This disclosure generally relates to production logging of a cased wellbore extending into a subterranean formation, and more specifically to cement evaluation of the cased wellbore.
Operations involving production logging of a cased wellbore that extends into a subterranean formation may include cement monitoring and/or evaluation of the cement in spaces surrounding the outer surface of the casing. These evaluations may be important because when pressure imbalances cause crossflows through poorly cemented sections, excessive production of unwanted fluids might occur. Further, a section or large portions of the wellbore to be evaluated may include a production tubing extending within and through the interior annulus encircle by the casing, and wherein the production logging is to be performed with the production tubing remaining in place. As such, there is a high demand for a solution of cement bond logging and evaluation that can be performed for example through production tubing in order to save time and money.
The drawings are provided for the purpose of illustrating example embodiments. The scope of the claims and of the disclosure are not necessarily limited to the systems, apparatus, methods, or techniques, or any arrangements thereof, as illustrated in these figures. In the drawings and description that follow, like parts are typically marked throughout the specification and drawings with the same or coordinated reference numerals. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness.
In the following detailed description of the illustrative embodiments, reference is made to the accompanying drawings that form a part hereof. These embodiments are described in sufficient detail to enable those skilled in the art to practice the techniques and methods described herein, and it is understood that other embodiments may be utilized and that logical structural, mechanical, electrical, and chemical changes may be made without departing from the scope of the disclosure. To avoid detail not necessary to enable those skilled in the art to practice the embodiments described herein, the description may omit certain information known to those skilled in the art. The following detailed description is, therefore, not to be taken in a limiting sense.
In various embodiments, production logging of a wellbore system requires cement monitoring, which in various instances requires the logging of a wellbore including the existence of a tubing, such as a production tubing, present in the portion of the wellbore to be logged. When pressure imbalance causes crossflow through poorly cemented sections of the casing, excessive production of unwanted fluids might occur. There is a high demand for a solution of cement bond logging, including wellbore with tubing, to save time and money. Not only in the area of production logging, the operation of well abandonment is also eager for the technique of cement bond logging through tubing. A wellbore or well system that comes close to the end of its operating life cycle must be plugged and abandoned (P&A). One possible way to cut the costs during P&A operations is to leave most of the production tubing in wells so that the rig time and money could be significantly reduced. As an essential preparation task for P&A operations, well integrity such as cement bond condition behind casing must be tested beforehand.
Previous efforts of through tubing cement evaluation include using the frequency spectrum of recorded signals, MIE resonance, and general borehole sonic dispersion response. These methods provide a free-pipe indicator used to reflect the position of free-pipe zones or the top of the cement. However, limited to the omnidirectional monopole transmitter they use, these methods have limited capability in detecting and locating azimuthal bonding information behind casing.
This disclosure describes methods and techniques that utilize the directional source and receivers with rotation capability to scan the casing A0 waves for evaluating the materials behind the casing of a wellbore. Spatial filters in the slowness-frequency domain are used to extract the casing-related A0 waves. Amplitude or attenuation information of casing A0 waves is used to reveal bonding conditions behind the casing.
Cement evaluation (TTCE) is challenging through tubing as most sonic signals are limited in the steel tubing. Traditional methods using 20 kHz acoustic signals or ultrasonic signals encounter issues for TTCE. The systems, apparatus, method and techniques as described here utilize low-frequency casing pseudo A0 waves having a short wavelength with local-focused energy to generate information related to the quality of cement bonding outside a casing and within a wellbore structure. The amplitude information from the A0 waves dispersed by the casing reflects zones with channels behind the casing and within the cement. Additionally, in various embodiments, to enable azimuthal detection A0 waves are excited and captured by unipole transmitters and unipole receivers, which are mounted at a rotary head of a sonic tool deployed with the casing of the wellbore. The casing A0 signals at any azimuths are measured by rotating a transmitter and one or more receivers located on the sonic tool. The bonding condition behind the casing can be further extracted from the amplitude of measured casing A0 waves received at the one or more receivers of the sonic tool.
