METHOD FOR ESTIMATING A TUBE PROPERTY FOR A PLURALITY OF NESTED TUBES

Abstract

METHOD FOR ESTIMATING A PIPE PROPERTY FOR A PLURALITY OF NESTED PIPES. A method for estimating a pipe property for a plurality of nested pipes. The method may comprise arranging an electromagnetic (EM) logging tool in a wellbore. The electromagnetic logging tool may comprise a transmitter arranged on the electromagnetic logging tool and a receiver arranged on the electromagnetic logging tool.The method may also involve transmitting an electromagnetic field from the transmitter to one or more tubes, measuring the eddy current in the tubing string with the receiver on at least one channel to obtain a plurality of measurements, forming an EM profile from the plurality of measurements, extracting data and distinct features from the EM profile, forming a relationship between the EM profile data and a database, wherein the database is formed from one or more high-resolution measurements, and producing a mapping function between the EM profile and the database.

Description

/ 33 METHOD FOR ESTIMATING A TUBE PROPERTY FOR A PLURALITY OF NESTED TUBES - FUNDAMENTALS

[001] For oil and gas exploration and production, a network of wells, installations, and other conduits can be established by connecting sections of metal pipe. For example, a well installation can be completed, in part, by lowering several sections of metal pipe (i.e., a casing string) into a wellbore and cementing the casing string in place. In some well installations, multiple casing strings are employed (e.g., a concentric arrangement of multiple strings) to allow for different operations related to well completion, production, or enhanced oil recovery (EOR) options.

[002] Corrosion of metal pipes is a permanent problem. Efforts to mitigate corrosion include the use of corrosion-resistant alloys, coatings, treatments, and corrosion transfer, among others. Also, efforts to improve corrosion monitoring are ongoing. For downhole casing strings, several types of corrosion monitoring tools are available. One type of corrosion monitoring tool uses electromagnetic (EM) fields to estimate pipe thickness or other corrosion indicators.

[003] In addition, high-resolution corrosion tools can be used for corrosion detection. However, high-resolution corrosion tools operate by direct contact with the coating, which can produce high-resolution data and circumferential data. High-resolution corrosion tools can be magnetic flux leakage tools, acoustic tools, mechanical calipers, and others that typically analyze a single tube. This forces the operator to pull the tube so that the outer tubes can be inspected by the high-resolution corrosion tool. Petition 870260009405, dated 01 / 30 / 2026, page 11 / 109 / 33 resolution, which brings risk and downtime for the well.

[004] Other technologies, such as electromagnetic (EM) technology, offer multi-column analysis. However, the resolution is degraded and not as informative as the data provided by high-resolution corrosion tools. Both technologies, high-resolution corrosion tools and EM corrosion tools, have data and monetary considerations that make performing corrosion monitoring operations difficult and expensive. BRIEF DESCRIPTION OF THE DRAWINGS

[005] These drawings illustrate certain aspects of some examples in this disclosure and should not be used to limit or define the disclosure.

[006] Figure 1 illustrates an example of an EM logging tool positioned in a wellbore; Figure 2 illustrates an example of arbitrary defects within multiple pipes; Figure 3A illustrates an example of an EM logging tool traversing a wellbore; Figure 3B illustrates another example of an EM logging tool traversing a wellbore; Figure 3C illustrates another example of an EM logging tool traversing a wellbore; Figure 3D illustrates another example of an EM logging tool traversing a wellbore; Figure 3E illustrates another example of an EM logging tool traversing a wellbore; Figure 4 illustrates an example of a well plan; Figure 5 illustrates a workflow for creating a corrosion map; Petition 870260009405, dated 01 / 30 / 2026, page 12 / 109 / 33 Figures 6A-6C illustrate a high-resolution tool measurement operation; Figure 7 illustrates a deep neural network; Figures 8A and 8B illustrate a simple graph of how thickness varies over time; Figure 9 illustrates the workflow for predicting corrosion in a tubular structure; Figures 10A and 10B are measurements at times t1 and t2, respectively; Figures 11A and 11B illustrate the inverted tube thickness of the EM profiles for the two data sets in Figures 10A and 10B, respectively; Figures 12A and 12B are resolution-enhanced inverted tube thicknesses derived from the EM profiles in Figures 10A and 10B; and Figures 13A and 13B illustrate the extent of a corrosion area at times t1 and t2. DETAILED DESCRIPTION

[007] This disclosure may generally refer to the inspection of pipes in underground wells and, more particularly, to methods and systems for identifying artifacts, corrosion and / or anomalies using an electromagnetic logging tool together with measurements from a high-resolution tool in an eccentric pipe configuration comprising a plurality of pipes. The use of high-resolution information, together with the configuration of corrosion patterns or geometric information, allows for improved calibration and resolution of electromagnetic (EM) logging data. By combining high-resolution logging of corrosion data and using it with the lower-resolution EM logging tool measurement, an operator can create a detailed corrosion map on multiple pipes in a concentric multi-column arrangement during the Petition 870260009405, dated 01 / 30 / 2026, page 13 / 109 / 33 operation in which an EM profiling tool is run.

[008] Electromagnetic (EM) sensing can provide continuous in situ measurements of parameters related to the integrity of pipes in cased wells. As a result, EM sensing can be used in well monitoring applications. EM logging tools can be configured for multiple concentric pipes (e.g., for one or more) with the first pipe diameter varying (e.g., from about two inches to about seven inches or more).

[009] EM profiling tools can measure currents of Eddy current (EM) profiling tools can use pulsed eddy current (time domain) and can employ multiple coils (long, short, and transverse) to evaluate multiple types of defects in multiple concentric tubes. It should be noted that techniques used in the time domain can be applied to frequency domain measurements. In the examples, EM profiling tools can operate in a transport medium. Furthermore, EM profiling tools can include an independent power supply and can store the acquired data in memory.

[0010] Monitoring the condition of production tubing and intermediate casing is crucial in oil and gas field operations. Eddy current (EC) techniques have been successfully used in the inspection of these components. EC techniques include two broad categories: frequency domain EC techniques and time domain EC techniques. In both techniques, one or more transmitters are excited with an excitation signal, and the signals from the tubing are received and recorded for interpretation. The magnitude of a received signal is typically inversely proportional to the amount of metal present at the location. Petition 870260009405, dated 01 / 30 / 2026, page 14 / 109 / 33 of inspection. For example, less signal magnitude is typically an indication of more metal and more signal magnitude is an indication of less metal. This relationship can allow measurements of metal loss, which is normally due to a pipe-related anomaly such as corrosion or buckling.

