Downhole Anomaly Localization and Interpretation Using Acoustic and Electromagnetic Logging

The present technology pertains to localizing and interpreting downhole anomalies in well casings.

A well system comprises a well-drilling system to form the well and a well-pumping system to retrieve materials from the well. A well-drilling system is a setup of equipment and machinery designed to extract natural resources, such as water, oil, or gas, from the ground. The system typically includes a drilling rig, which is used to bore a hole into the earth's crust, a casing, which can be a steel pipe that lines the well and cementation between casing and the wall of well which prevents the walls from collapsing. The drilling process begins with the placement of a drill bit at the end of a drill string. The drill bit is then rotated, using a motor or a manual mechanism, to create a hole in the ground. As the hole is drilled, the drill string is gradually lengthened by adding more sections of pipe and cementation outside the pipe. The process continues until the desired depth is reached.

Once the drilling is complete, a casing is installed into the well to protect it from collapse and prevent contamination of the extracted resources. The casing is typically cemented into place to seal off any potential pathways for groundwater to enter the well. Once the well is prepared, a well-pumping system is installed to extract the resources from the well.

Certain aspects of this disclosure are provided below. Some of these aspects may be applied independently and some of them may be applied in combination as would be apparent to those of skill in the art. In the following description, for the purposes of explanation, specific details are set forth in order to provide a thorough understanding of aspects of the application. However, it will be apparent that various aspects may be practiced without these specific details. The figures and descriptions are not intended to be restrictive.

The ensuing description provides example aspects only and is not intended to limit the scope, applicability, or configuration of the disclosure. Rather, the ensuing description of the example aspects will provide those skilled in the art with an enabling description for implementing an example aspect. It should be understood that various changes may be made in the function and arrangement of elements without departing from the spirit and scope of the application as set forth in the appended claims.

The terms “exemplary” and/or “example” are used herein to mean “serving as an example, instance, or illustration.” Any aspect described herein as “exemplary” and/or “example” is not necessarily to be construed as preferred or advantageous over other aspects. Likewise, the term “aspects of the disclosure” does not require that all aspects of the disclosure include the discussed feature, advantage or mode of operation.

The present disclosure includes systems and methods for localizing a downhole anomaly in a wellbore. Current downhole acoustic tools, including but not limited to hydrophone array tools, are not capable of adequately differentiating between a leak in a casing and a flow behind a casing, particularly when the flow behind the casing is close to the casing. However, a leak or a flow behind a casing can be determined using electromagnetic tools, in conjunction with downhole acoustic tools, in order to differentiate between leaks in casings and flows behind casings. For example, a downhole acoustic tool can be used to determine a location (e.g., flow depth) of a flow near a casing. An electromagnetic tool can then be used to determine an integrity (e.g., corrosion level, thickness, metal loss) of the casing at the location (e.g., flow depth) where the flow was detected. Various interpretations can be made based on the integrity of the casing at the one or more flow depths where the flow was detected, including determining the likelihood that a leak is occurring or whether the flow is behind the casing and no leak is occurring. In some examples, the use of the downhole acoustic tool and the electromagnetic tool can be referred to as joint logging.

Additional details and aspects of the present disclosure are described in more detail below with respect to the figures.

is a schematic diagram of an example logging while drilling (LWD) operating environment of a well site, in accordance with various aspects of the disclosure.

In some aspects, a drilling arrangement is shown that exemplifies a LWD configuration in a wellbore drilling scenario. The LWD typically incorporates sensors that acquire formation data. The drilling arrangement ofalso exemplifies measurement while drilling (MWD) and utilizes sensors to acquire data from which the wellbore's path and position in three-dimensional space can be determined.shows a drilling platformequipped with a derrickthat supports a hoistfor raising and lowering a drill string. The hoistsuspends a top drivesuitable for rotating and lowering the drill stringthrough a well head. A drill bitcan be connected to the lower end of the drill string. As the drill bitrotates, the drill bitcreates a wellborethat passes through one or more subterranean formations. A pumpcirculates drilling fluid through a supply pipeto top drive, down through the interior of the drill string, and out orifices in the drill bitinto the wellbore. The drilling fluid returns to the surface via the annulus around the drill string, and into a retention pit. The drilling fluid transports cuttings from the wellboreinto the retention pitand the drilling fluid's presence in the annulus aids in maintaining the integrity of the wellbore. Various materials can be used for drilling fluid, including oil-based fluids and water-based fluids.

