Abstract: Apparatus, methods, and systems for determining body wave slowness values for a target formation zone. A method includes selecting a target axial resolution based on the size of a receiver array, obtaining a plurality of waveform data sets corresponding to a target formation zone and each acquired at a different shot position, reconstructing the plurality of waveform data sets to generate a plurality of subarray data sets corresponding to the target formation zone, determining a slowness value for each subarray data set and determining a slowness versus offset value for each subarray data set. The method may also include generating a borehole model having at least one alteration formation zone and a virgin formation zone and generating a slowness versus offset model based at least in part on the borehole model. The method may also include determining a radial depth of the alteration formation zone.

Abstract: A method for correlating data comprises acquiring a first sequence signal and a second sequence signal, wherein the first sequence signal comprises at least a first data point including a first set of components and the second sequence signal comprises at least a second data point including a second set of components; acquiring a first set of user picks and a second set of user picks, wherein the first and the second sets of user picks each contain a respective first and second correspondence between a component in the first set of components and a component in the second set of components; combining the first and second sets of user picks with the first and second sequence signals to create a first hyper-complex signal and a second hyper-complex signal; and performing signal alignment on the first and second hyper-complex signals.

Abstract: A method of determining wettability may include: measuring an electrical property of a drilling fluid; and correlating the electrical property to wettability.

Abstract: Provided are methods of reducing water consumption in a fracturing operation. The methods can include imaging a geologic formation surrounding a borehole using a downhole tool within the borehole. The method can further include identifying, within the image, fractures conducive to hydrocarbon production; correlating the fractures conducive to hydrocarbon production to fracture zones; and selecting locations of the fracture zones to be hydraulically fractured, wherein the selected locations collectively represent less than the axial length of the borehole, thereby reducing water consumption compared to hydraulic fracturing along an entirety of the axial length.

Abstract: A method may comprise: modeling a complex fracture network within the subterranean formation with a mathematical model based on a natural fracture network map and measured data of the subterranean formation collected in association with a fracturing treatment of the subterranean formation to produce a complex fracture network map; importing microseismic data collected in association with the fracturing treatment of the subterranean formation into the mathematical model; identifying directions of continuity in the microseismic data via a geostatistical analysis that is part of the mathematical model; and correlating the directions of continuity in the microseismic data to the complex fracture network with the mathematical model to produce a microseismic-weighted (MSW) complex fracture network map.

Abstract: A method for seismic exploration of a subsurface formation with a seismic survey system includes directly receiving a message, at a first fleet of seismic sources, from a second fleet; storing the message at the first fleet; verifying one or more constraints related to the first and second fleets, at the first fleet; initiating a triggering sequence of the seismic sources of the first fleet, upon verification of the one or more constraints, with no input from a central unit of the seismic survey system; and performing a sweep based on the triggering sequence.

Abstract: The subject matter of this specification can be embodied in, among other things, a method for remotely sensing vibration includes transmitting a collection of optical pulses through an optical fiber at a predetermined frequency, detecting a collection of backscattered Rayleigh traces from the optical fiber based on a vibration of the optical fiber at a vibration frequency at a location along the optical fiber, determining a normalized differential trace based on the collection of Rayleigh traces, determining, based on the normalized differential trace, the location in the optical fiber of the vibration, and determining, based on the raw Rayleigh traces, the vibration frequency.

Abstract: The present disclosure is directed to numerically estimating the shear modulus of Kerogen by using a combination of mineralogy from digital image analysis and sonic log analysis, when measured data on only one elastic constant (Bulk, Young's or P-wave modulus) is available. In some instances, elastic properties predicted from the digital images are compared with sonic, shear, and density logs, to estimate the shear modulus of kerogen. As a one-to-one correspondence is not expected between the core sub-samples and the rock unit sampled by the well logs, cross-property relations can be used to identify the suitability of the effective medium models and to iteratively determine the shear modulus of kerogen.

