DOWNHOLE ANOMALY LOCALIZATION AND INTERPRETATION USING ACOUSTIC AND ELECTROMAGNETIC LOGGING

Description

TECHNICAL FIELD

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

BACKGROUND

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.

BRIEF DESCRIPTION OF THE DRAWINGS

In order to describe the manner in which the various advantages and features of the disclosure may be obtained, a more particular description of the principles described herein will be rendered by reference to specific embodiments thereof which are illustrated in the appended drawings. Understanding that these drawings depict only example embodiments of the disclosure and are not to be considered to limit its scope, the principles herein are described and explained with additional specificity and detail through the use of the drawings in which:

FIG. 1 is a schematic diagram of an example logging while drilling (LWD) wellbore operating environment in accordance with various aspects of the disclosure;

FIG. 2 is a diagram of an example downhole environment having tubulars, in accordance with various aspects of the disclosure;

FIG. 3 illustrates an electromagnetic tool within one or more casings of a well;

FIG. 4A is a schematic diagram of an acoustic tool environment in accordance with various aspects of the present disclosure;

FIG. 4B is a schematic cross-sectional depiction of an example acoustic-sensor array deployed within a wellbore in accordance with various aspects of the present disclosure;

FIG. 4C is a schematic diagram of an acoustic tool environment in accordance with various aspects of the present disclosure;

FIG. 5 is a schematic depiction of the relative locations of a source and three sensors for locating an acoustic source in two dimensions in accordance with various aspects of the present disclosure;

FIG. 6 is a diagram illustrating various possible array-signal-processing techniques;

FIG. 7 is a flowchart of a method in accordance with various aspects of the disclosure;

FIG. 8 illustrates an example of power spectral density from noise logging;

FIG. 9A illustrates a noise logging beamforming plot at a depth of 0 inches;

FIG. 9B illustrates a noise logging beamforming plot at a depth of −15 inches;

FIGS. 10A-10D illustrate azimuthal electromagnetic logging tool responses;

FIGS. 11A-11C illustrate vertical electromagnetic logging responses;

FIG. 12 is an interpretation map for different combinations of joint logging responses; and

FIG. 13 is a diagram illustrating an example of a system for implementing certain aspects of the present technology in accordance with some aspects of the disclosure.

DETAILED DESCRIPTION

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.

FIG. 1 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 100. The LWD typically incorporates sensors that acquire formation data. The drilling arrangement of FIG. 1 also 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. FIG. 1 shows a drilling platform 102 equipped with a derrick 104 that supports a hoist 106 for raising and lowering a drill string 108. The hoist 106 suspends a top drive 110 suitable for rotating and lowering the drill string 108 through a well head 112. A drill bit 114 can be connected to the lower end of the drill string 108. As the drill bit 114 rotates, the drill bit 114 creates a wellbore 116 that passes through one or more subterranean formations 118. A pump 120 circulates drilling fluid through a supply pipe 122 to top drive 110, down through the interior of the drill string 108, and out orifices in the drill bit 114 into the wellbore. The drilling fluid returns to the surface via the annulus around the drill string 108, and into a retention pit 124. The drilling fluid transports cuttings from the wellbore 116 into the retention pit 124 and the drilling fluid's presence in the annulus aids in maintaining the integrity of the wellbore 116. 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 tools 126 can be integrated into the bottom-hole assembly 125 near the drill bit 114. As the drill bit 114 extends the wellbore 116 through the subterranean formations 118, logging tools 126 collect 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 assembly 125 can also include a telemetry sub 128 to transfer measurement data to a surface receiver 132 and to receive commands from the surface. In at least some cases, the telemetry sub 128 communicates with a surface receiver 132 using mud pulse telemetry. In some instances, the telemetry sub 128 does 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 tools 126 can 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 tools 126 can 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 tools 126 can communicate with a surface receiver 132 by a wire, such as a wired drill pipe. In other cases, the one or more of the logging tools 126 can communicate with a surface receiver 132 by wireless signal transmission, such as ground penetrating radar. In at least some cases, one or more of the logging tools 126 can receive electrical power from a wire that extends to the surface, including wires extending through a wired drill pipe.

In some aspects, a collar 134 is a frequent component of a drill string 108 and 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 collars 134 can be included in the drill string 108 and are constructed and intended to be heavy to apply weight on the drill bit 114 to 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 collar 134 as a component of the drill string 108.

