Patent ID: 12234716

DESCRIPTION OF EMBODIMENTS

The description that follows includes example systems, methods, techniques, and program flows that embody embodiments of the disclosure. However, it is understood that this disclosure may be practiced without these specific details. For instance, this disclosure refers to different example transmitters and receivers (e.g., dipole, monopole, etc.) in illustrative examples. Embodiments of this disclosure can also be applied to other types of transmitters and receivers. As another example, this disclosure refers to evaluation of the cement bonding condition. Embodiments of this disclosure can also be applied to other material outside the casing, other properties of the cement or material, etc. In other instances, well-known instruction instances, protocols, structures and techniques have not been shown in detail in order not to obfuscate the description.

Example embodiments can be used for various downhole well logging applications, including through tubing cement evaluation (TTCE). For instance, example embodiments can include a transmitter and receiver (e.g., dipole) positioned in a wellbore for acoustic well logging (including anisotropy measurement, formation stress estimation, cement bond evaluation, etc.).

TTCE can be used as part of plug and abandonment operations of a wellbore. In particular, at the end of a well's life, cement integrity needs to be evaluated to ensure the well can be properly plugged. In a TTCE application, the downhole tool having the transmitter and receiver can be positioned within a production tubing that is within a casing of the wellbore. For the TTCE application, the cement bonding condition to be evaluated (via acoustic signaling) is positioned in an annulus that is between the casing and a wall of the wellbore. Thus, TTCE can be challenging because the acoustic signals emitted from a conventional downhole tool can have insufficient energy to penetrate beyond the production tubing. A conventional cement bond log (CBL) tool requires the production tubing to be pulled from the wellbore so that the acoustic signaling can directly reach casing through the wellbore fluid. The casing response can be too low relative to the overall signal, which makes evaluation of the cement behind the casing difficult. As further described below, in contrast to conventional TTCE approaches, example embodiments can evaluate cement integrity without removing the production tubing—which can result in significant savings in time and money.

Another challenge for accurate TTCE can include eccentricity, which can occur from the production tubing being off-center within the casing (which can be due to various factors, such as the curvature of the production tubing, well inclination, etc.). As the severity of the eccentricity increases, the effects caused by the casing also increases. Such effects can adversely affect cement evaluation. Thus, conventional approaches based on the assumption of no eccentricity may not provide accurate evaluations when there is eccentricity. Some embodiments can be configured to overcome the effect of eccentricity. In some implementations, eccentricity can be defined as displacement of at least one of the production tubing and the downhole tool away from the centering of the casing. In some implementations, the production tubing and the downhole tool can be assumed to be concentric with centralizers used to center the production tubing and the downhole tool. As further described below, example embodiments can include operations that can account for this eccentricity.

Conventional TTCE includes a monopole excited borehole resonance. However, a monopole resonance mode can change with eccentricity, thereby making isolation of the resonance in the time and frequency domain difficult. Thus, example embodiments include the use of a dipole resonance mode—which can have several advantages over a conventional monopole resonance mode. As further described below, a dipole resonance mode can provide an alternative approach to TTCE to complement the monopole result for a more accurate evaluation of the cement.

Some embodiments can include a dipole mode that can be excited with a cross-dipole (X dipole and Y dipole). In some implementations, a late time acoustic signal can be detected and transformed into the frequency domain. The peaks in the frequency domain can indicate the resonance modes of the wellbore. The casing-sensitive modes can be identified. The amplitude of the mode can then be used to perform cement evaluation (e.g., cement bonding). In the case of partial bonded case (casing with a fluid channel), the cross-dipole response can be rotated according to the channel direction to obtain desired response. Using a dipole mode, only one mode is be needed over the eccentricity from 0% up to approximately 90%. Also, eccentricity has limited effects on TTCE when using the dipole mode. Thus, as further described below, example embodiments can include the use of a low frequency dipole mode to provide for a more accurate TTCE, wherein the definition of low frequency can vary (e.g., 10 kilohertz, 5 kilohertz, etc.).

Example TTCE Application

Some embodiments can be used in a downhole application to increase the measurement sensitivity of through tubing cement evaluation (TTCE) and acoustic signals at target points such as at or near a casing, a cement layer, and/or a casing/cement interface. However, example embodiments can be used any other types of application. For example, example embodiments can be used in Measurement While Drilling and wireline operations, which are further described below. An example application for TTCE is now described. In particular,FIG.1depicts an example sensor configuration that is part of a through tubing cement evaluation (TTCE) system, according to some embodiments.

FIG.1Adepicts a side cross-sectional view of an example downhole tool having a transmitter and receiver for through tubing cement evaluation, according to some embodiments.FIG.1Bdepicts an overhead cross-sectional view of the example downhole tool ofFIG.1A, according to some embodiments.

As shown inFIGS.1A and1B(collectively,FIG.1), an acoustic logging tool105is deployed within a well that is defined by a wellbore114in which a production tubing110is installed within cement and metallic casing layers. The acoustic logging tool105is generally configured to induce acoustic echo responses and process the responses to determine material and structural properties of multiple material layers within the wellbore114. For example, the echo responses may comprise reflected and/or refracted acoustic waves generated when acoustic signals transmitted from acoustic logging tool105reflect and/or refract at acoustic impedance boundaries within and between the wellbore layers.

The wellbore114is formed within a subsurface formation102, such as may comprise a hydrocarbon formation in part, by drilling, and is typically filled with liquid and/or slurry substances such as water, reservoir fluids, etc. The outer perimeter of the wellbore114can be sealed from the subsurface formation102by one or more barrier layers. For instance, a casing106comprises a metallic tubular member forming an inner liner that seals the interior of the wellbore114. To securely position the casing106with respect to the inner surface of the subsurface formation102, a cement layer104is formed between the casing106and the inner surface of the subsurface formation102that bounds the wellbore114. The production tubing110is installed within the cylindrical interior space of the casing106to form an innermost production conduit117and an annular space112that typically forms an annular fluid layer between the outer surface of the production tubing110and the inner surface of casing106.

The acoustic logging tool105includes a tool housing121within which an acoustic sensor125and a controller120can be disposed. As shown inFIG.1A, the acoustic sensor125comprises an acoustic transmitter116and an acoustic receiver118within the tool housing121within which the controller120is also disposed. As further described below, the acoustic transmitter116can include one or more transmitters. Similarly, the acoustic receiver118can include one or more receivers.

The acoustic logging tool105is positioned within the innermost production conduit117in the production tubing110with an additional annular fluid layer123formed in the annular space between the outer surface of the tool housing121and the inner surface of the production tubing110. The acoustic sensor components are movably disposed within the fluid and along the length of the production conduit117via a conveyance means115such as may be a wireline or slickline. In some embodiments, the acoustic sensor125may be configured with the acoustic transmitter116and the acoustic receiver118being individually contained and independently movable components. Alternatively, the acoustic sensor125may be configured within a contiguous sensor housing such as depicted inFIG.1in which both the transmitter116and the receiver118are contained in a common tool housing121.

The acoustic logging tool105comprises acoustic source/transmission components and acoustic detection and processing components within the acoustic sensor125. The transmitter and receiver components of the acoustic sensor125are configured to measure acoustic responses, such as in the form of acoustic echoes, generated from acoustic source signals transmitted from the acoustic transmitter116to various acoustic response target points within the wellbore114. In the depicted embodiment ofFIG.1B, the acoustic sensor125comprises a transmitter and/or receiver that are configured as piezoelectric transducers that are electrically, optically, or otherwise communicatively coupled to the controller120. The overhead representation inFIG.1Bof the acoustic sensor125may represent either a transmitter and/or a receiver, which may be distinct, axially offset components as shown inFIG.1A.

