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    • 专利摘要:
    An apparatus, method, and system for determining the slowness of volume waves from borehole guided waves. The method includes selecting a target axial resolution based on the size of a receiver array, obtaining a plurality of waveform data sets corresponding to a target training area and acquired each at a different firing position, computing a slow-frequency 2D dispersion similarity map for each waveform data set, stacking 2D slow-frequency dispersion similarity maps to generate a 2D stacked similarity map, and determination of a volume slowness from the extracted dispersion curve. The method may also include generating a self-adaptive weighting function based on a dispersion model and the extracted dispersion curve, adjusting the weighted dispersion curve and the dispersion model to determine a slow wave of volume that minimizes the poor fit between the weighted dispersion curve and the dispersion model. The method can also be applied to processing in the frequency domain and in the time domain.
    公开号:FR3057978A1
    申请号:FR1758390
    申请日:2017-09-12
    公开日:2018-04-27
    发明作者:Ruijia Wang；Chung Chang
    申请人:Halliburton Energy Services Inc；
    IPC主号:
    专利说明:

    FIELD OF THE INVENTION The present disclosure relates to improved methods of acoustic logging in underground boreholes. In particular, the present disclosure relates to devices, methods and systems for improving the resolution of a slowness using guided borehole waves.
    BACKGROUND Wells are drilled in the earth for various reasons, in particular to exploit formations containing hydrocarbons in order to extract the hydrocarbons for use, inter alia, as fuel, as lubricants and in the production of products chemicals. In order to facilitate the processes and operations in the wellbore, various tools can be routed downhole. For example, acoustic logging tools can be lowered into the wellbore to facilitate petrophysical interpretation and petroleum engineering analysis. Acoustic logging provides various properties related to the rock formation and the borehole fluid, including, for example, the slow compression and shear waves of the formation, the permeability of the formation, the anisotropy of the slow shear formation and slowness of mud from the borehole. Among these properties, the slowness of the compression and shear waves is one of the most important because it provides the fundamental dynamic elastic properties of the formation.
    The slowness of volume waves of rock formations, for example, the slowness of compression and shear waves, provides useful information for mechanical characterization, lithological interpretation and analysis of the physics of rocks properties. underground rocks and, therefore, have become essential measures in the oil and gas industry during wireline logging (WL) and drilling in progress logging (LWD). In general, dipole sources are generally used for the estimation of the shear slowness during a wireline log, because the asymptotes of the slowness of the low-frequency dipole bending waves are close to the slowness of the waves. volume shear of different formations. However, low frequency bending signals are generally associated with low signal to noise ratios (SNR) due to their poor amplitude of excitation at low frequencies. To overcome insufficient SNR, modern acoustic logging tools are designed to increase SNR at low frequencies through the use of a larger network of receivers. Processing with a wide coverage network is very effective in improving the quality of slow speed collection at low frequencies, however such a wide coverage receiver network can compromise the spatial resolution of slow shear logs. This is verified in particular for the stratified formations containing thin layers or the very heterogeneous formations, in which case the processing of the data using the whole network gives an average shear slowness of several layers, which makes certain thin layers not identifiable in because of the low spatial resolution. Consequently, average slowness logs move away from an accurate characterization of the shear slowness of thin layers and may not be useful for identifying thin layers or likely to be subjected to an advanced analysis of rock physics. .
    [0004] The evaluation of the slowness of the compression waves from the leakage P waves in the flexible formations presents similar problems. In flexible formations, the slowness of the leakage P waves approaches the slowness of the compression waves of the formations at low frequencies, where the SNR of the data is not good for their low excitation frequency at these frequencies. Treatment with a network of receptors with wide coverage is often used to improve the SNR, which therefore leads to a decrease in the resolution of the slowness and which compromises the interpretation of the thin layers. In addition, processing helical waves to obtain slow shear in LWD environments is plagued by similar problems. Therefore, it is desirable to develop a processing and workflow method capable of improving the resolution of slowness using guided borehole waves.
    BRIEF DESCRIPTION OF THE FIGURES In order to describe the manner in which the advantages and the characteristics of the disclosure can be obtained, reference is made to its embodiments which are illustrated in the accompanying drawings. It being understood that these drawings represent only examples of embodiments of the disclosure and should therefore not be considered as a limit to its scope, the principles are here described and explained with specific features and additional details by the use of the appended drawings on which ones :
    Figure 1 is a diagram of an environment for implementing a well drilling log (LWD) or a well drilling measurement (MWD) of a wellbore, where the apparatus, method and system disclosed in this document can be deployed, in accordance with an exemplary embodiment of this disclosure;
    FIG. 2 illustrates a schematic view of an environment for implementing a wired line logging on a wellbore, where the apparatus, the method and the system disclosed in this document can be deployed, according to an exemplary embodiment of the present disclosure;
    FIG. 3A is an illustration representing a conventional architecture of a system bus calculation system, according to an exemplary embodiment of the present disclosure;
    Figure 3B is an illustration showing a computer system having a chipset architecture, according to an exemplary embodiment of the present disclosure;
    FIG. 4 illustrates a process diagram representing a data processing method with improved resolution in the frequency domain, according to an exemplary embodiment of the present disclosure;
    FIG. 5 illustrates a process diagram representing an improved processing process of waveform data in the time domain, according to an exemplary embodiment of the present disclosure;
    Figure 6 illustrates a schematic view of an acoustic logging tool capable of implementing the methods and techniques disclosed in this document, according to an exemplary embodiment of this disclosure;
    Figure 7 illustrates a schematic view of an acoustic logging tool 600 lowered into a wellbore to collect waveforms from a target area at a plurality of firing positions according to a conventional collection of transmitters, according to an exemplary embodiment of this disclosure;
    FIG. 8 illustrates a schematic view of an acoustic logging tool lowered into a wellbore to collect waveforms originating from a target area at a plurality of firing positions according to a conventional collection of receivers, according to an exemplary embodiment of the present disclosure;
    Figure 9 is an illustration showing similarity maps and an estimated dispersion from waveform data of a subnetwork at different firing points, according to an exemplary embodiment of the present disclosure ;
    Figure 10 is an illustration showing a stacked similarity map from the data shown in Figure 9 and an estimated dispersion from the map, according to an exemplary embodiment of this disclosure;
    Figure 11 illustrates the preferred frequencies in the general processing of guided waves to estimate the slowness of volume waves from a conventional dispersion and excitation of guided waves of a borehole, according to an example of the embodiment of this disclosure;
    FIG. 12 illustrates a normalized slowness density log projected onto the frequency axis, according to an exemplary embodiment of the present disclosure;
    FIG. 13 illustrates a curve of average amplitude coming from waveform data, according to an exemplary embodiment of the present disclosure;
    Figure 14 illustrates a dispersion map, constructed weights and processing results for slowness estimates according to the methods and techniques disclosed in this document, according to an exemplary embodiment of this disclosure; and FIG. 15 illustrates processing results according to the methods and techniques of the present disclosure, for realistic field data obtained by means of a sub-network having an axial resolution of two feet, four feet and six feet, according to an exemplary embodiment of this disclosure.
    DETAILED DESCRIPTION [0022] Various embodiments of the disclosure are described in detail below. Although specific embodiments are presented, it is understood that this is done for illustrative purposes only. Those skilled in the art will understand that other components and other configurations can be used without departing from the spirit and scope of the disclosure.
    It should be understood at the outset that although illustrative implementations of one or more embodiments are illustrated below, the apparatus and the disclosed methods can be implemented using any what number of techniques. Disclosure should under no circumstances be limited to illustrative embodiments, drawings and techniques illustrated in this document, but may be varied within the scope of the appended claims with their full scope of equivalents.