Abstract: A method for seismic imaging includes receiving a multi-shot seismic data set that was collected using one or more streamers having recorders configured to detect seismic waves that propagate through a subterranean domain. The method also includes partitioning the multi-shot seismic data set into windows including a source dimension. The method also includes defining one or more first basis functions that describe the windows of the multi-shot seismic data set. The method also includes generating a model that describes a decomposition of the multi-shot seismic data set using the one or more first basis functions. The method also includes defining one or more second basis functions that describe a selected output data. The method also includes combining the one or more second basis functions with the model to produce a result for a source side wavefield and a receiver side wavefield.

Abstract: Disclosed is an acoustic sensor system comprising an electrical connector, at least one transducer connected to the electrical connector, a fluid compensating piston connected to the electrical connector, a housing having the electrical connector, the at least one transducer, and the fluid compensating piston arranged in a linear arrangement, and a collar having the housing mounted along an interior surface of the collar.

Abstract: A system for collecting subsurface formation data in a petroleum exploration environment includes a drilling tool and a subsurface formation data hub. A drilling tool may include drill pipe, a geophone, a drilling hammer, and a drill bit. The subsurface formation data hub may comprise a seismic data processor and a user interface. The seismic data processor may be operable to drive the drilling hammer at a frequency and an energy, synchronize the geophone to sense seismic vibration at a frequency, and determine subsurface formation properties. The user interface may be operable to display subsurface formation data. A method of collecting subsurface formation data in a petroleum exploration environment may include defining a drilling hammer frequency and energy, synchronizing a geophone to sense seismic vibration at a frequency, generating an impact in the petroleum exploration environment, receiving a returning seismic vibration at the geophone, and collecting subsurface formation data.

Abstract: This disclosure describes processes and systems for generating a high-resolution velocity model of a subterranean formation from recorded seismic data gathers obtained in a marine seismic survey of the subterranean formation. A velocity model is computed by iterative FWI using reflections, resolving the velocity field of deep subterranean targets without requiring ultralong offsets. The processes and systems use of an impedance sensitivity kernel to characterize reflections in a modeled wavefield, and then use the reflections to compute a velocity sensitivity kernel that is used to produce low-wavenumber updates to the velocity model. The iterative process is applied in a cascade such that position of reflectors and background velocity are simultaneously updated. Once the low-wavenumber components of the velocity model are updated, the velocity model is used as an input of conventional FWI to introduce missing velocity components (i.e., high-wavenumber) to increase the resolution of the velocity model.

Abstract: A method for characterizing a tubular includes obtaining acoustic waveform data in a time domain using an acoustic transducer configured to emit an acoustic signal and receive a return acoustic signal and transforming the acoustic waveform data into a frequency domain to provide frequency domain acoustic waveform data. The method also includes determining a complex group delay function Gk derived from the frequency domain acoustic waveform data to provide a phase delay function as a function of frequency, wherein the complex group delay function Gk represents a first derivative of phase in the frequency domain with respect to frequency. The method further includes determining an imaginary component function of the complex group delay function Gk to provide a phase delay function as a function of frequency and characterizing the tubular using the phase delay function.

Abstract: A system and method are provided to detect and avoid wellbore collision. The method may include receiving, by a processor, a path of a proposed wellbore. The processor then receives a boundary surrounding the path of the proposed wellbore. The processor then generates, automatically, a list of avoidance components within the boundary using an internal database. The proposed wellbore and avoidance components in the list are then displayed by a visualization system.

Abstract: Disclosed is a system and method for improving the performance of downhole Distributed Acoustic Sensing (DAS) systems by simultaneous use of co-propagating and counter-propagating Distributed Raman Amplification (DRA). It uses a surface DRA system with a surface DAS system to combine their laser sources where the distal end of the downhole sensing fiber use uses a Wavelength Division Multiplexer (WDM) to optically split the DRA and DAS signals onto two optical fibers. The DAS fiber/signal is terminated with a low reflectance termination to minimize a potential back reflection whereas the DRA fiber is terminated with a high reflectance termination causing all the light to reflect back up the sensing fiber. This arrangement allows for simultaneous co and counter-propagating DRA of the DAS signals, both the transmitted pulse and the back scattered light, thus creating the maximum amount of gain possible.