[0011] Figure 1 illustrates an operational environment for an EM 100 profiling tool, as disclosed in this document, according to some embodiments. The EM 100 profiling tool may comprise a transmitter 102 and / or a receiver 104. In the examples, the transmitters 102 and the receivers 104 may be coil antennas. Furthermore, the transmitter 102 and the receiver 104 may be separated by a space between about 0.1 inch (0.254 cm) and about 200 inches (508 cm). In examples, the EM 100 profiling tool may be an induction tool that can operate with continuous wave running of at least one frequency. This can be accomplished with any number of transmitters 102 and / or any number of receivers 104, which can be arranged in the EM 100 profiling tool. In further examples, the transmitter 102 may function and / or operate as a receiver 104 or vice versa.The EM 100 logging tool can be operatively coupled to a transport means 106 (e.g., steel cable, flat cable, spiral tubing, pipe, downhole tractor and / or the like) which can provide mechanical suspension as well as electrical connectivity for the EM 100 logging tool. The transport means 106 and the EM 100 logging tool can extend within the casing string 108 to a desired depth within the wellbore 110. The transport means 106, which may include one or more electrical conductors, can exit the wellhead 112, can pass around the pulley 114, can engage the odometer 116 and can be wound onto the winch 118, which can be employed to raise and lower the tool assembly in the wellbore 110. Petition 870260009405, dated 01 / 30 / 2026, page 15 / 109 / 33

[0012] The signals recorded by the EM 100 logging tool can be stored in memory and then processed by the display and storage unit 120 after retrieval of the EM 100 logging tool from the wellbore 110. Alternatively, the signals recorded by the EM 100 logging tool can be conveyed to the display and storage unit 120 via transport 106. The display and storage unit 120 can process the signals, and the information contained therein can be displayed for an operator to observe and stored for future processing and reference. It should be noted that an operator may include an individual, group of individuals, or organization, such as a service company. Alternatively, the signals can be processed at the bottom of the well before reception by the display and storage unit 120 or at the bottom of the well and at the surface 122, for example, by the display and storage unit 120.The display and storage unit 120 may also contain a device for providing control and power signals to the EM 100 profiling tool in the casing column 108.

[0013] A typical casing string 108 may extend from the wellhead 112 to or above ground level to a selected depth within a wellbore 110. The casing string 108 may comprise a plurality of joints 130 or casing string segments 108, each joint 130 being connected to adjacent segments by a collar 132. There may be any number of layers in the casing string 108. Such as a first casing 134 and a second casing 136. It should be noted that there may be any number of casing layers.

[0014] Figure 1 also illustrates a typical pipe string 138, which can be positioned within the casing string 108, extending part of the distance down the wellbore 110. The pipe string 138 can be production tubing, tubing string, or casing string. Petition 870260009405, dated 01 / 30 / 2026, p. 16 / 109 / 33 or other pipe arranged within the casing string 108. The pipe string 138 may comprise concentric pipes. It should be noted that the concentric pipes may be connected by collars 132. The EM logging tool 100 may be sized so that it can be lowered into the wellbore 110 through the pipe string 138, thus avoiding the difficulty and expense associated with pulling the pipe string 138 out of the wellbore 110.

[0015] The EM 100 profiling tool may include a digital telemetry system which may further include one or more electrical circuits, not illustrated, to supply power to the EM 100 profiling tool and to transfer data between the display and storage unit 120 and the EM 100 profiling tool. A DC voltage may be supplied to the EM 100 profiling tool by a power supply located above ground level, and the data may be coupled to the DC power conductor by a baseband current pulse system. Alternatively, the EM 100 profiling tool may be powered by batteries located within the EM 100 profiling tool and the data supplied by the EM 100 profiling tool may be stored within the EM 100 profiling tool instead of being transmitted to the surface to the display and storage unit 120 during profiling operations.The data may include signals and measurements related to corrosion detection.

[0016] During operations, transmitter 102 can transmit electromagnetic fields to the underground formation 142. It should be noted that the transmission of electromagnetic fields can also be referred to as electromagnetic field transmission. The electromagnetic fields transmitted from transmitter 102 can be referred to as a primary electromagnetic field. Primary electromagnetic fields can produce eddy currents in the casing string 108 and in the column of Petition 870260009405, dated 01 / 30 / 2026, page 17 / 109 8 / 33 tubes 138. These eddy currents, in turn, produce secondary electromagnetic fields that can be detected and / or measured by receivers 104. Characterization of the cladding string 108 and the tube string 138, including the determination of tube attributes, can be performed by measuring and processing primary and secondary electromagnetic fields. Tube attributes may include, but are not limited to, tube thickness, tube conductivity, and / or tube permeability.

[0017] As illustrated, the receivers 104 can be positioned in the EM 100 profiling tool at selected distances (e.g., axial spacing) away from the transmitters 102. The axial spacing of the receivers 104 from the transmitter 102 can vary, for example, from about 0 inches (0 cm) to about 40 inches (101.6 cm) or more. It should be understood that the configuration of the EM 100 profiling tool shown in FIG. 1 is merely illustrative and that other configurations of the EM 100 profiling tool can be used with current techniques. A spacing of 0 inches (0 cm) can be achieved by placing coils with different diameters. Although Figure 1 shows only a single array of receivers 104, there may be multiple sensor arrays where the distance between the transmitter 102 and the receivers 104 in each of the sensor arrays may vary.Furthermore, the EM 100 profiling tool can include more than one transmitter 102 and more or less than six receivers 104. Additionally, the transmitter 102 can be a coil implemented for magnetic field transmission while also measuring EM fields in some cases. When multiple transmitters 102 are used, their operation can be multiplexed or time-multiplexed. For example, a single transmitter 102 can transmit, for example, a multi-frequency signal or a broadband signal. Although not shown, the EM 100 profiling tool can include a transmitter 102 and receiver 104 that are in the form of coaxial coils or solenoids. Petition 870260009405, dated 01 / 30 / 2026, page 18 / 109 9 / 33 positioned within a downhole tubular (e.g., casing string 108) and separated along the tool axis. Alternatively, the EM 100 logging tool may include a transmitter 102 and receiver 104 which are in the form of coils or solenoids coaxially positioned within a downhole tubular (e.g., casing string 108) and placed along the tool axis.

[0018] The transmission of EM fields by the transmitter 102 and the detection and / or measurement of secondary electromagnetic fields by the receivers 104 can be controlled by the display and storage unit 120, which may include an information processing system 144. As illustrated, the information processing system 144 may be a component of, or be referred to as, the display and storage unit 120, or vice versa. Alternatively, the information processing system 144 may be a component of the EM recording tool 100. An information processing system 144 may include any instrumentation or aggregate of instrumentation operable to calculate, estimate, classify, process, transmit, disseminate, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, process or utilize any form of information, intelligence or data for commercial, scientific, control or other purposes.For example, an information processing system 144 can be a personal computer, a network storage device, or any other suitable device, and can vary in size, shape, performance, functionality, and price.