FIG. 2 is a diagram of an example downhole environment having tubulars in accordance with various aspects of the disclosure. In some aspects, an example system 140 is 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 body 146 to perform logging, measurements, and/or other operations. For example, instead of using the drill string 108 of FIG. 1 to lower a tool body 146, which can contain sensors and/or other instrumentation for detecting and logging nearby characteristics and conditions of the wellbore 116 and surrounding formations, a wireline conveyance 144 can be used.

The tool body 146 can be lowered into the wellbore 116 by wireline conveyance 144. The wireline conveyance 144 can be anchored in the drill rig 142 or by a portable device such as a truck 145. The wireline conveyance 144 can 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 conveyance 144 provides power and support for the tool, as well as enabling communication between processing systems 150 on the surface. In some examples, the wireline conveyance 144 can include electrical and/or fiber optic cabling for performing any communications. The wireline conveyance 144 is sufficiently strong and flexible to tether the tool body 146 through the wellbore 116, while also permitting communication through the wireline conveyance 144 to one or more of the processing systems 150, which can include local and/or remote processors. Additionally, the processing systems 150 can be coupled to a first communication system 152 that can communicate via wireless and/or satellite connections. Additionally, a local communication device 153 can be included. The local communication device 153 can communicate with other devices near the site. In some cases, power can be supplied via the wireline conveyance 144 to 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 casing 162 that can be coupled to the formation by cement 164 that is located within an annulus formed between the casing 162 and 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.

FIG. 3 is a close up view of a tool 320 within one or more casings 300 of a well bore. As illustrated the casings 300 can include a first casing 310, a second casing 312, a third casing 314, and a fourth casing 316. While the illustrated example includes four casings 300, the present disclosure is operable from one to dozens of casings. As illustrated, in a portion of the well bore the casings 300 overlap such that a given depth two or more casings 300 can be positioned within the well bore. In at least one example, the casings 300 can 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 FIG. 3, the casings 300 have been truncated for illustration purposes and can extend much longer relative distances.

The tool 320 can be configured to measure an integrity of one or more of the casings or pipes. For example, the tool 320 can 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 tool 320 can include a transmitter coil 330, a first receiver 340, a second receiver 342, a third receiver 344, a fourth receiver 346, a fifth receiver 348, and sixth receiver 350. The tool 320 can be implemented for electromagnetic (EM) techniques. One example of an EM technique is eddy current effect. The tool 320 can be used to characterize the casing 300 around the well bore. Another technique is to use frequency domain eddy current techniques. In this arrangement the transmitter coil 330 is provided a continuous sinusoidal signal, producing primary fields that illuminate the casings 300. The primary fields induce eddy currents in the casings 300 and/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 340, 342, 344, 346, 348, 350. Each of the receiver coils 340, 342, 344, 346, 348, 350 can be placed a predetermined distance away from the transmitter coil 330. As illustrated, the first receiver 340 is closer to the transmitter coil 330 than the remainder of the receiver coils 342, 344, 346, 348, 350. The second receiver 342 can be placed next. The third receiver 344 can be further away from the transmitter coil 330 than the first receiver 340 and the second receiver 342. The fourth receiver 346 can be located still further away from the transmitter coil 330 as compared to the third receiver 344. The fifth receiver 348 can be next followed by the sixth receiver 350, which can be located the furthest from the transmitter coil 330. While six receiver coils 340, 342, 344, 346, 348, 350 are illustrated, the present technology can be implemented with two to twelve receiver coils 340, 342, 344, 346, 348, 350.

In one example, the transmitter coil 330 can have a core with a relative permeability of 75. The receiver coils 340, 342, 344, 346, 348, 350 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 tool 320 can include two or more transmitter coils (e.g., transmitter coil 330). In some examples, a first transmitter coil can be a low frequency transmitter and the second transmitter coil can be a high frequency transmitter.