Abstract: The disclosed embodiments include downhole leak monitor systems, downhole leak monitors, and methods to monitor downhole leaks. In one embodiment, a downhole leak monitor system includes a plurality of downhole leak monitors (monitor), where each monitor is deployed along a casing of a wellbore. Each monitor is operable to detect at least one property of a fluid flow through an aperture of a barrier and to determine a location of the aperture. Each monitor is also operable to establish a connection with at least one other monitor, the connection being one of a plurality of connections, together which, communicatively connects the monitor to a top monitor. Each of the monitor is further operable to transmit data indicative of the at least one property of the fluid flow and the location of the aperture to the at least one other monitor.

Abstract: A method to generate a vertical seismic profile includes acquiring a set of distributed acoustic sensing measurements from a set of overlapping measurement channels on an optical fiber, wherein each of the set of distributed acoustic sensing measurements are measured at a gauge length. The method also includes generating a set of virtual seismic measurements corresponding with subdivisions in the set of overlapping measurement channels based on the set of distributed acoustic sensing measurements and generating the vertical seismic profile based on the set of virtual seismic measurements.

Abstract: A system and method for processing and combining data from multiple curves or data-sets in oil field operations based upon a common index. The multiple input curves are combined to form an input vector. The input vector is aligned on the common index, without any values in the curve or data-set being changed. The input vector is then processed to ensure that all curves have values for all index values by interpolation. The input vector may be further processed to create a fixed step increment. An output vector is formed by operation of a set of formulas on the interpolated input vector.

Abstract: An apparatus for controlling water production in a wellbore comprises a body in the form of a base pipe, the base pipe having an axial flow passage in the form of axial throughbore and a lateral flow passage in the form of radial port. A shroud is disposed around the base pipe and forms a housing of the apparatus. In use, the apparatus forms part of a completion string for location in the wellbore, the apparatus configured to direct production fluid into a production conduit for recovery to surface, perform a quantitative measurement of water content within the production fluid, and vary the fluid flow in the fluid flow path based on the quantitative measurement of water content within the production fluid to maintain water production at or below a predetermined threshold.

Abstract: Methods and apparatuses for processing seismic data acquired with multicomponent sensors build an accurate S-wave velocity model of a surveyed underground formation using a full waveform inversion (FWI) approach. PS synthetic data is generated using approximative acoustic equations in anisotropic media with a P-wave model, a current S-wave velocity model and a reflectivity model as inputs. The current S-wave velocity model is updated using FWI to minimize an amplitude-discrepancy-mitigating cost function that alleviates the amplitude mismatch between the PS observed data and the PS synthetic data due to the use of the approximative acoustic equations.

Abstract: A downhole seismic array is disclosed. The array comprises a load-bearing cable for carrying a series of seismic sensor units arranged along its length. Each seismic sensor unit is attached to the load-bearing cable via a vibration-absorbing material and has a magnet to attach the seismic sensor unit to the well casing.

Abstract: A method for borehole measurements may comprise receiving one or more signals from a linear receiver array, computing an arctan of a Hilbert Transform, isolating a first arriving energy, selecting a reference instantaneous phase on a reference receiver, finding the reference instantaneous phase for the linear receiver array, computing a relative travel time shift, combining a reference pick time with a relative time, and determining a travel time. A system for borehole measurements comprise a conveyance, a bottom hole assembly attached to the conveyance, a linear receiver array, wherein the linear receiver array is disposed on the bottom hole assembly, and a computer system connected to the linear receiver array.

Abstract: A method, system, and computer readable medium for managing drilling operations include calibrating a drilling model using collected drilling data, and executing, during a drilling operation, a simulation on the drilling model to generate a predicted measurement value for a drilling property. During the drilling operation and from a drillstring, an actual measurement value for the drilling property is obtained. Based on the actual measurement value matching the predicted measurement value, the simulation is extended to generate a simulated state of the drilling operation during the drilling operation, and a condition of the drilling operation is detected. A notification may be presented based on the condition during the drilling operation.