[0019] The information management system 144 may include a processing unit 146 (e.g., microprocessor, central processing unit, etc.) that can process EM profiling data by executing software or instructions obtained from a machine-readable medium. Petition 870260009405, dated 01 / 30 / 2026, page 19 / 109 10 / 33 non-transient local computer 148 (e.g., optical disks, magnetic disks). Non-transient computer-readable media 148 may store software or instructions for the methods described in this document. Non-transient computer-readable media 148 may include any instrumentation or aggregation of instrumentation that can retain data and / or instructions for a period of time.Non-transient computer-readable media 148 may include, for example, storage media such as a direct access storage device (e.g., a hard disk drive or floppy disk drive), a sequential access storage device (e.g., a tape disk drive), compact disc, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM) and / or flash memory; as well as communication media such as wires, optical fibers, microwaves, radio waves and other electromagnetic and / or optical carriers; and / or any combination thereof. The information management system 144 may also include input device(s) 150 (e.g., keyboard, mouse, touchpad, etc.) and output device(s) 152 (e.g., monitor, printer, etc.).Input device(s) 150 and output device(s) 152 provide a user interface that allows an operator to interact with the EM 100 profiling tool and / or software running on the processing unit 146. For example, the information handling system 144 may allow an operator to select analysis options, view collected profiling data, view analysis results, and / or perform other tasks.

[0020] The EM 100 profiling tool can use any suitable EM technique based on eddy currents (“EC”) for the inspection of concentric pipes (e.g., casing string 108 and pipe string 138). EC techniques may be particularly suitable for characterizing a multi-string arrangement where the pipes Petition 870260009405, dated 01 / 30 / 2026, page 20 / 109 / 33 concentrics are used. EC techniques may include, but are not limited to, frequency domain EC techniques and time domain EC techniques.

[0021] In frequency domain EC techniques, the transmitter 102 of the EM 100 profiling tool can be fed by a continuous sinusoidal signal, producing primary magnetic fields that illuminate the concentric tubes (e.g., casing string 108 and tube string 138). The primary electromagnetic fields produce eddy currents in the concentric tubes. These eddy currents, in turn, produce secondary electromagnetic fields that can be detected and / or measured with the primary electromagnetic fields by the receivers 104. Characterization of the concentric tubes can be performed by measuring and processing these electromagnetic fields.

[0022] In time-domain EC techniques, which may also be referred to as pulsed EC (“PEC”), the transmitter 102 may be powered by a pulse. Transient primary electromagnetic fields may be produced due to the pulse transition from the “off” state to the “on” state, or from the “on” state to the “off” state (more common). These transient electromagnetic fields produce EC in the concentric tubes (e.g., casing string 108 and tube string 138). The EC, in turn, produces secondary electromagnetic fields that can be detected and / or measured by receivers 104 placed at some distance on the EM profiling tool 100 from the transmitter 102, as shown in Figure 1. Alternatively, the secondary electromagnetic fields may be detected and / or measured by a colocalized receiver (not shown) or with the transmitter 102 itself.

[0023] It should be understood that, although casing string 108 is illustrated as a single casing string, there may be multiple layers of concentric tubing arranged in the wellbore section 110 with the Petition 870260009405, dated 01 / 30 / 2026, page 21 / 109 / 33 casing string 108. EM logging data can be obtained from two or more sections of the wellbore 110 with multiple layers of concentric tubing. For example, the EM logging tool 100 can make a first measurement of the tubing string 138 comprising any suitable number of joints 130 connected by collars 132. Measurements can be made in the time domain and / or frequency range. The EM logging tool 100 can make a second measurement on a casing string 108 of the first casing 134, wherein the first casing 134 comprises any suitable number of tubing connected by collars 132. Measurements can be made in the time domain and / or frequency domain. These measurements can be repeated any number of times for the first casing 134, for the second casing 136 and / or any additional layers of the casing string 108.In this disclosure, as further discussed below, the methods can be used to determine the location of any number of collars 132 in the casing string 108 and / or tube string 138. Determining the location of the collars 132 in the frequency domain and / or time domain can allow for precise processing of the recorded data in determining the properties of the casing string 108 and / or tube string 138, such as corrosion. As mentioned above, measurements can be made in the frequency domain and / or time domain.

[0024] In the EC frequency domain, the excitation frequency can be adjusted so that multiple reflections on the tube wall (e.g., cladding column 108 or tube column 138) are negligible, and the spacing between the transmitters 102 and / or the receiver 104 is large enough so that the contribution to the mutual impedance of the dominant (but evanescent) waveguide mode is small compared to the contribution to the mutual impedance of the cutoff component. Petition 870260009405, dated 01 / 30 / 2026, page 22 / 109 13 / 33 branching. In the examples, a remote field eddy current (RFEC) effect can be observed. In an RFEC regime, the mutual impedance between the transmitter coil 102 and the coil of one of the receivers 104 can be sensitive to the tube wall thickness. To be more specific, the phase of the impedance varies as: (1) and the magnitude of the impedance shows the dependence: (2) where m is the angular frequency of the excitation source, μ is the magnetic permeability of the tube, σ is the electrical conductivity of the tube and / is the thickness of the tube. Using the common definition of skin depth for metals as: (3)

[0025] The phase of the impedance varies as follows: (4) and the magnitude of the impedance shows the dependence: [v] (5)

[0026] In RFEC, the estimated quantity can be the total thickness of the metal. Thus, for multiple concentric tubes, the estimated parameter can be the total or the sum of the tube thicknesses. The quasi-linear variation of the mutual impedance phase with the total metal thickness can be employed to perform a quick estimate of the total thickness of multiple concentric tubes. To this end, for any given set of tube dimensions, material properties, and tool configuration, such a linear variation can be quickly constructed and used to estimate the total thickness of concentric tubes. The information processing system Petition 870260009405, dated 01 / 30 / 2026, p. 23 / 109 / 33 144 can allow an operator to select analysis options, view collected profile data, view analysis results, and / or perform other tasks.

[0027] Monitoring the condition of the pipe string 138 and the casing string 108 can be performed on the information processing system 144 in oil and gas field operations. The information processing system 144 can be used with Electromagnetic (EM) Eddy Current (EC) techniques to inspect the pipe string 138 and the casing string 108. The EM EC techniques can include frequency domain EC techniques and time domain EC techniques. In time domain and frequency domain techniques, one or more transmitters 102 can be excited with an excitation signal that transmits an electromagnetic field, and the receiver 104 can detect and / or measure the reflected excitation signal, a secondary electromagnetic field, for interpretation. The received signal is proportional to the amount of metal surrounding the transmitter 102 and the receiver 104.For example, a lower signal magnitude typically indicates more metal, and a higher signal magnitude indicates less metal. This relationship can be used to determine metal loss, which may be due to a pipe-related abnormality such as corrosion or buckling.