    Unless otherwise indicated, any use of any form of the terms "connect", "come into contact", "mate", "attach" or any other term describing an interaction between elements is not intended to limit the interaction to a direct interaction between the elements and may also include an indirect interaction between the elements described. In the following discussion and in the claims, the terms "including" and "comprising" are used openly and, therefore, should be understood to mean "including, but not limited to ...". Reference will be made to top and bottom for the purpose of carrying out a description with “top”, “highest”, “upwards”, “upstream” or “at the top of the well” meaning towards the surface of the well. and with "bottom", "lower", "down", "downstream" or "down well" meaning towards the terminal end of the well, regardless of the orientation of the wellbore. The various features described in further detail below will be readily apparent to those skilled in the art with the assistance of this disclosure upon reading the following detailed description, and with reference to the accompanying drawings.
    The conventional processing of acoustic data, for example the location of the slow compression, is carried out in the time domain with various methods based on similarity / coherence. These methods generally work well since the borehole compression waves are usually non-dispersive and the processing in the time domain makes it possible to obtain the waves with the best consistency or quality. However, in other cases, for example the localization of a slow shear from bending / helical waves produced by a dipolar / quadrupole source, or the localization of a slow compression wave from leakage P waves which are excited by a monopolar, dipolar or quadrupole source, these types of methods may be inappropriate for a processing process in the time domain. As these guided waves (for example, bending waves, helical waves, trailing P waves) are highly dispersive and their low frequency asymptotes approximate the slowness of volume waves, the slowness of volume waves is extracted from the low frequency part of the guided waves. However, the amplitude of excitation of these waves tends to be small when their slowness approaches the slowness of the volume waves, which gives a low SNR at low frequencies. In order to improve the signal-to-noise ratio at low frequencies, a wide coverage receiver network is used and the noise level is improved due to stacking.
    In general, such processing with a large network is efficient and stable, and provides stable and precise sluggish logs. However, in certain cases, for example for the characterization of stratified formations or very heterogeneous formations, the results of a treatment with a wide coverage network, which is considered to be a weighted average of all the formations within l openness of the corresponding receptor network, deviate from the actual slowness of the formation, and they may not be able to reveal the desired stratification information of the rocks due to their low spatial resolution. Therefore, it is desirable to develop a processing method and workflow which could improve the resolution of the slowness using guided borehole waves.
    There are various processing methods that could be used to extract a slow / compressive / shear wave from a rock formation from guided borehole waves (e.g., bending waves, waves helical, leakage P waves). Generally, these processes are divided into two categories: modeling-based processes and data-driven processes. The modeling-based methods deliver a volume wave slowness by reducing the poor fit between the measurements and the modeling data at certain frequencies. The modeling data are calculated in advance by an analytical and numerical simulation. In some cases, modeling-based methods provide stable and reliable results. However, in other cases, the use of such methods based on advance modeling may be limited because the model may not fit the measurements perfectly since some factors or parameters may not be taken into account in the calculation. anticipated model.
    Another group of processing methods are data-driven methods which use an approach with a flexible or simplified model. These flexible or simplified models can include independent parameters that are able to better fit the model data to the data. Data-driven processing methods may include, for example, curve fitting methods, parameter inversion methods, and choosing the first peak on a slowness histogram. Data-driven methods have obvious advantages when the data quality of low frequency dispersion estimates is good. In other words, the results of the processing are precise and reliable when the quality of the data is good enough to guide the model. However, with regard to complex borehole environments, good quality slowness dispersions may not be available, for example, poor data quality at low frequency may occur, especially during implementation processing with a subnet. In these situations, the traditional data-driven approach may not provide better estimates of slowness.
    In order to solve the above problems during the processing of guided wave data, networks of receivers with wider coverage are often used to improve the quality of data at low frequencies. However, the use of wider coverage receiver networks compromises the axial resolution of slow logging. This approach is particularly problematic for thin layers or formations with high heterogeneity because, in these circumstances, the low resolution data may lose correlation with small geological structures, and the slowness logs may be biased towards neighboring formations. In these circumstances, treatment with a subnet is preferred. Therefore, methods of processing with a subnet with better quality of collection and full use of the available waveform data are desired.
    The present disclosure relates to a method for improving the resolution of slow compression / shear logs using borehole guided waves. The present disclosure relates to two approaches for improving the processing of guided wave data by increasing data redundancy and optimizing the use of data by introducing a reliable data-driven weighting function. . To increase data redundancy, waveform data obtained at different firing locations within the wellbore is combined to maximize the amount of data corresponding to the same target formation area. This is implemented by the stacking of cards of ίο similarity / coherence in a 2D (frequency-slowness) or ID (slowness) domain. The method of stacking similarity maps provided by the present disclosure improves the quality of the dispersion or slowness estimation.
    In addition, the present disclosure provides a self-adaptive weighting function calculated and applied in the processing of the data in order to further improve the use of the waveform data which has both a good SNR and a minimum amount of dispersion correction. This weighting function weights good quality data more than other data. The data quality indicator may be different for the different wave modes. For bending waves, helical waves and trailing P waves, more weight is given to the data at frequencies close to the "cutoff frequency", where the slowness of the guided waves begins to differ from the slowness volume waves. This is explained by the fact that, at these frequencies, these waves have a greater amplitude of better RSB, and they also have a relatively small deviation compared to the slowness of the volume waves. The improvements to the processing of the data provided by this disclosure ensure that increasing this data can help decrease the uncertainty of the slowness of volume waves induced by random noise and modeling errors, and can help improve the accuracy of estimated slowness logs. The methods provided in the present disclosure can be implemented in both frequency and time domain processing.
    Figure 1 is a schematic view of an environment 100 for implementing a well drilling log (LWD) or a well drilling measurement (MWD) of a wellbore, where the apparatus, method and system disclosed in this document can be deployed in accordance with certain exemplary embodiments of this disclosure. As shown in Figure 1, a drilling rig 102 is equipped with a derrick 104 which supports a hoist 106 for raising and lowering a drill string 108. The hoist 106 suspends a mechanism the upper drive 110 suitable for rotating the drill string 108 and lowering the drill string 108 through the well head 112. A drill bit 114 is connected to the lower end of the drill string 108. When the drill bit drill 114 rotates, the drill bit 114 creates a borehole 116 which passes through various formations 118. A pump 120 circulates a drilling fluid through a supply line 122 to the upper drive mechanism 110, at through the interior of the drill string 108, through holes in the drill bit 114, to the surface via an annular space located around the drill string 108, and in a re pit 124. The drilling fluid transports the cuttings from the wellbore 116 to the pit 124 and participates in maintaining the integrity of the wellbore 116. Various materials can be used for the drilling fluid, such as fluids based oil and water-based fluids.
    As shown in Figure 1, logging tools 126 are integrated into the downhole assembly 125 near the drill bit 114. As the drill bit 114 extends the wellbore 116 through the formations 118, the logging tools 126 collect measurements relating to the various properties of the formation as well as to the orientation of the tools and to various other drilling conditions. The downhole assembly 125 may also include a telemetry fitting 128 for transferring measurement data to a surface receiver 130 and for receiving commands from the surface. In at least some cases, the telemetry fitting 128 communicates with a surface receiver 130 by means of a pulse transmission through the mud. In at least some embodiments, the telemetry fitting 128 does not communicate with the surface, but instead stores the log data for later surface retrieval when the log set is retrieved.
    Each of the logging tools 126 may include a plurality of tool components, separated from each other, and coupled in communication with one or more cables. The logging tools 126 may include an apparatus such as that shown in Figures 6 to 8, for example to perform an acoustic (that is, "sound") logging. Telemetry fitting 128 may include wireless telemetry or logging capabilities, or both, for example to transmit or subsequently provide information indicating reception of acoustic energy to operators on the surface or for access and further processing of the data for the evaluation of the properties of the formation 118.
    The logging tools 126, in particular the acoustic logging tool, can also include one or more calculation devices 150 coupled in communication with one or more of the tool components. The computing device 150 can be configured to control or monitor the performance of the tools 126, process the logging data and / or implement the methods of this disclosure.