While drilling, the well is cemented to prevent collapse and fluid flowing outside of the casing. The objective is to displace well-bonded cement between casing and formation. However, during the cementing some space can remain and/or include liquid and/or gas resulting in the potential leakage while fluid production or even collapse of well wall. The purpose of the methodology introduced in the disclosure is to classify the materials in the cementing layer (also called annulus in the disclosure) into solid (for example, cement), liquid, and/or gas and detect the potential risk for cementation of a wall of the well.

In some aspects, one or more logging toolscan be integrated into the bottom-hole assemblynear the drill bit. As the drill bitextends the wellborethrough the subterranean formations, logging toolscollect measurements relating to various formation properties as well as the orientation of the tool and various other drilling conditions. In some cases, the logging tools interface with various sensors and equipment. The bottom-hole assemblycan also include a telemetry subto transfer measurement data to a surface receiverand to receive commands from the surface. In at least some cases, the telemetry subcommunicates with a surface receiverusing mud pulse telemetry. In some instances, the telemetry subdoes not communicate with the surface, but rather stores logging data for later retrieval at the surface when the logging assembly is recovered.

Each of the logging toolscan include one or more tool components spaced apart from each other and communicatively coupled by one or more wires and/or another communication arrangement. The logging toolscan also include one or more computing devices communicatively coupled with one or more of the tool components. The one or more computing devices can be configured to control or monitor the performance of the tool, process logging data, and/or carry out one or more aspects of the methods and processes of the present disclosure.

In at least some instances, one or more of the logging toolscan communicate with a surface receiverby a wire, such as a wired drill pipe. In other cases, the one or more of the logging toolscan communicate with a surface receiverby wireless signal transmission, such as ground penetrating radar. In at least some cases, one or more of the logging toolscan receive electrical power from a wire that extends to the surface, including wires extending through a wired drill pipe.

In some aspects, a collaris a frequent component of a drill stringand generally resembles a very thick-walled cylindrical pipe, typically with threaded ends and a hollow core for the conveyance of drilling fluid. In some cases, multiple collarscan be included in the drill stringand are constructed and intended to be heavy to apply weight on the drill bitto assist the drilling process. Because of the thickness of the collar's wall, pocket-type cutouts or other type recesses can be provided into the collar's wall without negatively impacting the integrity (strength, rigidity, and the like) of the collaras a component of the drill string.

is a diagram of an example downhole environment having tubulars in accordance with various aspects of the disclosure. In some aspects, an example systemis depicted for conducting downhole measurements after at least a portion of a wellbore has been drilled and the drill string removed from the well. A downhole tool is shown having a tool bodyto perform logging, measurements, and/or other operations. For example, instead of using the drill stringofto lower a tool body, which can contain sensors and/or other instrumentation for detecting and logging nearby characteristics and conditions of the wellboreand surrounding formations, a wireline conveyancecan be used.

The tool bodycan be lowered into the wellboreby wireline conveyance. The wireline conveyancecan be anchored in the drill rigor by a portable device such as a truck. The wireline conveyancecan include one or more wires, slicklines, cables, and/or the like, as well as tubular conveyances such as coiled tubing, joint tubing, or other tubulars.

The wireline conveyanceprovides power and support for the tool, as well as enabling communication between processing systemson the surface. In some examples, the wireline conveyancecan include electrical and/or fiber optic cabling for performing any communications. The wireline conveyanceis sufficiently strong and flexible to tether the tool bodythrough the wellbore, while also permitting communication through the wireline conveyanceto one or more of the processing systems, which can include local and/or remote processors. Additionally, the processing systemscan be coupled to a first communication systemthat can communicate via wireless and/or satellite connections. Additionally, a local communication devicecan be included. The local communication devicecan communicate with other devices near the site. In some cases, power can be supplied via the wireline conveyanceto meet the power requirements of the tool. For slickline or coiled tubing configurations, power can be supplied downhole with a battery or via a downhole generator.