[0028] Figure 2 shows the EM 100 profiling tool arranged in the pipe string 138 which may be surrounded by a plurality of nested pipes (e.g., first casing 134 and second casing 136) and an illustration of anomalies 200 arranged within the plurality of nested pipes, according to some embodiments. As the EM 100 profiling tool moves through the pipe string 138 and the casing string 108, one or more transmitters 102 may be excited, and a signal (mutual impedance between transmitter 102 and receiver 104) in one or more receivers 104 may be recorded. Petition 870260009405, dated 01 / 30 / 2026, p. 24 / 109 / 33

[0029] Due to the physics of eddy currents and electromagnetic attenuation, the 138 tubing column and / or the 108 casing column may generate an electrical signal that is in the opposite polarity to the incident signal and results in a reduction in the received signal. Typically, more metal volume translates to more signal loss. As a result, when inspecting signal gains, it is possible to identify zones with metal loss (such as corrosion). In order to distinguish signals originating from anomalies in different tubes of a nested multi-tube configuration, multiple transmitter-receiver spacings and frequencies may be used. For example, smaller-spacing 102 transmitters and 104 receivers may be sensitive to the first casing 134, while larger-spacing 102 transmitters and 104 receivers may be sensitive to the second casing 136 and / or deeper tubes (3rd, 4th, etc.).By analyzing signal levels in these different channels using inversion methods, it is possible to relate a certain received signal to a certain metal loss or gain in each tube. Besides metal loss, other tube properties, such as magnetic permeability and conductivity, can also be estimated by inversion methods. It should be noted that inversion methods may include model-based inversion, which may include direct modeling. However, there may be factors that complicate the interpretation of losses. For example, signals from deep tubes may be significantly lower than other signals. Double dip indications appear for 102 transmitters and 104 receivers with large spacing. The spatial spread of transmitter-receiver signals with large spacing for a 132 collar can be long (up to 6 feet (1.8 meters)). Due to these complications, methods may need to be used to precisely inspect tube features.

[0030] Figures 3A-3E illustrate an electromagnetic inspection and detection of anomalies 200 (e.g., defects) or collars 132 (e.g. Petition 870260009405, dated 01 / 30 / 2026, page 25 / 109 / 33 example, referring to Figure 2), according to some embodiments. As illustrated, the EM 100 profiling tool can be arranged in the tube column 138, by a means of transport, which can comprise any number of concentric tubes. As the EM 100 profiling tool passes through the tube 300, one or more transmitters 102 can be excited and a signal (mutual impedance between the transmitter 102 and the receiver 104) in one or more receivers 104 can be registered. Due to eddy currents and electromagnetic attenuation, the tube 300 can generate an electrical signal that is in the opposite polarity to the incident signal and results in a reduction in the received signal. Thus, more metal volume translates into greater signal loss. As a result, by inspecting the signal gains, it may be possible to identify areas with metal loss (such as corrosion).Similarly, when inspecting signal loss, it may be possible to identify metal gain, such as due to the presence of a sheath collar 132 (e.g., referring to Figure 1) where two tubes meet with a threaded connection. In order to distinguish signals from different tubes in a multi-concentric tube configuration, multiple transmitter-receiver spacings and frequencies can be used. For example, transmitters 102 and receivers 104 with little spacing may be sensitive to the tube column 138, while transmitters 102 and receivers 104 with large spacing may be sensitive to deeper tubes (e.g., first sheath 124, second sheath 136, etc.). By analyzing the signal levels in these different channels through an inversion process, it may be possible to relate a certain set of received signals with a certain set of metal loss or gain in each tube.In the examples, there may be factors that complicate the interpretation and / or identification of collars 132 and / or anomalies 200 (for example, defects).

[0031] For example, due to the physics of eddy currents and electromagnetic attenuation, the tubes arranged in the tube column 138 (by Petition 870260009405, dated 01 / 30 / 2026, p. 26 / 109 / 33 example, referring to Figure 1 and Figure 2) can generate an electrical signal that may be in the opposite polarity to the incident signal and results in a reduction in the received signal. Generally, as the volume of metal increases, signal loss may increase. As a result, when inspecting signal gains, it may be possible to identify zones with metal loss (such as corrosion). In order to distinguish signals originating from anomalies (e.g., defects) in different tubes of a nested multi-tube configuration, multiple transmitter-receiver spacings and frequencies can be used. For example, transmitters 102 and receivers 104 with small spacing may be sensitive to the first column of tubes 138 (e.g., referring to Figure 2), while transmitters 102 and receivers 104 with large spacing may be sensitive to deeper tubes (2nd, 3rd, etc.).) (for example, first coating 134 and second coating 136).

[0032] By analyzing the signal levels in different channels with an inversion scheme, it may be possible to relate a certain received signal to a certain metal loss or gain in each tube. In addition to metal loss, other tube properties, such as magnetic permeability and electrical conductivity, can also be estimated by inversion.There may be several factors that complicate the interpretation of losses: (1) deep tube signals may be significantly lower than other signals; (2) double dip indications appear for 102 transmitters and 104 receivers with large spacing; (3) the spatial propagation of the transmitter-receiver signal with large spacing for a 132 collar may be long (up to 6 feet); (4) to accurately estimate the thickness of the individual tube, the material properties of the tubes (such as magnetic permeability and electrical conductivity) may need to be known with fair precision; (5) inversion may be a non-unique process, meaning that several solutions to the same problem may be obtained. Petition 870260009405, dated 01 / 30 / 2026, p. 27 / 109 / 33 a solution that may be more physically reasonable may be chosen. Due to these complications, an advanced algorithm or workflow may be used to accurately inspect the tube characteristics, for example, when more than two tubes may be present in the tube column 138.

[0033] During logging operations, as the EM logging tool 100 traverses tube 300 (e.g., referring to Figure 3), an EM profile of the received signals can be produced and analyzed. The EM profile can be calibrated before performing the inversion to account for deviations between measurement and simulation (direct model). Deviations can arise from various factors, including nonlinear behavior of the magnetic core, tube magnetization, mandrel effect, and inaccurate well planes. Multiplicative coefficients and constant factors can be applied, either together or individually, to the measured EM profile for this calibration.

