Patent Publication Number: US-11662495-B2

Title: Sonic through tubing cement evaluation

Description:
BACKGROUND 
     In order to obtain hydrocarbons such as oil and gas, boreholes are drilled through hydrocarbon-bearing subsurface formations. Eventually, the boreholes are plugged and abandoned. Plugging and abandoning wells is controlled by local governments which place liability on companies for environment contamination. Therefore, ensuring proper integrity of the plugged well may prevent future litigation. Government regulations of placing a well barrier for permanent abandonment are often strenuous. For example, a cement barrier may have to be placed adjacent to an impermeable formation with sufficient formation integrity and extend across several hundreds of feet. The cement barrier may need to be verified, however, production tubing within the well may lead to unsatisfactory measurements from current tools and measurement methods. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       These drawings illustrate certain aspects of some examples of the present disclosure and should not be used to limit or define the disclosure. 
         FIG.  1    illustrates an example of a wellbore acoustic logging system; 
         FIG.  2    illustrates a graph of a receiver array response; 
         FIG.  3    illustrates a cut away view of an example of an acoustic logging tool; 
         FIG.  4 A  illustrates a cut away view of an example of a receiver module and a transmitter module; 
         FIG.  4 B  illustrates an example of an operative flow chart; 
         FIG.  4 C  illustrates another example of an operative flow chart; 
         FIG.  5 A  illustrates constant offset measurements along a downhole tubular; 
         FIG.  5 B  illustrates monopole mode responses corresponding with the constant offset measurements of  FIG.  5 A ; 
         FIG.  6    illustrates a graph of dipole mode responses with neighbor subtraction; 
         FIG.  7    illustrates a cross-sectional view of a cement channel with production tubing and casing; 
         FIG.  8    illustrates a graph of an angular waveform; 
         FIG.  9    illustrates a graph of a processed angular waveform of  FIG.  8   ; 
         FIG.  10    illustrates a graph of a laboratory off-center monopole measurement; 
         FIG.  11    illustrates a graph of processed results, after removing a monopole component; 
         FIG.  12    illustrates a graph of simulated dipole measurements in a wellbore with a vertical cement channel; and 
         FIG.  13    illustrates a graph of processed results of  FIG.  12    to identify one or more cement channels. 
     
    
    
     DETAILED DESCRIPTION 
     This disclosure may generally relate to systems and methods for an acoustic logging tool that measures and provides cement conditions for zonal isolation through production tubing. This may be advantageous as pulling production tubing from a well may not be required. As discussed below, the acoustic logging tool may be configured at a low frequency to minimize an acoustic effect created by the reflection of acoustic waves transmitted from the acoustic logging tool and reflected off the production tubing. The frequencies may range from 5 to 35 kHz. The acoustic logging tool may further preserve high fidelity waveform measurements without tool wave interferences. This may allow for the acoustic logging tool to measure an amplitude difference between a cemented and non-cemented annulus, which may range from 1% to 10%. 
     In certain examples, cement conditions may change along a length of the wellbore as well as along the wellbore&#39;s azimuthal direction. For angular measurement coverages, the acoustic logging tool may utilize inversion solutions to detect cement azimuthal changes. For example, to address azimuthal detectability, techniques may be employed to utilize an off-centered monopole, a dipole, and a uni-pole. In some examples, azimuthal detectability solutions may rotate the transmitter, a transmitter cover, or a tool body of the acoustic logging tool. 
