropy of a formation; receiving a model that models one or more planes of weakness in an anisotropic formation; and, based at least in part on the model and the data, outputting information germane to stability of a bore in an anisotropic formation.

Abstract: A wellbore tool string includes a combination of acoustic inspection tool(s) and electro-mechanical inspection tool(s). The tool string is configured to combine acoustic with electro-mechanic wellbore inspection to circumvent limitations that both technologies may be subject to in wellbore environments. Anomalous data from one or more acoustic tools can be correlated with data acquired by an electro-mechanical tool incorporated into the same tool string to determine wellbore conditions that may have adversely affected the operation of the acoustic tool(s).

Abstract: Apparatus having a focused transducer and methods of operating a focused transducer downhole in a well can provide high resolution downhole imaging. In various embodiments, a focused transducer is used for imaging downhole in a well in which the imaging is based on a seismoelectric effect. In various embodiments, a focused transducer is used for imaging downhole in a well in which the imaging is based on an electroacoustic effect. Additional apparatus, systems, and methods are disclosed.

Abstract: Maximum and minimum horizontal stresses are estimated using radial profiles of shear moduli for a deviated borehole. Inversion enables estimation of maximum and minimum horizontal stresses using radial profiles of three shear moduli associated with an orthogonal set of axis defined by the deviated borehole azimuth from the North and the deviation of the longitudinal axis of the borehole from the vertical.

Abstract: A downhole measurement apparatus includes a tool body supporting a logging tool. The logging tool includes a detector outsert coupled into and exposed through an exterior pocket of the tool body to position the outer surface of the outsert adjacent or in close proximity to the outer diameter of the tool body. A stabilizer or off-center stabilizer may be provided to further deflect the outsert portion of the logging tool toward an earth formation to increase detector proximity to the formation. Radial and axial distances can be calibrated and maintained across multiple different tool collars.

Abstract: A method of generating an axial shear wave in a formation surrounding a wellbore comprising urging a clamp pad into contact with a wall of the wellbore, and applying an axial force to the clamp pad to impart a shear force into the wall of the wellbore to generate a shear wave in the formation.

Abstract: A method for visualizing parametric logging data includes interpreting logging data sets, each logging data set corresponding to a distinct value of a progression parameter, calculating a geometric image including a representation of data from each of the logging data sets corresponding to a wellbore measured depth, and displaying the geometric image(s) at a position along a well trajectory corresponding to the wellbore measured depth. The progression parameter includes time, a resistivity measurement depth, differing tool modes that are sampling different volumes of investigation, and/or sampling different physical properties. The geometric images include a number of parallel lines having lengths determined according to the logging data and/or an azimuthal projection of the logging data, a number of concentric axial projections, and/or shapelets determined from parallel lines and/or concentric axial projections.

Abstract: A method of processing downhole measurement data includes: receiving formation measurement data generated by a downhole tool during a logging-while drilling operation over a selected time period; receiving a measured depth corresponding to the selected time period based on data taken at a surface location; receiving tool rotation data generated by measurements of a rotational rate of the downhole tool taken by a downhole sensor during the selected time period; calculating a new depth of the tool as a function of time over the selected time period based on a relationship between the tool rotation data and the measured depth; and correcting an original depth of the measurement data with the new depth.

Abstract: There is provided a radar system that includes an emitter system (e.g., an antenna), configured to emit electromagnetic pulses and detect electromagnetic pulses, and a reflection target, placed opposite the emitter system. The emitter system and the reflection target define an area of interest. A controller is configured to identify a reflection from the reflection target and, if the reflection is not identified, to stop sending a radar check signal. The radar system may be part of a warning horn control system, where the radar check signal is used as a control input for activating a warning horn.

Abstract: A system and method to synchronize distributed measurements in a borehole are described. The system includes a plurality of wired segments coupled together by couplers and a plurality of nodes configured to measure, process, or relay information obtained in the borehole to a surface processing system, each of the plurality of nodes comprising a local clock and being disposed at one of the couplers or between couplers. The system also includes a surface processing system coupled to a master clock and configured to determine a time offset between the master clock and the local clock of an nth node among the plurality of nodes based on a downhole generated synchronization signal.