[0034] Figure 4 illustrates an example of a 400 well plan according to some embodiments. Depending on the 400 well plan design, the well construction may have between two and four main components. These components include conductor, surface, intermediate, and production casings. After well completion, a pipeline may be inserted to pump hydrocarbon products. In this example, the 400 well plan may comprise a 138 pipe string, first casing 134, second casing 136, a conductor casing 402, and wherein cement may be disposed in the annular space 404 between each casing. However, it should be noted that the 400 well plan may include any number of pipes, casings, tubulars, and / or the like. The 400 well plan is not limited or delimited by the four pipes shown in Figure 4. When the EM 100 logging tool is used to monitor pipe condition, a logging can be produced. Petition 870260009405, dated 01 / 30 / 2026, p. 28 / 109 / 33

[0035] Monitoring the condition of casing strings is crucial in oil and gas field operations. As discussed above, EM techniques can be used to inspect pipes, casings, tubulars, and / or similar structures. To obtain a stronger response from the outer pipes of a nested tubular structure, typically, a larger transmitter coil is employed in conjunction with larger receiver coils that are placed at greater distances from the transmitter with low-frequency excitation. However, such measurements degrade the vertical resolution (along the depth) in the thickness estimation results, and since unidirectional coils are used, the measurements made by such tools have no directional sensitivity. On the other hand, there are some corrosion tools used in casing inspection that have very high resolution and circumferential information.These high-resolution tools can be flow leak tools, ultrasonic tools, mechanical calipers, and others that typically analyze an immediate pipe only in each logging operation.

[0036] Methods are disclosed below for combining an electromagnetic profiling from the EM 100 profiling tool and measurements from a high-resolution tool (not shown) to provide a map of possible corrosion within pipes, casings, tubulars and / or the like. A corrosion map can be created through a mapping process to relate an EM profiling, formed using an EM 100 profiling tool, with high-resolution measurements. High-resolution measurements are defined as measurements with directional sensitivity of a few degrees or less circumferentially, less than one foot (0.3 meters) from a receiver 104 (e.g., referring to Figure 1) and along the axis of the EM 100 profiling tool.

[0037] Figure 5 illustrates a workflow 500 for identifying corrosion in one or more tubulars in wellbore 110 (e.g., Petition 870260009405, dated 01 / 30 / 2026, page 29 / 109 / 33 (referring to Figure 1). As illustrated in Figure 5, corrosion identification can be divided into two distinct operations, a database operation 502 and a comparison operation 504. The use of database operation 502 and comparison operation 504 allows for the identification of corrosion in tubulars in well plan 400 (e.g., referring to Figure 4). Database formation in operation 502 can begin with block 506. In block 506, the known nominal outside diameter and thickness of the individual tube can be determined from the manufacturing specification. This information can also come from previous well correction profiles, measurements, and recordings of previous well plans.Well plans may include information such as nominal outside diameter and thickness, on the pipe string 138, first casing 134, second casing 136, a conductor casing 402, and where the cement may be disposed in the annular space 404 between each casing (e.g., referring to Figure 4).

[0038] Block 506 information can be fed into Block 508. In Block 508, characterization of all tubulars within a specified wellbore can be performed. Characterization of all tubulars in Block 508 may also require high-resolution measurements of each tubular with a high-resolution tool. In Block 510, a high-resolution tool (discussed further below) can be run on tubing string 138, first casing 134, second casing 136, or conductor casing 402.

[0039] Figures 6A-6C illustrate a method for the 600 high-resolution tool to measure each tubular. As illustrated, a high-resolution profile is created for each tubular that the 600 high-resolution tool contacts. A high-resolution profile is created for vertical directions of 1 foot (0.3 meters) or less. The high-resolution profile includes azimuthal information at each measurement depth. Thus, the profile of Petition 870260009405, dated 01 / 30 / 2026, page 30 / 109 / 33 High resolution includes different angle measurements that identify different thickness values ​​in each tubular. For better resolution, the high-resolution tool 600 can be in immediate contact with a tubular; therefore, the inner tubular needs to be pulled out after performing a measurement on the inner tubular to measure the next outer tubular. For example, in Figure 6A, the high-resolution tool 600 is in contact with the tube column 138, in which a high-resolution profile is formed from measurements taken from the tube column 138. In Figure 6B, the tube column 138 is removed, and the high-resolution tool 600 performs a high-resolution measurement on the first casing 134 to create a high-resolution profile of the first casing 134.In Figure 6C, the process is repeated, the first coating 134 is removed, and the high-resolution tool 600 performs a high-resolution measurement on the second coating 136 to create a high-resolution profile of the second coating 136. If a particular pipe is inaccessible, the nominal information of the pipe from block 506 (e.g., referring to Figure 5) can be used.

[0040] The high-resolution 600 tool can characterize all pipe information, including internal diameter and thickness. As discussed above, the high-resolution 600 tool can only measure the first pipe that is immediately adjacent to the high-resolution 600 tool. Therefore, in order to measure external pipes in the presence of internal pipe, the internal pipes need to be pulled out of wellbore 110 (e.g., referring to Figure 1). However, block 506 information (e.g., referring to Figure 5) can be used if certain pipes cannot be measured or analyzed by high-resolution 600 tools. Thus, each pipe can have its own profile stored in a database with all measurements taken by the high-resolution 600 tool in block 510 (e.g., referring to Figure 5).

[0041] Referring again to Figure 5, in block 512, a Petition 870260009405, dated 01 / 30 / 2026, page 31 / 109 / 33. The EM 100 logging tool (e.g., referring to Figure 1) is run in wellbore 110 (e.g., referring to Figure 1). During this operation, the EM 100 logging tool is run without removing any casing or tubing to obtain multi-frequency and multi-spacing profiles. As discussed above, the EM 100 logging tool may include one or more electromagnetic transmitters 102 (e.g., referring to Figure 1) and one or more electromagnetic receivers 104 (e.g., referring to Figure 1). This may allow the EM 100 logging tool to acquire measurements in frequency or time domains. As discussed above, eddy current techniques allow multiple pipe characterizations during a single operation.

[0042] In block 514, multiple frequency and multiple spacing configurations are created to form an EM profile. For example, different penetration depths and vertical resolutions are achieved by means of a transmitter 102 (e.g., referring to Figure 1) and multiple receivers 104 (e.g., referring to Figure 1) placed at various distances from the transmitter 102. In the examples, the receivers 104 can be placed at a shorter distance from the transmitter 102, which can allow the EM profiling tool 100 to measure internal pipe responses with enhanced vertical resolution. The enhanced vertical resolution can increase within 1 foot (0.3 meters) of the receivers 104. Furthermore, the azimuthal resolution can be enhanced at any angle with the receivers 104. This increase in vertical resolution within 1 foot (0.3 meters) is not found in current technology.Receivers 104, which can be placed at greater distances from transmitter 102, can measure the responses of all tubes, but have a degradation of vertical resolution. Thus, an electromagnetic profile formed from a profiling operation can be processed to invert all coating information with one. Petition 870260009405, dated 01 / 30 / 2026, page 32 / 109 / 33 race. The information from blocks 508 and 514 may be further processed in block 516.