FIGS. 4A-4C illustrate an exemplary acoustic tool environment and acoustic tool within the acoustic tool environment in accordance with the present disclosure. FIGS. 4A and 4C 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 tubing 404 through which oil or gas can be pumped up and out of the well, one or optionally multiple nested well casings 406, and a cement sheath 408 filling the space between the casing(s) 406 and the formation 410 surrounding the wellbore. Additionally, the wellbore can be divided into multiple vertical sections, e.g., by packers 412 between the casings 406. Unintended flow scenarios that can occur in such a configuration include, e.g., flows across the casing 406 or tubing 404 due to cracks or holes therein (indicated by arrows 420), flows past a packer 412 between adjacent vertical wellbore sections due to insufficient sealing (indicated by arrows 422), and flows within the formation 410, cement sheath 408, or other layer more or less parallel to the layer boundaries (indicated by arrows 424). As these flows pass through restricted paths, acoustic signals can be generated as a result of the accompanying pressure drops. As illustrated in FIG. 4B, the sensors 400 can be arranged linearly along the longitudinal axis 402 of the wellbore (whose radial coordinate is zero). The sensors 400 can 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 sensors 400 in the acoustic tool 401.

Acoustic sensors 400 suitable 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 sensors 400 can be arranged in a hydrophone array. In some examples, the acoustic sensors 400 are 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 sensors 400 in a linear arrangement, as shown in FIG. 4B, 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 tool 401 or 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).

FIG. 5 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 R1, R2, R3, 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 t_i of the signal from the source at (r_s, z_s) to a sensor i at (r_r,i, z_r,i) is simply the ratio of the distance d_i between source and sensor to the speed of sound v:

t i = d t v = ( r s - r r , i ) 2 + ( z s - z r , i ) 2 v ( Eq . 1 )

The absolute travel time t_i cannot 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_ij=t_i−t_j (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_s,z_s) of the source:

Δ ⁢ t ij = 
 t i - t j = ( r s - r r , i ) 2 + ( z s - z r , i ) 2 - ( r s - r r , j ) 2 + ( z s - z r , j ) 2 v ( Eq . 2 )

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. FIG. 6 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).

FIG. 7 illustrates a flow chart of a method 700 for detecting a downhole anomaly. At block 702, the method 700 can 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 method 700 can be performed as part of routine maintenance and monitoring of an existing wellbore. In some examples, the method 700 can 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 704, the method 700 can 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 706, the method 700 can 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 method 700 can 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 708, the method 700 can 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 710, the method 700 can 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 712, the method 700 can 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. FIGS. 8, 9A-9B, 10A-10D, and 11A-11C illustrate various acoustic and electromagnetic measurements for an example leak detection method and system. The example of FIGS. 8, 9A-9B, 10A-10D, and 11A-11C illustrate the method for determining whether a flow is a leak or a flow behind the casing.

FIG. 8 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.

FIG. 9A 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). FIG. 9B 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 FIGS. 9A-9B, 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).

FIGS. 10A-10D illustrate responses of an azimuthal electromagnetic tool for the same casing as FIGS. 8 and 9A-9B. 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). FIG. 10A 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, FIG. 10B 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.

FIG. 10C 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, FIG. 10D 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.

FIG. 11A 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 FIGS. 8, 9A-9B, and 10A-10D. 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.

FIG. 11B 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 FIGS. 8, 9A-9B, and 10A-10D. 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).

FIG. 11C 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 FIGS. 8, 9A-9B, and 10A-10D. 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.

TABLE 1
Interpretation of different combinations of joint logging responses

Acoustic	EM	Anomaly Interpretation
Y	N-no metal	Casing in good condition, flow behind
	loss	casing
Y	Y-slight metal	Flow behind casing or leak through a small
	loss	crack or hole on the casing (ambiguous
		situation. Azimuthal electromagnetic tool
		can help resolve the ambiguity)
Y	Y-severe	Corrosion causing leak through casing
	metal loss
N	Y-slight metal	Corrosion not penetrating the casing, no
	loss	leak
N	Y-severe	Corrosion, no leak (unlikely situation -
	metal loss	check the quality of both acoustic and
		electromagnetic inversions)
N	N-no metal	Casing in good condition, no flow behind
	loss	casing

In some examples, the interpretations shown in Table 1 can be made by a computing system utilizing software. For example, the computing system can receive the acoustic measurements and electromagnetic measurements at a plurality of depths. The computing system can then determine the flow depths where flow is detected. The computing system can then determine the metal loss (e.g., corrosion) at the flow depths and determine whether the flow is a leak in the casing or a flow behind the casing. While Table 1 shows metal loss interpreted as no metal loss, slight metal loss, and severe metal loss, it will be appreciated that the electromagnetic measurements can be used to determine a degree of metal loss, for example, a percentage of metal loss and/or a thickness of the casing.