As shown inFIG.1B, the acoustic sensor125can include a transducer comprising a piezoelectric material layer126and a pair of electrodes122coupled to a front side and a back side of the piezoelectric material layer126. An electrical or optical communication interface137can provide electrical contact and connectivity between the acoustic sensor125and controller120. The acoustic sensor125can further include a backing material layer124disposed behind the piezoelectric material layer126. The backing material layer124can include acoustic attenuation material such as ultrasonic attenuation material that is compositionally and structurally configured to attenuate acoustic waves emitted from the back side of the primary transducer. The acoustic sensor125can further include a protective cover layer129coupled to the radially outward front side of the transducer. The cover layer129can form a fluid impermeable seal preventing fluids from contacting the internal components of the acoustic sensor125. To minimize front side external acoustic reflection during signal transmission and internal acoustic reflection during reception of acoustic echoes, the cover layer129may comprise a material having an acoustic impedance matching the acoustic impedance of the external acoustic medium, such as fluids within production conduit117.

The controller120may be a programmable electronic module that is communicatively coupled to the piezoelectric transducer(s) of the transmitter/receiver components within the acoustic sensor125. The controller120is configured, using electronics and program code instructions, to provide excitation pulse signals to the transducer electrodes during pulse transmit periods that may comprise the excitation phase of measurement cycles. The controller120can include a signal generator127and a signal processor128. The signal generator127is configured using any combination of hardware and/or program code constructs to generate and send excitation pulse signals to the electrodes122via the communication interface137that may include one or more electrical conduction paths. The signal processor128is configured using any combination of hardware and/or program code constructs to detect/measure echo response signals received from receiver transducer electrodes via the communication interface137.

The signal generator127can generate pulse signals comprising alternating current signals and corresponding voltage fluctuations that are applied to the transducer electrodes, resulting in fluctuating electrical fields and corresponding fluctuating electrical charges applied across the piezoelectric layer of the transducer within the acoustic transmitter116. Piezoelectric effect results in changes to mechanical stress and consequent mechanical deformation of the piezoelectric material layers. The mechanical deformation corresponds in terms of frequency and amplitude to the frequency and amplitude of the received electrical excitations signals, resulting in an ultrasonic vibration of the piezoelectric layer. The ultrasonic vibration of the piezoelectric layer mechanically induces corresponding ultrasonic pressure waves within and across the wellbore114. The acoustic pressure waves generated by the transmitter transducer, such as the sensor pulse138, propagate through a wellbore annulus111that includes all of the material layers and layer boundaries within the wellbore114. The sensor pulse138induces a corresponding acoustic echo signal140that results from reflection and/or refraction from various downhole acoustic boundaries within and at the boundaries between the various material layers within the wellbore114.

Sensor pulses, such as the sensor pulse138, can be generated periodically, intermittently, or otherwise as part of individual measurement cycles. Each measurement cycle can begin with an excitation phase during which the signal generator127applies an electrical excitation that induces corresponding acoustic pulses in the transmitter transducer(s) to which the excitation is applied. Each measurement cycle can further include an echo response phase such as may be defined and implemented by the signal processor components128. During the echo response phase of each measurement cycle, signal processor components can detect and process acoustic echo response signals such as the signal140that are transduced by a receiver transducer from acoustic waves to an electrical acoustic response signal.

TTCE analysis can include acoustic response information that is location-specific (e.g., along the cylindrical boundary between the cement layer104and the casing106) as well as properties specific (e.g., density, structural characteristics). The multiple different material layers that may present acoustic barriers (reflectors and sinks) and varying ambient environmental conditions may present interference for or otherwise reduce accuracy of the acoustic measurements and particularly acoustic measurements for which the target response locations are outside of one or more of the wellbore tubulars such as the production tubing110and the casing106. The apparatus100is configured to collect and process acoustic response information in a manner that removes interference such as extraneous acoustic response information and sensor variations to enable more accurate representation of target acoustic response information. The acoustic measurement components of the apparatus100are configured to implement efficient and accurate acoustic measurements of wellbore material properties with reduced reliance on removing internal acoustic barriers such as production tubing.

In some embodiments, the apparatus100is configured to collect acoustic measurement information that uses differential processing of acoustic responses to more precisely isolate intended acoustic response information such as cement bond response information. As further described below, the acoustic transmitter116can include an azimuthally directional transmitter such as a dipole transmitter that emits acoustic pulses. Also, as further described below, the acoustic receiver118can be a multi-receiver array. For example, the acoustic receiver118can be an array of two or more azimuthal receivers.

The target points for acoustic measurements by the directional acoustic transmitter/receiver pair may be included along one or more circumferential boundaries at various radial distances from the center of the wellbore114. In the depicted embodiment, primary target points may be included in the cylindrical contact interface between the cement layer104and the outer metallic surface of the casing106. Target points may also be included between the inner and outer surfaces of the cement layer104and or within other material layers or material boundaries within the wellbore114. For example, target points may be included at the liquid/metal boundary between the annular fluid layer112and the casing106to test casing material properties such as calcium or other mineral buildup on the casing surface. All or most target points are located outside of the production tubing110and some of the most important, such as cement-to-casing bond target points, are located outside of both the production tubing110and the casing106.

FIG.2depicts an example system that is configured to implement through tubing cement evaluation (TTCE), according to some embodiments. InFIG.2, a well system200is particularly configured to address issues posed by TTCE, which entails measuring acoustic responses, such as acoustic echoes, generated by acoustic source signals that originate within an innermost tubing within a wellbore. The well system200includes subsystems, devices, and components configured to implement acoustic measurement testing procedures within a substantially cylindrical wellbore volume207that in the depicted embodiment is bounded and sealed by a casing205. A cement layer209between the casing205and an inner borehole wall208provides a protective seal that maintains structural and positional stability of the casing205. The well system200includes a wellhead202configured to deploy drilling and production and/or injection equipment such as drilling strings, production strings, etc. As shown, an interior tubing214is deployed within the wellbore volume207and may comprise production tubing, drilling tubing such as drill pipes, injection tubing, or other type of tubing.

The wellhead202includes components for configuring and controlling deployment in terms of insertion and withdrawal of a test string within the wellbore volume207. The test string may be configured as a wireline test string deployed within the interior tubing214and having a wireline cable204for moving and providing communication and power source connectivity for downhole test tools. In the depicted embodiment, the wireline cable204is configured as the conveyance means for a logging tool216that includes an acoustic transmitter220and an acoustic receiver222disposed within a tool housing219. Communication and power source couplings are provided to the acoustic transmitter220and the acoustic receiver222via the wireline cable204having one or more communication and power terminals within the wellhead202.

The acoustic transmitter220and the acoustic receiver222comprise components, including components not expressly depicted, configured to implement acoustic measurement testing including TTCE testing. The acoustic transmitter220may be configured as an acoustic transducer as depicted inFIG.1Bthat transmits acoustic pulses in an azimuthally directional manner.

The acoustic receiver222may comprise an array of azimuthal receivers with two or more receivers. The logging tool216further includes a controller218comprising components including a signal generator224and a response processor226for controlling acoustic measurement operation. The signal generator224is configured to generate electrical signals that are converted by the acoustic transmitter220into acoustic waves emitted within the wellbore207. The response processor226is configured to measure acoustic responses by processing the converted acoustic wave information from the acoustic receiver222.