[0043] In block 516, key data points that include distinct characteristics are extracted from the information provided in blocks 508 and 514. Distinct characteristics are defined as one or more pipe properties. For example, different pipe properties may be specific to individual pipes in well plane 400 (e.g., referring to Figure 4). This can be seen in that different pipes may induce different electromagnetic responses. Thus, once the electromagnetic response is given, pipe information can be inferred by inversion techniques based on optimization. However, the results are generally biased, as the measurements may be given with predetermined averages or one-way data.To increase the resolution of the EM 100 profiling tool (e.g., referring to Figure 1), the high-resolution profile from block 508 can be integrated with data from block 514, which may include a wide range of pipe thickness information to achieve accurate pipe information prediction. The block 514 data includes known pipe information and corresponding electromagnetic response. Thus, data points with different characteristics (such as different thicknesses due to manufacturing tolerances, defects, collars, perforations, and changes in the number of pipes) can be extracted and stored in a database. The stored data points, for example, as shown in Figure 2, may include the location of a collar 132. A collar 132 is a threaded coupling used to join two pipe lengths, which can increase the pipe thickness where the collar 132 is located.Anomalies 200 (for example, referring to Figure 2), whether a data point that is referred to as a penetration, could be a corroded or perforated pipe section that is thinner than standard pipes. Other data points can be found from calculations. For example, in the calculations... Petition 870260009405, dated 01 / 30 / 2026, page 33 / 109 / 33 if the number of tubulars changes during measurements, this can be considered a complete loss of metal. Other data points may be information such as universally agreed standards. For example, the American Petroleum Institute (API) allows a 12% thickness variation between joints. Using this database formed from blocks 510 and 508 and the EM profile formed from blocks 512 and 514, a correlation between the EM profile and the database can be found and identified. To form the correlation, or relationship, key data and distinct characteristics are identified between the database and the EM profile, which is discussed above for block 516.

[0044] Once the database is built in operation 502, comparison operations 504 can be performed. Comparison operations 504 can begin by performing a logging operation in block 520. In block 520, a relationship can be established to relate tubular information (m1) from the well log (di, ti) created in block 512 in database operation 502. The relationship is found by defining the geometric shape or size of the defect and translating the unidirectional measurement of the well log into metal loss in the corrosion area instead of a unidirectional metal loss approach. This relationship can enable corrosion mapping. In the examples, methods can be employed to construct a mapping function for block 522.For example, the mapping function for unidirectional measurements can operate by taking the average metal loss that is measured, having a definition of the area of ​​metal loss involved; the metal loss can be transposed from a broader average estimate to a representative metal loss for the defined area. In some modalities, the relationship and an EM profile can be used to obtain a high-resolution metal loss profile. This is possible because the metal loss is calculated as an average, and the final output will lose directionality. Furthermore, the gross metal loss of... Petition 870260009405, dated 01 / 30 / 2026, page 34 / 109 / 33: The high-resolution profile includes metal loss directionality in the input data. Therefore, the output will still have directionality when used with the EM profile.

[0045] In examples to determine a relationship, a deep neural network (DNN) 700, as illustrated in Figure 7, can be used to connect tube information with high-resolution profile data and EM profile data. A DNN 700 is an artificial neural network with one or more hidden layers 702 between the input layer 704 and the output layer 706. As illustrated, the input layer 704 can include all electromagnetic responses extracted from the EM profiling tool 100 (e.g., referring to Figure 1) and the output layers 706 can include tube information from other sources, such as the operation 502. During operations, input data is taken by neurons 712 in the first layer, which then provide an output to neurons 712 within the next layer and so on, which provides a final output in the output layer 706. Each layer can have one or more neurons 712.The connection between two 712 neurons in successive layers can have an associated weight. The weight defines the influence of the input on the output for the next 712 neuron and, eventually, for the overall final output. The DNN training process is to find the appropriate weights that help in correctly predicting the tube thickness.

[0046] Since the relationship between electromagnetic responses and high-resolution pipe information is established by DNN 700, high-resolution pipe thickness prediction is obtainable at any future time when only electromagnetic measurement is made to further investigate the pipe condition. In block 516, the mapping function established in block 614 can be used by DNN 700 with EM profiles to determine the thickness, and therefore the corrosion, of tubulars with high resolution. This can enable corrosion operations where the EM 100 profiling tool Petition 870260009405, dated 01 / 30 / 2026, p. 35 / 109 / 33, can be run in a short time span (e.g., 1-2 years), and high-resolution 600 tools (e.g., referring to Figure 6) can be run in long time spans (e.g., 3-4 years). Since running a high-resolution 600 tool generally requires the removal of tubulars, as discussed above, the cost of the operation increases along with the risk of well damage (e.g., referring to Figure 1). Running high-resolution 600 tools in longer time spans can reduce the cost and provide high-resolution tubular information. However, using the methods described above, electromagnetic measurements made by the EM 100 logging tool may be able to predict tubular information, such as thickness, with better resolution.When the high-resolution tool 600 is run to perform a complete examination, the data can be added to the database established in database operations 502 (e.g., referring to Figure 5) to refine the mapping function for better future prediction. Applying regular inspections can provide a time-lapse profile of thickness variation for each tubular. This can provide information on areas vulnerable to defects, and tubulars can be replaced or treated before any major problems occur in wellbore 110.

[0047] Figures 8A and 8B illustrate a simple graph of how thickness variation over time can provide information on susceptible areas in a wellbore 110 (e.g., referring to Figure 1). Figure 8A illustrates electromagnetic measurements from the EM logging tool 100 (e.g., referring to Figure 1) forming a wellbore profile during a corrosion measurement operation over four distinct time periods. As illustrated in Figure 8A, anomalies 200 (defect 1 and defect 2) can be detected based on the amount of corrosion each anomaly 200 may contain. However, it can be difficult to identify the shape of Petition 870260009405, dated 01 / 30 / 2026, p. 36 / 109 / 33 each anomaly 200 only in EM measurements. Figure 8B uses workflow 500 (e.g., referring to Figure 5), described above, to combine an electromagnetic profile and a high-resolution profile in a database to improve the resolution of a well log. Workflow 500 sharpens the edges of defects 1 and 2. This is further illustrated in small defect 2, where detecting small defect 2 at an early stage of the tubular life can prevent worsening. This type of information is critical for deciding when to apply treatment to tubulars or replace them.

[0048] Once a mapping function has been established, workflow 900 can be implemented as seen in Figure 9 to predict corrosion in a tubular. Workflow 900 starts with block 902. In block 902, the EM logging tool 100 (e.g., referring to Figure 1) is run on wellbore 110 (e.g., referring to Figure 1) and mirrors the operations in block 512 (e.g., referring to Figure 5), discussed above. From block 902, the information is used in block 904 to form a multi-frequency, multi-spacing EM profile, which mirrors the operations discussed above in block 514 (e.g., referring to Figure 5). The information in block 904 is fed to block 906. Additionally, a mapping function M(mi; di, ti) from block 908 is an input in block 906.