Abstract: System and method for analyzing and evaluating the performance of a directional driller (“DD”) include acquiring and analyzing drilling data in real time, identifying activities and decisions that are the responsibility of the directional driller, and confirming whether or not the directional driller's decisions were appropriate or not and in what timeframe. The system and method may provide output information for evaluation purposes, for example, in the form of a directional drilling quality report. The directional drilling quality report may allow evaluation of an individual directional driller and also comparison of directional drillers relative to each other. The use of real-time drilling data allows the report to be modified to reflect actual drilling conditions and objectives as needed.

Abstract: A velocity model is generated based upon seismic waveforms via any seismic model building method, such as full waveform inversion or tomography. Data representative of a measurement of a physical attribute of an area surrounding a well is received and an attribute model is generated based upon the velocity model and the data. An image is rendered based upon the attribute model for use with seismic exploration above a region of a subsurface comprising a hydrocarbon reservoir and containing structural or stratigraphic features conducive to a presence, migration, or accumulation of hydrocarbons.

Abstract: A graphical user interface may provide visualization of comparison between planned value(s) and usage value(s) of a set of operating parameters for a tool. The graphical user interface may include a planned usage region and a usage region. The planned usage region may provide visualization of the planned value(s) for the tool. The usage region may provide visualization of the usage value(s) for the tool. The usage region may include a compliance section. The compliance section may provide visualization of whether the usage value(s) complies with the corresponding planned value(s) such that the compliance section includes different visual features based on whether the usage value(s) complies or does not comply with the corresponding planned value(s). The usage region may provide comments and/or recommendations based on the learnings from analysis of offset wells.

Abstract: A signal transmission system including a first transducer mounted to a surface of a member, a second transducer movable into contact with a second surface of the member, a material disposed between the second transducer and the second surface of the member. A method for communicating acoustic energy through a member including pressing a second transducer to a second surface of the member, the member having a first transducer mounted to an opposite surface thereof, sandwiching a material between the second transducer and the second surface of the member, and transmitting a signal between the first transducer and the second transducer.

Abstract: Systems and methods for determining a shear wave slowness may include emitting an emitted acoustic wave within a borehole from an acoustic tool. A return acoustic wave may be detected via one or more sensors. The return acoustic wave may be generated when the emitted acoustic wave interacts with a physical feature within the borehole. A signal may be generated that may be indicative of the return acoustic wave. The method may include evaluating the signal via a processor to determine a pseudo-Rayleigh mode slowness and calculating a shear wave slowness using an analytical relationship. The analytical relationship may include a mathematical correlation between the pseudo-Rayleigh mode slowness and the shear wave slowness. The analytical relationship may also include input parameters that are measured physical parameters of borehole properties.

Abstract: A method for use in or for detecting a downhole feature in a well comprises transmitting an electromagnetic signal from a first position located substantially at or adjacent to surface through a first space to the downhole feature. The method further comprises receiving an electromagnetic signal at a second position located substantially at or adjacent to surface after reflection of the transmitted electromagnetic signal from the downhole feature and after propagation of the reflected electromagnetic signal through a second space. The method may comprise sealing the well before transmitting the electromagnetic signal. Such a method may be used to detector determine a distance from surface to a downhole feature such as a fluid interface in a completed production, injection or observation well.

Abstract: A method and system for determining cement bonding. The method may comprise disposing an acoustic logging tool in a wellbore, wherein the acoustic logging tool comprises a transmitter and a receiver, broadcasting a shaped signal with the transmitter such that fluid between concentric pipes disposed in the wellbore is excited, recording a reverberating signal with the receiver, processing the reverberating signal with an information handling system, and determining presence of a material outside an outermost of the concentric pipes. A well measurement system for determining cement bonding may comprise an acoustic logging tool. The acoustic logging tool may comprise at least one transmitter, wherein the at least one transmitter is configured to broadcast a shaped signal, and at least one receiver, wherein the at least one receiver is configured to record a reverberating signal. The acoustic logging tool may also comprise a conveyance and an information handling system.