The logging tool216is coupled via a telemetry link within the wireline cable204to a data processing system (DPS)240. The DPS240includes a communication interface238configured to transmit and receive signals to and from the logging tool216as well as other devices within well system200using a communication channel with the wireline cable204as well as other telemetry links such as wireless electromagnetic links, acoustic links, etc. The DPS240may be implemented in any of one or more of a variety of standalone or networked computer processing environments. As shown, the DPS240may operate above a terrain surface203within or proximate to the wellhead202, for example. The DPS240includes processing, memory, and storage components configured to receive and process acoustic measurement information to determine material and structural properties and conditions within and/or external to the cylindrical volume defined by the borehole wall208. The DPS240is configured to receive acoustic response data from the logging tool216as well as from other sources such as surface test facilities. The acoustic data received from the logging tool216includes echo response signals detected by the acoustic receiver222. The DPS240comprises, in part, a computer processor242and a memory244configured to execute program instructions for controlling measurement cycles and processing the resultant echo response signals to determine wellbore material properties. Such properties and structural attributes may include but are not limited to cement structural integrity and the state of adhesion of the bonding between the cement layer209and the casing205.

The DPS240includes program components including a TTCE processor248and a logging controller250. The TTCE processor248includes program components and data configured to process acoustic response data received from the logging tool216. The logging controller250includes program components and data configured to coordinate and otherwise control positioning and repositioning of the logging tool216within and along the length of the interior tubing214, as well as the acoustic measurement procedures at each position. Loaded from the memory244, the TTCE processor248is configured to execute program instructions to receive and process acoustic response data such as the logging data230.

The components within the DPS240and the test string interoperate to implement acoustic measurement collection and processing in a manner enabling optimal accuracy of through tubing material evaluation. A next acoustic measurement cycle may begin with positioning of the logging tool216at a next axial location along the length of interior tubing214. At the next axial location, the logging tool216can rotationally positioned to an initial specified azimuthal angle. In the depicted embodiment, the logging tool216may be rotated via controlled actuation of a DC motor229. For example, a rotation controller227may be incorporated within the controller218and be configured to azimuthally position the logging tool216, and more specifically the transmitter/receiver within the logging tool216, to a specified initial measurement azimuth angle.

The measurement cycle may continue with the logging tool216measuring an acoustic response at the initial azimuthal angle. For TTCE logging, the overall acoustic response includes an echo response window in which echo signal characteristics profile material and structural characteristics of the cement-to-casing bonding at the azimuth angle. Following the initial azimuth measurement, the logging tool216is rotated to a next azimuth at which a next azimuthally specific acoustic response is measured and otherwise collected, and the process is repeated at other azimuthal angles along a full 360° azimuthal path. The azimuthal angles at which the measurements are performed are selected to result in measurement pairs that are substantially azimuthally offset (e.g., one measurement is separated by at least 90° from the other measurement in the pair). In some embodiments, the measurement angles are selected to result in measurement pairs that are substantially azimuthally opposed (e.g., separated by approximately 180° within a range of 10°). It should be noted that the measurements at each point may be nearly instantaneous due to the proximity of the cement layer target points such that the rotation of the logging tool216between measurements may be intermittent or continuous.

Example Transmitter-Receiver Configurations

Example transmitter-receiver configurations are now described. Two example configurations are now described. Both configurations can be arranged to generate a dipole emission from different azimuthal positions.FIG.3depicts a first example transmitter-receiver configuration having a cross-dipole transmitter and azimuthal receiver array for performing TTCE, according to some embodiments.FIG.3depicts a wellbore301formed in a subsurface formation350. The wellbore301has been cased (with a casing316) such that an annulus314has been defined between a wall of the wellbore301and the casing316. A cement318has been poured into the annulus314. In this example, the cement318includes three channels360. Thus, these portions of the cement318are partially (not fully) bonded. As further described below, example embodiments can evaluate the cement to determine varying bonding conditions of the cement.

A production tubing312has been positioned down the wellbore301within the casing316. A downhole tool302is positioned within the production tubing312. In this example, the downhole tool302includes a cross-dipole transmitter that includes an X dipole transmitter306and a Y dipole transmitter308. The X dipole transmitter306and the Y dipole transmitter308can emit in directions that are orthogonal to each other. In some implementations, the cross-dipole transmitter can be replaced with a single dipole transmitter such that the transmitter can rotate to emit from the two orthogonal directions.

Additionally, a receiver array332is positioned at a different longitudinal position as compared to the cross-dipole transmitter. In this example, the receiver array332includes a number of receivers are at different azimuthal positions circumferentially around the downhole tool302. In some implementations, the receiver array332can be replaced with an X dipole receiver and a Y dipole receiver to receive the dipole response being emitted from the cross-dipole transmitter. In operation, the transmitter(s) can emit acoustic waves that interact with the wellbore structure (including the production tubing312, the casing316, wellbore fluid, and the downhole tool302itself). The returned acoustic wave can be detected by the receiver array332. Example operations of the first example transmitter-receiver configuration is further described below in reference toFIGS.5-6.

FIG.4depicts a second example transmitter-receiver configuration having a rotatable transmitter and azimuthal receiver array for performing TTCE, according to some embodiments.FIG.4depicts a wellbore401formed in a subsurface formation450. The wellbore401has been cased (with a casing416) such that an annulus414has been defined between a wall of the wellbore401and the casing416. A cement418has been poured into the annulus414. In this example, the cement418includes four channels460. Thus, these portions of the cement418are partially (not fully) bonded. As further described below, example embodiments can evaluate the cement to determine varying bonding conditions of the cement.

A production tubing412has been positioned down the wellbore401within the casing416. A downhole tool402is positioned within the production tubing412. In this example, the downhole tool402includes a rotatable transmitter406. The rotatable transmitter406can rotate for emission in different azimuthal directions. In some implementations, the rotatable transmitter406can be a unipole, dipole, or higher order pole. The rotatable transmitter406can emit acoustic transmissions at different azimuthal directions such that there is at least one rotation. The dipole component along any direction can be computed by summing the dipole response of each of the emissions at the specific direction.

Additionally, a receiver array432is positioned at a different longitudinal position as compared to the rotatable transmitter406. In this example, the receiver array432includes a number of receivers are at different azimuthal positions circumferentially around the downhole tool402. In some implementations, the receiver array432can be replaced with an X dipole receiver and a Y dipole receiver to receive the dipole response being emitted from the rotatable transmitter406. Also, the receiver array or receivers can be mounted on a fixed or rotatable section of the downhole tool402. In operation, the rotatable transmitter406can emit acoustic waves that interact with the wellbore structure (including the production tubing412, the casing416, wellbore fluid, and the downhole tool402itself). The returned acoustic wave can be detected by the receiver array432. Example operations of the second example transmitter-receiver configuration is further described below in reference toFIGS.21-22.

Example Operations

Example operations are now described.FIGS.5-6depict a flowchart of first example operations for performing TTCE using wellbore multi-pole resonance, according to some embodiments.FIGS.5-6depict a flowchart500and a flowchart600, respectively, having operations that include a transition point A for operations to move between the flowchart500and the flowchart600. Operations of the flowchart500-600can be performed by software, firmware, hardware or a combination thereof. Such operations are described with reference to the systems ofFIGS.1A-1B and2-3. However, such operations can be performed by other systems or components. For example, at least some of the operations of the flowcharts500-600are described as being performed by a computer at a surface of the wellbore. In some embodiments, one or more of these operations can be performed by a computer at the surface and/or downhole in the wellbore. The operations of the flowchart500start at block502.