    In at least some cases, one or more of the logging tools 126 can communicate with a surface receiver 130, such as a wired drill pipe. In other cases, one or more logging tools 126 can communicate with a surface receiver 130 by wireless signal transmission. In at least some cases, one or more of the logging tools 126 may receive electrical energy from a cable that extends to the surface, including cables that extend through a wired drill pipe. In at least some cases, the methods and techniques of the present disclosure can be implemented by a computing device 150 at the surface. In some cases, the computing device 150 may be included in a surface receiver 130. For example, a surface receiver 130 of an operating environment 100 of LWD or MWD drilling on the surface may include one or more of a telemetry wireless, processor circuit, or memory facilities to assist in drilling (LWD) or measurement in drilling (MWD) operations.
    Figure 2 illustrates a schematic view of an environment
    200 for implementing a wired line logging on a wellbore, where the apparatus, method and system disclosed in this document can be deployed, according to some exemplary embodiments of this disclosure. As shown in Figure 2, a hoist 206 may be included as part of a platform 202, such as that coupled to the derrick 204, and used to raise or lower equipment, such as the acoustic logging tool by cable line 210 in or out of a borehole. The logging tool 210 may include, for example, an apparatus like that shown in Figures 6 to 8. A cable 242 may allow communication between the acoustic logging tool 210 and a logging facility 244 at the surface. The logging facility 244 may include a computing device 250 capable of implementing the methods and techniques of this disclosure. In this way, information relating to formation 218 can be obtained by means of the acoustic logging tool 210 and processed by a calculation device, such as the calculation device 250.
    The calculation devices 150 and 250 can include any suitable computer, control device or data processing device capable of being programmed to implement the method, the system and the device, as described more later in this document. Figures 3A and 3B illustrate exemplary embodiments of computing devices 150, 250 which can be used to practice the concepts, methods and techniques disclosed in this document. The most suitable embodiment will be apparent to the specialist in the field when practicing the present technology. The specialist in the field will also quickly understand that other embodiments of systems are possible.
    FIG. 3A illustrates a conventional architecture of a system bus calculation system 300, in which the components of the system are in electrical communication with each other by means of a bus 305. The system 300 may include a processing (CPU or processor) 310 and a system bus 305 which couples various components of the system, in particular the memory of the system 315, such as a read-only memory (ROM) 320 and a random access memory (RAM) 335, to the processor 310. system 300 can include a high speed memory cache connected directly to, very close to or integrated as part of processor 310. System 300 can copy data from memory 315 and / or storage device 330 to cache 312 for quick access by the processor 310. In this way, the cache 312 can provide an increase in performance which prevents the processor 310 from delaying while waiting for data. These and other modules can control or be configured to control processor 310 to perform various actions. Another system memory 315 may also be available for use. Memory 315 can include multiple different types of memory with different performance characteristics. It can be understood that the disclosure can operate on a computing device 300 having more than one processor 310 or on a group or grouping of networked computing devices in order to provide a higher processing capacity. The processor 310 can include any conventional processor and a hardware or software module, such as the first module 332, the second module 334 and the third module 336 stored in the storage device 330, configured to control the processor 310, as well as a special processor where software instructions are incorporated into the actual design of the processor. The processor 310 can essentially be a completely autonomous computer system, containing multiple cores or processors, a bus, a memory controller, a cache, etc. A multi-core processor can be balanced or unbalanced.
    The system bus 305 can be any type of bus structure comprising a memory bus or a memory controller, a peripheral bus, and a local bus using any of the various bus architectures. A basic input / output system (BIOS) stored in ROM 320 or equivalent can provide the basic routine that helps transfer information between elements within computing device 300, such as during startup. The computing device 300 further comprises storage devices 330 or computer-readable storage media, such as a hard disk drive, a magnetic disk drive, an optical disk drive, a tape drive, an electronic disk, a RAM drive, removable storage devices, a redundant network of independent disks (RAID), a hybrid storage device, or equivalent. The storage device 330 may include software modules 332, 334, 336 for controlling the processor 310. The system 300 may include other hardware or software modules. The storage device 330 is connected to the system bus 305 by an interface. The readers and associated computer-readable storage devices provide non-volatile storage of computer-readable instructions, data structures, program modules, and other data for the computing device 300. In one aspect, a module hardware that performs a particular function includes short-circuit software components in a tangible computer-readable storage device in connection with the hardware components necessary, such as processor 310, bus 305, and so on, to perform a function particular. Alternatively, the system may use a processor and a computer-readable storage device to store instructions which, when executed by the processor, cause the processor to perform specific operations, process or other actions. The basic components and appropriate variations can be changed depending on the type of device, for example if the device 300 is a small portable computing device, a desktop computer, or a computer server. When the processor 310 executes instructions to carry out "operations", the processor 310 can directly carry out the operations and / or help, direct or cooperate with another device or component to carry out the operations.
    To allow user interaction with the computing device 300, an input device 345 can represent any number of input mechanisms, such as a microphone for speech, a touch screen for gestural or graphic input. , keyboard, mouse, motion input, speech and so on. An output device 342 can also be one or more of a number of output mechanisms known to those skilled in the art. In some cases, multimodal systems can allow a user to provide multiple types of input to communicate with the computing device 300. The communication interface 340 can generally govern and manage user input and output from the system. There are no restrictions on the operation of any particular hardware arrangement, and therefore the basic features here can easily be replaced by improved hardware and firmware arrangements as they are developed.
    The storage device 330 and a non-volatile memory and can be a hard disk or another type of computer-readable medium which can store data which are accessible by a computer, such as magnetic cassettes, flash memory cards , semiconductor memory devices, general purpose digital disks (DVDs), cartridges, RAM 325, ROM 320, cable containing a bit stream, and their hybrids.
    The logical operations making it possible to implement the present disclosure may include: (1) a sequence of steps, operations or procedures implemented by a computer, executed by a programmable circuit with a conventional computer, (2) a sequence of steps, operations or procedures implemented by a computer, executed by a programmable circuit for specific use; and / or (3) machine modules or program motors interconnected within the programmable circuits. The system 300 shown in FIG. 3A can practice all or part of the methods described, can be part of the systems described and / or operate according to the instructions in the tangible computer-readable storage device described.
    One or more parts of the computing device 300 given as an example, up to and including the entire computing device 300, can be virtualized. For example, a virtual processor can be a software object that runs according to a particular instruction set, even when a physical processor of the same type as the virtual processor is unavailable. A virtualization layer or a virtual "host" can allow virtualized components of one or more different computing devices or different types of device by translating virtualized operations into real operations. Ultimately, however, virtualized hardware of each type is implemented or executed by certain underlying physical hardware. Therefore, a virtualization compute layer can operate on top of a physical compute layer. The virtualization computing layer can include one or more of a virtual machine, a dedicated network, a hypervisor, virtual switching, and any other virtualization application.
    The processor 310 can include all the types of processors disclosed in this document, including a virtual processor. However, when reference is made to a virtual processor, processor 310 includes the software components associated with running the virtual processor in a virtualization layer and the underlying hardware necessary to run the virtualization layer. The system 300 may include a physical or virtual processor 310 which receives instructions stored in a computer-readable storage device, which causes the processor 310 to implement certain operations. When reference is made to a virtual processor 310, the system also includes the underlying physical hardware running the virtual processor 310.
    FIG. 3B illustrates an example of a computer system 350 having a chipset architecture which can be used to execute the method described and to generate and display a graphical user interface (GUI). The computer system 350 can be computer hardware, software, and firmware that can be used to implement the disclosed technology. The system 350 may include a processor 355, representative of any number of physically and / or logically distinct resources capable of executing software, firmware and hardware configured to perform identified calculations. The 355 processor can communicate with a 360 chipset which can control input to and output from the 355 processor. The 360 chipset can output information to an output device 365, such as a display, and can read and writing information to a storage device 370, which may include magnetic media, and solid state media. The 360 chipset can also read data from and write data to RAM 375. A bridge 380 for interfacing with various user interface components 385 can include a keyboard, microphone, detection and touch processing circuitry , a pointing device, like a mouse, and so on. In general, inputs to the 350 system can come from a variety of sources, generated by a machine and / or generated by a human.