       FIG.  1    illustrates an operating environment for an acoustic logging tool  100  as disclosed herein. The acoustic logging tool  100  may comprise a transmitter  102  and/or a receiver  104 . In examples, there may be any number of transmitters  102  and/or any number of receivers  104 , which may be disponed on the acoustic logging tool  100 . A diameter of the acoustic logging tool  100  may range from 1 and 11/16 inches (4.3 centimeters) to 4 and ½ inches (11.4 centimeters). The acoustic logging tool  100  may be operatively coupled to a conveyance  106  (e.g., wireline, slickline, coiled tubing, pipe, downhole tractor, and/or the like) which may provide mechanical suspension, as well as electrical connectivity, for the acoustic logging tool  100 . The conveyance  106  and the acoustic logging tool  100  may extend within a casing string  108  to a desired depth within a wellbore  110 . The conveyance  106 , which may include one or more electrical conductors, may exit a wellhead  112 , may pass around a pulley  114 , may engage an odometer  116 , and may be reeled onto a winch  118 , which may be employed to raise and lower a tool assembly in the wellbore  110 . Signals recorded by the acoustic logging tool  100  may be stored on memory and then processed by display and storage unit  120 , after recovery of the acoustic logging tool  100  from the wellbore  110 . Alternatively, signals recorded by the acoustic logging tool  100  may be conducted to the display and storage unit  120  by way of the conveyance  106 . The display and storage unit  120  may process the signals, and the information contained therein may be displayed for an operator to observe and stored for future processing and reference. Alternatively, signals may be processed downhole prior to receipt by the display and storage unit  120  or both downhole and at a surface  122 , for example, by the display and storage unit  120 . The display and storage unit  120  may also contain an apparatus for supplying control signals and power to the acoustic logging tool  100 . The casing string  108  may extend from the wellhead  112  at or above ground level to a selected depth within the wellbore  110 . The casing string  108  may comprise a plurality of joints  130  or segments of the casing string  108 , each joint  130  being connected to the adjacent segments by a collar  132 . In examples, the casing string  108  may be held in place by cement  137 . There may be any number of layers in the casing string  108 . For example, a first casing  134  and a second casing  136 . It should be noted that there may be any number of casing layers. 
       FIG.  1    also illustrates production tubing  138 , which may be positioned inside of the casing string  108  extending part of the distance down the wellbore  110 . The production tubing  138  may be production tubing, tubing string, casing string, or other pipe disposed within casing string  108 . The production tubing  138  may comprise concentric pipes. It should be noted that concentric pipes may be connected by collars  132 . The acoustic logging tool  100  may be dimensioned so that it may be lowered into the wellbore  110  through the production tubing  138 , thus avoiding the difficulty and expense associated with pulling the production tubing  138  out of the wellbore  110 . 
     In logging systems, such as, for example, logging systems utilizing the acoustic logging tool  100 , a digital telemetry system may be employed, wherein an electrical circuit may be used to both supply power to acoustic logging tool  100  and to transfer data between display and storage unit  120  and acoustic logging tool  100 . A DC voltage may be provided to the acoustic logging tool  100  by a power supply located above ground level, and data may be coupled to the DC power conductor by a baseband current pulse system. Alternatively, the acoustic logging tool  100  may be powered by batteries located within the downhole tool assembly, and/or the data provided by the acoustic logging tool  100  may be stored within a downhole tool assembly, rather than transmitted to the surface  122  during logging. 
     The acoustic logging tool  100  may be used for excitation of the transmitter  102 . As illustrated, one or more receiver  104  may be positioned on the acoustic logging tool  100  at selected distances (e.g., axial spacing) away from transmitter  102 . The axial spacing of receiver  104  from transmitter  102  may vary, for example, from about 0 inches (0 cm) to about 40 inches (101.6 cm) or more. In some examples, at least one receiver  104  may be placed near the transmitter  102  (e.g., within at least 1 inch (2.5 cm) while one or more additional receivers may be spaced from 1 foot (30.5 cm) to about 5 feet (152 cm) or more from the transmitter  102 . It should be understood that the configuration of acoustic logging tool  100  shown on  FIG.  1    is merely illustrative and other configurations of acoustic logging tool  100  may be used with the present techniques. In addition, acoustic logging tool  100  may include more than one transmitter  102  and more than one receiver  104 . For example, an array of receivers  104  may be used. The transmitters  102  may include any suitable acoustic source for generating acoustic waves downhole, including, but not limited to, an off-centered monopole, a dipole, and a unipole or other multipole sources (e.g., dipole, cross-dipole, quadrupole, hexapole, or higher order multi-pole transmitters). Specific examples of suitable transmitters  102  may include, but are not limited to, piezoelectric elements, bender bars, or other transducers suitable for generating an excitation downhole. An excitation may be an acoustic wave, pressure pulse, radio wave, electromagnetic field, and/or the like. The receiver  104  may include any suitable acoustic receiver suitable for use downhole, including piezoelectric elements that may convert acoustic waves into an electric signal or hydrophones. Additionally, the receiver  104  may be able to record any reflected excitation that was transmitted from the transmitter  102  and reflected off an object in the wellbore  110 . 