At block502, a downhole tool (having a multi-pole transmitter and a receiver array with at least two receivers positioned in different azimuthal positions) is conveyed in a production tubing positioned in a casing positioned around a wellbore such that there is an annular area (between the casing and a wall of the wellbore) into which cement is placed. For example, with reference toFIG.3, the downhole tool302is lowered down the wellbore301within the production tubing312.

At block504, an acoustic transmission is emitted, based on an X dipole excitation by the multi-pole transmitter, in a first direction (outward through the production tubing and the casing and into the cement). For example, with reference toFIG.3, the transmitter306can perform an X dipole excitation outward in a first direction in the wellbore301outward toward through the production tubing312and the casing316and into the cement318.

At block506, an acoustic response generated from the X dipole excitation is detected by the receiver array. For example, with reference toFIG.3, one or more of the receivers330-338can detect an acoustic response generated from the acoustic transmission that passes through the production tubing312and the casing316and into the cement318.

At block508, an acoustic transmission is emitted, based on a Y dipole excitation by the multi-pole transmitter, in a second direction that is orthogonal to the first direction (outward through the production tubing and the casing and into the cement). For example, with reference toFIG.3, the transmitter306can perform an Y dipole excitation outward in a second direction in the wellbore301outward toward through the production tubing312and the casing316and into the cement318.

At block510, an acoustic response generated from the Y dipole excitation is detected by the receiver array. For example, with reference toFIG.3, one or more of the receivers330-338can detect an acoustic response generated from the acoustic transmission that passes through the production tubing312and the casing316and into the cement318.

At block512, a determination is made of whether there is another azimuthal position from which to emit an acoustic transmission. For example, with reference toFIG.2, the logging controller250can make this determination. For instance, the TTCE operations may be configured such that emission and detection may be performed at N number of different azimuthal positions. Accordingly, the logging controller250can determine whether emission and detection has occurred at each of the N number of azimuthal positions. If there is another azimuthal position from which to emit an acoustic transmission, operations of the flowchart500continue at block514. Otherwise, operations of the flowchart500continue at transition point A, which continues at transition point A of the flowchart600ofFIG.6.

At block514, the downhole tool is rotated to a next azimuthal position. For example, with reference toFIG.2, the logging controller250can cause the downhole tool to be rotated in a next azimuthal position from which an X-dipole excitation, Y-dipole excitation, and detection. Operations of the flowchart500then return to block504to emit an X-dipole excitation.

From transition point A of the flowchart600ofFIG.6, operations continue at block602.

At block602, a decomposed response is generated from the first and second acoustic responses. For example, with reference toFIG.2, the TTCE processor248can generate the decomposed response. To illustrate,FIG.7depicts a graph of an example sample time domain decomposed response for casing with and without cement bonding, according to some embodiments. InFIG.7, a graph700includes a y-axis702that is an amplitude of the response and an x-axis704that is time (micro-seconds). The graph700includes a curve706and a curve708. The curve706is an acoustic response that traverses a free pipe section of the casing/cement (in which the cement is not fully bonded to the casing). The curve708is an acoustic response that traverses a fully bonded section of the casing/cement (in which the cement is fully bonded to the casing).

In the graph700, the signal is a decomposed dipole response computed from eight azimuthal receivers. A range710includes early time arrivals. As shown, the range710includes the bulk of the acoustic energy, which can include reflection from the production tubing, reflection from the casing through the production tubing, guided wave refraction from the production tubing, guided-wave refraction from the casing through the production tubing, Stoneley wave, tool wave, etc. After a certain time, certain waves propagate away from the receiver in the form of a guided casing wave, a guided tubing wave, a tool wave, a Stoneley wave or multiple reflections. Hence in a range712that includes the late time arrivals, the signal is observed to have fixed frequency components and with decreasing amplitude over time. This can be considered the borehole resonance mode. The graph700shows that the dipole signal with a four kilohertz frequency is sensitive to cement bonding behind the casing (as the free pipe case is showing much higher time domain signal compared to a fully bonded case).

FIG.8depicts a graph of example dipole late time responses for various eccentricities with a free pipe condition, according to some embodiments. InFIG.8, a graph800includes a y-axis802that is an amplitude of the response and an x-axis804that is time (micro-seconds). The graph800includes example dipole responses for a free pipe condition (no cement bonding on the casing) at five different eccentricities. A response806is an example dipole response at 0% eccentricity. A response808is an example dipole response at 20% eccentricity. A response810is an example dipole response at 40% eccentricity. A response812is an example dipole response at 60% eccentricity. A response814is an example dipole response at 80% eccentricity.

The eccentricity can be measured in terms of percentage, which is calculated to be the production tubing/tool offset divided by the annulus thickness between production tubing and casing. Hence a 0% eccentricity means that the production tubing/tool is concentric, while 100% eccentricity means that the production tubing is touching the casing inner wall. The graph700shows that for various eccentricities, both amplitude and decay rate remain essentially the same. Therefore, amplitude or decay can be used to invert the cement bonding to the casing with limited influence from eccentricity. As shown, different levels of eccentricity have a limited effect on the dipole responses. Thus, dipole responses can be essentially insensitive to eccentricity. Additionally, as shown, the amount of decay of the responses over time is similar across the different levels of eccentricity.

FIG.9depicts a graph that includes the example dipole late time responses ofFIG.8transformed into the frequency domain, according to some embodiments. InFIG.9, a graph900includes example frequency domain responses for various eccentricities with free pipe and fully bonded conditions. The graph900includes a y-axis902that is a power spectrum of the response and an x-axis904that is frequency (kilohertz).

The graph900includes example dipole responses for a free pipe (FP) condition (no cement bonding on the casing) at five different eccentricities (responses906-914). A response906is an example dipole response for a FP condition at 0% eccentricity. A response908is an example dipole response for a FP condition at 20% eccentricity. A response910is an example dipole response for a FP condition at 40% eccentricity. A response912is an example dipole response for a FP condition at 60% eccentricity. A response914is an example dipole response for a FP condition at 80% eccentricity.

The graph900also includes example dipole responses for a fully bonded (FB) condition (cement bonding on the casing) at five different eccentricities (responses916-924). A response916is an example dipole response for a FB condition at 0% eccentricity. A response918is an example dipole response for a FB condition at 20% eccentricity. A response920is an example dipole response for a FB condition at 40% eccentricity. A response922is an example dipole response for a FB condition at 60% eccentricity. A response924is an example dipole response for a FB condition at 80% eccentricity. The FP (free pipe) responses show high modal energy near 4 kHz with relatively similar amplitude. The FB (fully bonded) responses shows minimum energy.

The energy variation for both FP and FB responses for different eccentricities can be plotted—by converting the overall energy computed as an integration of the frequency domain amplitude fromFIG.9. In particular,FIG.10depicts a graph of example dipole energies for free pipe and fully bonded conditions based on the responses ofFIG.9, according to some embodiments.

InFIG.10, a graph1000includes a y-axis1002that is a dipole energy of the response and an x-axis1004that is eccentricity. A curve1006represents an energy variation over different eccentricities for a free pipe condition. A curve1008represents an energy variation over different eccentricities for a fully bonded condition. As shown, the free pipe condition and the fully bonded condition can be identified based on the energy of a specific mode (four kHz dipole mode in this example). Accordingly, the decay from the time domain signal can be extracted. This decay of a specific mode can be used to identify free pipe and fully bonded responses. As shown by the curve1008, the fully bonded responses have minimal energy that is essentially flat. As shown by the curve1006, the free pipe responses have a higher energy that decreases slowly over time. Because of this separation in energy levels between fully bonded responses and free pipe responses, a response can be correctly identified as fully bonded or free pipe based on the energy level of the response.