Abstract: Techniques for estimating velocity ahead of a drill bit include generating seismic waves at a surface from at least two different source positions in the vicinity of a borehole, receiving seismic waves reflected from a reflector ahead of the drill bit at one or more locations in the borehole, determining travel times of the seismic waves received at the one or more locations in the borehole, and inverting the travel times to determine a velocity of a formation ahead of the drill bit. One embodiment includes transforming the velocity into pore pressure of the formation.

Abstract: A downhole tool starts recording seismic energy. During the recording time, a surface seismic source is activated a specified number of times with a nominally defined separation between successive. The downhole sensor receives seismic waves resulting from the activation, but the time of the shooting sequence is not known downhole. The recorded data stream is processed and converted in real-time into seismic traces. A predefined number of traces are stacked and the quality of this sliding stack is used to detect time of the shooting sequence. The method could be used to detect one or several shooting sequences during a measurement window.

Abstract: An apparatus for use in a wellbore is provided that in one embodiment may include at least one transmitter configured to generate acoustic signals in the wellbore, at least one receiver configured to receive acoustic signals from a formation surrounding the wellbore in response to the transmitted acoustic signal and also configured to provide electrical signals representative of the received acoustic signals, a circuit configured to apply a time-variable gain to the electrical signals to amplify the electrical signals, and a processor configured to process the amplified electrical signals and provide a property of interest.

Abstract: A disclosed example method includes providing, in a borehole, a transmitter (Tx) and receivers (Rxs) spaced linearly from Tx at known distances, measuring linear propagation times (LPts) for a signal to propagate from Tx to each of Rxs, determining an inline velocity (VINL) based on LPts, measuring reflection times (Rts) for a signal to propagate from Tx to each of the Rxs via a boundary, for each of Rts, providing a time-distance anisotropic velocity (TDAV) relationship depending on an effective signal velocity (ESV) in an anisotropic formation adjacent the boundary as a function of reflection angle for the reflection time signal to the boundary, VINL and orthogonal velocity, performing semblance processing to combine the TDAV relationships with VINL for a best-fit calculation of the ESVs for the different reflection angles of the reflection time signals, and calculating a distance for the corresponding receiver to the boundary on the calculation.

Abstract: A method for measuring three-dimensional coordinates of a probe center includes: providing a spherically mounted retroreflector; providing a probe assembly; providing an orientation sensor; providing a coordinate measurement device; placing the spherically mounted retroreflector on the probe head; directing the first beam of light from the coordinate measurement device to the spherically mounted retroreflector; measuring the first distance; measuring the first angle of rotation; measuring the second angle of rotation; measuring the three orientational degrees of freedom based at least in part on information provided by the orientation sensor; calculating the three-dimensional coordinates of the probe center based at least in part on the first distance, the first angle of rotation, the second angle of rotation, and the three orientational degrees of freedom; and storing the three-dimensional coordinates of the probe center.

Abstract: Systems, apparatuses and methods for neural network signal processing of microseismic events. A series of sensors are disposable in at least one first well positioned about a second well disposed in a subterranean formation. The series of sensors obtain a data signal measurement including noise events and microseismic acoustic emission events. A processor includes a first neural network. The processor may remove the noise events from the data signal measurement and determine with the first neural network an arrival time for each microseismic acoustic emission event. An interface can output the arrival time for each microseismic acoustic emission event.

Abstract: An ultrasonic imaging method is provided. A wideband acoustic pulse is fired at a wall. A wideband response signal is received. The wideband response signal is processed to select an impedance measurement frequency. A wavelet having a characteristic frequency approximately equal to the impedance measurement frequency is fired. A wavelet response signal is received. A reflection coefficient is determined from the wavelet response signal. An impedance measurement is calculated from the reflection coefficient. Related tools and systems are also disclosed.