    The chipset 360 can also be interfaced with one or more communication interfaces 390 which may have different physical interfaces. Such communication interfaces may include interfaces for wired and wireless local area networks, broadband wireless networks, as well as personal networks. Some applications of the methods for generating, displaying and using the GUI disclosed in this document may include the reception of ordered data sets on the physical interface or be generated by the machine itself by the processor 355 analyzing data stored in storage 370 or RAM 375. In addition, the machine can receive input from a user through the user interface components 385 and perform appropriate functions, such as navigation functions by the user. interpretation of these inputs using processor 355.
    It can be understood that the systems 300 and 350 may have more than one processor 310, 355 or be part of a group or grouping of networked computing devices jointly to provide processing capacity. For example, processor 310, 355 may include multiple processors, such as a system having multiple physically separated processors in different connections, or a system having multiple processor cores on a single physical chip. Likewise, processor 310 may include multiple distributed processors located in multiple separate computing devices, but working together, such as through a communication network. Multiple processors or processor cores can share resources, such as memory 315 or cache 312, and can operate using independent resources. The processor 310 may include one or more of a state machine, a specific application integrated circuit (ASIC), or a pre-broadcast network (PGA) such as a pre-broadcast network programmable by the user.
    The methods according to the above description can be implemented using computer executable instructions that are stored or otherwise available from computer readable media. Such instructions may include instructions and data which cause or otherwise configure a conventional computer, a specialized computer, or a specialized computing device to implement a certain function or group of functions. Parts of the IT resources used can be accessed over a network. Computer-executable instructions can be binary instructions of intermediate form, such as assembly language, firmware, or source code. Computer readable media which can be used to store instructions, information used and / or information created in processes as described above include magnetic or optical discs, flash memory, USB devices with non-removable memory volatile, networked storage devices, and so on.
    For clarity of explanation, in some cases, the present technology can be presented as comprising individual functional blocks comprising functional blocks comprising devices, device components, steps or routines in a process incorporated in software. , or combinations of hardware and software. The functions that these blocks represent can be provided by the use of shared or dedicated hardware, including, but not limited to, hardware capable of running software and hardware, such as a 310 processor, which is built for this purpose to operate as software running on a conventional processor. For example, the functions of one or more processors shown in Figure 3A can be provided by a single shared processor or by multiple processors. (Use of the term "processor" should not be considered as referring exclusively to hardware capable of running software.) Illustrative embodiments may include microprocessor and / or digital signal processor (DSP) hardware ), a ROM 320 for storing software performing the operations described below, and a RAM 335 for storing the results. Embodiments of Very Large Scale Integration (VLSI) hardware, as well as a custom VLSI circuit in combination with a conventional DSP circuit, can also be provided.
    The computer-readable storage devices, media and memories can include a cable or wireless signal containing a stream of bits and the like. However, when mentioned, computer-readable non-transient storage media expressly exclude media such as energy, carrier signals, electromagnetic waves, and the signals themselves.
    The devices implementing the methods according to these disclosures can include hardware, firmware and / or software, and can take any varied form factor. These form factors can include laptops, smart phones, small form factor personal computers, personal digital assistants, chassis devices, standalone devices and so on. The functionality described in this document can also be implemented in peripherals or addition cards. Such functionality can also be implemented on a circuit board among different chips or different processes running in a single device.
    The instructions, the supports for routing these instructions, the computer resources for executing them, and the other structures for supporting these computer resources are means making it possible to provide the functions described in this disclosure.
    FIG. 4 illustrates a process diagram representing a process 400 for processing data with improved resolution in the frequency domain, according to certain exemplary embodiments of the present disclosure. The method shown in Figure 4 is provided by way of example, since there are various ways to implement the method. Each block presented in FIG. 4 represents one or more methods, one or more methods or one or more subroutines, implemented in the example method presented in FIG. 4. In addition, the illustrated order of the blocks is illustrative only because, according to certain aspects of this disclosure, the order of the blocks may change. Additional blocks may be added or fewer blocks may be used, without departing from the present disclosure.
    The example of method 400 can start at block 410.
    In block 410, a target axial resolution is selected based on the size of the receiver array. In block 420, several sets of waveforms are collected for a target formation area having the same lattice size, but at different firing positions. In block 430, all waveform data that corresponds to the target formations is selected. Slow-frequency 2D dispersion similarity maps are calculated for each waveform data set in block 440. In block 450, 2D similarity maps that cover the same target formation area are stacked together to produce an improved or stacked 2D similarity map. Data processing represented by blocks
    410 to 450 reduces the influence of noise by using a large amount of redundant data. After stacking to produce the improved or stacked 2D similarity map (block 450), guided wave dispersal responses can be extracted from the stacked 2D similarity map by selecting the similarity peaks at each frequency, as shown in the block
    460.
    Already known borehole characteristics, such as the types of fluid in the borehole, the diameter of the borehole, the density of the formation and the compressive slowness from previous measurements, are obtained in block 470. In block 480, a theoretical exact or simplified borehole dispersion model is generated based on the already known characteristics of the borehole, which will be used to generate a self-adaptive weighting function in block 490 and to adjust the measurements in block 492. The exact dispersion model refers to processes based on advance modeling, while the simplified dispersion model which introduces adjustable parameters is still used in data-driven processes.
    After obtaining the dispersion measurements from the improved dispersion map, in block 460, and the generation of the dispersion modeling curves of the anticipated modeling, in block 480, the modeling dispersions are adjusted to the dispersions measured in block 492 to construct a self-adaptive weighting function. Before the adjustment procedure in block 492, a self-adaptive weighting function can be generated in 490 and applied to the data in the frequency domain, in order to reinforce the weighted part of the data which have a good SNR and which require only a minimum dispersion correction. In block 492, an inversion procedure can be used to minimize the differences between the dispersion model and the weighted measures. Finally, in block 494, the slowness of the volume waves which is capable of minimizing the poor fit between the model and the measurements is output in the form of improved slowness responses.
    FIG. 5 illustrates a process diagram representing a method 500 of improved processing of waveform data in the time domain, according to certain exemplary embodiments of the present disclosure. The method shown in Figure 5 is provided by way of example, since there are various ways to implement the method. Each block presented in FIG. 5 represents one or more methods, one or more methods or one or more subroutines, implemented in the example method presented in FIG. 5. Furthermore, the illustrated order of the blocks is illustrative only because, according to certain aspects of this disclosure, the order of the blocks may change. Additional blocks may be added or fewer blocks may be used, without departing from the present disclosure.
    The example of method 500 can start at block 505. In block 505, a target axial resolution is selected based on the size of the receiver network. In block 510, a plurality of waveform sets are collected for a target formation area having the same lattice size, but at different firing positions. In block 515, all waveform data that corresponds to the target formations is selected. A self-adaptive weighting function is generated in block 520 to enhance the desired portion of the data in the waveforms. In block 525, the waveform data is filtered based on the weights by reconstructing the amplitude portion of the waveform with the weights and filtering the waveforms to improve the RSB of the data and minimize dispersion correction.
    The filtered waveforms are entered into a time domain similarity calculation in block 530. In order to perform the time domain similarity calculation, an exact or simplified dispersion model is generated in the block 540, based on prior knowledge of the characteristics of the borehole, obtained in block 535. The dispersion model generated in block 540 is used to propagate the waveforms to different receivers in block 530.