FIG. 12 is an interpretation map 1200 of different combinations of joint logging responses. The acoustic response (e.g., one or more acoustic measurements) is shown on the vertical axis and can divide the map 1200 into two zones (e.g., no flow/leak and flow/leak). The electromagnetic response (EM response) (e.g., one or more electromagnetic measurements) is shown on the horizontal axis and can divide the map 1200 into three zones (e.g., no metal loss, slight metal loss, and severe metal loss). Therefore, the map 1200 is divided into 6 zones, a first zone 1202, a second zone 1204, a third zone 1206, a fourth zone 1208, a fifth zone 1210, and a sixth zone 1212. The first zone 1202 occurs when the acoustic response indicates flow and the electromagnetic response indicates no metal loss at a depth in the casing. In the first zone 1202, the casing is in good condition and the flow is behind the casing (e.g., the acoustic response is a false alarm for a leak). The second zone 1204 occurs when the acoustic response indicates flow and the electromagnetic response indicates slight metal loss at a depth in the casing. In the second zone 1204, the flow is either behind the casing or there is a leak through a small crack or hole on the casing. The second zone 1204 can require additional measurement to determine the azimuthal location of the flow and/or the metal loss to determine whether a leak is present.

The third zone 1206 occurs when the acoustic response indicates flow and the electromagnetic response indicates severe metal loss at a depth in the casing. In the third zone 1206, there is corrosion in the casing causing a leak through the casing. The fourth zone 1208 occurs when the acoustic response indicates no flow and the electromagnetic response indicates severe metal loss at a depth in the casing. In the fourth zone 1208, there is corrosion in the casing but there is no leak. The fourth zone 1208 is an unlikely scenario and the inversions of the acoustic and electromagnetic responses should be checked for accuracy. The fifth zone 1210 occurs when the acoustic response indicates flow and the electromagnetic response indicates slight metal loss at a depth in the casing. In the fifth zone 1210, there is corrosion in the casing that does not penetrate the casing and there is no leak. The sixth zone 1212 occurs when the acoustic response indicates no flow and the electromagnetic response indicates no metal loss at a depth in the casing. In the sixth zone 1212, the casing is in good condition and there is no leak or flow behind the casing.

FIG. 13 is a diagram illustrating an example of a system for implementing certain aspects of the present technology in accordance with some aspects of the disclosure. In particular, FIG. 13 illustrates an example of computing system 1300, which can be for example any computing device making up an internal computing system, a remote computing system, a sensor, or any component thereof in which the components of the system are in communication with each other using connection 1305. Connection 1305 can be a physical connection using a bus, or a direct connection into processor 1310, such as in a chipset architecture. Connection 1305 cam also be a virtual connection, networked connection, or logical connection.

In some aspects, computing system 1300 is a distributed system in which the functions described in this disclosure can be distributed within a datacenter, multiple data centers, a peer network, etc. In some aspects, one or more of the described system components represents many such components each performing some or all of the function for which the component is described. In some aspects, the components can be physical or virtual devices.

Example computing system 1300 includes at least one processing unit (CPU or processor) 1310 and connection 1305 that couples various system components including system memory 1315, such as ROM 1320 and RAM 1325 to processor 1310. Computing system 1300 can include a cache 1312 of high-speed memory connected directly with, in close proximity to, or integrated as part of processor 1310.

Processor 1310 can include any general purpose processor and a hardware service or software service, such as services 1332, 1334, and 1336 stored in storage device 1330, configured to control processor 1310 as well as a special-purpose processor where software instructions are incorporated into the actual processor design. Processor 1310 can essentially be a completely self-contained computing system, containing multiple cores or processors, a bus, memory controller, cache, etc. A multi-core processor can be symmetric or asymmetric.