Various aspects and features of the methods and techniques described herein include:
The methods and techniques as described herein are applicable for the evaluation of cement bonding to a casing in systems with and without a production tubing being present within the casing. The technique enables the through tubing cement evaluation with low-frequency casing A0 waves. Lamb waves exhibit velocity dispersion; their propagation velocity depends on the frequency (or wavelength) and the elastic constants and density of the material. This phenomenon is central to the study and understanding of wave behavior in plates or a pipe. For the lamb wave propagating in a cylindrical pipe, the dispersions of the lamb waves rely on the pipe's thickness and diameter.
The symmetrical and antisymmetric zero-order modes deserve special attention. These modes have “nascent frequencies” of zero. Thus they are the only modes that exist over the entire frequency spectrum from zero to indefinitely high frequencies. In the low-frequency range (i.e., when the wavelength is greater than the pipe thickness) these modes are often called the “extensional mode” and the “flexural mode” respectively, terms that describe the nature of the motion and the elastic stiffnesses that govern the velocities of propagation. The elliptical particle motion is mainly in the plane of the pipe for the symmetrical, extensional mode and perpendicular to the plane of the pipe for the antisymmetric, flexural mode. These characteristics change at higher frequencies. These two modes are the most important and often used in cement bond logging because (a) they exist at all frequencies and (b) in most practical situations, they carry more energy than the higher-order modes. The zero-order symmetrical mode (designated S0) and the zero-order antisymmetric mode (designated A0) in a casing or tubing pipe are slightly different from these waves in a plate.
In various embodiments, not all portions of the space between the casing 104 and the inner surface 103 of the borehole 101 are filled with cement. As illustrated in
A sonic tool 120 is configured to be placed within the casing 104, and using the devices, methods, and techniques as described herein, gather measurements and process these measurements to produce data that may be used to evaluate the bonding and fill of the cement, and/or the absence of cement, within various portions of the space between the casing and the inner surface of the borehole. As shown in
Sonic tool 120 includes at least one transmitter 121. Transmitter 121 is positioned on sonic tool 120, for example on an outer surface of the tool body of the sonic tool, and is configured to transmit sonic signals from the transmitter that are directed toward the casing 104 in the area adjacent to the location of the transmitter within the casing. Sound waves that propagated through the casing 104, along with propagating through any fluid within the casing (and/or the tubing 110 when the tubing is present), are received at one or more receivers located on the sonic tool 120. The number of receivers included on a given embodiment of sonic tool 120 is not limited to a particular number of receivers, and may be a positive integer number of receivers, including in various embodiments a single (one) receiver. As shown in
In various embodiments, some or all of the signal processing and/or data generation associated with the transmission and receiving of sound signal performed by the sonic tool may be performed by one or more processors included in a computing section 134 of the sonic tool. Computing section 134 may include computer or microprocessors and associated devices, such as computer memory and network interfaces, which allow the computing section 134 to perform any of the signal processing operations and/or data analysis processes as described in this disclosure in order to generate data for cement bonding evaluation. In various embodiments, computing section 134 includes memory devices where data associated with the operation of the sonic tool 120 and/or data generated as a result of the operation of the sonic tool may be stored, and which can be retrieved from these memory devices at a later time when the sonic tools is removed from the borehole where it was deployed and operated. In various embodiments, computing section 134 includes a network interface configured to allow sonic tool 120 to transmit data, such as raw signal data from waveforms captured by the receiver of the sonic tool, processed signals generated by the processing the captured waveforms, and/or other data generated from the captured waveforms, to another device, such as positioning control system 130, for example in real-time. Transmission of the data to or from sonic tool 120 to another device such as positioning control system 130 may utilize a transmission line incorporated into cable 131 to carry the data between the devices. In various embodiments, transmission to and/or from sonic tool 120 to another device such as positioning control system 130 may be performed using a wireless transmission.