    The waveform is truncated and the similarity / coherence value of all the waveforms at a reference receiver which are propagated from different receivers is calculated in block 530. The setting work of the procedure of block 530 for different values of slowness allows the calculation, in block 545, of a value of similarity / coherence compared to slowness, or of a VDL 1D of similarity / coherence in a truncated time window . The implementation of the processing with the waveform data for the same target formation zone, but at different firing positions, allows the calculation of a set of 1D VDL for the current zone. In block 550, all VDLs for the current area are stacked to obtain an improved VDL with improved RSB.
    If the model contains adjustable parameters, blocks 530 to 550 can be implemented again with different parameter values in order to minimize the bad adjustment between the model and the measurements. In block 555, the peaks on the VDL data are located and the corresponding slowness of the volume waves is output. Adjustable parameters, if used, can also be output. Unlike the frequency processing method 400 described in FIG. 4, the time domain processing method 500 introduces a time window for truncating part of the waveforms, which facilitates the elimination of the influence of noise or the diffusion of wave displacements outside the time window.
    FIG. 6 illustrates a schematic view of an acoustic logging tool 600 capable of implementing the methods and techniques disclosed in the present document according to certain examples of embodiments of the present disclosure. As can be seen in FIG. 6, the acoustic logging tool 600 comprises at least one transmitter 610 capable of exciting acoustic signals of different azimuth orders. The acoustic logging tool 600 furthermore comprises a network of receivers with wide coverage comprising thirteen receivers 620 to 632 with a spacing 640 of 0.5 feet, similar to the Xaminer® Array Sonic Tool (XAST), available from Halliburton Energy Services, Inc. The wide coverage receiver network is capable of capturing an acoustic wave field of different azimuth orders. In such an acoustic logging tool 600, the axial resolution of the slow logging can vary with different sub-network processing. Generally, the axial resolution of an extracted slowness curve is located between the spacing between the receivers and the size of the network, which can be from approximately 0.5 feet to approximately 6 feet, depending on the size of the sub- network.
    As can be seen with the method 400 of FIG. 4, the block 410 involves the determination of the target axial resolution at the level, for example, of a signal processor. Then, the size of the receiver network can be calculated by the following equation:
    Eqn 1 where L indicates the size of the sub-network, Res represents the target resolution, and RR indicates the spacing between the receivers.
    FIG. 7 illustrates a schematic view of an acoustic logging tool 600 lowered into a wellbore to collect waveforms originating from a target area at a plurality of firing positions according to a conventional collection of issuers, according to certain exemplary embodiments of this disclosure. As shown in Figure 7, the acoustic logging tool 600 can be lowered to a depth in the borehole corresponding to a target area of interest 750, then the transmitter is fired and the acoustic signals are captured at the receptor network 725. The acoustic logging tool 600 can be repositioned several times in the wellbore in order to collect waveform data at the receptor network 725 for the same target area 750, but with different shooting positions 1 to 9. In this way, it is possible to collect a large amount of data to evaluate the target area of interest 750. For example, the network of transmitters 725 shown in FIG. 7 can have an axial resolution of 2 feet. An axial resolution of 2 feet requires a size of sub-network comprising 5 receivers when RR = 0.5 feet. Assuming the data is acquired at equal firing distances of 0.5 feet with the transmitter in motion, Figure 7 shows that sorting the data on each shot covers the same target area 750. As shown in Figure 7 , at shot 1, the waveform data at receivers 628 to 632 meet the sorting requirements, and for shot 2, receivers 627 to 631 meet the sorting requirements. In total, the Acoustic Logging Tool 600 can acquire nine sets or 9 x 5 sets of waveforms, which greatly exceeds those used in processing with an entire array using only thirteen waveforms. receivers. As shown in Figure 7, all of the selected waveform data sets cover the same target area 750, the same study depth, and the same axial resolution. Therefore, it is possible to combine the processing of all waveform data sets together to obtain a unique and reliable slowness / dispersion response.
    Figure 8 illustrates a schematic view of an acoustic logging tool 600 lowered into a wellbore to collect waveforms from a target area at a plurality of firing positions according to a conventional collection of receivers , according to some exemplary embodiments of this disclosure. As shown in Figure 8, you can select waveforms that share the same reception area, but have different firing positions, while ensuring that the firing positions of the waveforms align with the target training area. As shown in Figure 8, nine sets of waveform data are obtained, each set containing five waveforms with receivers corresponding to the target area. The combination of processing of the common transmitter sub-network and the common receiver sub-network makes it possible to calibrate the influence of the changes in radius of the borehole and allows the correction of the tool tilt. Both types of network share exactly the same processing steps.
    According to the present disclosure, the waveform data from different firing positions can be combined. Generally, the data of a sub-network from different firing positions can be considered as "repeated measurements" of the same target area with different sets of receivers. “Repeated measurements” can be averaged to improve the SNR. During guided wave analysis, waveform data can be entered into a dispersion analysis program and a similarity / coherence map can be generated by the program. For example, a program can use differential phase frequency similarity (DPFS), ¢ (/, 5) = tan -1
    1 5 - / V- 1 (Λ Ό * C, (/, *))
    Eqn. 2 where is the frequency phase difference value at each frequency f and the slowness s , Y (f is the complex conjugate of ^ // ^, e t real e t imag son j- | es p ar tîes real and imaginary of a complex number, when it processes receivers 1 to N. The 2D similarity map can be obtained from the value of phase difference frequency with the equation Semb {f, s) = max (l -2 ^ (/, s) / π, θ) _ La | oca | j sa tion of the peaks on the map at different frequencies gives the dispersion responses, in the form of slowness with respect to frequency.
    Here, there are several datasets of subnets which measure the properties of the same training area. All the data in the processing in the frequency domain can be combined by taking the average of the dispersion response. However, this approach may not work perfectly if there is noise in the dispersion response at certain frequencies. In such a situation, the centroid of the scatter response may be incorrect. A better approach is to first decrease the noise level of the 2D similarity map according to the methods of this disclosure. In particular, the present disclosure provides a method for improving the 2D map by stacking all the 2D subnetwork maps,
    SemJ (f, s) = /
    Eqn. 3 or we can use a weight to minimize the contribution of poor quality data,
    Semb f, s) = ^ = x Weighif) * Semb i (f, s) £ qn 4 [0072] Figures 9 and 10 illustrate an example of a 2D card stacking process with a treatment of wave dispersion bending, according to some exemplary embodiments of this disclosure. Figures 9A to 91 show the 2D maps from positions 1 to 9 of fire in Figure 7, respectively. The results indicate that for the subarray data, both the 2D maps and the estimated dispersions contain noise and are unstable at low frequencies when the slow bending waves begin to approach the shear slowness of the training. This fact makes the data estimated at low frequencies very uncertain, and gives slower estimates of slowness. FIG. 10 represents the stacked 2D maps presented in FIGS. 9A to 91. As can be seen in FIG. 10, the use of redundant data, according to the methods of the present disclosure, eliminates the noise level, which allows to obtain a clear and convergent 2D map. In addition, the qualities of the similarities at low frequencies are improved, and the estimated dispersions converge towards the slow shear of the formation. Figure 10 also shows that the present methods identify slow shear by matching all of the dispersion responses.
    Although the above examples are described with respect to processing in the frequency domain, the same procedures apply in the same way to the processing methods in the time domain of this disclosure. During guided time hole processing in the time domain, an ID similarity map along the axis of slowness is produced. A similarity map with lower noise can be obtained by stacking 1D similarity maps of different sets of lattice waveforms.
    As described above, two types of advance modeling methods can be used when processing guided borehole waves. One method is the exact model, which corresponds to a model-based processing method, and the other is a simplified data-driven model with adjustable parameters, which can be called the data-driven processing approach. The methods and techniques of this disclosure are suitable for use with modeling-based or data-driven approaches.