As illustrated, the tool can be located within a casingthat can be coupled to the formation by cementthat is located within an annulus formed between the casingand the formation.

In at least one example, the systems and methods described herein utilize an electromagnetic tool (e.g., electromagnetic logging tool) for determining metal loss in a casing and/or one or more pipes. The electromagnetic tool can be operable to provide an excitation energy (e.g., via one or more transmitter coil stations) to the casing and/or well tubulars. The one or more transmitter stations can include one or more transmitter coils. In some examples, the one or more transmitter coils can be operable to induce eddy currents in one or more well tubulars and/or the casing. The electromagnetic tool can receive electromagnetic measurements (e.g., voltage responses) from the casing and/or well tubulars at one or more receiver stations (e.g., receiver coils). The one or more receiver stations can include one or more receiver coils. The received voltage responses can be compared to voltage responses from other casings and/or well tubulars or other portions of the same casing and/or well tubulars. The compared voltage responses can indicate metal loss at certain locations in the casing and/or well tubulars. In some examples, a severity of the metal loss can be determined. In some examples, the receiver coils can be operable to measure a magnetic field generated, at least in part, by the eddy currents. In some examples, the electromagnetic tool can be operable to determine a vertical, radial, and azimuthal location of the metal loss. Any electromagnetic tool operable to determine metal loss can be used without deviating from the scope of the present disclosure. Further, alternatively to, or in conjunction with, the electromagnetic tools described herein other downhole tools operable to determine metal loss can be used without deviating from the scope of the present disclosure.

In some examples, the transmitter stations (e.g., including one or more transmitter coils) and receiver stations (e.g., including one or more transmitter receivers) can have various spacings to achieve different depths of investigation. For example, one or more receiver coils can be spaced from one or more transmitter stations at differing distances. In some examples, one or more receiver coils can be spaced from a first transmitter station differently than one or more additional receiver coils are spaced from a second transmitter station, depending on the depths of investigation.

is a close up view of a toolwithin one or more casingsof a well bore. As illustrated the casingscan include a first casing, a second casing, a third casing, and a fourth casing. While the illustrated example includes four casings, the present disclosure is operable from one to dozens of casings. As illustrated, in a portion of the well bore the casingsoverlap such that a given depth two or more casingscan be positioned within the well bore. In at least one example, the casingscan be one or more downhole pipes. The one or more downhole pipes includes a nested casing arrangement in which multiple pipes of the plurality of downhole pipes are arranged in a well bore. In the illustrated example of, the casingshave been truncated for illustration purposes and can extend much longer relative distances.

The toolcan be configured to measure an integrity of one or more of the casings or pipes. For example, the toolcan be configured to measure a thickness of the casing and/or pipes and determine a level of corrosion in the casing and/or pipes based on electromagnetic data. In some examples, the electromagnetic data can be converted to a metal loss in the casing and/or pipes utilizing an inversion algorithm or calculation. For example, inverse algorithms or calculations can calculate the metal loss (e.g., corrosion) and thickness of the casing based on the voltage responses recorded at the receivers. The metal loss can then be used to determine a thickness of the casing and/or pipes. In some examples, the electromagnetic data can also provide data to estimate parameters such as electrical conductivity, magnetic permeability, and eccentricity.

The toolcan include a transmitter coil, a first receiver, a second receiver, a third receiver, a fourth receiver, a fifth receiver, and sixth receiver. The toolcan be implemented for electromagnetic (EM) techniques. One example of an EM technique is eddy current effect. The toolcan be used to characterize the casingaround the well bore. Another technique is to use frequency domain eddy current techniques. In this arrangement the transmitter coilis provided a continuous sinusoidal signal, producing primary fields that illuminate the casings. The primary fields induce eddy currents in the casingsand/or one or more well tubulars. The eddy currents produce secondary fields that can be sensed along with the primary field by the receiver coils,,,,,. Each of the receiver coils,,,,,can be placed a predetermined distance away from the transmitter coil. As illustrated, the first receiveris closer to the transmitter coilthan the remainder of the receiver coils,,,,. The second receivercan be placed next. The third receivercan be further away from the transmitter coilthan the first receiverand the second receiver. The fourth receivercan be located still further away from the transmitter coilas compared to the third receiver. The fifth receivercan be next followed by the sixth receiver, which can be located the furthest from the transmitter coil. While six receiver coils,,,,,are illustrated, the present technology can be implemented with two to twelve receiver coils,,,,,.