To enable user interaction, computing system 1300 includes an input device 1345, which can represent any number of input mechanisms, such as a microphone for speech, a touch-sensitive screen for gesture or graphical input, keyboard, mouse, motion input, speech, etc. Computing system 1300 can also include output device 1335, which can be one or more of a number of output mechanisms. In some instances, multimodal systems can enable a user to provide multiple types of input/output to communicate with computing system 1300. Computing system 1300 can include communications interface 1340, which can generally govern and manage the user input and system output. The communication interface can perform or facilitate receipt and/or transmission wired or wireless communications using wired and/or wireless transceivers, including those making use of an audio jack/plug, a microphone jack/plug, a universal serial bus (USB) port/plug, an Apple® Lightning® port/plug, an Ethernet port/plug, a fiber optic port/plug, a proprietary wired port/plug, a Bluetooth® wireless signal transfer, a BLE wireless signal transfer, an IBEACON® wireless signal transfer, an RFID wireless signal transfer, near-field communications (NFC) wireless signal transfer, dedicated short range communication (DSRC) wireless signal transfer, 802.11 WiFi wireless signal transfer, WLAN signal transfer, Visible Light Communication (VLC), Worldwide Interoperability for Microwave Access (WiMAX), IR communication wireless signal transfer, Public Switched Telephone Network (PSTN) signal transfer, Integrated Services Digital Network (ISDN) signal transfer, 3G/4G/5G/LTE cellular data network wireless signal transfer, ad-hoc network signal transfer, lamb wave signal transfer, microwave signal transfer, infrared signal transfer, visible light signal transfer, ultraviolet light signal transfer, wireless signal transfer along the electromagnetic spectrum, or some combination thereof. The communications interface 1340 can also include one or more Global Navigation Satellite System (GNSS) receivers or transceivers that are used to determine a location of the computing system 600 based on receipt of one or more signals from one or more satellites associated with one or more GNSS systems. GNSS systems include, but are not limited to, the US-based GPS, the Russia-based Global Navigation Satellite System (GLONASS), the China-based BeiDou Navigation Satellite System (BDS), and the Europe-based Galileo GNSS. There is no restriction on operating on any particular hardware arrangement, and therefore the basic features here can easily be substituted for improved hardware or firmware arrangements as they are developed.

Storage device 1330 can be a non-volatile and/or non-transitory and/or computer-readable memory device and can be a hard disk or other types of computer readable media which can store data that are accessible by a computer, such as magnetic cassettes, flash memory cards, solid state memory devices, digital versatile disks, cartridges, a floppy disk, a flexible disk, a hard disk, magnetic tape, a magnetic strip/stripe, any other magnetic storage medium, flash memory, memristor memory, any other solid-state memory, a compact disc read only memory (CD-ROM) optical disc, a rewritable compact disc (CD) optical disc, digital video disk (DVD) optical disc, a blu-ray disc (BDD) optical disc, a holographic optical disk, another optical medium, a secure digital (SD) card, a micro secure digital (microSD) card, a Memory Stick® card, a smartcard chip, a EMV chip, a subscriber identity module (SIM) card, a mini/micro/nano/pico SIM card, another integrated circuit (IC) chip/card, RAM, static RAM (SRAM), dynamic RAM (DRAM), ROM, programmable read-only memory (PROM), erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), flash EPROM (FLASHEPROM), cache memory (L1/L2/L3/L4/L5/L #), resistive random-access memory (RRAM/ReRAM), phase change memory (PCM), spin transfer torque RAM (STT-RAM), another memory chip or cartridge, and/or a combination thereof.

The storage device 1330 can include software services, servers, services, etc., that when the code that defines such software is executed by the processor 1310, it causes the system to perform a function. In some aspects, a hardware service that performs a particular function can include the software component stored in a computer-readable medium in connection with the necessary hardware components, such as processor 1310, connection 1305, output device 1335, etc., to carry out the function. The term “computer-readable medium” includes, but is not limited to, portable or non-portable storage devices, optical storage devices, and various other mediums capable of storing, containing, or carrying instruction(s) and/or data. A computer-readable medium can include a non-transitory medium in which data can be stored and that does not include carrier waves and/or transitory electronic signals propagating wirelessly or over wired connections. Examples of a non-transitory medium can include, but are not limited to, a magnetic disk or tape, optical storage media such as CD or DVD, flash memory, memory or memory devices. A computer-readable medium can have stored thereon code and/or machine-executable instructions that can represent a procedure, a function, a subprogram, a program, a routine, a subroutine, a module, a software package, a class, or any combination of instructions, data structures, or program statements. A code segment can be coupled to another code segment or a hardware circuit by passing and/or receiving information, data, arguments, parameters, or memory contents. Information, arguments, parameters, data, etc. can be passed, forwarded, or transmitted via any suitable means including memory sharing, message passing, token passing, network transmission, or the like.