Abstract: A method for determining relative location of an acoustic event along a channel such as a wellbore includes obtaining two acoustic signals at are obtained at two different and known depths in the wellbore, dividing the acoustic signals into windows, and determining the relative loudnesses of pairs of the windows. The power of the acoustic signals may be used as a proxy for the loudness of the acoustic event, and this determination can be made in the time or frequency domains. The relative depth of the acoustic event can then be determined relative to the two known depths from the relative loudnesses. The acoustic event may be, for example, casing vent flow, gas migration, a leak along a pipeline, or sounds observed in an observation well from a nearby well in which fracking is being performed.

Abstract: A system and method for measuring a formation property in a wellbore is disclosed. In the method, an acoustic measurement tool is introduced into a wellbore. The acoustic measurement tool may include a transmitter and a plurality of sensors. At least one of the plurality of sensors may be positioned in a non-uniform spacing configuration. The transmitter may transmit energy into the formation. The plurality of sensors may measure energy received from the formation. Additionally, a time semblance of the formation may be determined using at least one time semblance algorithm generalized for non-uniform sensor spacing.

Abstract: Refracted ultrasonic waves are utilized to calculate tool standoff. An ultrasonic transmitter sends a wave toward (and into) the borehole wall at a critical incidence angle for refracted waves. The refracted wave travels along the borehole wall and continuously radiates energy back into the borehole at the critical angle. The refracted wave is detected by a receiver, and the travel time of the refracted acoustic wave from transmitter to receiver is measured and used to calculate standoff. By making repeated measurements at various azimuths (for instance, as the tool rotates), one or more caliper measurements can be made. The caliper measurements can be combined to yield two-dimensional geometry of the borehole. Measurements made at different azimuths and depths yield three-dimensional borehole geometry. Arrays of transmitter-receiver pairs can be used to obviate the need for varying azimuth.

Abstract: An illustrative embodiment of a method is disclosed for assessing image quality of a down hole formation image, the method comprising collecting acquisition system data from a plurality of sensors down hole; applying a set of rules to the acquisition system data to obtain an acquisition quality indicator; and presenting the acquisition quality indicator at a surface location. A system is disclosed for performing the method.

Abstract: Disclosed are various embodiments of methods for determining the velocity of seismic energy in geologic layers using Seismic Emission Tomography (SET) imaging of drill bit noise, by recording microseismic data during a drilling operation, recording the time and the position of a drill bit in a well bore during the drilling operation, processing the microseismic data using SET software to image microseismic events proximate a known time and position of the drill bit using an estimated velocity model, computing the difference between the known time and position of the drill bit and the time and position of the microseismic event determined from the SET data, varying the estimated velocity model to minimize the difference between the known time and position of the drill bit and the time and time and position of the microseismic event determined from the SET data.

Abstract: Disclosed are various embodiments of methods for identifying faults and fractures, and other permeable features, within geologic layers during a drilling operation comprising; recording microseismic data during a drilling operation; recording times and positions of a drill bit in a well bore during the drilling operation; processing microseismic data at a plurality of selected times and locations to image microseismic events and identifying faults and fractures, and other permeable features, from corresponding images of microseismic events.

Abstract: A downhole tool for subsurface disposal is provided. The tool comprises an elongated tool body, an enclosure attached to an exterior surface of the tool body. The enclosure comprises at least one transducer disposed at an angle with respect to a longitudinal axis of the enclosure, and an electronics board coupled to and disposed adjacent to the at least one transducer. The enclosure also defines an internal cavity, and the internal cavity contains a fluid for insulating the at least one transducer from a downhole environment. The fluid is in direct contact with the at least one transducer and the electronics board.

Abstract: A walkaway VSP survey is carried out using a receiver array. Using a vertical VSP survey and arrival times of surface multiples on the walkaway VSP, vertical interval velocities and the anisotropy parameters ? and ? are estimated. This may then be used to process surface seismic data to do a prestack depth migration of surface seismic data and used for interpretation. For multi-azimuthal walkaway or 3D VSP data, we determine two VTI parameters ? and ? for multi-azimuth vertical planes. Then we determine five anisotropic interval parameters that describe P-wave kinematics for orthorhombic layers. These orthorhombic parameters may then be used to process surface seismic data to give a stacked image in true depth and for the interpretation purposes.