In one example, the transmitter coilcan have a core with a relative permeability of 75. The receiver coils,,,,,can be implemented without a core. The measurements can be performed at frequencies ranging from 0.1 Hz to 1000 Hz. In at least one example, the toolcan include two or more transmitter coils (e.g., transmitter coil). In some examples, a first transmitter coil can be a low frequency transmitter and the second transmitter coil can be a high frequency transmitter.

illustrate an exemplary acoustic tool environment and acoustic tool within the acoustic tool environment in accordance with the present disclosure.illustrate schematic diagrams for a sensor environment in accordance with the present disclosure. The acoustic tool environment generally includes multiple physical barriers to fluid flow, such as the production tubingthrough which oil or gas can be pumped up and out of the well, one or optionally multiple nested well casings, and a cement sheathfilling the space between the casing(s)and the formationsurrounding the wellbore. Additionally, the wellbore can be divided into multiple vertical sections, e.g., by packersbetween the casings. Unintended flow scenarios that can occur in such a configuration include, e.g., flows across the casingor tubingdue to cracks or holes therein (indicated by arrows), flows past a packerbetween adjacent vertical wellbore sections due to insufficient sealing (indicated by arrows), and flows within the formation, cement sheath, or other layer more or less parallel to the layer boundaries (indicated by arrows). As these flows pass through restricted paths, acoustic signals can be generated as a result of the accompanying pressure drops. As illustrated in, the sensorscan be arranged linearly along the longitudinal axisof the wellbore (whose radial coordinate is zero). The sensorscan be uniformly spaced (as shown) or have varying spacings between adjacent sensors. The acoustic signals propagate generally in all directions through the formation and/or wellbore, eventually being detected by the sensorsin the acoustic tool.

Acoustic sensorssuitable for use include, for example and without limitation, (piezoelectric) hydrophones, FBG sensors, or segments of a distributed fiber-optic cable. In some examples, the acoustic sensorscan be arranged in a hydrophone array. In some examples, the acoustic sensorsare omnidirectional, unable to discriminate by themselves between different incoming directions of the signal. By exploiting the spatiotemporal relations between the signals received from the same source at multiple sensors, however, information about the signal direction and/or source location can be obtained. For example, by using at least three sensorsin a linear arrangement, as shown in, it is possible, at least under certain conditions, to determine the depth (vertical distance) and radial distance of the source (as further explained below). To further localize the source in the azimuthal direction, the configuration of the sensor array can be modified, e.g., by placing different sensors at different radial positions in relation to the acoustic toolor otherwise arrange them two- or three-dimensionally, by partially shielding sensors to limit their detection to certain azimuthal windows (different ones for different sensors), or by using directional sensors (e.g., sensors that inherently provide directional information).

illustrates a schematic of how an acoustic source can be located in two dimensions (e.g., radial distance r and depth z) based on the signals received simultaneously at three or more sensor locations R, R, R, provided the medium is uniform such that the signal travels from the source to the sensors along straight lines (without undergoing, e.g., refraction or reflection) and at a known, constant speed of sound v. In this case, the travel time tof the signal from the source at (r, z) to a sensor i at (r, z) is simply the ratio of the distance dbetween source and sensor to the speed of sound v:

The absolute travel time tcannot be measured in the passive flow-detection methods described herein because the acoustic signal does not have a known starting point in time (as the flow typically commences long before the measurements take place and, in any case, at an unknown time). However, the time delay Δt=t−t(corresponding to the relative phase shift) between the receipt of a certain signal feature (e.g., a peak in the temporal wave form) at a sensor i and receipt of the same feature at a sensor j can in principle be determined. With known sensor locations (e.g., measured by the depth of the acoustic tool and sensor location in relation to the acoustic tool) and a known speed of sound v, this time delay yields a nonlinear equation containing two unknowns, namely the coordinates (r,z) of the source:

A second time delay measured between one of the sensors i, j and the third sensor k provides a second, independent nonlinear equation. From these two equations, the two-dimensional source location can be calculated straightforwardly in a manner known to those of ordinary skill in the art. If the speed of sound v is unknown and/or changes as the signal propagates through different media, an array with a larger number of sensors (e.g., four or more sensors) can be used to provide sufficient information to localize the source.

In the more complex scenarios typically encountered in flow-detection applications as contemplated herein, signal processing generally takes a more complex form. In various embodiments, an array-signal-processing method (such as spatial filtering) is employed to fuse the various simultaneously acquired sensor signals and localize the acoustic source.illustrates an overview of various possible array-signal processing techniques. In some examples, beamforming methods can be used to determine the acoustic source (e.g., water flow).

illustrates a flow chart of a methodfor detecting a downhole anomaly. At block, the methodcan include deploying an acoustic tool (e.g., the acoustic sensors and tools described herein) and an electromagnetic tool (e.g., the electromagnetic tools described herein) downhole to measure various parameters and characteristics of a wellbore and a casing. The acoustic tool can be operable to determine one or more flow depths where a presence of a flow has been detected in the casing. The acoustic tool can be any acoustic tool described herein or any acoustic tool operable to determine at least a vertical position of a flow (e.g., flow of liquid or gas). The electromagnetic tool can be any electromagnetic tool described herein or any kind of tool operable to determine an integrity (e.g., metal loss, corrosion) of a casing at a vertical position. In some examples, the methodcan be performed as part of routine maintenance and monitoring of an existing wellbore. In some examples, the methodcan be performed when there are indications of insufficient wellbore integrity. For example, the indications can include indications that there is a leak in the casing.

At block, the methodcan include receiving, via the acoustic tool, one or more acoustic measurements within and/or around a casing at a plurality of corresponding depths. The one or more acoustic measurements can be indicative of a flow within the casing or near the casing. The acoustic tool can include one or more acoustic sensors. In some examples, the one or more acoustic sensors can be arranged in an array. The one or more acoustic sensors can include hydrophones, FBG sensors, or segments of a distributed fiber-optic cable. In some examples, the acoustic tool can an include an array of eight hydrophones. The acoustic tool can be operable to characterize an acoustic source as flow or no flow.

At block, the methodcan include determining, based on the one or more acoustic measurements, a presence of a flow at one or more flow depths in the casing. For example, beamforming methods or other localization methods can be used to determine a position (e.g., a depth and radial distance of the acoustic source (e.g., flow)). In some examples, the one or more acoustic measurements can be processed to filter out any excess noise and ensure that the acoustic source is properly characterized as flow. In some examples, flow includes water flow, liquid fluid, and//or gaseous flow. When the one or more acoustic measurements are characterized as flow, the presence of flow at the one or more flow depths is determined. However, the presence of flow can indicate flow either within the casing (e.g., leak) or flow that is behind the casing. When the one or more acoustic measurements are not characterized as flow, the absence of flow at the location is determined. In some examples, when an absence of flow is determined, the methodcan end as there is no need to determine the integrity of the casing because no leak will occur in an absence of flow.