Abstract: A protection member is arranged such that the distance from an opening plane of a reception guide to the center of the protection member is half of the distance from the opening plane of the reception guide to the surface of a reception vibration member. In other words, the arrangement position of the protection member is in the center between the opening plane of the reception guide and the surface of the reception vibration member. Accordingly, even if a protection member is arranged, a transmission coefficient is obtained that is equal to a transmission coefficient in the case where no protection member is present.

Abstract: The present disclosure relates to a device for laying out a prefabricated magnetic field and a method for responding state of a slip mass in the prefabricated magnetic field. The device may include a traction mechanism, a control mechanism and a layout probe. The layout probe may include a shell, a circuit board and at least one set of layout mechanism equipped in the shell. The layout mechanism may include a cartridge, a screw pole, an electromagnet, a driving mechanism and a pressing mechanism. The traction mechanism may lay down the layout probe to a default location of a drill hole. The control mechanism may control the driving mechanism to transmit an uppermost permanent-magnet in the layout probe to the cartridge nozzle and be attracted by the electromagnet. The pressing mechanism may move the electromagnet which presses the permanent-magnet in the inner wall of the drill hole.

Abstract: Disclosed herein is method of computing formation attributes from acoustic measurements in a borehole. The acoustic measurements can be made by operating an acoustic source at multiple frequencies to excite the formation and operating receivers at multiple, longitudinally spaced receiver stations to receive acoustic energy from the formation. The method can include: deriving phase data from the spectrum of received acoustic signals; unwrapping phase information of the phase spectrum data; determining two or more values of difference of phase between acoustic signals at each of a range of frequencies each based on a single generated signal received at two or more pairs of adjacent said receiver stations; generating a value of slope of phase difference values; and in any case of slope ambiguity, unwrapping phase difference information and deriving a dominant slope, at each frequency, from which slowness of the acoustic signal in the formation can be derived.

Abstract: A downhole tool system may include a Stoneley wave emitter, located in a downhole tool, designed to emit Stoneley waves into a borehole. The downhole tool system may include one or more Stoneley wave sensors, located in the downhole tool, and a processor. The processor may be designed to receive signals from the one or more Stoneley wave sensors based on the detection of the Stoneley waves. The processor may use the signals to obtain a temporal measurement of the Stoneley waves. Based at least in part on the temporal measurement, the processor may calculate a distance from the downhole tool or a bottom-hole assembly to the bottom of the borehole.

Abstract: The present invention relates to a downhole completion system for completing a well having a borehole, said downhole completion system comprising a well tubular metal structure arranged in the borehole forming an annulus and comprising a wall and a plurality of sensor units forming a mesh network, wherein at least a number of said sensor units is provided with a self-powering device configured to harvest energy downhole. Furthermore, the present invention relates to a sensor unit for use with a downhole completion system according to the present invention.

Abstract: At least some of the disclosed systems and methods employ one or more seismic receivers that gather seismic data from a plurality of positions in a borehole that penetrates a formation. Further, at least some of the disclosed systems and methods employ a memory to store the gathered seismic data. Further, at least some of the disclosed systems and methods employ logic that inverts the seismic data for simultaneous determination of asymmetric axis velocity (V0) and Thomsen parameters, epsilon (?) and delta (?), in a tilted transversely isotropic (TTI) model.

Abstract: The present disclosure describes methods and systems, including computer-implemented methods, computer-program products, and computer systems for integration of physical reservoir rock interpretation data into reservoir formation modeling. At least one digital photograph of a rock outcrop is generated using a mobile device and the contact and boundary features associated with the at least one digital photograph are interpreted using the mobile device. A reservoir modulation trend is generated from the interpretation of the at least one digital photograph and transmitted to a three-dimensional reservoir interpretation system. A three-dimensional lithofacies model is generated using the generated reservoir modulation trend.