In some cases, the computing device or apparatus can include various components, such as one or more input devices, one or more output devices, one or more processors, one or more microprocessors, one or more microcomputers, one or more cameras, one or more sensors, and/or other component(s) that are configured to carry out the steps of processes described herein. In some examples, the computing device can include a display, one or more network interfaces configured to communicate and/or receive the data, any combination thereof, and/or other component(s). The one or more network interfaces can be configured to communicate and/or receive wired and/or wireless data, including data according to the 3G, 4G, 5G, and/or other cellular standard, data according to the Wi-Fi (802.11x) standards, data according to the Bluetooth™ standard, data according to the IP standard, and/or other types of data.

The components of the computing device can be implemented in circuitry. For example, the components can include and/or can be implemented using electronic circuits or other electronic hardware, which can include one or more programmable electronic circuits (e.g., microprocessors, GPUs, DSPs, CPUs, and/or other suitable electronic circuits), and/or can include and/or be implemented using computer software, firmware, or any combination thereof, to perform the various operations described herein.

In some aspects the computer-readable storage devices, mediums, and memories can include a cable or wireless signal containing a bit stream and the like. However, when mentioned, non-transitory computer-readable storage media expressly exclude media such as energy, carrier signals, electromagnetic waves, and signals per se.

Specific details are provided in the description above to provide a thorough understanding of the aspects and examples provided herein. However, it will be understood by one of ordinary skill in the art that the aspects can be practiced without these specific details. For clarity of explanation, in some instances the present technology can be presented as including individual functional blocks including functional blocks comprising devices, device components, steps or routines in a method embodied in software, or combinations of hardware and software. Additional components can be used other than those shown in the figures and/or described herein. For example, circuits, systems, networks, processes, and other components can be shown as components in block diagram form in order not to obscure the aspects in unnecessary detail. In other instances, well-known circuits, processes, algorithms, structures, and techniques can be shown without unnecessary detail in order to avoid obscuring the aspects.

Individual aspects may be described above as a process or method which is depicted as a flowchart, a flow diagram, a data flow diagram, a structure diagram, or a block diagram. Although a flowchart may describe the operations as a sequential process, many of the operations may be performed in parallel or concurrently. In addition, the order of the operations can be re-arranged. A process is terminated when its operations are completed but can have additional steps not included in a figure. A process can correspond to a method, a function, a procedure, a subroutine, a subprogram, etc. When a process corresponds to a function, its termination can correspond to a return of the function to the calling function or the main function.

Processes and methods according to the above-described examples can be implemented using computer-executable instructions that are stored or otherwise available from computer-readable media. Such instructions can include, for example, instructions and data which cause or otherwise configure a general purpose computer, special purpose computer, or a processing device to perform a certain function or group of functions. Portions of computer resources used can be accessible over a network. The computer executable instructions can be, for example, binaries, intermediate format instructions such as assembly language, firmware, source code, etc. Examples of computer-readable media that can be used to store instructions, information used, and/or information created during methods according to described examples include magnetic or optical disks, flash memory, USB devices provided with non-volatile memory, networked storage devices, and so on.

Devices implementing processes and methods according to these disclosures can include hardware, software, firmware, middleware, microcode, hardware description languages, or any combination thereof, and can take any of a variety of form factors. When implemented in software, firmware, middleware, or microcode, the program code or code segments to perform the necessary tasks (e.g., a computer-program product) can be stored in a computer-readable or machine-readable medium. A processor(s) can perform the necessary tasks. Typical examples of form factors include laptops, smart phones, mobile phones, tablet devices, or other small form factor personal computers, personal digital assistants, rackmount devices, standalone devices, and so on. The functionality described herein also can be embodied in peripherals or add-in cards. Such functionality can also be implemented on a circuit board among different chips or different processes executing in a single device, by way of further example.

The instructions, media for conveying such instructions, computing resources for executing them, and other structures for supporting such computing resources are example means for providing the functions described in the disclosure.