At block, the methodcan include receiving, via the electromagnetic tool, one or more electromagnetic measurements within and/or around the casing at each of the one or more depths. Once the acoustic tool has determined the presence of flow at the one or more flow depths, the electromagnetic tool can be positioned within the casing near or at each of the one or more flow depths such that electromagnetic measurements can be taken at each of the one or more flow depths to further analyze the downhole anomaly (e.g., whether there is a leak into the casing or the flow is behind the casing). The electromagnetic tool can be implemented for electromagnetic (EM) techniques. One example of an EM technique is eddy current effect. The electromagnetic tool can be used to characterize the casing around the well bore. Another technique is to use frequency domain eddy current techniques. In this arrangement one or more transmitter coils are provided a continuous sinusoidal signal, producing primary fields that illuminate the casing. The primary fields produce eddy currents in the casing. The eddy currents produce secondary fields that can be sensed along with the primary field by the receiver coils. Each of the receiver coils can be placed a predetermined distance away from the transmitter coils. For example, a first receiver coil can be located closest to a first transmitter coil. A second receiver coil can be located further from the first transmitter coil than the first receiver coil and so one for as many additional receiver coils as desired. Similarly, receiver coils can be placed at varying distances from the second transmitter coil. In one example, the transmitter coils can have cores with a relative permeability of 75. The receivers can be implemented without a core. The measurements can be performed at frequencies ranging from 0.1 Hz to 1000 Hz.

At block, the methodcan include determining, based on the one or more electromagnetic measurements, an integrity of the casing at the each of the one or more flow depths in the casing. For example, the one or more electromagnetic measurements can provide magnitudes and phases of the response in the casing. These magnitudes can be used to determine a corrosion level (e.g., metal loss) in the casing at each of the one or more flow depths, for example, lower voltages correspond to higher levels of corrosion. The azimuthal distance can also be recorded for the one or more electromagnetic measurements. The phase can also provide characteristics related to the thickness at locations in the casing. The integrity of the casing is determined based on the corrosion level (e.g., thickness) of the casing at the location where the flow was detected by the acoustic tool. In some examples, the electromagnetic measurements can be used to determine a degree of metal loss. For example, the electromagnetic measurements can be used to determine a degree of metal loss as a percentage from 0% to 100% in a location. The electromagnetic measurements can also determine a total area of metal loss to determine the size (e.g., azimuthal, radial, and vertical positions) of the metal loss.

At block, the methodcan include determining, based on the integrity of the casing at each of the one or more flow depths, a presence or absence of a leak at each of the one or more flow depths in the casing. When presence of flow is determined at the one or more flow depths, then the integrity of the casing is analyzed at each of the one or more flow depths to determine whether there is a leak or there is flow behind the casing at each of the one or more flow depths. The integrity of the casing, as measured by the electromagnetic tool, can be one of no metal loss (e.g., thickness remains at substantially original thickness), slight metal loss (e.g., thickness has corroded from the original thickness, casing has minor cracks), and severe metal loss (e.g., thickness has corroded substantially from original thickness, casing has major cracks or holes). In some examples, slight metal loss can indicate metal loss of less than about 20% of the original casing thickness. In some examples, severe metal loss can indicate metal loss of greater than or equal to about 20% of the original casing thickness. In some examples, the metal loss calculation can further include image processing.

When the presence of flow is determined and the one or more electromagnetic measurements show no metal loss, it can be determined that the flow is behind the casing and no leak is present at the flow depth. When the presence of flow is determined and the one or more electromagnetic measurements show slight metal loss, the presence of a leak can be ambiguous at the flow depth, for example, there can be flow behind the casing or there can be a minor leak through a small crack in the casing. In this ambiguous case, azimuthal distances of the one or more acoustic measurements at the flow depth and azimuthal distances of the one or more electromagnetic measurements at the flow depth can be compared to determine whether the flow is aligned with the slight metal loss. The azimuthal distances can be recorded by an azimuthal electromagnetic tool. The azimuthal electromagnetic tool can provide accurate azimuthal locations and the severity of the corrosion (e.g., metal loss) at the azimuthal locations within the casing. The azimuthal location data can resolve the ambiguity between flow behind the casing or a minor leak through a small crack by determining the metal loss in a certain direction. When the presence of flow is determined and the one or more electromagnetic measurements show severe metal loss, the presence of a leak is determined at the flow depth.