[0049] In block 906, the EM profile from block 904 and the mapping function from block 908 are used to estimate the pipe thickness by mapping m2 using M(mi; di, ti). This mapping function from block 908 originates from workflow 500 (e.g., referring to Figure 5), specifically mirroring the operations in block 520 (e.g., referring to Figure 5). After estimating the pipe thickness by mapping in block 906, high-resolution pipe information is estimated in block 910. The high-resolution pipe information can take the form of a Petition 870260009405, dated 01 / 30 / 2026, p. 37 / 109 / 33 high-resolution image or information. The prediction in block 910 can be summarized as follows: the high-resolution characterization of all tubes is characterized as t1= (di, ti)1 and the EM measurements are characterized as t1=m1 and t2=m2. This may allow the prediction of a high-resolution thickness of the tubulars to be characterized as t2= (di, ti)2.

[0050] The following is an example of how workflows 500 and 900 can be used to improve the results of electromagnetic measurements and high-resolution profiling. In this example, there are three tubulars, whose outside diameters are 4.5, 7, and 9.625 inches. Their tubular thicknesses are 0.25, 0.317, and 0.395 inches. There is a 4.3-foot-long defect in the second tubular. When the EM profile was obtained at time t1, as shown in Figure 10A, the tubular thickness in the defective area was 0.226 inches (29% metal loss) with an azimuthal angle of 60 degrees. When the EM profile was obtained at time t2, as shown in Figure 10B, the tubular thickness in the defective area was 0.189 inches (40% metal loss) with an azimuthal angle of 120 degrees. Figures 11A and 11B show the inverted tube thickness of the EM profiles only for these two data sets from Figures 10A and 10B, respectively.Due to the vertical resolution limitations of the tool, the edges of the defect were not accurately reconstructed. Furthermore, since the EM 100 profiling tool is unidirectional, the amount of metal loss estimated by the EM 100 profiling tool (e.g., referring to Figure 1) underestimates the true metal loss. Once the high-resolution profile, shown in Figures 12A and 12B, from the database formed in workflow 500 is added, the resolution of the inverted tube thickness is improved. The edges of a corrosion area are highlighted as shown in Figures 13A and 13B. This can allow for predicting the azimuthal distribution of the defect.

[0051] Improvements to the methods and systems described above include Petition 870260009405, dated 01 / 30 / 2026, page 38 / 109 / 33: Use of high-resolution profile to refine the electromagnetic profile and recreate a more detailed map of one or more pipes in a wellbore. This map can be used at any time to provide an accurate prediction of pipe condition by running only the electromagnetic tool and comparing the electromagnetic tool measurements with the map. Thus, this improves vertical resolution within the one-foot level and allows the electromagnetic tool to improve azimuthal resolution.

[0052] This method and system for determining corrosion along a tubular in a wellbore may include any of the various composition, method, and system features disclosed in this document, including one or more of the following statements.

[0053] Statement 1: A method for estimating a pipe property for a plurality of nested pipes may comprise disposing of an electromagnetic (EM) logging tool in a wellbore. The EM logging tool may comprise a transmitter disposed on the EM logging tool and a receiver disposed on the EM logging tool. The method may further comprise transmitting an electromagnetic field from the transmitter to one or more pipes to energize the one or more pipes with the electromagnetic field, thereby producing an eddy current emanating from one or more pipes.Furthermore, the method may include measuring the eddy current in the pipe string with the receiver in at least one channel to obtain a plurality of measurements, forming an EM profile from the plurality of measurements, forming a relationship between the EM profile and a database, where the database is formed from one or more high-resolution measurements, and producing a mapping function between the EM profile and the database.

[0054] Statement 2. The method of statement 1, wherein one or more high-resolution measurements are taken for each of the one or more tubulars.

[0055] Statement 3. The method of statement 2, in which one or Petition 870260009405, dated 01 / 30 / 2026, p. 39 / 109 / 33 more high-resolution measurements characterize each of the one or more tubulars.

[0056] Statement 4. The method of statement 3, combining known external dimensions and nominal tube thickness with one or more high-resolution measurements.

[0057] Statement 5. The method of statements 1 or 2, in which the relationship between the EM profile data and the database is formed using a deep neural network (DNN).

[0058] Statement 6. The method of statement 5, in which the DNN forms the mapping function from the relationship between the EM profile data and the database.

[0059] Statement 7. The method of statements 1, 2 or 5, further comprising identifying corrosion in one or more pipes using the mapping function.

[0060] Statement 8. The method of statement 7, further comprising removing or repairing one or more pipes that have corrosion.

[0061] Statement 9. The method of statements 1, 2, 5 or 7, further comprising identifying the thickness of one or more tubulars using the mapping function.

[0062] Declaration 10. The method of declaration 9, further comprising removing or repairing one or more tubes that have corrosion identified by the thickness of one or more tubes.

[0063] Statement 11. A method for estimating a pipe property for a plurality of nested pipes may comprise arranging an electromagnetic (EM) logging tool in a wellbore. The EM logging tool may comprise a transmitter arranged in the EM logging tool and a receiver arranged in the EM logging tool. The method may further comprise transmitting an electromagnetic field from the transmitter to one or more pipes to energize the Petition 870260009405, dated 01 / 30 / 2026, p. 40 / 109 / 33 one or more tubes with the electromagnetic field, thus producing an eddy current emanating from one or more tubes. In addition, the method may include measuring the eddy current in one or more tubes with the receiver on at least one channel to obtain a plurality of measurements, inserting the plurality of measurements through a mapping function and estimating high-resolution measurements for one or more tubes.

[0064] Statement 12. The method of statement 11, further comprising making one or more high-resolution measurements with a high-resolution tool.

[0065] Statement 13. The method of statement 12, in which one or more high-resolution measurements characterize each of the one or more tubulars.

[0066] Statement 14. The method of statement 13, further comprising combining known external dimensions and nominal tube thickness with one or more high-resolution measurements.

[0067] Statement 15. The method of statement 13, wherein the high-resolution tool is a flow leakage tool, an ultrasonic tool, or a mechanical caliper tool.

[0068] Statement 16. The method of statement 13, further comprising the creation of an enhanced resolution corrosion map which includes one or more tubular properties using the mapping function, wherein the one or more tubular properties include a thickness.

[0069] Statement 17. The method of statement 16, further comprising identifying corrosion in one or more pipes using the higher resolution corrosion map.

[0070] Statement 18. The method of statement 16, further comprising the prediction of an azimuthal distribution of an anomaly using the higher resolution corrosion map.

[0071] Statement 19. The method of statement 11 or 12, Petition 870260009405, dated 01 / 30 / 2026, page 41 / 109 / 33, also including identifying the thickness of one or more tubulars using the mapping function and removing or repairing one or more tubulars that have corrosion identified by the thickness of one or more tubulars.