In the foregoing description, aspects of the application are described with reference to specific aspects thereof, but those skilled in the art will recognize that the application is not limited thereto. Thus, while illustrative aspects of the application have been described in detail herein, it is to be understood that the inventive concepts can be otherwise variously embodied and employed, and that the appended claims are intended to be construed to include such variations, except as limited by the prior art. Various features and aspects of the above-described application can be used individually or jointly. Further, aspects can be utilized in any number of environments and applications beyond those described herein without departing from the broader spirit and scope of the specification. The specification and drawings are, accordingly, to be regarded as illustrative rather than restrictive. For the purposes of illustration, methods were described in a particular order. It should be appreciated that in alternate aspects, the methods can be performed in a different order than that described.

One of ordinary skill will appreciate that the less than (“<”) and greater than (“>”) symbols or terminology used herein can be replaced with less than or equal to (“≤”) and greater than or equal to (“>”) symbols, respectively, without departing from the scope of this description.

Where components are described as being “configured to” perform certain operations, such configuration can be accomplished, for example, by designing electronic circuits or other hardware to perform the operation, by programming programmable electronic circuits (e.g., microprocessors, or other suitable electronic circuits) to perform the operation, or any combination thereof.

The phrase “coupled to” refers to any component that is physically connected to another component either directly or indirectly, and/or any component that is in communication with another component (e.g., connected to the other component over a wired or wireless connection, and/or other suitable communication interface) either directly or indirectly.

Claim language or other language reciting “at least one of” a set and/or “one or more” of a set indicates that one member of the set or multiple members of the set (in any combination) satisfy the claim. For example, claim language reciting “at least one of A and B” or “at least one of A or B” means A, B, or A and B. In another example, claim language reciting “at least one of A, B, and C” or “at least one of A, B, or C” means A, B, C, or A and B, or A and C, or B and C, or A and B and C. The language “at least one of” a set and/or “one or more” of a set does not limit the set to the items listed in the set. For example, claim language reciting “at least one of A and B” or “at least one of A or B” may mean A, B, or A and B, and may additionally include items not listed in the set of A and B.

The various illustrative logical blocks, modules, circuits, and algorithm steps described in connection with the aspects disclosed herein can be implemented as electronic hardware, computer software, firmware, or combinations thereof. To clearly illustrate this interchangeability of hardware and software, various illustrative components, blocks, modules, circuits, and steps have been described above generally in terms of their functionality. Whether such functionality is implemented as hardware or software depends upon the particular application and design constraints imposed on the overall system. Skilled artisans may implement the described functionality in varying ways for each particular application, but such implementation decisions should not be interpreted as causing a departure from the scope of the present application.

The techniques described herein can also be implemented in electronic hardware, computer software, firmware, or any combination thereof. Such techniques can be implemented in any of a variety of devices such as general purposes computers, wireless communication device handsets, or integrated circuit devices having multiple uses including application in wireless communication device handsets and other devices. Any features described as modules or components can be implemented together in an integrated logic device or separately as discrete but interoperable logic devices. If implemented in software, the techniques can be realized at least in part by a computer-readable data storage medium comprising program code including instructions that, when executed, performs one or more of the methods described above. The computer-readable data storage medium can form part of a computer program product, which can include packaging materials. The computer-readable medium can comprise memory or data storage media, such as RAM such as synchronous dynamic random access memory (SDRAM), ROM, non-volatile random access memory (NVRAM), EEPROM, flash memory, magnetic or optical data storage media, and the like. The techniques additionally, or alternatively, can be realized at least in part by a computer-readable communication medium that carries or communicates program code in the form of instructions or data structures and that can be accessed, read, and/or executed by a computer, such as propagated signals or waves.

The program code can be executed by a processor, which can include one or more processors, such as one or more DSPs, general purpose microprocessors, an application specific integrated circuits (ASICs), field programmable logic arrays (FPGAs), or other equivalent integrated or discrete logic circuitry. Such a processor can be configured to perform any of the techniques described in this disclosure. A general purpose processor can be a microprocessor; but in the alternative, the processor can be any conventional processor, controller, microcontroller, or state machine. A processor can also be implemented as a combination of computing devices, e.g., a combination of a DSP and a microprocessor, a plurality of microprocessors, one or more microprocessors in conjunction with a DSP core, or any other such configuration. Accordingly, the term “processor,” as used herein may refer to any of the foregoing structure, any combination of the foregoing structure, or any other structure or apparatus suitable for implementation of the techniques described herein.

Numerous examples are provided herein to enhance understanding of the present disclosure. A specific set of statements are provided as follows.