Returning to the flowchart600, operations continue at block604.

At block604, a channel direction is determined based on at least one of the selected mode and rotated angle with a maximum value of the selected mode. For example, with reference toFIG.2, the TTCE processor248can determine the channel direction. A channel direction can be determined without and with eccentricity. Examples of how to determine of a channel direction without eccentricity is first described. A dipole response has directionality because of its mode shape. Therefore, the dipole response varies as the dipole direction changes. For example, for a Y dipole excitation (dipole direction along Y axis), the response of a channel is higher at 0°/180° as compared to 90°/270°.FIG.11depicts a graph of example time domain resonance signals for a Y dipole excitation while the channel is at 0° and 90°, according to some embodiments. InFIG.11, a graph1100includes a y-axis1102that is an amplitude of the response and an x-axis1104that is time (micro-seconds). A curve1106represents a dipole response while the channel is at 0°. A curve1108represents a dipole response while the channel is at 90°.

The reason for directional response is that the dipole energy radiates into the surrounding material in two general forms—P-wave (compressional wave) and SH-wave (horizontal shear wave). To illustrate,FIGS.12A-12Bdepict example snapshots of dipole energy for a Y dipole excitation for the channel at 0° and 90°, respectively, according to some embodiments.FIG.12Adepicts a snapshot1200of dipole energy for a Y dipole excitation for the channel at 0°.FIG.12Bdepicts a snapshot1250of dipole energy for a Y dipole excitation for the channel at 90°.

In the snapshots1200and1250, the darker shading indicates lower stress or pressure, while the lighter shading indicates higher stress or pressure. The snapshots1200and1250depict a downhole tool1202(that include any of the example transmitter-receiver configurations described herein). The snapshots1200and1250also depicts the downhole tool1202within a production tubing1204that is within a casing1206. A cement1208is outside the casing1206.

The snapshot1200depicts a channel1210at 0°. As shown in the snapshot1200, for a Y dipole, the area near 0°/180° is dominated by SH-wave radiation. The acoustic energy is transmitted to the cement1208behind the casing1206in the form of an SH-wave1222. When fluid in a channel exists behind the casing1206, the SH-wave1222gets totally reflected and resulted in higher energy (also corresponding to the curve1106in the graph1100ofFIG.11).

As shown in the snapshot1250, for a Y dipole, the area near 0°/180° is dominated by P-wave radiation. A P-wave1212can partially be transmitted through fluid in a channel behind the casing1206and into the subsurface formation. Therefore, more acoustic energy is lost when the channel occurs at this angle (also corresponding to the curve1108in the graph1100ofFIG.11). Accordingly, the snapshot1250is very similar to a fully bonded case.

FIGS.13A-13Bdepict graphs of example dipole excited responses for channels of different sizes in the frequency domain and amplitude, respectively, according to some embodiments. InFIG.13A, a graph1300shows the frequency domain response of a Y dipole excitation for fluid channels of various size at 0°. The graph1300includes a y-axis1302that is the power spectrum and an x-axis1304that is the frequency for the dipole excited responses.

A curve1306is a dipole excited response with the channel at 0°. A curve1308is a dipole excited response with the channel at 60°. A curve1310is a dipole excited response with the channel at 120°. A curve1312is a dipole excited response with the channel at 0°. A curve1308is a dipole excited response with the channel at 180°.

InFIG.13B, a graph1350shows a relationship between the energy and the channel size. The graph1350includes a y-axis1352that is the energy between approximately 3.1 kHz and 4.2 kHz and an x-axis1354that is the channel size (which can be defined as the number of degrees in an arc). The graph1350includes an x-axis1354that is the channel size. The amplitude of a dipole excited response can be positively related to the channel size. Accordingly, the channel size of a given response can be determined based on its amplitude.

A fluid channel in the cement can occur at any azimuthal location. Also, the dipole response can be sensitive to this azimuthal location. Accordingly, in some embodiments, the dipole response can be rotated based on the channel direction to provide consistent results. To illustrate,FIGS.14A-14Bdepict example cross-dipole responses rotated 360° with the tool at a standard orientation and an arbitrary orientation, respectively, according to some embodiments.

InFIG.14A, a graph1400depicts a standard configuration where a channel1402is at 0° and the dipole excitation is along Y direction. InFIG.14B, the graph1410depicts an arbitrary orientation where the channel1402is at angle θ relative to 0°. In some implementations, if the channel is at an arbitrary orientation, the channel can be computationally rotated to a standard orientation. For example, for the arbitrary orientation depicted inFIG.14B, the dipole response can be computationally rotated such that the response is rotated to a standard orientation where θ is 0°.

Alternatively, the dipole response can be obtained at a specific direction by using multiple acoustic emissions at different azimuths. For example, a rotating unipole transmitter can emit acoustic transmissions at different azimuths via one or more revolutions. The average dipole response can then be determined at a specific azimuthal direction.

To illustrate,FIG.15depicts graph of an example rotated tool response with a 25° rotation compared to an example tool response with a standard orientation, according to some embodiments. InFIG.15, a graph1500includes a y-axis1502that is an amplitude of a response and an x-axis1504that is time (ms). A curve1506is the response at a standard orientation where θ is 0° (YY). A curve1508is the response that is rotated such that θ is 25° (Y″Y″).

The channel direction can be determined by decomposing the response to 360° and finding the direction with a highest energy. To illustrate,FIG.16Adepicts a graph of an example frequency response of a rotated response versus the rotated angle, according to some embodiments.FIG.16Bdepicts a graph of an example amplitude of the selected mode based on the rotated angle, according to some embodiments.

An example of a tubing/casing configuration with zero eccentricity and a 60° channel at 25° is shown inFIGS.16A-16B. InFIG.16A, a graph1600includes a y-axis1602that is an azimuthal angle (degrees) and an x-axis1604that is frequency (kHz). InFIG.16B, a graph1610includes a y-axis1612that is the spectrum energy between 2.6 kHz to 4.6 kHz and an x-axis1614that is the azimuthal angle (degrees).

As shown in graph1600, the highest energy is near 3.6 kHz (1606). The energy of the dipole mode near 3.6 kHz can be computed within a frequency range and plotted as shown by the graph1610ofFIG.16B. In graph1610ofFIG.16B, the maximum amplitude corresponds to the channel location at 25° (1616). Due to the symmetry property of a dipole, another peak is shown at 105° (1618). Hence the channel direction can be identified with 180° ambiguity. However, the response at both angles can be identical and can be used to measure the channel size.

Some embodiments can identify a channel location even with eccentricity. For cases with fluid channel or/and eccentricity, asymmetry can be introduced into the wellbore by channel location and eccentricity direction. The asymmetry can cause the original dipole mode to convert to other modes with a different mode shape and frequency.FIGS.17A-17Cdepict graphs of example rotated angle versus frequency response at a 45° azimuthal location, 135° azimuthal location, and 180° azimuthal location, respectively, according to some embodiments.FIG.17Adepicts a graph1700having a y-axis1702that is the azimuthal angle (degree) and an x-axis1704that is frequency (kHz).FIG.17Bdepicts a graph1710having a y-axis1712that is the azimuthal angle (degree) and an x-axis1714that is frequency (kHz).FIG.17Cdepicts a graph1710having a y-axis1722that is the azimuthal angle (degree) and an x-axis1724that is frequency (kHz).