The acoustic signals received by the acoustic tool can be used to locate the acoustic source (e.g., location of flow either within or behind the casing) at a vertical and/or radial position within the casing. For example, the methods (e.g., beamforming methods) for determining the location of the acoustic source described herein can be used to determine one or more depths of an acoustic source in relation to the acoustic tool within the casing. One or more flow depths can be calculated from the known position of the acoustic tool and the position of the acoustic source relative to the acoustic tool. Flow depth means a vertical position within the casing calculated by the vertical position of the acoustic tool within the casing and a vertical position of the acoustic tool from the acoustic tool reference position (e.g., a position on the acoustic tool where the depth of the tool within the casing is calculated and the vertical distance to a source is calculated). The vertical position of the acoustic tool, and thereby the reference position, can be known at any point in time based on a displacement rate (e.g., rate at which the acoustic tool is lowered into the casing). Once the one or more flow depths are determined, the electromagnetic tool can be lowered through the casing to the flow depths to determine the integrity of the casing at the one or more flow depths., andA-C illustrate various acoustic and electromagnetic measurements for an example leak detection method and system. The example ofillustrate the method for determining whether a flow is a leak or a flow behind the casing.

illustrates an example of noise logging power spectral density as logged by an acoustic tool of the present disclosure. As illustrated, there are two high levels of noise within the casing at relative depths (e.g., acoustic source vertical position in relation to the acoustic tool) of 0 inches and at −15 inches. The flow depths can be calculated by determining the vertical position of the acoustic tool. For example, the vertical position of the acoustic tool can correspond to the flow depth shown at a relative depth of 0 inches. The flow depth for the source at −15 inches corresponds to the vertical position of the acoustic tool plus 15 inches further down within the casing. The noise is indicative of a flow at relative depths of 0 inches and −15 inches. However, due to the low resolution of the acoustic tool, it cannot be determined whether the noise is indicative of a leak or flow behind the casing.

illustrates a noise logging beamforming plot for the flow detected at a relative depth of 0 inches (e.g., an acoustic source (flow) has been detected at a relative depth of 0 inches).illustrates a noise logging beam forming plot for the flow detected at a relative depth of −15 inches (e.g., an acoustic source (flow) has been detected 15 inches below the acoustic source). As illustrated in, the noise logging beamforming plots look substantially the same for the flow at the relative depth of 0 inches and the flow at the relative depth at −15 inches. In this example, a known leak was located at a relative depth of 0 inches and a known flow behind the casing with no leak was located at a relative depth of −15 inches. As illustrated, there is no indication that the flow at 0 inches and the flow at the relative depth of-15 inches are different types of flow. Therefore, the acoustic tool may not be operable to determine when there is a leak in the casing which would require maintenance or when there is a false alarm (e.g., flow behind the casing that does not require maintenance).

illustrate responses of an azimuthal electromagnetic tool for the same casing as. The electromagnetic tool was deployed downhole at the determined flow depths (e.g., the depth of the acoustic tool plus the relative depth of the acoustic source in relation to the acoustic tool).illustrates the magnitude (voltage) of the response in the casing as received at a first receiver of the electromagnetic tool. As illustrated, there is a low magnitude at a relative depth of 0 inches, while there is a relatively normal magnitude measurement at a relative depth of −15 inches. The magnitude can be converted, using an inverse algorithm or calculation, to a metal loss of the casing. Lower magnitudes correspond to greater metal loss. The lower magnitude at a depth of 0 inches indicates that there is a leak at the flow depth corresponding to the relative depth of 0 inches, while the higher magnitude at the flow depth corresponding to the relative depth of −15 inches indicates there is flow behind the casing at the depth of −15 inches. Similarly,illustrates the magnitude (voltage) of the response in the casing as received at a second receiver of the electromagnetic tool. As illustrated, there is a low magnitude at a relative depth of 0 inches, while there is a relatively normal magnitude measurement at a relative depth of −15 inches. The magnitude can be converted, using an inverse algorithm or calculation, to a metal loss of the casing. Lower magnitudes correspond to greater metal loss. The lower magnitude at the flow depth corresponding to 0 inches indicates that there is a leak at the flow depth corresponding to the relative depth of 0 inches, while the higher magnitude at the flow depth corresponding to the relative depth of −15 inches indicates there is flow behind the casing at the flow depth corresponding to the relative depth of −15 inches.