[0072] Statement 20. The method of statement 11, 12 or 19, further comprising predicting the thickness of one or more tubulars using a second set of one or more electromagnetic measurements from the EM profiling tool.

[0073] The preceding description provides several examples of the systems and methods of use disclosed in this document, which may contain different method steps and alternative combinations of components. It should be understood that, although individual examples may be discussed in this document, the present disclosure covers all combinations of the disclosed examples, including, without limitation, different combinations of components, combinations of method steps, and system properties. It should be understood that compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps; compositions and methods may also “essentially consist of” or “consist of” various components and steps. Furthermore, the indefinite articles “a” or “an,” as used in the claims, are defined in this document to mean one or more than one of the element they introduce.

[0074] For the sake of brevity, only certain ranges are explicitly disclosed in this document. However, ranges at any lower limit may be combined with any upper limit to cite a range not explicitly cited, just as ranges at any lower limit may be combined with any other lower limit to cite a range not explicitly cited; similarly, ranges at any upper limit may be combined with any other upper limit to cite a range not explicitly cited. Additionally, whenever Petition 870260009405, dated 01 / 30 / 2026, p. 42 / 109 / 33, a numerical range with a lower limit and an upper limit is disclosed; any number and any range included falling within the range are specifically disclosed. In particular, every range of values ​​(of the form, “from approximately aa to approximately b”, or, equivalently, “from approximately aab”, or, equivalently, “from approximately ab”) described in this document shall be understood to represent each number and range encompassed within the broader range of values, even if not explicitly cited. Thus, each individual point or value may serve as its own lower or upper limit combined with any other individual point or value or any other lower or upper limit, to cite a range not explicitly cited.

[0075] Therefore, the present examples are well adapted to achieve the aforementioned purposes and advantages, as well as those inherent therein. The particular examples disclosed above are merely illustrative and may be modified and practiced in different but equivalent ways, evident to those skilled in the art, having the benefit of the teachings of the present document. Although individual examples are discussed, the disclosure covers all combinations of all examples. Furthermore, no limitation is intended for the details of construction or design shown in this document, except as described in the following claims. Also, the terms in the claims have their simple common meaning unless explicitly and clearly defined otherwise by the patent holder.Therefore, it is evident that the particular illustrative examples disclosed above may be altered or modified, and all such variations are considered within the scope and spirit of those examples. If there is any conflict in the uses of a word or term in this descriptive report and one or more patent(s) or other documents that may be incorporated herein by reference, the definitions that are consistent with this descriptive report shall prevail. Petition 870260009405, dated 01 / 30 / 2026, page 43 / 109

Claims

1 / 4 CLAIMS 1. Method for estimating a pipe property for a plurality of nested pipes, characterized in that it comprises: arranging an electromagnetic (EM) logging tool (100) in a wellbore (110), wherein the EM logging tool (100) comprises: a transmitter (102) disposed in the EM logging tool (100); and a receiver (104) disposed in the EM logging tool (100); transmitting an electromagnetic field from the transmitter (102) to one or more pipes to energize one or more pipes with the electromagnetic field, thereby producing an eddy current emanating from one or more pipes; measuring the eddy current in the pipe string (138) with the receiver (104) in at least one channel to obtain a plurality of measurements; forming a first EM profile from the plurality of measurements;To establish a relationship between the first EM profile and a database, where the database is formed from one or more high-resolution measurements; to produce a mapping function between the first EM profile and the database; and to apply the mapping function to a second EM profile to improve the azimuthal resolution of the second EM profile.

2. Method according to claim 1, characterized in that one or more high-resolution measurements are taken for each of the Petition 870260009405, dated 01 / 30 / 2026, page 44 / 109 2 / 4 one or more tubular.

3. Method according to claim 2, characterized in that one or more high-resolution measurements characterize each of the one or more tubulars.

4. Method according to claim 3, characterized in that it combines known nominal external dimensions and tube thickness with one or more high-resolution measurements.

5. Method according to claim 1, characterized in that the relationship between the first EM profile data and the database is formed using a deep neural network (DNN), wherein the DNN forms the mapping function from the relationship between the first EM profile data and the database.

6. Method according to claim 1, characterized in that it further comprises identifying corrosion in one or more pipes using the mapping function and removing or repairing one or more pipes that have the corrosion.

7. Method according to claim 1, characterized in that it further comprises identifying the thickness of one or more tubulars using the mapping function and removing or repairing one or more tubulars that have corrosion identified by the thickness of one or more tubulars.

8. Method for estimating a pipe property for a plurality of nested pipes, characterized in that it comprises: disposing of an electromagnetic (EM) logging tool (100) in a wellbore (110), wherein the EM logging tool (100) comprises: a transmitter (102) disposed in the EM logging tool (100); and Petition 870260009405, dated 01 / 30 / 2026, p.45 / 109 3 / 4 a receiver (104) disposed in the EM profiling tool (100); transmit an electromagnetic field from the transmitter (102) to one or more tubes to energize one or more tubes with the electromagnetic field, thus producing an eddy current emanating from one or more tubes; measure the eddy current in one or more tubes with the receiver (104) in at least one channel to obtain a first plurality of measurements; input the first plurality of measurements via a mapping function; estimate high-resolution measurements for the one or more tubes; and apply the mapping function and high-resolution measurements to a second plurality of measurements to improve the azimuthal resolution of the second plurality of measurements.

9. Method according to claim 8, characterized in that it further comprises taking one or more high-resolution measurements with a high-resolution tool.

10. Method according to claim 9, characterized in that one or more high-resolution measurements characterize each of the one or more tubulars.

11. Method according to claim 11, characterized in that it further comprises combining known external dimensions and nominal tube thickness with one or more high-resolution measurements.

12. Method according to claim 11, characterized in that the high-resolution tool is a flow leakage tool, an ultrasonic tool, or a mechanical caliper tool. Petition 870260009405, dated 01 / 30 / 2026, page 46 / 109 4 / 4 13. Method according to claim 11, characterized in that it further comprises creating a resolution-enhanced corrosion map that includes one or more tubular properties using the mapping function, wherein one or more tubular properties include a thickness, identifying corrosion in one or more tubulars using the resolution-enhanced corrosion map and, optionally, predicting an azimuthal distribution of an anomaly using the resolution-enhanced corrosion map.

14. Method according to claim 8, characterized in that it further comprises identifying the thickness of one or more tubes using the mapping function and removing or repairing one or more tubes that have corrosion identified by the thickness of one or more tubes.

15. Method according to claim 8, characterized in that it further comprises predicting a thickness of one or more tubulars using a second set of one or more electromagnetic measurements of the EM profiling tool (100). Application 870260009405, dated 01 / 30 / 2026, p. 47 / 109

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