System 100 may include various devices configured with regards to the positioning of sonic tool 120 within the casing 104 (and within tubing 110 when present). In various embodiments, positioning control system 130 includes an actuator 132 that is configured to control the depth-wise positioning of the sonic tool 120 within the casing 104 by controllably releasing and retracting, at different times, the length of cable 131 extended into the borehole 101. In various embodiments, positioning control system 130 determines at what depth to position and reposition the sonic tool 120 based on information transmitted to the position control system from the sonic tool, for example as provided by the computing section 134 of the sonic tool. With regards to the rotational positioning of the sonic tool 120, in various embodiments actuator 132 controls the rotational positioning, and thus the azimuthal orientation of the sonic tool, by rotational forces applied to the sonic tool through cable 131. In various embodiment, positioning control system 130 determines the rotational positioning and repositioning of the sonic tool 120 based on information transmitted to the position control system from the sonic tool, for example as provided by the computing section 134 of the sonic tool. In various embodiments, sonic tool 120 includes a local rotational actuator, such as rotational actuator 136, which may be coupled to the sonic tool and to cable 131, and is configured to provide rotational motion and control of the rotational position of the sonic tool within the casing 104 (and within tubing 110 when present).
A “unipole transmitter” or a “unipole receiver” when utilized as part of a sonic tool, such as sonic tool 120, refers to a sonic transducer that can emit/receive signals to/from a specific direction. The transducer's transmitting or receiving pattern depends on the transducer itself and its packaging. For example,
In operation, the sonic tool is positioned at a desired location with a cased borehole, and operated to generate sonic signals that are transmitted from the transmitter of the sonic tool toward and into the casing. One or more receivers receive the sonic signals propagated through the casing, and the received signals are then processed using the techniques and methods as described herein to provide data that may be used to evaluate the quality of the cement bonding present outside of the casing within the borehole. One or more actuators may be used to reposition the sonic tool, both relative to the depth and rotational position of the sonic tool, in order to gain information about the cement bonding qualities over a range of depths and/or a range of azimuthal orientations.
In addition, embodiments of system 100 are not limited to the acoustic system with a unipole transmitter and unipole receivers. Embodiments as described herein may be applied to combinations of different sources and receivers. For example, monopole sources and unipole receivers, dipole sources and unipole receivers, or unipole sources and monopole receivers may be used in various embodiments.
In various embodiments, the signals received at the receivers of the sonic tool may need to be calibrated or provided with correction due to the fact that the relative position of the sonic tool may not correspond to the center axis of the casing, wherein the sonic tool may be poisoned closer to one side of the casing compared to an opposite side of the casing. As an example, as illustrated in
The S0 waves and A0 waves have interfered with each other at low frequencies. The A0 approaches and takes the position of the S0 dispersion at low frequencies, while the high-frequency S0 has a cutoff frequency at the frequency when A0 waves take the place of S0 waves. This phenomenon is due to the curvature of the pipe, and the cutoff frequency is related to the diameter of the pipe. Although modes are coupled, the features of these waves stay the same. For instance, the modes with speeds close to 5000 m/s all show the property of S0 waves; the wave modes with a slowness less than the pipe shear slowness show the property of A0 waves.
The lamb waves in a pipe are different from those in a plate, and therefore are referred to as pseudo-lamb waves. In the frequency range of interest, for example over the range included in window 305, the pseudo-Lamb waves are coupled with the wave motions propagating in the fluid (fluid mode, including Stoneley waves, and high order of fluid modes). For example, the A0 waves approach the Stoneley waves at low frequencies, and are coupled with other fluid modes at high frequencies. Although modes are coupled, the features of these pseudo-lamb waves stay the same. In other words, the wave motions with slowness values close to the original lamb wave slowness (not coupled with the fluid modes, solid lines in
It has been demonstrated that the lamb waves are sensitive to the materials surrounding the plate or pipe. When the surrounding materials change, the properties of the lamb waves change. Thus, the lamb waves can be used to understand the material behind the plate or pipe. In various embodiments, the low-frequency casing pseudo A0 waves have a short wavelength with local-focused energy. Its amplitude reflects zones with channels. Additionally, to enable azimuthal detection, A0 waves are excited and captured by unipole transmitters and unipole receivers, which are mounted at a rotary head. The casing A0 signals at any azimuths are measured by rotating the transmitter and receiver(s). The bonding condition behind the casing can be further extracted from the amplitude and attenuation of the measured low-frequency casing A0 waves.