    After the selection of the anticipated model, an adjustment / optimization step of the data can be carried out between the result of the modeling and the measurements in order to generate the final slow response. In some cases, the data quality may not be good enough even after the implementation of the similarity cards stacking step. In order to further improve the fit, the present disclosure provides a method for generating a self-adaptive weighting function and applying it to the data. The weighting function generates different weights at different frequencies to optimize the adjustment processing. The weighting function can be changed for different applications depending on the characteristics of the guided waves.
    For example, in the case of estimating the slowness of volume waves from guided borehole waves, two important factors must be taken into account. One factor is the need to assign more weight to preferred data due to the favorable signal-to-noise ratio (SNR) of this data. The second consideration is that the slowness value of the preferred data must be close to the actual value of shear slowness so that a small dispersion correction is only necessary.
    FIG. 11 illustrates the preferred frequencies in the general processing of guided waves to estimate the slowness of volume waves from a conventional dispersion and excitation of guided waves from a borehole, according to certain examples of embodiments of this disclosure. The slowness of the guided waves begins to differ from the slowness of the volume waves at a specific frequency, which is known in the industry as the "cutoff frequency". The excitation amplitude reaches a maximum at the frequency with Airy phase, and decreases to zero at the "cut-off frequency". As shown in Figure 11, only the data sets at frequencies close to the "cutoff frequency", as indicated by the dotted square in Figure 11, have a certain amplitude of excitation and require a small dispersion correction . Therefore, these data are preferably associated with higher weights in the inversion. There are several methods that can be used to generate an adaptive weighting function to enhance the contribution of preferred data to the data processing method.
    As shown in Figure 11, the dispersion curve becomes smooth and flat when the frequency approaches the "cutoff frequency". When displaying the VDL of the distributed dispersion, the flat parts of the dispersion responses often form peaks or edges in the VDL. VDLs can be used to monitor the quality of correct peaks in volume wave slowness. The methods and techniques of the present disclosure use such VDLs to construct a weighting function to increase the weights of a "substantially flat" portion of the data curve. It is possible to use different VDL display methods in this approach. Below, we present an example of the use of standardized slowness density logs. The normalized slowness density log can be calculated by the following equation:
    NSDL (s) = exp (—min max (l, rifa) length [Coh (s, fy> 0] 'f-fmax coh (s, n] 2 ' T. f fJff ax Coh ( s F
    Eqn. 5 where f max indicates the range of maximum frequencies to be taken into account and length [Coh (s, f)> 0] indicates the number of frequency points 5 having coherence values greater than 0, and Coh (s , /) indicates the sum of all the coherence values along the frequency axis for a specific slowness s, n f is the number of frequency points between f max and fl, and a is an empirically adjustable parameter .
    In the weighting function, the domain argument is the frequency. Consequently, the normalized slowness density log can be projected on the frequency by the projection equation,
    JVSW) = / VSZ> 4 (/)]
    Eqn. 6 where indicates the measured dispersion curve.
    FIG. 12 illustrates a normalized slowness density log projected onto the frequency axis, according to certain examples of embodiments of the present disclosure. As Figure 12 shows, it is clear that the datasets which are close to the cutoff frequencies are greatly improved by the weights. Another aspect of the inversion is that the high energy signal should be more reliable than the low energy signals. Therefore, weights can also be assigned based on the average amplitude of the target waveform data at different receivers,
    Eqn. 7 where N is the size of the sub-network, M is the number of shots.
    For example, FIG. 13 illustrates a curve of average amplitude coming from the waveform data, according to certain examples of embodiments of the present disclosure. As shown in Figure 13, the averaged waveform spectrum has a relatively large excitation bandwidth, since it drops to zero at the cutoff frequencies. Figure 13 further demonstrates that the amplitude weights can be used to assess the reliability of the data at low frequencies.
    In order to combine the weights of the slowness density projection and the weights of the amplitudes, the following equation can be used,
    Weight (f) = NSDLXf) * AMP h flf) ' Eqn . θ In addition, in order to reduce the influence of the asymptotes of the data at high frequencies, the weights of the data at high frequencies can be reduced according to the following equation,
    WeigMJf = max [fFeighl (f)] ' lf
    Eqn. The parameter ^ Rcf can be determined by an optimized selection process of the limit at high frequencies. The Wei s ht MghMœ: parameter is | e max j mum of weight adjusted for data at high frequencies.
    FIG. 14 illustrates a dispersion map, constructed weights and processing results for estimates of slowness according to the methods and techniques disclosed in this document, according to certain examples of embodiments of the present disclosure. As shown in Figure 14, it is evident that the weights generated according to equation 9 improve the preferred data to produce a slowness response that adapts to the measurement. In addition, Figure 14 shows that at low frequencies, data that is close to the cutoff frequency has high weights, while data well below the cutoff frequency jumps around the shear slowness values of training due to the low amplitudes of excitation associated with the assigned weights assigned or the low weights assigned. These characteristics of the weights make the reversal of the slowness stable and more reliable, which makes it possible to produce a more precise response to the slowness of the waves. The self-adaptive weighting feature described in this document can also be used when processing with an entire network to further improve the results of the processing.
    FIG. 15 illustrates processing results according to the methods and techniques of the present disclosure, for realistic field data obtained by means of a sub-network having an axial resolution of two feet, four feet and six feet , according to some exemplary embodiments of this disclosure. Figure 15A shows the results of processing an entire network of 13 receivers with an axial resolution of 6 feet. FIG. 15B presents the results of a processing of a network of 9 receivers having an axial resolution of 4 feet. FIG. 15C presents the results of a processing of a network of 5 receivers having an axial resolution of 2 feet.
    The three slowness logs shown in Figure 15 are stable, smooth and consistent in terms of accuracy. Additional details and minor formation changes are observed both on the VDL maps and in the shear slowness estimates for results at an axial resolution of 2 feet compared to the axial resolution of 6 feet. For example, at a depth of 2,050 m, the treatment with the entire network gives a single layer, while the treatment at the axial resolution of 2 feet shows two layers and minor changes in slowness. A similar phenomenon can be observed at other depths, for example at the depths of 2,090 m, 2,122 m and 2,143 m. More importantly, treatment with a sub-network decreases the influence of neighboring rocks and, therefore, estimates of volume waves in the thinner layer, demonstrating that the methods and techniques disclosed in this document provide more precise results than a conventional treatment with an entire network.
    Disclosure statements include:
    Statement 1: A method of determining the volume wave slowness from guided borehole waves, the method comprising: selecting a target axial resolution based on the size of a network of receivers; obtaining a plurality of waveform data sets corresponding to a target training area, wherein each waveform data set is acquired at a different firing position; calculating a slow-frequency 2D dispersion similarity map for each waveform data set; stacking 2D slow-frequency dispersion similarity maps to generate a stacked 2D similarity map; extracting a dispersion curve from the stacked 2D similarity map to generate an extracted dispersion curve; and determining a volume slowness from the extracted dispersion curve.
    Statement 2: A method according to statement 1, further comprising: obtaining the already known characteristics of a borehole; generating a self-adaptive weighting function based on the dispersion model and the extracted dispersion curve; applying the auto-adaptive weighting function to the frequency domain data of the extracted dispersion curve to generate a weighted dispersion curve; adjusting, using an inversion procedure, the weighted dispersion curve and the dispersion model; and determining a volume slowness which minimizes the poor fit between the weighted dispersion curve and the dispersion model.
    Statement 3: A method according to statement 1 or statement 2, further comprising: lowering an acoustic logging tool to a depth in a borehole corresponding to a target formation area.
    Statement 4: A method according to statement 3, further comprising: causing the acoustic logging tool to acquire a plurality of waveform data sets corresponding to a target training area, wherein each waveform data set is acquired at a different firing position.
    Statement 5: A method according to any of claims 1 to above, wherein the guided borehole waves are selected from the group consisting of bending waves, helical waves, and trailing P waves.