FIGS.17A-17Cshow the rotated response from cross-dipole firings with a 90° channel at different direction. As shown, the 3 kHz mode is found to be sensitive to the channel direction. The maximum amplitude of the 3 kHz mode occurs when the response is rotated to point to the channel direction. Due to the symmetry of a dipole mode, another maximum energy occurs at 180° away from the true channel location. Hence the 3 kHz mode can be used to identify channel direction with a 180° ambiguity. The time domain signal used to generateFIGS.17A-17Ccan be selected from different time segments (because the 3 kHz mode can be developed later in time). The time segment can be any range of time that allows for this mode to be developed.

Some embodiments can identify a channel location (even with eccentricity) from the mode shape of the 3 kHz mode computed from an azimuthal receiver response. To illustrate,FIGS.18A-18Cdepict graphs of example mode shapes computed from an azimuthal response at a 45° azimuthal location, 135° azimuthal location, and 180° azimuthal location, respectively, according to some embodiments.FIGS.18A-18Cdepict a graph1800, a graph1810, and a graph1820, respectively. In the graph1800, the channel location is at 45° based on a mode shape1804. In the graph1810, the channel location is at 135° based on a mode shape1814. In the graph1820, the channel location is at 180° based on a mode shape1824. The radial amplitude can be computed from the frequency domain amplitude of the azimuthal receiver at the corresponding angle and at 3 kHz. The mode shape also points to the channel direction with 180° ambiguity.

Returning to the flowchart600, operations continue at block606.

At block606, a time segment and a frequency range are selected based on the selected mode sensitive to the determined channel direction. For example, with reference toFIG.2, the TTCE processor248can determine the time segment and the frequency range. Operations for selection of the time segment and the frequency range can be based on two inputs (an input610and an input612). The input610includes a library of amplitude (decay) for various tubing/casing configurations, eccentricity, channel direction, etc. The input612includes eccentricity amplitude and direction for the given configuration. In other words, the input612can include how far the production tubing is from the center of the casing and its azimuthal direction.

At block608, an amplitude (or decay) is determined based on the time segment and frequency range that is according to the selected mode. For example, with reference toFIG.2, the TTCE processor248can determine the amplitude (or decay). Operations for determining the amplitude (or decay) based on the time segment and the frequency range can also be based on the two inputs (the input610and the input612).

For example, with channel direction identified and a known tubing eccentricity (both eccentricity direction and offset distance from other measurement or tool), the amplitude or decay of a selected dipole mode can be computed and compared with a library to identify the channel size. The data in the library may be obtained from simulation, experiment, field data, etc. The computed amplitude or decay can be estimated based on cases extracted from the library with the same channel direction, eccentricity, tubing/casing configurations, etc.

To illustrate,FIG.19depicts a graph of example frequency responses for amplitude or decay of a selected dipole mode, according to some embodiments. InFIG.19, a graph1900includes a y-axis1902that is the amplitude of the responses and an x-axis1904that is the frequency (kHz) of the responses. The graph1900includes five curves. A curve1906is the amplitude over a frequency response for a fully bonded case. A curve1908is the amplitude over a frequency response for a channel of 60° size. A curve1910is the amplitude over a frequency response for a channel of 120° size. A curve1912is the amplitude over a frequency response for a channel of 180° size. A curve1914is the amplitude over a frequency response for a free pipe case.

At block614, the cement bonding condition is evaluated based on amplitude (or decay) in comparison to a library of amplitude (or decay) for various tubing/casing configuration, eccentricity, channel direction, etc. For example, with reference toFIG.2, the TTCE processor248can make this evaluation. For example, the frequency domain response can be plotted relative to the amplitude. The amplitude is computed for the mode at or near 4 kHz based on the frequency domain response. The bonding condition can then be defined relative to this amplitude. To illustrate,FIG.20depicts a graph of an example plotting of the amplitude versus the bonding condition for the frequency responses ofFIG.19, according to some embodiments. InFIG.20, a graph2000includes a y-axis2002that is the amplitude of the responses and an x-axis2004that is the bonding condition. As shown, for a free pipe (FP) condition, the amplitude is approximately 0.00 (2006). For a channel at 60°, the amplitude is approximately 0.005 (2008). For a channel at 120°, the amplitude is approximately 0.008 (2010). For a channel at 1800°, the amplitude is approximately 0.01 (2012). For a fully (FB) condition, the amplitude is approximately 0.053 (2014). Accordingly, the bonding condition can be determine based on the amplitude of the response.

Returning to the flowchart600, operations continue at block616.

At block616, a determination is made of whether a remedial action is needed based on the cement bonding condition evaluation. For example, with reference toFIG.2, the TTCE processor248can make this determination. For instance, if the cement bonding condition evaluation identifies one or more fluid channels having a size greater than a threshold, the determination can be made that a remedial action is needed to correct these faults. If a remedial action is needed, operations of the flowchart600continue at block618. Otherwise, operations of the flowchart600are complete.

At block618, a remedial action based on the cement bonding condition evaluation is performed. For example, with reference toFIG.2, the TTCE processor248can initiate such an operation. For instance, the TTCE processor248could initiate an operation to provide a remedial action to correct a fault (such as the cement bonding). An example of a remedial action can include different types of remedial cementing (such as squeeze cementing). Operations of the flowchart600are complete.

A second example of operations for performing TTCE using multi-pole resonance is now described. In contrast to the first example of operations depicted inFIGS.5-6, the second example operations includes a rotatable transmitter to provide a multi-pole resonance. In particular,FIGS.21-22depict a flowchart of second example operations for performing TTCE using wellbore multi-pole resonance, according to some embodiments.FIGS.21-22depict a flowchart2100and a flowchart2200, respectively, having operations that include a transition point A for operations to move between the flowchart2100and the flowchart2200. Operations of the flowchart2100-2200can be performed by software, firmware, hardware or a combination thereof. Such operations are described with reference to the systems ofFIGS.1A-1B,2, and4. However, such operations can be performed by other systems or components. For example, at least some of the operations of the flowcharts2100-2200are described as being performed by a computer at a surface of the wellbore. In some embodiments, one or more of these operations can be performed by a computer at the surface and/or downhole in the wellbore. The operations of the flowchart2100start at block2102.

At block2102, a downhole tool (having a rotatable transmitter and a receiver array with at least two receivers positioned in different azimuthal positions) is conveyed in a production tubing positioned in a casing positioned around a wellbore such that there is an annular area (between the casing and a wall of the wellbore) into which cement is placed. For example, with reference toFIG.4, the downhole tool402is lowered down the wellbore401within the production tubing412.

At block2104, an acoustic transmission is emitted, by a transmitter at a current azimuthal position (outward through the production tubing and the casing and into the cement). For example, with reference toFIG.4, the transmitter406can emit an acoustic transmission at a current azimuthal dipole excitation outward in a first direction in the wellbore401outward toward through the production tubing412and the casing416and into the cement418.

At block2106, an acoustic response generated from the acoustic transmission is detected by the receiver array. For example, with reference toFIG.4, one or more of the receivers430-438can detect an acoustic response generated from the acoustic transmission that passes through the production tubing412and the casing416and into the cement418.

At block2108, a determination is made of whether there is another azimuthal position from which to emit an acoustic transmission. For example, with reference toFIG.2, the logging controller250can make this determination. For instance, the TTCE operations may be configured such that emission and detection may be performed at N number of different azimuthal positions. Accordingly, the logging controller250can determine whether emission and detection has occurred at each of the N number of azimuthal positions. If there is another azimuthal position from which to emit an acoustic transmission, operations of the flowchart2100continue at block2110. Otherwise, operations of the flowchart2100continue at block2112.