In various embodiments, these waveforms may be processed using the methods and techniques as further described herein to provide information about the quality of cement bonding associated with a wellbore casing, such as casing 104 and cement 106 as illustrated and described with respect to
In various embodiments, waveforms such as the waveforms shown in graph 400 are input into a workflow involving processes for use in performing cement evaluation based on low-frequency A0 waves. In various embodiments, the waveforms measured by receivers of a sonic tool at the rotary head are inputted into computer application(s) were one or more computer processors, (such as computer processor(s) 1201,
Based on the extracted dispersion of the target A0 waves, for each depth and azimuth, the raw waveform data are converted to a slowness-frequency amplitude map in the slowness-frequency domain, for example, by the beamforming method or the T-p transform. Then the amplitude of the target A0 wave may be extracted from the slowness-frequency amplitude map using a slowness-frequency window determined by the slowness-frequency semblance analysis. At this step, displaying the amplitude values in the depth-azimuth plane yields the raw amplitude map. Next, with the tubing eccentricity information that are generated from the third interface echo (TIE), an eccentricity calibration processing may be performed to remove the tubing eccentricity effect. A baseline of the well-bond zone response and map the two-dimensional (depth-azimuthal) cement bond image is then identified from the calibrated amplitude image.
The peaks in graph 500 represent modal waves. Different methods may be used to create the semblance map, for example, the Prony method, the matrix-pencil method, the DPFS method. In various embodiments, the casing A0 wave has the highest slowness among all the modes at low frequencies. The semblance map allows for identification of the picking window 504 for the casing A0 waves. In other cases, the dispersion analysis may be applied to simulated data for window selection. Alternatively, the governing equation of the multilayer model with a tubing layer, a casing layer, and a cement layer may be directly solved to understand the dispersions of target A0 signals.
Based on the extracted dispersion of the target A0 waves, for each depth and azimuth, the raw waveform data are converted to a slowness-frequency amplitude map in the slowness-frequency domain, for example, by the beamforming method or the T-p transform.
Calculating the summation, average, or root-square-mean values of the amplitude map in the window represented by window 604 determined by the semblance map yields the amplitude estimate of the A0 modes. The beamforming method is one of the methods that may be used to generate the amplitude map. In various embodiments, other ways may be used to create the amplitude map, including but not limited to the Fourier transform, the T-p transform, and the radon transform. After extracting the amplitude information of A0 waves for different azimuths and depths, a map of the A0 waves may be obtained that can be used to describe the bonding condition behind the casing.
For example,
Also illustrated in
The final step is to map the A0 amplitude values to a bonding condition map. First, a base value is selected from the well-bond zone, indicated as “Base value” in graph 800, then the area whose values are close to the base values is identified as the good-bond zone, and the others are identified as channeled zones. The bonding condition is calculated based on the difference between the A0 amplitude and the base value.
As shown in graph 900 of
The disclosure as further described below also discloses workflows to introduce a time-spatial window in the processing to enable the time-spatial resolution. For example, before the step of ‘create a slowness-frequency amplitude map with beamforming’, a time-spatial window may be applied in the raw array waveforms to enhance the data of interest in the time-spatial domain. The time-spatial window can be estimated based on the starting Transmitter-Receiver (TR) offset and the travel time of target modes calculated from numerical simulations.
Referring again to flowchart 1000 and
After receiving the sonic waveforms at the one or more receivers, at block 1004 the method of flowchart 1000 includes performing a slowness-frequency semblance analysis, which is applied to a set of selected data to extract the dispersion of the target A0 waves. In various embodiments, the slowness-frequency semblance analysis comprises DPFS. In various embodiments, the target A0 waves are the A0 wave present over a predefined range of frequencies, such as but not limited to the range of frequencies depicted by window 504 in
At block 1008, the method of flowchart 1000 includes extracting the amplitude of the target A0 wave from the slowness-frequency amplitude map using a slowness-frequency window determined by the slowness-frequency semblance analysis. This step of the method may include displaying the amplitude values in the depth-azimuth plane to yield a raw amplitude map.
At block 1010, embodiments of the method of flowchart 1000 include performing eccentricity calibration to remove the tubing eccentricity effect. Eccentricity calibration may be performed using tubing eccentricity information that are generated from the third interface echo (TIE), and provided (block 1009) in order to generate the eccentricity calibration. This step of the method would normally be performed when a tubing was present with the casing where the measurements using a sonic tool to transmit and receive the sonic waveforms received at block 1002 was present in the wellbore system.