    Statement 6; A method according to any one of the preceding statements 1 to 5, in which the already known characteristics of the borehole are selected from the group consisting of the type of fluid of the borehole, the diameter of the borehole, the density of the training, slowness, and any combination of these.
    Statement 7: A method according to any one of the preceding statements 1, in which the dispersion model is an exact dispersion model based on an advance modeling method.
    Statement 8: A method according to any one of the preceding statements 1 to 6, in which the dispersion model is a simplified dispersion model based on a process guided by data having adjustable parameters.
    Statement 9: A method according to any one of the preceding statements 1 to 8, in which each of the different firing positions corresponds to a discrete depth of wellbore.
    Statement 10: A method of determining the volume wave slowness from guided borehole waves, the method comprising: selecting a target axial resolution based on the size of the array. receivers; obtaining a plurality of waveform data sets corresponding to a target training area, wherein each waveform data set is acquired at a different firing position; generating a self-adaptive weighting function; applying the auto-adaptive weighting function to the time domain data of each waveform data set to generate weighted waveform data sets; and filtering the weighted waveform data sets based on the weights to enhance the preferred frequency of the data and to generate filtered waveform data sets.
    Statement 11: A method according to statement 10, further comprising: obtaining the already known characteristics of a borehole; generating a dispersion model based on the already known characteristics of the borehole; propagating the filtered waveform data sets to different receivers using the dispersion model; calculating a set of variable density (VDL) logs of 1D similarity / coherence in a truncated time window using propagated waveforms; stacking VDLs to generate an improved VDL having an improved signal to noise ratio; and determining a volume wavelength by locating the peaks on the VDL data.
    Item 12: A method according to item 11, further comprising: generating a second dispersion model by adjusting one or more adjustable parameters in order to minimize the poor fit between the dispersion model and filtered waveform data sets.
    Statement 13: A method according to any one of the preceding statements 10 to 12, further comprising: lowering an acoustic logging tool to a depth in a borehole corresponding to a target formation zone .
    Statement 14: A method according to statement 13, further comprising: causing the acoustic logging tool to acquire a plurality of waveform data sets corresponding to a target training area, wherein each waveform data set is acquired at a different firing position.
    Statement 15: A method according to any of the preceding statements 10 to 14, in which the borehole guided waves are selected from the group consisting of bending waves, helical waves, and trailing P waves .
    Statement 16: A method according to any one of the preceding statements 10 to 15, in which the characteristics already known of the borehole are selected from the group consisting of the type of fluid of the borehole, the diameter of the borehole drilling, formation density, compressional slowness, and any combination thereof.
    Statement 17: A method according to any one of the preceding statements 10 to 16, in which the dispersion model is an exact dispersion model based on an advance modeling method.
    Statement 18: A method according to any one of the preceding statements 10 to 16, in which the dispersion model is a simplified dispersion model based on a method guided by data having adjustable parameters.
    Statement 19: A method according to any one of the preceding statements 10 to 18, in which each of the different firing positions corresponds to a discrete depth of wellbore.
    Statement 20: An apparatus comprising: an acoustic logging tool having a network of receivers, the acoustic logging tool being designed to acquire a plurality of waveform data sets corresponding to a target training area, wherein each waveform data set is acquired at a different firing position; at least one processor in communication with the acoustic logging tool, in which the processor is coupled to a non-transient computer-readable storage medium on which instructions are stored which, when they are executed by the at least one processor, cause the at least one processor to: select a target axial resolution based on the size of an array of receivers; obtaining a plurality of waveform data sets corresponding to a target training area, wherein each waveform data set is acquired at a different firing position; calculating a 2D slow-frequency dispersion similarity map for each waveform data set; stacking 2D slow-frequency dispersion similarity maps to generate a stacked 2D similarity map; extracting a dispersion curve from the stacked 2D similarity map to generate an extracted dispersion curve; and determining a volume wavelength from the extracted dispersion curve.
    Statement 21: An apparatus according to statement 20, in which the computer-readable non-transient storage medium also contains a set of instructions which, when executed by the at least one processor, bring the at least one processor for: obtaining already known characteristics of a borehole; generating a dispersion model based on the already known characteristics of the borehole; generating a self-adaptive weighting function based on the dispersion model and the extracted dispersion curve; applying the self-adaptive weighting function to the data of the frequency domain of the extracted dispersion curve to generate a weighted dispersion curve; adjusting, by means of an inversion procedure, the weighted dispersion curve and the dispersion model; and determining a volume wavelength which minimizes the poor fit between the weighted dispersion curve and the dispersion model.
    Item 22: An apparatus according to item 20 or item 21, in which the borehole guided waves are selected from the group consisting of bending waves, helical waves, and trailing P waves.
    Statement 23: An apparatus according to any one of the preceding statements 20 to 22, in which the characteristics already known of the borehole are selected from the group consisting of the type of fluid of the borehole, the diameter of the borehole drilling, formation density, compressional slowness, and any combination thereof.
    Statement 24: A system comprising: an acoustic logging tool disposed in a wellbore, the acoustic logging tool having an array of receivers and being designed to acquire a plurality of corresponding waveform data sets at a target training area, in which each waveform data set is acquired at a different firing position; at least one processor in communication with the acoustic logging tool, in which the processor is coupled to a non-transient computer-readable storage medium on which instructions are stored which, when they are executed by the at least one processor, cause the at least one processor to: select a target axial resolution based on the size of an array of receivers; obtaining a plurality of waveform data sets corresponding to a target training area, wherein each waveform data set is acquired at a different firing position; calculating a 2D frequency similarity dispersion map for each waveform data set; stacking 2D slow-frequency dispersion similarity maps to generate a stacked 2D similarity map; extracting a dispersion curve from the stacked 2D similarity map to generate an extracted dispersion curve; and determining a volume wavelength from the extracted dispersion curve.
    Statement 25: A system according to statement 24, in which the computer-readable non-transient storage medium also contains a set of instructions which, when executed by the at least one processor, bring the at least one processor for: obtaining already known characteristics of a borehole; generating a dispersion model based on the already known characteristics of the borehole; generating a self-adaptive weighting function based on the dispersion model and the extracted dispersion curve; applying the self-adaptive weighting function to the data of the frequency domain of the extracted dispersion curve to generate a weighted dispersion curve; adjusting, using an inversion procedure, the weighted dispersion curve and the dispersion model; and determining a volume wavelength which minimizes the poor fit between the weighted dispersion curve and the dispersion model.
    Item 26: A system according to item 24 or item 25, in which the borehole guided waves are selected from the group consisting of bending waves, helical waves, and trailing P waves.
    Statement 27: A system according to any one of the preceding statements 24 to 26, in which the characteristics already known of the borehole are selected from the group consisting of the type of fluid of the borehole, the diameter of the borehole drilling, formation density, compressional slowness, and any combination thereof.
    Statement 28: An apparatus comprising: an acoustic logging tool having a network of receivers, the acoustic logging tool being designed to acquire a plurality of waveform data sets corresponding to a target training area, wherein each waveform data set is acquired at a different firing position; at least one processor in communication with the acoustic logging tool, in which the processor is coupled to a non-transient computer-readable storage medium on which instructions are stored which, when they are executed by the at least one processor, cause the at least one processor to: select a target axial resolution based on the size of the array of receivers; obtaining a plurality of waveform data sets corresponding to a target training area, wherein each waveform data set is acquired at a different firing position; generating a self-adaptive weighting function; applying the auto-adaptive weighting function to the time domain data of each waveform data set to generate weighted waveform data sets; and filtering the weighted waveform data sets based on the weights to enhance the preferred frequency of the data and to generate filtered waveform data sets.
    Item 29: An apparatus according to item 28, in which the computer-readable non-transient storage medium further contains a set of instructions which, when executed by the at least one processor, further bring about the at least one processor to: obtain characteristics already known of a borehole; generating a dispersion model based on the already known characteristics of the borehole; propagate the filtered waveform data sets to different receivers using the dispersion model; calculating a set of variable density / VDLs of ID similarity / coherence in a truncated time window using the propagated waveforms; stacking the VDLs to generate an improved VDL having an improved signal to noise ratio; and determining a volume wave slowness by locating the peaks on the VDL data.