     With continued reference to  FIG.  1   , transmission of acoustic waves by the transmitter  102  and the recordation of signals by the receivers  104  may be controlled by the display and storage unit  120 , which may include an information handling system  144 . As illustrated, the information handling system  144  may be a component of the display and storage unit  120 . Alternatively, the information handling system  144  may be a component of the acoustic logging tool  100 . The information handling system  144  may include any instrumentality or aggregate of instrumentalities operable to compute, estimate, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes. For example, an information handling system  144  may be a personal computer, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price. Information handling system  144  may include a processing unit  146  (e.g., microprocessor, central processing unit, etc.) that may process EM log data by executing software or instructions obtained from a local non-transitory computer readable media  148  (e.g., optical disks, magnetic disks). The non-transitory computer readable media  148  may store software or instructions of the methods described herein. Non-transitory computer readable media  148  may include any instrumentality or aggregation of instrumentalities that may retain data and/or instructions for a period of time. Non-transitory computer readable media  148  may include, for example, storage media such as a direct access storage device (e.g., a hard disk drive or floppy disk drive), a sequential access storage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory; as well as communications media such wires, optical fibers, microwaves, radio waves, and other electromagnetic and/or optical carriers; and/or any combination of the foregoing. The information handling system  144  may also include input device(s)  150  (e.g., keyboard, mouse, touchpad, etc.) and output device(s)  152  (e.g., monitor, printer, etc.). The input device(s)  150  and output device(s)  152  provide a user interface that enables an operator to interact with the acoustic logging tool  100  and/or software executed by processing unit  146 . For example, the information handling system  144  may enable personnel to view a receiver array response, select analysis options, view collected log data, view analysis results, and/or perform other tasks. 
       FIG.  2    illustrates a receiver array response  200 , in accordance with examples of the present disclosure. The receiver array response  200  may be acquired via receivers  104 , as shown on  FIG.  1   , for example. The array response may be a transient pressure response based on receiver offsets and time in seconds (s), for example. As illustrated, received signals may become increasingly complex, as additional wellbore events/modes occur and as the separation between transmitter  102  to receiver  104  increases, as shown on  FIG.  1   , for example. Therefore, a shorter spacing between transmitter  102  to receiver  104  may simplify the received signal, hence its interpretation or data processing and inversion. However, with a shorter distance from transmitter  102  to receiver  104 , there may be several measurement challenges to overcome. As previously noted, the axial spacing of receiver  104  from transmitter  102  may vary, for example, from about 0 inches (0 cm) to about 40 inches (101.6 cm) or more. In some examples, at least one receiver  104  may be placed near the transmitter  102  (e.g., within at least 1 inch (2.5 cm) while one or more additional receivers may be spaced from 1 foot (30.5 cm) to about 5 feet (152 cm) or more from the transmitter  102 . 