Abstract: Described herein is a method including acquiring a set of transimpedance coupling voltages, between different antenna components of different axes of a transmitting station transmitting into a formation and different antenna components of different axes of a receiving station receiving from the formation, using an induction tool undergoing random movement during the acquisition. Fourier coefficients for the set of transimpedance coupling voltages are determined using a least square process. A mean tool eccentering azimuthal angle and an apparent formation azimuthal angle are estimated as a function of the Fourier coefficients. Compensated measurements are computed as a function of the Fourier coefficients. An inversion loop receives as input the compensated measurements, the estimated mean tool eccentering azimuthal angle, and the estimated apparent formation azimuth, and outputs final parameters as a function thereof.

Abstract: This disclosure presents methods and systems for deblending blended seismic data obtained during simultaneous shooting acquisition into deblended seismic data gathers. Methods and systems iteratively separate the blended seismic data into the deblended seismic data gathers based on semblance analysis of a residual difference between the blended seismic data and the deblended seismic data gathers. Each deblended seismic data gather is associated with one of the sources and appears to have been obtained without substantial interference from seismic energy produced by other sources.

Abstract: A method of inspecting a pipe for flaws includes emitting ultrasonic waves, controlling the emission of the ultrasonic waves, receiving reflections of the ultrasonic waves, and determining at least one characteristic of one or more flaws. The ultrasonic waves are emitted in a helical pattern through the pipe from an array of ultrasonic transducer elements. The emission of the ultrasonic waves from the array is controlled such that the ultrasonic waves are emitted at a plurality of helical angles within a range of helical angles. The reflections of the ultrasonic waves are caused by impingement of the ultrasonic waves on the one or more flaws. The at least one characteristic of the one or more flaws is determined based on the received reflections of the ultrasonic waves.

Abstract: Methods include providing a blowout preventer body having at least one sealing ram for engaging with a downhole tool, and the sealing ram is hydraulically actuatable between a ram open position and a ram closed position. A hydraulic control valve is provided and used for sensing a differential pressure across the at least one sealing ram. The hydraulic control valve is fluidly connected to the blowout preventer body, and the hydraulic control valve operates as a hydraulic interlock to prevent the at least one sealing ram from being moved to the ram open position under predetermined differential pressure conditions. The blowout pre-venter is connected to a wellhead disposed on a wellbore, and the downhole tool and coiled tubing are deployed into and out of the wellbore.

Abstract: Examples of techniques for anonymizing data are disclosed. In one example implementation according to aspects of the present disclosure, a computer-implemented method includes receiving, by a processing device, raw data from a wellbore operation. The raw data can be associated with depths. The method further includes anonymizing, by the processing device, the raw data to convert the raw data to anonymized data. One or more techniques can be implemented to anonymize the data, such as shuffling the raw data, normalizing the raw data, and/or non-dimensionalizing the raw data. The method further includes analyzing, by the processing device, the anonymized data. The method further includes performing an action at the wellbore operation based at least in part on the analysis of the anonymized data.

Abstract: Examples of techniques for anonymizing data are disclosed. In one example implementation according to aspects of the present disclosure, a computer-implemented method includes receiving, by a processing device, raw data from a wellbore operation. The raw data can be associated with depths. The method further includes anonymizing, by the processing device, the raw data to convert the raw data to anonymized data. One or more techniques can be implemented to anonymize the data, such as shuffling the raw data, normalizing the raw data, and/or non-dimensionalizing the raw data. The method further includes analyzing, by the processing device, the anonymized data. The method further includes performing an action at the wellbore operation based at least in part on the analysis of the anonymized data.

Abstract: An apparatus for mounting one or more transducers to a drill pipe. The apparatus comprises a sub-pipe having a bore and a transducer-holding assembly, wherein the transducer-holding assembly is insertable into the bore of the sub-pipe from an axial end of the sub-pipe. The apparatus further comprising a tension collar connected to the bore-defining surface of the sub-pipe and bearing upon the transducer-holder.