illustrates the phase of the response in the casing as received at a first receiver of the electromagnetic tool. As illustrated, the phase is lower at a relative depth of 0 inches than it is at any other depth, indicating that there is metal loss at the flow depth corresponding to the relative depth of 0 inches. The phase at a relative depth of −15 inches has a relatively normal value compared to the rest of the casing (besides at 0 inches), thereby showing that the noise logging at the flow depth corresponding to the relative depth of −15 inches is a false alarm (e.g., flow behind casing. Similarly,illustrates the phase of the response in the casing as received at a second receiver of the electromagnetic tool. As illustrated, the phase is lower at the flow depth corresponding to 0 inches than it is at any other depth, indicating that there is metal loss at 0 inches. The phase at the flow depth corresponding to the relative depth of −15 inches has a relatively normal value compared to the rest of the casing (besides at relative depth of 0 inches), thereby showing that the noise logging at the flow depth corresponding to −15 is a false alarm (e.g., flow behind casing.

illustrates the absolute value of the voltage measurements received by a first receiver of the electromagnetic tool at relative depths (e.g., the measurements received in relation to the electromagnetic tool's vertical position) ranging from 20 inches to −20 inches for the same casing as. As illustrated, the absolute value of the voltage spikes at of the flow depth corresponding to the relative depth of 0 inches. The absolute value of the voltage can be converted using an inverse algorithm or calculation to metal loss in the casing. As illustrated, the metal loss at the flow depth corresponding to the relative depth of 0 inches is significantly greater than the metal loss at any other depth in the casing, indicating that there is a likely leak in the casing at of the flow depth corresponding to the relative depth of 0 inches and the flow detected at the flow depth corresponding to the relative depth of −15 inches is a false alarm (e.g., flow behind the casing). In some examples, a computing system can be used to automate the process of determining a flow using the acoustic tool, determining the corrosion (e.g., metal loss) at the flow depth where a flow has been detected, and determining whether there is a leak or flow behind the casing at the flow depth.

illustrates the absolute value of the voltage measurements received by a second receiver of the electromagnetic tool at relative depths (e.g., measurements received in relation to the electromagnetic tool's vertical position) ranging from 20 inches to −20 inches for the same casing as. As illustrated, the absolute value of the voltage spikes at the flow depth corresponding to 0 inches. The absolute value of the voltage can be converting using an inverse algorithm or calculation to metal loss in the casing. As illustrated, the metal loss at the flow depth corresponding to the relative depth of 0 inches is significantly greater than the metal loss at any other depth in the casing, indicating that there is a likely leak in the casing at the flow depth corresponding to the relative depth of 0 inches and the flow detected at the flow depth corresponding to the relative depth of −15 inches is a false alarm (e.g., flow behind the casing).

illustrates the absolute value of the voltage measurements received by a third receiver of the electromagnetic tool at relative depths (e.g., measurements received in relation to the electromagnetic tool's vertical position) ranging from 20 inches to −20 inches for the same casing as. As illustrated, the absolute value of the voltage spikes at a flow depth correspond to the relative depth of 0 inches. The absolute value of the voltage can be converting using an inverse algorithm or calculation to metal loss in the casing. As illustrated, the metal loss at the flow depth corresponding to the relative depth of 0 inches is significantly greater than the metal loss at any other depth in the casing, indicating that there is a likely leak in the casing at the flow depth corresponding to the relative depth of 0 inches and the flow detected at the flow depth corresponding to the relative depth of −15 inches is a false alarm (e.g., flow behind the casing).

Different downhole anomaly interpretations can be made depending on the responses of acoustic tool and electromagnetic tool during joint logging (e.g., one or more acoustic measurements and the one or more electromagnetic measurements). Table 1 illustrates the different interpretations that can be made depending on the one or more acoustic measurements and the one or more electromagnetic measurements. “Y” indicates that the acoustic tool has detected the presence of flow and/or the electromagnetic tool (EM) has detected the presence of metal loss. “N” indicates that the acoustic tool has detected the absence of flow and/or the electromagnetic tool (EM) has detected the absence of metal loss. By joint logging, the downhole anomaly can be localized at least vertically and interpreted as one of the categories in the anomaly interpretation column.