       FIG.  3    illustrates a cross-sectional view of acoustic logging tool  100 , in accordance with certain examples of the present disclosure. As illustrated, acoustic logging tool  100  may include a center mechanical load carrying pipe  300 , which may traverse the length of acoustic logging tool  100 . In some examples, modules may be disposed on center load carrying pipe  300  to form logging tool  100 . A modular design may allow for acoustic logging tool  100  to be configured in any suitable manner. The load being carried may need to match the maximum tension load of a typical wireline cable. As illustrated, acoustic logging tool  100  may include a receiver module  302 , one or more transmitter modules  304 , and one or more mass modules  306 . The mass modules  306  may include a steel mass block or a portion thereof. A typical mass block size may be limited by the choice of a center load carrying pipe diameter and outer diameter of the acoustic logging tool  100 . In examples, receiver  104  is disposed in receiver module  302  and transmitter  102  is disposed in transmitter module  304 . Each module disposed on acoustic logging tool  100  may be connected together by a press fitting/bolted or a sealed fitting. This type of connection may reduce and/or prevent the movement of acoustic waves up and down the length of acoustic logging tool  100 . Additionally, contact area  308  between mass modules  306  and center load carrying pipe  300  may minimize direct acoustic energy coupling. Thus, borehole waves coupling onto the mass module  306  are trapped within the mass module  306  and very limited acoustic energy may be allowed to leak and travel along the body of acoustic logging tool  100  due to a small contact area. The contact area may need to be smaller than 5% of the surface area if the mass modules  306  and the center load carrying pipe  300  are fully bonded. Similarly, a tool wave propagating along the center load carrying pipe  300  may only leak less than 5% of its acoustic energy through direct contact into mass modules  306 . Additionally, a mass cavity  310  which is a void of contact and material between center load carrying pipe  300  and mass module  306  may further reduce acoustic energy transfer between center load carrying pipe  300 , mass module  304 , and other modules that form acoustic logging tool  100 . The mass cavity  310  may be a few tenths of micrometer (e.g., less than a micrometer, less than half a micrometer, or less than a quarter of a micrometer) thick as long as it prevents direct surface contact between the center load carrying pipe  300  and the mass modules  306 . 
       FIG.  4 A  illustrates a close-up view of receiver module  302 , one or more transmitter modules  304 , and one or more mass modules  306 , in accordance with some examples of the present disclosure. Within transmitter module  304  a transmitter  102  may be configured to chirp with a relatively 10 times lower voltage while sweeping across a frequency band. A typical firing voltage for a pulse is about several hundreds of volts. A cross-correlation may then be performed on a recorded waveform with the chirp signal in order to obtain an impulse response. As illustrated, a receiver module  302  is adjacent to and disposed between two transmitter modules  304 . However, in some examples, the transmitter modules  304  may be spaced further apart from the receiver module  302  and other modules may be placed between the transmitter module  304  and the receiver module  302 . The receiver module  302  may include the receiver  104 , which may be circumferentially mounted to an outer surface of the receiver module  302 , which may shield the receiver  104  from propagating tool waves. 
     Without limitation, borehole wave scattering may be minimized due to irregular shapes of the acoustic logging tool  100 . For example, an irregular shape may include a cavity  400  disposed underneath a receiver  104  (i.e., a monopole PZT (lead zirconate titanate) ring). The size of this cavity depends upon the receiver crystal size of a typical 1 cm 3 . Additionally, a signal conditioning electronic compartment  402  may be disposed next to the receiver  104 . The signal conditioning electronic compartment  402  may be covered with a portion of a cylinder  407  that is a tubular portion of the body of the acoustic logging tool  100 . The cylinder  407  may be made of steel or any suitable material as should be understood by one having skill in the art with the benefit of this disclosure. The steel cylinder  407  geometrically matches or is flush with a body  409  of acoustic logging tool  100  to reduce borehole acoustic interactions. A thickness of a wall of the steel cylinder  407  may be in the order of sub-millimeter to 1 or 2 millimeters as long as it does not affect those received signals. 