Abstract: A method can include receiving acoustic emission data for acoustic emissions originating in a formation, performing a moment tensor analysis of the data, thereby yielding acoustic emission source parameters, determining at least one acoustic emission source parameter angle having a highest number of associated acoustic emission events, and calculating an in situ stress parameter, based on the acoustic emission source parameter angle. A system can include multiple sensors that sense acoustic emissions originating in a formation, and a computer including a computer readable medium having instructions that cause a processor to perform a moment tensor analysis of the data and yield acoustic emission source parameters, determine at least one acoustic emission source parameter angle having a highest number of associated acoustic emission events, and calculate an in situ stress parameter, based on the acoustic emission source parameter angle.

Abstract: Systems and methods for modeling subsurface rock formations based on well log data are provided. Systems include a downhole tool for acquiring data from which borehole dips may be picked and a processor including machine-readable instructions for curvature analysis based on inputs generated from the picked borehole dips data and which may be independent of 2D cross section model orientation. Methods (which may be incorporated in the machine-readable instructions corresponding to the systems) include pre-processing borehole dips data to generate inputs such as true stratigraphic thickness index, Local Constant Dips, borehole structural dip, and attributes for structural dip projections which may be used in a curvature analysis process for generating curvature logs such as standard, curvature along axis and curvature normal to axis logs from for smoothed dips, short zone structural dips and/or long zone structural dips.

Abstract: Systems, devices, and methods for estimating a value of a parameter of interest of an earth formation intersected by a borehole. Methods include conveying a carrier in the borehole having disposed thereon an acoustic imaging tool including at least one convex linear phased array module, each of the at least one module comprising a rigid shell forming a compartment containing a piezoelectric component array; using the acoustic imaging tool to take acoustic measurements of the borehole; and using the acoustic measurements to estimate at least one parameter of interest. Each module may be self-contained. The tool may include a plurality of modules circumferentially arrayed about a portion of the acoustic tool. Methods include individually removing one selected module from the acoustic tool. Methods may include selecting an outer tool diameter the same as an inner borehole diameter borehole and selecting a maximum number of modules fitting the outer tool diameter.

Abstract: The present disclosure relates to the technical field of acoustic logging while drilling, and provides an integral packaging device for acoustic receiving transducers while drilling, wherein, the receiving transducers are directly arranged in a signal processing circuit, which is installed in an internal supporting frame fitted in a rectangular bellow; one side of the bellow has a deformable surface that is of a corrugated structure, and oil is filled in the bellow; the receiving transducers are arranged on the side that has a deformable surface; a shock absorbing rubber piece is of a U-shaped structure; one end of a connecting unit is connected to the signal processing circuit, and the other end of the connecting unit is connected to a main control circuit in a logging while drilling instrument. The present disclosure employs an integral packaging structure, which is easy to install structurally.

Abstract: A seismic data analysis system includes seismic receivers to collect seismic survey data, wherein the seismic survey data includes direct and reflected arrival data in response to at least one seismic source fired at different shot offsets. The system also includes memory that stores the collected seismic survey data. The system also includes a processing unit that extracts traveltimes for direct and reflected arrivals from the seismic survey data and performs an inversion using the direct and reflected arrival traveltimes simultaneously to determine anisotropy parameters, including Thomsen parameters, epsilon (?) and delta (?), for at least one layer of a vertical transversely isotropic (VTI) model.

Abstract: Hybrid inversion processing techniques are implemented that result in improved speed and accuracy of determining formation properties using log data, for example, from an multi-component induction logging tool. Logging data relating to the formation of interest is obtained and used as an input. High frequency noise is then removed from the logging data and bed-boundary determination is performed using the logging data. An adaptive low pass filter is applied to the logging data and the logging data is inverted. The inverted logging data is correct and enhanced by determining one or more weights based on one or more quality indicators. The inverted logging data may then be visually interpreted and used to adjust one or more drilling parameters.