At block 1012, the method of flowchart 1000 includes identifying the baseline of the well-bond zone response(s) and using that baseline to map the two-dimensional (depth-azimuthal) cement bond image from the eccentricity calibrated amplitude image. The two-dimensional cement bond image may be used to determine the quality of the cement bond to a casing of a wellbore system, and/or to determine the presence and location of any channels in the cement bonding the casing within the borehole of the wellbore system.
In
After receiving the sonic waveforms at the one or more receivers, at block 1104 the method of flowchart 1100 includes performing a two-dimension (2D) fast Fourier transform (FFT) to obtain the frequency-wavenumber (FK) spectra of the data.
At block 1106, the method of flowchart 1100 includes applying a frequency-wavenumber (FK) filter with a slowness frequency window of the target mode to the FK spectra.
At block 1108, the method of flowchart 1100 includes performing an inversed two-dimensional Fast Fourier transform to obtain the filtered time-spatial waveform data.
At block 1110, the method of flowchart 1100 includes applying a time-spatial window to enhance the data of interest in the time-spatial domain.
At block 1112, the method of flowchart 1100 includes extracting the amplitude of the target modes from the time-spatial domain data. In various embodiments, the extraction of the amplitude includes taking a root-square mean or area of the signal with a designated window.
At block 1114, embodiments of the method of flowchart 1100 include performing eccentricity calibration to remove the tubing eccentricity effect. Eccentricity calibration may be performed using tubing eccentricity information that are generated from the third interface echo (TIE), and provided (block 1113) in order to generate the eccentricity calibration. This step of the method would normally be performed when a tubing was present with the casing where the measurements using a sonic tool to transmit and receive the sonic waveforms received at block 1002 was present in the wellbore system.
At block 1116, the method of flowchart 1100 includes identifying the baseline of the well-bond zone response(s) and using that baseline to map the two-dimensional (depth-azimuthal) cement bond image from the eccentricity calibrated amplitude image. The two-dimensional cement bond image may be used to determine the quality of the cement bond to a casing of a wellbore system, and/or to determine the presence and location of any channels in the cement bonding the casing within the borehole of the wellbore system.
Referring back to
The computer may also include an image processor 1211. Image processor 1211 may be configured to produce graphical display data related to the cement evaluation data, which may then be displayed on a display device, such as display included in input/output devices 1220. Various embodiments of system 1200 include a signal generator/signal processor, hereinafter “controller” 1215. In various embodiments, controller 1215 is coupled to transmitter 1219, and is configured to generate sonic waveforms that are then provided to the transmitter for transmission into a casing of a wellbore system, such as casing 104 of system 100 (
In various embodiments, processor 1201 may be configured to generate control signals to control the different operations that may be performed for positioning of a sonic tool within a casing of a wellbore structure. For example, processor 1201 may generate control signals that may be used to control one or more actuators, such as actuator 132 (
Any one of the previously described functionalities may be partially (or entirely) implemented in hardware and/or on the processor 1201. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor 1201, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated in
Processor 1201 may be configured to execute instruction that provide control over the positioning of a sonic tool with a wellbore structure, to control the generation and transmission of sonic wave directed toward the casing of the wellbore structure, to control receivers configured to detect sonic waves dissipated from the casing of the wellbore structure, and to process the detected sonic waves using and of the methods and techniques described in this disclosure.
With respect to computing system 1200, basic features here may easily be substituted for improved hardware or firmware arrangements as they are developed. In some examples, memory 1207 includes non-transient and/or non-volatile memory devices, and can be a hard disk or other types of computer readable media which can store data that are accessible by a computer, such as magnetic cassettes, flash memory cards, solid state memory devices, digital versatile disks (DVDs), cartridges, RAM, ROM, a cable containing a bit stream, and hybrids thereof.