At block2110, the transmitter is rotated to a next azimuthal position. For example, with reference toFIG.2, the logging controller250can control rotation of the transmitter. For example, with reference toFIG.4, the transmitter406is rotated to the next azimuthal position for emission of a next acoustic transmission. Operations of the flowchart2100return to block2104.

At block2112, a decomposed response is generated from the acoustic responses. For example, with reference toFIG.2, the TTCE processor248can generate the decomposed response (similar to the operations at block602in the flowchart600ofFIG.6described above).

At block2114, a channel direction is determined based on at least one of the selected mode and rotated angle with a maximum value of the selected mode. For example, with reference toFIG.2, the TTCE processor248can determine the channel direction (similar to the operations at block604in the flowchart600ofFIG.6described above). Operations of the flowchart2100continue at transition point A, which continues at transition point A of the flowchart2200ofFIG.22.

From transition point A of the flowchart2200ofFIG.22, operations continue at block2202.

At block2202, a time segment and a frequency range are selected based on the selected mode sensitive to the determined channel direction. For example, with reference toFIG.2, the TTCE processor248can determine the time segment and the frequency range. Operations for selection of the time segment and the frequency range can be based on two inputs (an input2204and an input2206). The input2204includes a library of amplitude (decay) for various tubing/casing configurations, eccentricity, channel direction, etc. The input2206includes eccentricity amplitude and direction for the given configuration. In other words, the input2206can include how far the production tubing is from the center of the casing and its azimuthal direction. Operations for selection of the time segment and frequency range can be similar to the operations at block606in the flowchart600ofFIG.6described above).

At block2208, an amplitude (or decay) is determined based on the time segment and frequency range that is according to the selected mode. For example, with reference toFIG.2, the TTCE processor248can determine the amplitude (or decay). Operations for determining the amplitude (or decay) based on the time segment and the frequency range can also be based on the two inputs (the input2204and the input2206). Operations for determining the amplitude (or decay) can be similar to the operations at block608in the flowchart600ofFIG.6described above).

At block2210, the cement bonding condition is evaluated based on amplitude (or decay) in comparison to a library of amplitude (or decay) for various tubing/casing configuration, eccentricity, channel direction, etc. For example, with reference toFIG.2, the TTCE processor248can make this evaluation (similar to the operations at block614in the flowchart600ofFIG.6described above).

At block2212, a determination is made of whether a remedial action is needed based on the cement bonding condition evaluation. For example, with reference toFIG.2, the TTCE processor248can make this determination. For instance, if the cement bonding condition evaluation identifies one or more fluid channels having a size greater than a threshold, the determination can be made that a remedial action is needed to correct these faults. If a remedial action is needed, operations of the flowchart2200continue at block2210. Otherwise, operations of the flowchart2200are complete.

At block2214, a remedial action based on the cement bonding condition evaluation is performed. For example, with reference toFIG.2, the TTCE processor248can initiate such an operation. For instance, the TTCE processor248could initiate an operation to provide a remedial action to correct a fault in the cement (such as the cement bonding). An example of a remedial action can include different types of remedial cementing (such as squeeze cementing). Operations of the flowchart2200are complete.

The flowcharts are provided to aid in understanding the illustrations and are not to be used to limit scope of the claims. The flowcharts depict example operations that can vary within the scope of the claims. Additional operations may be performed; fewer operations may be performed; the operations may be performed in parallel; and the operations may be performed in a different order. It will be understood that each block 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 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.

Any combination of one or more machine-readable medium(s) may be utilized. The machine-readable medium may be a machine-readable signal medium or a machine-readable storage medium. A machine-readable storage medium may be, for example, but not limited to, a system, apparatus, or device, that employs any one of or combination of electronic, magnetic, optical, electromagnetic, infrared, or semiconductor technology to store program code. More specific examples (a non-exhaustive list) of the machine-readable storage medium would include the following: a portable computer diskette, a hard disk, a random-access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM or Flash memory), a portable compact disc read-only memory (CD-ROM), an optical storage device, a magnetic storage device, or any suitable combination of the foregoing. In the context of this document, a machine-readable storage medium may be any tangible medium that can contain or store a program for use by or in connection with an instruction execution system, apparatus, or device. A machine-readable storage medium is not a machine-readable signal medium.

A machine-readable signal medium may include a propagated data signal with machine readable program code embodied therein, for example, in baseband or as part of a carrier wave. Such a propagated signal may take any of a variety of forms, including, but not limited to, electro-magnetic, optical, or any suitable combination thereof. A machine-readable signal medium may be any machine-readable medium that is not a machine-readable storage medium and that can communicate, propagate, or transport a program for use by or in connection with an instruction execution system, apparatus, or device.

Program code embodied on a machine-readable medium may be transmitted using any appropriate medium, including but not limited to wireless, wireline, optical fiber cable, RF, etc., or any suitable combination of the foregoing. The program code/instructions may also be stored in a machine-readable medium that can direct a machine to function in a particular manner, such that the instructions stored in the machine-readable medium produce an article of manufacture including instructions which implement the function/act specified in the flowchart and/or block diagram block or blocks.

Example Computer

FIG.23depicts an example computer, according to some embodiments. A computer2300system includes a processor2301(possibly including multiple processors, multiple cores, multiple nodes, and/or implementing multi-threading, etc.). The computer2300includes a memory2307. The memory2307may be system memory or any one or more of the above already described possible realizations of machine-readable media. The computer2300also includes a bus2303and a network interface2305. The computer2300can communicate via transmissions to and/or from remote devices via the network interface2305in accordance with a network protocol corresponding to the type of network interface, whether wired or wireless and depending upon the carrying medium. In addition, a communication or transmission can involve other layers of a communication protocol and or communication protocol suites (e.g., transmission control protocol, Internet Protocol, user datagram protocol, virtual private network protocols, etc.).

The computer2300also includes a signal processor2311that can perform at least some of the operations described herein. Any one of the previously described functionalities may be partially (or entirely) implemented in hardware and/or on the processor2301. For example, the functionality may be implemented with an application specific integrated circuit, in logic implemented in the processor2301, in a co-processor on a peripheral device or card, etc. Further, realizations may include fewer or additional components not illustrated inFIG.23(e.g., video cards, audio cards, additional network interfaces, peripheral devices, etc.). The processor2301and the network interface2305are coupled to the bus2303. Although illustrated as being coupled to the bus2303, the memory2307may be coupled to the processor2301.

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 cement bonding condition evaluation as 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.

EXAMPLE EMBODIMENTS

Embodiment #1: A method comprising: conveying a downhole tool in a tubing that is positioned in a casing that is positioned to form an annulus between the casing and a wall of a wellbore formed in a subsurface formation, wherein a cement with unknown bonding condition exists in the annulus, wherein the downhole tool includes at least one transmitter configured to emit an acoustic transmission at different azimuthal positions, and wherein the downhole tool includes a receiver array that includes at least two receivers physically positioned in different azimuthal directions; emitting, from the at least one transmitter, a first acoustic transmission in a first azimuthal direction and outward to the cement such that at least a portion of the first acoustic transmission is to penetrate the cement; detecting, by the receiver array, a first acoustic response that is derived from the first acoustic transmission; emitting, from the at least one transmitter, a second acoustic transmission in a second azimuthal direction and outward to the cement such that at least a portion of the second acoustic transmission is to penetrate the cement, wherein the second azimuthal direction is orthogonal to the first azimuthal direction; detecting, by the receiver array, a second acoustic response that is derived from the second acoustic transmission; determining a dipole wellbore resonance based on the first acoustic response and the second acoustic response; and evaluating a property of the cement based on the dipole wellbore resonance.