• • Statement 1: A method for detecting a downhole anomaly, the method comprising: deploying an acoustic tool and an electromagnetic tool downhole; receiving, via the acoustic tool, one or more acoustic measurements within and/or around a casing at a plurality of corresponding depths; determining, based on the one or more acoustic measurements, a presence of a flow at one or more flow depths in the casing; receiving, via an electromagnetic tool, one or more electromagnetic measurements within and/or around the casing at the one or more flow depths; determining, based on the one or more electromagnetic measurements, an integrity of the casing at each of the one or more flow depths in the casing; and determining, based on the integrity of the casing, a presence or absence of a leak at each of the one or more flow depths in the casing.
  • Statement 2: The method according to Statement 1, wherein the acoustic tool includes a hydrophone array.
  • Statement 3: The method according to Statement 1 or 2, wherein determining the presence or absence of the flow includes utilizing a beamforming method to determine a position of the one or more flow depths in the casing.
  • Statement 4: The method according to any of preceding Statements 1 to 3, wherein the position is a vertical position and a radial position of the flow.
  • Statement 5: The method according to any of preceding Statements 1 to 4, wherein the electromagnetic tool includes at least one transmitter station having at least one transmitter coil and at least one receiver station having at least one receiver coil.
  • Statement 6: The method according to Statement 5, wherein the at least one transmitter coil is operable to induce eddy currents in one or more well tubulars and the at least one receiver coil is operable to measure a magnetic field generated at least in part by the eddy currents.
  • Statement 7: The method according to Statement 6, wherein the at least one receiver coil is operable to determine a thickness of the one or more well tubulars and/or a thickness of the casing.
  • Statement 8: The method according to any of preceding Statements 1 to 7, wherein the electromagnetic tool is operable to determine a vertical position and/or an azimuthal position at the location in the casing.
  • Statement 9: The method according to any of preceding Statements 1 to 8, wherein the integrity of the casing comprises a degree of metal loss.
  • Statement 10: The method according to any of preceding Statements 1 to 9, wherein the presence of the leak is determined when the integrity of the casing is determined to show metal loss.
  • Statement 11: The method according to any of preceding Statements 1 to 10, wherein the absence of the leak is determined when the integrity of the casing is determined to show no metal loss.
  • Statement 12: A system for detecting a downhole anomaly, the system comprising: an acoustic tool, an electromagnetic tool, at least one processor; and a memory coupled to the at least one processor having instructions stored therein, which when executed by the at least one processor, cause the at least one processor to perform a plurality of functions, including functions to: receive, via the acoustic tool, one or more acoustic measurements within and/or around a casing at a plurality of corresponding depths; determine, based on the one or more acoustic measurements, a presence of a flow at one or more flow depths in the casing; receive, via the electromagnetic tool, one or more electromagnetic measurements within and/or around the casing at each of the one or more flow depths; determine, based on the one or more electromagnetic measurements, an integrity of the casing at each of the one or more flow depths in the casing; and determine, based on the integrity of the casing, a presence or absence of a leak at the each of the one or more flow depths in the casing.
  • Statement 13: The system according to Statement 12, wherein the acoustic tool includes a hydrophone array.
  • Statement 14: The system according to Statement 12 or 13, wherein determining the presence or absence of the flow includes utilizing a beamforming method to determine a position of the one or more flow depths in the casing.
  • Statement 15: The system according to any of preceding Statements 12 to 14, wherein the position is a vertical position and a radial position.
  • Statement 16: The system according to any of preceding Statements 12 to 15, wherein the electromagnetic tool includes at least one transmitter station having at least one transmitter coil and at least one receiver station having at least one receiver coil.
  • Statement 17: The system according to Statement 16, wherein the at least one transmitter coil is operable to induce eddy currents in one or more well tubulars and the at least one receiver coil is operable to measure a magnetic field generated at least in part by the eddy currents.
  • Statement 18: The system according to Statement 17, wherein the at least one receiver coil is operable to determine a thickness of the one or more well tubulars and a thickness of the casing.
  • Statement 19: The system according to any of preceding Statements 12 to 18, wherein the electromagnetic tool is operable to determine a vertical position and/or an azimuthal position at the one or more flow depths in the casing.
  • Statement 20: The system according to any of preceding Statements 12 to 19, wherein the presence of a leak is determined when the integrity of the casing is determined to show metal loss.