It will be understood that one or more blocks of the flowchart illustrations and/or block diagrams, and combinations of blocks in the flowchart illustrations and/or block diagrams, can be implemented by program code. The program code may be provided to a processor of a general-purpose computer, special purpose computer, or other programmable machine or apparatus. As will be appreciated, aspects of the disclosure may be embodied as a system, method or program code/instructions stored in one or more machine-readable media. Accordingly, aspects may take the form of hardware, software (including firmware, resident software, micro-code, etc.), or a combination of software and hardware aspects that may all generally be referred to herein as a “circuit,” “module” or “system.” The functionality presented as individual modules/units in the example illustrations can be organized differently in accordance with any one of platform (operating system and/or hardware), application ecosystem, interfaces, programmer preferences, programming language, administrator preferences, etc.
Computer program code for carrying out operations for aspects of the disclosure may be written in any combination of one or more programming languages, including an object oriented programming language such as the Java® programming language, C++ or the like; a dynamic programming language such as Python; a scripting language such as Perl programming language or PowerShell script language; and conventional procedural programming languages, such as the “C” programming language or similar programming languages. The program code may execute entirely on a stand-alone machine, may execute in a distributed manner across multiple machines, and may execute on one machine while providing results and or accepting input on another machine. While depicted as a computing system 1200 or as a general purpose computer, some embodiments can be any type of device or apparatus to perform operations described herein.
While the aspects of the disclosure are described with reference to various implementations and exploitations, it will be understood that these aspects are illustrative and that the scope of the claims is not limited to them. In general, techniques for automatically pressure testing frac iron described herein may be implemented with facilities consistent with any hardware system or hardware systems. Many variations, modifications, additions, and improvements are possible.
Plural instances may be provided for components, operations or structures described herein as a single instance. Finally, boundaries between various components, operations and data stores are somewhat arbitrary, and particular operations are illustrated in the context of specific illustrative configurations. Other allocations of functionality are envisioned and may fall within the scope of the disclosure. In general, structures and functionality presented as separate components in the example configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the disclosure.
Use of the phrase “at least one of” preceding a list with the conjunction “and” should not be treated as an exclusive list and should not be construed as a list of categories with one item from each category, unless specifically stated otherwise. A clause that recites “at least one of A, B, and C” can be infringed with only one of the listed items, multiple of the listed items, and one or more of the items in the list and another item not listed.
Embodiment 1. A method comprising: receiving, at a sonic receiver, a set of waveforms induced in a casing of a borehole, wherein one or more portions of the casing include a cement layer bonding the casing to an inner surface of the borehole; perform a slowness-frequency semblance analysis on the waveforms to extract a dispersion of a target set of A0 waves; generating a slowness-frequency amplitude map in a slowness-frequency domain; extracting an amplitude for the target set of A0 wave from the slowness-frequency amplitude map using a slowness-frequency window determined by the slowness-frequency semblance analysis; and generating a two-dimensional cement bonding image based on the extracted amplitude of the target A0 waves.
Embodiment 2. The method of embodiment 1, further comprising: detecting a presence of a channel in the cement layer based on the two-dimensional cement bonding image.
Embodiment 3. The method of embodiments 1 or 2, wherein the slowness-frequency window includes frequencies in a range of 500 to 40000 Hz, inclusive.
Embodiment 4. The method of any one of embodiments 1-3, wherein generating the slowness-frequency amplitude map includes using a beamforming method.
Embodiment 5. The method of any one of embodiments 1-3, wherein generating the slowness-frequency amplitude map includes using one of the Prony method, the matrix-pencil method, or the Differential-Phase Frequency-semblance method.
Embodiment 6. The method of any one of embodiments 1-5, further including: receiving data generated by a third interface echo; generate a tubing eccentricity information from the data generated by the third interface echo; generate an eccentricity calibration based at least in part on the tubing eccentricity information; and calibrate the amplitude of the target A0 waves by removing a tubing eccentricity effect based on the eccentricity calibration.
Embodiment 7. The method of any one of embodiments 1-6, wherein receiving the set of waveforms induced in the casing of the borehole includes receiving the set of waveform from the casing through a wall of a production tubing positioned with an annulus encircled by the casing.
Embodiment 8. The method of any one of embodiments 1-7, further comprising: transmitting, using a sonic transmitter, a set of transmitted sonic waves directed toward and induced in the casing in order to generate the set of waveforms dispersed by the casing of the borehole.