Embodiment #2: The method of claim 1, further comprising: rotating the at least one transmitter from the first azimuthal direction to the second azimuthal direction, after emitting the first acoustic transmission and before emitting the second acoustic transmission.

Embodiment #3: The method of any one of claims 1-2, further comprising: generating a decomposed response based on the first acoustic response and the second acoustic response, wherein determining the dipole wellbore resonance comprises: determining an azimuthal direction where a channel is located in the cement; selecting at least one of a time segment and a frequency range of decomposed response based on the azimuthal direction where the channel is located in the cement; and evaluating the property of the cement based on the selected at least one of the time segment and the frequency range.

Embodiment #4: The method of claim 3, wherein determining the dipole wellbore resonance comprises: determining an amplitude of a mode of the decomposed response based on the at least one of the time segment and the frequency range; comparing the determined amplitude of the mode to a library of amplitudes for different tubing and casing configurations, eccentricities, and channel directions; and evaluating the property of the cement based on the comparing.

Embodiment #5: The method of any one of claims 1-4, further comprising: determining an eccentricity of the tubing that defines an offset of a position of the tubing from the center of the wellbore, wherein determining the dipole wellbore resonance comprises determining the dipole wellbore resonance based on the eccentricity.

Embodiment #6: The method of any one of claims 1-5, wherein evaluating the property of the cement comprises evaluating a bonding condition of the cement.

Embodiment #7: The method of claim 6, wherein evaluating the bonding condition of the cement comprises determining whether the bonding condition is at least one of a fully bonded condition, a free pipe condition, and a partially bonded condition.

Embodiment #8: The method of any one of claims 1-7, further comprising performing a remedial action to correct a fault in the cement based on the evaluating the property of the cement.

Embodiment #9: A system comprising: a downhole tool to be conveyed in a tubing that is positioned in a casing that is positioned to form an annulus between the casing and a wall of a wellbore formed in a subsurface formation, wherein a cement has been placed in the annulus, wherein the downhole tool comprises, at least one transmitter configured to, emit a first acoustic transmission in a first azimuthal direction and outward to the cement such that at least a portion of the first acoustic transmission is to penetrate the cement; and emit a second acoustic transmission in a second azimuthal direction and outward to the cement such that at least a portion of the second acoustic transmission is to penetrate the cement, wherein the second azimuthal direction is orthogonal to the first azimuthal direction; a receiver array that includes at least two receivers physically positioned in different azimuthal directions, wherein the receiver array is configured to, detect a first acoustic response that is derived from the first acoustic transmission; and detect a second acoustic response that is derived from the second acoustic transmission; a processor; and a machine-readable medium having program code executable by the processor to cause the processor to, determine a dipole wellbore resonance based on the first acoustic response and the second acoustic response; and evaluate a property of the cement based on the dipole wellbore resonance.

Embodiment #10: The system of claim 9, wherein the at least one transmitter is to rotate from the first azimuthal direction to the second azimuthal direction, after emission of the first acoustic transmission and before emission of the second acoustic transmission.

Embodiment #11: The system of any one of claims 9-10, wherein the program code comprises program code executable by the processor to cause the processor to, generate a decomposed response based on the first acoustic response and the second acoustic response, wherein the program code executable by the processor to cause the processor to determine the dipole wellbore resonance comprises program code executable by the processor to cause the processor to, determine an azimuthal direction where a channel is located in the cement; select at least one of a time segment and a frequency range of decomposed response based on the azimuthal direction where the channel is located in the cement; and evaluate the property of the cement based on the selected at least one of the time segment and the frequency range.

Embodiment #12: The system of claim 11, wherein the program code executable by the processor to cause the processor to determine the dipole wellbore resonance comprises program code executable by the processor to cause the processor to, determine an amplitude of a mode of the decomposed response based on the at least one of the time segment and the frequency range; compare the determined amplitude of the mode to a library of amplitudes for different tubing and casing configurations, eccentricities, and channel directions; and evaluate the property of the cement based on the comparing.

Embodiment #13: The system of any one of claims 9-12, wherein the program code comprises program code executable by the processor to cause the processor to, determine an eccentricity of the tubing that defines an offset of a position of the tubing from the center of the wellbore, wherein the program code executable by the processor to cause the processor to determine the dipole wellbore resonance comprises program code executable by the processor to cause the processor to determine the dipole wellbore resonance based on the eccentricity.

Embodiment #14: The system of any one of claims 9-13, wherein the program code executable by the processor to cause the processor to evaluate the property of the cement comprises program code executable by the processor to cause the processor to evaluate a bonding condition of the cement.

Embodiment #15: The system of claim 14, wherein the program code executable by the processor to cause the processor to evaluate the property of the cement comprises program code executable by the processor to cause the processor to determine whether the bonding condition is at least one of a fully bonded condition, a free pipe condition, and a partially bonded condition.

Embodiment #16: The system of any one of claims 9-15, wherein the program code comprises program code executable by the processor to cause the processor to perform a remedial action to correct a fault in the cement based on the evaluation of the property of the cement.

Embodiment #17: One or more non-transitory machine-readable media comprising program code executable by a processor to cause the processor to: receive a first acoustic response, that is detected by a receiver array that includes at least two receivers physically positioned in different azimuthal directions, wherein the receiver array is mounted on a downhole tool that is positioned in a tubing that is positioned in a casing this is located in a wellbore such that an annulus is defined between the casing and a wall of the wellbore, wherein a cement is located within the annulus, wherein the first acoustic response is derived from a first acoustic transmission emitted from at least one transmitter mounted on the downhole tool; receive a second acoustic response that is detected by the receiver array, wherein the first acoustic response is derived from a second acoustic transmission emitted from the at least one transmitter determine a dipole wellbore resonance based on the first acoustic response and the second acoustic response; and evaluate a property of the cement based on the dipole wellbore resonance.

Embodiment #18: The one or more non-transitory machine-readable media of claim 17, wherein the program code comprises program code executable by the processor to cause the processor to, generate a decomposed response based on the first acoustic response and the second acoustic response, wherein the program code executable by the processor to cause the processor to determine the dipole wellbore resonance comprises program code executable by the processor to cause the processor to, determine an azimuthal direction where a channel is located in the cement; select at least one of a time segment and a frequency range of decomposed response based on the azimuthal direction where the channel is located in the cement; and evaluate the property of the cement based on the selected at least one of the time segment and the frequency range.

Embodiment #19: The one or more non-transitory machine-readable media of claim 18, wherein the program code executable by the processor to cause the processor to determine the dipole wellbore resonance comprises program code executable by the processor to cause the processor to, determine an amplitude of a mode of the decomposed response based on the at least one of the time segment and the frequency range; compare the determined amplitude of the mode to a library of amplitudes for different tubing and casing configurations, eccentricities, and channel directions; and evaluate the property of the cement based on the comparing.

Embodiment #20: The one or more non-transitory machine-readable media of any one of claims 17-19, wherein the program code comprises program code executable by the processor to cause the processor to, determine an eccentricity of the tubing that defines an offset of a position of the tubing from the center of the wellbore, wherein the program code executable by the processor to cause the processor to determine the dipole wellbore resonance comprises program code executable by the processor to cause the processor to determine the dipole wellbore resonance based on the eccentricity.

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.