     Further illustrated in  FIG.  4 A , a mass-pipe acoustic isolation section  404  is extended beyond transmitter sections  304  in an up-hole and downhole direction, up to three feet (one meter) in distance, in order to separate potential tool wave reflections returning from tool joints  411  disposed up-hole and downhole from the acoustic logging tool  100 , beyond a signal recording time window. In some examples, traditional wireline monopole transmitter packaging with a fluid cavity underneath may provide further challenges to measuring cement quality. One challenge may be that a tool cavity may induce reverberations, and a second challenge may be that the casing size and cement channel size may differ substantially, thus, additional bandwidth may be needed to cover all measurements. To address the bandwidth and cavity issue, a monopole ring (i.e., transmitter  102 ) is filled with a steel mass block  406  or a portion thereof, which is similar to a neighboring mass block. A typical mass block size may be limited by the choice of a center pipe diameter and outer diameter of the acoustic logging tool  100 . In certain examples, an allowable space for containing the steel mass block  406  may be fully occupied or maxed out with the steel mass block  406 . In some examples, an array of rubber O-rings  408 , at least one PZT disk, or a rubber sleeve with an array of extruded rings to damp sharp resonances may be utilized in place of the steel mass block  406 . The mass block  406  and/or the O-rings  408  may extend operating bandwidth of the acoustic logging tool  100  from 2 kilohertz (kHz) to 35 or 40 kHz, in some examples. 
     Measurement sensitivity may be boosted by subtracting and/or processing out signals that may always appear and remain the same (e.g., constant signals). For example, downhole equipment, such as tubing and casing may cause reverberations (e.g., constant signals). Without limitation, separating the detection of a vertical cement change (e.g., cement change occurring in lengthwise direction along a wellbore) from an azimuthal cement change increases sensitivity. For detecting changes in vertical cement conditions, a vertical dipole with centered receiver  104  may detect a cement change occurring lengthwise along a wellbore. Two matched transmitters  102  may emit or fire signals with opposite phases (e.g., in-phase and out-of-phase signals) to generate real time waveforms that indicate a vertical cement change. To quantify the cement change, both transmitters  102  may emit in-phase signals, and a model-based inversion may extract cement impedance. In some examples, an amplitude response may correlate to cement conditions. By arranging a ring receiver array of 8 elements or coils disposed between and in contact with two identical transmitters  102 , a pitch-catch measurement may be transformed into a pulse-echo measurement, as should be understood by one having skill in the art, with the benefit of this disclosure. In some examples, waveforms collected in two neighboring depths may be subtracted when a monopole transmitter is utilized. It should be noted that the transmitter  102  may include several variations or configurations, such as utilizing a monopole antenna, for example. 
       FIG.  4 B  illustrates an exemplary flow chart depicting an operation of the acoustic logging tool  100  for identifying cement thickness, in accordance with some examples of the present disclosure. At step  410 , the acoustic logging tool  100  may be disposed within the wellbore  110 , as shown on  FIG.  1   , for example. At step  412 , the acoustic logging tool  100  may transmit one or more signals or waveforms into the wellbore  110 . At step  414 , the acoustic logging tool  100  may receive the one or more signals or waveforms. 
       FIG.  4 C  illustrates an exemplary flow chart  416  depicting another operation of the acoustic logging tool  100  for identifying cement thickness, in accordance with some examples of the present disclosure. At step  418 , the acoustic logging tool  100  may be disposed within the wellbore  110 , as shown on  FIG.  1   , for example. At step  420 , the acoustic logging tool  100  may transmit a first waveform in a first phase from a first transmitter  102  of a first transmitter module  304 , as shown on  FIG.  4 A , for example. At step  422 , the acoustic logging tool  100  may receive a first reflected waveform with a receiver  104  of a receiver module  302 , as shown on  FIG.  4 A  for example. At step  424 , the acoustic logging tool  100  may transmit a second waveform in a second phase from a second transmitter  102  of a second transmitter module  304 , as shown on  FIG.  4 A  for example. At step  426 , the acoustic logging tool  100  may receive a second reflected waveform with a receiver  104  of a receiver module  302 , as shown on  FIG.  4 A  for example. At step  428 , the acoustic logging tool  100  may transmit an in-phase or out of phase waveform among the first transmitter  102  and a second transmitter  102 . At step  430 , the acoustic logging tool  100  receives a reflected in-phase waveform or differentiated waveform with the receiver  104  of the receiver module  302 , as shown on  FIG.  4 A  for example. 