Embodiment 9. The method of any one of embodiments 1-8, wherein generating a two-dimensional cement bonding image based on the extracted amplitude of the target A0 waves comprises: selecting a base value identified from a good-bond zone within the two-dimensional cement bonding image; and calculating a boding condition based on a difference between an A0 amplitude value and the base value.
Embodiment 10. A system comprising: a sonic tool configured to be lowered into a casing within a borehole of a wellbore extending into a subterranean formation, the sonic tool including a sonic transmitter and one or more sonic receivers, wherein the sonic transmitter is configured to generate and transmit into the casing a sonic signal comprising A0 waveforms, and wherein the one or more sonic receivers are configured to receive waveforms induced in the casing; and a processor configured to: input the received waveforms, perform slowness-frequency semblance analysis on the waveforms to extract a dispersion of a target set of A0 waves, generate a slowness-frequency amplitude map in a slowness-frequency domain, extract an amplitude for the target A0 wave from-using a slowness-frequency window determined by the slowness-frequency semblance analysis, and generate a two-dimensional cement bonding image based on the extracted amplitude of the target A0 waves.
Embodiment 11. The system of embodiment 10, wherein the processor is further configured to detect a presence of a channel in a cement layer positioned around the casing based on the two-dimensional cement bonding image.
Embodiment 12. The system of embodiments 10 or 11, wherein the slowness-frequency window includes frequencies in a range of 500 to 40000 Hz, inclusive.
Embodiment 13. The system of any one of embodiments 10-12, wherein the processor is further configured to: receive data generated by a third interface echo; generate a tubing eccentricity information from the data generated by the third interface echo; generate an eccentricity calibration based at least in part on the tubing eccentricity information; and calibrate the amplitude of the target A0 waves by removing a tubing eccentricity effect based on the eccentricity calibration.
Embodiment 14. The system of any one of embodiments 10-13, wherein the sonic tool is configured to be positioned within a tubing positioned present within a annulus encircled by the casing within the wellbore, and wherein the one or more sonic receivers are configured to receive waveforms from the casing through a wall of the tubing.
Embodiment 15. The system of any one of embodiments 10-14, wherein receiving the set of waveforms induced in the casing of the borehole includes receiving the set of waveform from the casing through a wall of a production tubing positioned with an annulus encircled by the casing.
Embodiment 16. The system of any one of embodiments 10-15, wherein the sonic transmitter is a unipole transmitter and the one or more sonic receivers are unipole receivers, wherein the sonic transmitter and the one or more sonic receivers are located on a same side of the sonic tool.
Embodiment 17. The system of any one of embodiments 10-16, wherein the sonic transmitter and the one or more sonic receivers are mounted on a rotary head configured to rotate and to transmit and receive one or more sonic signals at different azimuthal orientations within the borehole.
Embodiment 18. A non-transitory machine-readable storage medium having program code stored thereon and executable by a processor to cause the processor to: input a set of waveforms representing sonic waves induced in a casing of a borehole and detected by one or more receivers of a sonic tool, wherein one or more portions of the casing include a cement layer bonding the casing to an inner surface of the borehole; perform a slowness-frequency semblance analysis on the set of waveforms to extract a dispersion of a target set of A0 waves; generate a slowness-frequency amplitude map in a slowness-frequency domain; extract an amplitude for the target set of A0 wave from the slowness-frequency amplitude map using a slowness-frequency window determined by the slowness-frequency semblance analysis; and generate a two-dimensional cement bonding image based on the extracted amplitude of the target A0 waves.
Embodiment 19. The non-transitory machine-readable storage medium of embodiment 18, wherein the program code further comprises program code executable by the processor to cause the processor to: receive data generated by a third interface echo; generate a tubing eccentricity information from the data generated by the third interface echo; generate an eccentricity calibration based at least in part on the tubing eccentricity information; and calibrate the amplitude of the target A0 waves by removing a tubing eccentricity effect based on the eccentricity calibration.
Embodiment 20. The non-transitory machine-readable storage medium of embodiments 18 or 19, wherein the slowness-frequency window includes frequencies in a range of 500 to 40000 Hz, inclusive.