       FIG.  5 A  illustrates constant offset measurements, in inches, between various locations along a downhole tubular or pipe  500  (e.g., production tubing) disposed within cement (not shown), in accordance with examples of the present disclosure. The various locations may include locations of tubing centralizers  502  that may be disposed along a length of the pipe  500 , in some examples. The number at the right indicates the measurement height position from a measurement reference position of zero. However, logging depth at  FIG.  5 B  and  FIG.  6    flip the reference position to the surface. 
       FIG.  5 B  illustrates monopole mode responses corresponding with the offset measurements of  FIG.  5 A , in accordance with examples of the present disclosure. As illustrated on  FIG.  5 B , all boundaries  504  of cement thickness changes along the pipe  500 , are identified. To resolve azimuthal cement condition changes, the acoustic logging tool  100  may be rotated, or the transmitter  102  (e.g., a unipolar transmitter) may be rotated, as shown on  FIG.  1   , for example. Similarly, a measurement may be taken according to an angular position of the acoustic logging tool  100 . In some examples, if 360° wellbore measurements are unwrapped in 5° increments according to a tool-rotating angle, the result may be similar to a two-dimensional ( 2 -D) seismic survey, except an operating frequency may be different. The tubing, fluid annulus, casing, and cement may resemble stratified layers, and appropriate signal processing may remove reflected events and multiples thereof, which may remain constant regardless of angle changes. 
       FIG.  6    illustrates a graph  600  depicting dipole mode response differences  602  due to subtracting adjacent or neighboring responses, in accordance with examples of the present disclosure. 
       FIG.  7    is a cross section view of a cement channel  700  with production tubing  138 , casing string  108 , and cement  137 , in accordance with examples of the present disclosure. The cement channel  700  may be disposed at an angular position of a 45°, for example. The cement channel  700  may have a thickness ranging from 0.2 inch to 1 inch (0.5 cm to 2.5 cm). In certain examples, a tungsten cover with a cut-out window may be disposed over the transmitter  102  to configure the transmitter  102  as a unipolar transmitter. For example, as illustrated, the transmitter  102  may be disposed within a housing  702  with an angular cut-out window  704  for illumination. The housing  702  may have a diameter ranging from 1 to 4 inches (2.5 to 10.0 cm) and may be made of tungsten, for example. The production tubing  138  may have a diameter ranging from 3 to 5 inches (8.0 to 13.0 cm), for example. A thickness of the cement  137  may range from 1 to 3 inches (2.5 to 8.0 cm), for example. 
       FIG.  8    illustrates an angular waveform plot  800 , in accordance with examples of the present disclosure. The waveform plot  800  may be caused by rotating a transmitter  102  which may be or include a unipolar transmitter, as shown on  FIG.  3   , for example. It should be noted that the transmitter  102  may include several variations or configurations, such as unipolar, for example. 
       FIG.  9    illustrates processed angular waveforms  900  after removing unchanged reflections, in accordance with examples of the present disclosure. Therefore, a cement channel (e.g., the cement channel  700  shown on  FIG.  7   ) may be clearly identified with this measurement configuration. In additional examples, there are several variations of the transmitter  102  that may be used to identify a vertical cement channel while rotating the transmitter  102 , as shown on  FIG.  3   , for example. In some examples, the transmitter  102  may be or include an off-center monopole transmitter. A processing technique for azimuthal measurements may be utilized to subtract a monopole component from the waveform. The cement channel  700  may be visible after the processing, for example. 
       FIG.  10    illustrates a laboratory off-center monopole transmitter measurement, in accordance with examples of the present disclosure. As illustrated, a group of higher amplitude events  1000  at or around 0° with an arrival time of or about 0.5 milliseconds (ms) are illustrated. A second higher amplitude event group  1002  may be at or around 180°, which may be an out of phase event due to the nature of residual dipole components. 
       FIG.  11    illustrates processed results after removing a monopole component from received waveforms, in accordance with examples of the present disclosure. The group of higher amplitude events  1100  at or around 0° with an arrival time of or about 0.5 milliseconds (ms) are illustrated. The second higher amplitude event group  1102  is at or around 180° which may be an out of phase event due to the nature of residual dipole components. In examples, the actual position of a cement channel (e.g., the cement channel  700  shown on  FIG.  7   ) may be determined by evaluating angular monopole amplitudes in  FIG.  10   . Without cement, a monopole reflection is stronger at an angle facing the cement channel. Additionally, some examples of the present disclosure include use of a horizontal dipole transmitter to generate a dipole response directly, allowing identification of the cement channel. 
       FIG.  12    illustrates a simulated dipole measurement  1200  in a wellbore with a vertical cement channel, in accordance with examples of the present disclosure. 
       FIG.  13    illustrates processed results  1300  of the simulated dipole measurement  1200  of  FIG.  12   , to indicate a cement channel, in accordance with examples of the present disclosure. Improvements over current devices and methods may be found in the positioning of transmitters  102  and receivers  104  on the acoustic logging tool  100 , as shown on  FIG.  3   , for example. Additionally, the acoustic logging tool includes an acoustic isolator that is a slotted sleeve. Additionally, the acoustic logging tool described above allows for the placement of a transmitter module next to a receiver module without concern for tool wave interferences, and prevents borehole wave coupling along the acoustic logging tool, which may also minimize reflection of the borehole wave along the acoustic logging tool. This may allow for an implementation of a true pulse-echo type measurement using a sandwiched receiver module, which may allow for signals to be useful for interpretation for a substantially longer time window before the tool joint reflection is received. Additionally, the construction of the acoustic logging tool may allow for a uni-pole source to determine azimuthal cement quality resolution. 
     Accordingly, the examples of the present disclosure may provide a direct indication of cement condition changes in vertical or azimuthal directions for Through Tubing Cement Evaluation (TTCE) applications. The examples may include any of the various features disclosed herein, including one or more of the following statements. 
     Statement 1. An acoustic logging tool comprising: a center load carrying pipe; a receiver module connected to the center load carrying pipe; one or more transmitter modules connected to the center load carrying pipe; and one or more mass modules connected to the center load carrying pipe. 
     Statement 2. The acoustic logging tool of the statement 1, wherein the receiver module includes one or more receivers. 
     Statement 3. The acoustic logging tool of the statement 1 or 2, wherein the one or more receivers are circumferentially mounted to an outer surface of the receiver module. 
     Statement 4. The acoustic logging tool of any of the preceding statements, wherein the one or more transmitter modules includes one or more transmitters. 
     Statement 5. The acoustic logging tool of any of the preceding statements, further comprising a contact area between each of the one or more mass modules that reduces direct acoustic energy coupling. 
     Statement 6. The acoustic logging tool of any of the preceding statements, further comprising a mass cavity that is disposed between the one or more mass modules and the center load carrying pipe. 
     Statement 7. The acoustic logging tool of any of the preceding statements, wherein the receiver module is disposed between the one or more transmitter modules on the center load carrying pipe. 
     Statement 8. The acoustic logging tool of any of the preceding statements, wherein the one or more mass modules are disposed along the center load carrying pipe and separated from the receiver module by at least one of the one or more transmitter modules. 
     Statement 9. The acoustic logging tool of any of the preceding statements, wherein the one or more mass modules, the one or more transmitter modules, and the receiver module are connected to each other individually by a press fit. 
     Statement 10. The acoustic logging tool of any of the preceding statements, further comprising a mass-pipe acoustic isolation section configured to prevent tool wave reflections returning from one or more tool joints above or below the receiver module. 
     Statement 11. The acoustic logging tool of any of the preceding, wherein an array of O-rings, one or more PZT disks, or a rubber sleeve may be disposed below a transmitter in the one or more transmitter modules. 
     Statement 12. A method for identifying cement thickness comprises disposing an acoustic logging tool into a wellbore, wherein the acoustic logging tool comprises: a center load carrying pipe; a receiver module connected to the center load carrying pipe; one or more transmitter modules connected to the center load carrying pipe; one or more mass modules connected to the center load carrying pipe; and transmitting one or more waveforms from a transmitter on the one or more transmitter modules into the wellbore; and receiving one or more received waveforms with a receiver on the receiver module. 
     Statement 13. The method of the statement 12, further comprising transmitting the one or more waveforms and receiving the one or more received waveforms at one or more depths. 
     Statement 14. The method of the statement 12 or 13, further comprising subtracting adjacent received waveforms from the one or more depths. 
     Statement 15. The method of any of the statements 12-14, wherein the transmitter is a unipolar transmitter. 
     Statement 16. The method of any of the statements 12-15, further comprising rotating the unipolar transmitter to perform one or more transmitter firings. 
     Statement 17. The method of any of the statements 12-16, wherein the transmitter is a monopole transmitter and the acoustic logging tool further comprises a tungsten cover disposed over each of the one or more transmitter modules. 
     Statement 18. A method for identifying cement thickness comprises disposing an acoustic logging tool into a wellbore, wherein the acoustic logging tool comprises: a center load carrying pipe; a receiver module connected to the center load carrying pipe; one or more transmitter modules connected to the center load carrying pipe; one or more mass modules connected to the center load carrying pipe; and transmitting a first waveform in a first phase from a first transmitter on a first transmitter modules into the wellbore; receiving a first reflected waveform with a receiver on the receiver module; transmitting a second waveform in a second phase that is opposite the first phase from a second transmitter on a second transmitter module; receiving a second reflected waveform with the receiver on the receiver module; transmitting an in-phase or out of phase waveform among the first transmitter and the second transmitter; and receiving a reflected in-phase waveform or differentiated waveform with the receiver on the receiver module. 
     Statement 19. The method of the statement 18, further comprising performing an inversion on the first reflected waveform, second reflected waveform, and the reflected in phase waveform to extract a cement impedance. 
     Statement 20. The method of the statement 18 or 19, further comprising identifying an amplitude from the inversion to determine one or more cement conditions. 
     The preceding description provides various examples of the systems and methods of use disclosed herein which may contain different method steps and alternative combinations of components. It should be understood that although individual examples may be discussed herein, the present disclosure covers all combinations of the disclosed examples, including, without limitation, the different component combinations, method step combinations, and properties of the system. It should be understood that the compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the elements that it introduces. 
     For the sake of brevity, only certain ranges are explicitly disclosed herein. However, ranges from any lower limit may be combined with any upper limit to recite a range not explicitly recited, as well as, ranges from any lower limit may be combined with any other lower limit to recite a range not explicitly recited, in the same way, ranges from any upper limit may be combined with any other upper limit to recite a range not explicitly recited. Additionally, whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range are specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values even if not explicitly recited. Thus, every point or individual value may serve as its own lower or upper limit combined with any other point or individual value or any other lower or upper limit, to recite a range not explicitly recited. 
     Therefore, the present examples are well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular examples disclosed above are illustrative only and may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Although individual examples are discussed, the disclosure covers all combinations of all of the examples. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. It is therefore evident that the particular illustrative examples disclosed above may be altered or modified and all such variations are considered within the scope and spirit of those examples. If there is any conflict in the usages of a word or term in this specification and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.