    Statement 30: An apparatus according to statement 29, in which the computer-readable non-transient storage medium also contains a set of instructions which, when executed by the at least one processor, further bring about the at least one processor to: generate a second dispersion model by adjusting one or more adjustable parameters in order to minimize the bad fit between the dispersion model and the filtered waveform data sets.
    Statement 31; An apparatus according to any of the foregoing claims 28-30, wherein the guided borehole waves are selected from the group consisting of bending waves, helical waves, and trailing P waves.
    Statement 32: An apparatus according to any one of the preceding statements 28 to 31, in which the already known characteristics of the borehole are selected from the group consisting of the type of fluid of the borehole, the diameter of the borehole drilling, formation density, compressional slowness, and any combination thereof.
    Statement 33: A system comprising: an acoustic logging tool disposed in a wellbore, the acoustic logging tool having an array of receivers and being designed to acquire a plurality of corresponding waveform data sets at a target training area, in which each waveform data set is acquired at a different firing position; at least one processor in communication with the acoustic logging tool, in which the processor is coupled to a non-transient computer-readable storage medium on which instructions are stored which, when they are executed by the at least one processor, cause the at least one processor to: select a target axial resolution based on the size of the array of receivers; obtaining a plurality of waveform data sets corresponding to a target training area, wherein each waveform data set is acquired at a different firing position; generating a self-adaptive weighting function; applying the auto-adaptive weighting function to the time domain data of each waveform data set to generate weighted waveform data sets; and filtering the weighted waveform data sets based on the weights to enhance the preferred frequency of the data and to generate filtered waveform data sets.
    Statement 34: A system according to Statement 33, in which the computer-readable non-transient storage medium further contains a set of instructions which, when executed by the at least one processor, further bring about the at least one processor to: obtain characteristics already known of a borehole; generating a dispersion model based on the already known characteristics of the borehole; propagate the filtered waveform data sets to different receivers using the dispersion model; calculating a set of variable density (VDL) logs of 1D similarity / coherence in a truncated time window using the propagated waveforms; stacking the VDLs to generate an improved VDL having an improved signal to noise ratio; and determining a volume wave slowness by locating the peaks on the VDL data.
    Statement 35: A system according to statement 34, in which the computer-readable non-transient storage medium also contains a set of instructions which, when executed by the at least one processor, also bring about the at least one processor to: generate a second dispersion model by adjusting one or more adjustable parameters in order to minimize the bad fit between the dispersion model and the filtered waveform data sets.
    Statement 36: A system according to any of the preceding statements 33 to 35, in which the borehole guided waves are selected from the group consisting of bending waves, helical waves, and trailing P waves .
    Statement 37; A system according to any of the foregoing claims 33 to 36, in which the already known characteristics of the borehole are selected from the group consisting of the type of fluid of the borehole, the diameter of the borehole, the density of training, slowness, and any combination of these.
    权利要求:
    Claims (20)
    [1" id="c-fr-0001]
    1. Method for determining the slowness of volume waves from guided borehole waves, the method comprising:
    selecting a target axial resolution based on the size of an array of receivers;
    obtaining a plurality of waveform data sets corresponding to a target training area, wherein each waveform data set is acquired at a different firing position;
    calculating a 2D frequency slowness similarity map for each waveform data set;
    stacking 2D slow frequency similarity maps to generate a stacked 2D similarity map;
    extracting a dispersion curve from the stacked 2D similarity map to generate an extracted dispersion curve; and determining a volume slowness from the extracted dispersion curve.
    [2" id="c-fr-0002]
    2. Method according to claim 1, further comprising: obtaining the already known characteristics of a borehole; generating a dispersion model based on the already known characteristics of the borehole;
    generating a self-adaptive weighting function based on the dispersion model and the extracted dispersion curve;
    applying the auto-adaptive weighting function to the frequency domain data of the extracted dispersion curve to generate a weighted dispersion curve;
    adjusting, using an inversion procedure, the weighted dispersion curve and the dispersion model; and determining a volume slowness which minimizes the poor fit between the weighted dispersion curve and the model
    5 of dispersion.
    [3" id="c-fr-0003]
    3. Method according to claim 2, further comprising:
    the descent of an acoustic logging tool to a depth in a borehole corresponding to an area of
    10 target training.
    [4" id="c-fr-0004]
    4. Method according to claim 3, further comprising:
    causing the acoustic logging tool to acquire a plurality of waveform data sets corresponding to an area
    15 target training, in which each waveform data set is acquired at a different firing position.
    [5" id="c-fr-0005]
    5. The method of claim 2, wherein the guided borehole waves are selected from the group consisting of
    20 bending, helical waves, and trailing P waves.
    [6" id="c-fr-0006]
    6. The method of claim 2, wherein the already known characteristics of the borehole are selected from the group consisting of the type of fluid of the borehole, the diameter of the borehole, the density
    25 training, compression slowness, and any combination thereof.
    [7" id="c-fr-0007]
    7. Method for determining the slowness of volume waves from borehole guided waves, the method comprising:
    selecting a target axial resolution based on the size of the array of receivers;
    obtaining a plurality of waveform data sets corresponding to a target training area, wherein each waveform data set is acquired at a different firing position;
    generating a self-adaptive weighting function; applying the auto-adaptive weighting function to the time domain data of each waveform data set to generate weighted waveform data sets; and filtering the weighted waveform data sets based on the weights to enhance the preferred frequency of the data and to generate filtered waveform data sets.
    [8" id="c-fr-0008]
    8. The method of claim 7, further comprising: obtaining the already known characteristics of a borehole; generating a dispersion model based on the already known characteristics of the borehole;
    propagating the filtered waveform data sets to different receivers using the dispersion model;
    calculating a set of variable density (VDL) logs of 1D similarity / coherence in a truncated time window using propagated waveforms;
    stacking VDLs to generate an improved VDL having an improved signal to noise ratio; and determining a volume wavelength by locating the peaks on the VDL data.
    [9" id="c-fr-0009]
    9. The method according to claim 8, further comprising:
    generating a second dispersion model by adjusting one or more adjustable parameters to minimize the mismatch between the dispersion model and the filtered waveform data sets.
    [10" id="c-fr-0010]
    10. The method of claim 8, further comprising:
    lowering an acoustic logging tool to a depth in a borehole corresponding to a target formation area.
    [11" id="c-fr-0011]
    11. The method according to claim 10, further comprising:
    causing the acoustic logging tool to acquire a plurality of waveform data sets corresponding to a target formation area, in which each waveform data set is acquired at a position different from shoot.
    [12" id="c-fr-0012]
    The method of claim 11, wherein the guided borehole waves are selected from the group consisting of bending waves, helical waves, and trailing P waves.
    [13" id="c-fr-0013]
    13. The method of claim 8, wherein the already known characteristics of the borehole are selected from the group consisting of the type of fluid of the borehole, the diameter of the borehole, the density of the formation, the slowness compression, and any combination thereof.
    [14" id="c-fr-0014]
    14. Device comprising:
    an acoustic logging tool having an array of receivers, the acoustic logging tool being adapted to acquire a plurality of waveform data sets corresponding to a target training area, in which each form of wave is acquired at a different firing position;
    at least one processor in communication with the acoustic logging tool, in which the processor is coupled to a non-transient computer-readable storage medium on which instructions are stored which, when they are executed by the at least one processor, bring the at least one processor to:
    selecting a target axial resolution based on the size of an array of receivers;
    obtaining a plurality of waveform data sets corresponding to a target training area, wherein each waveform data set is acquired at a different firing position;
    calculating a 2D frequency similarity dispersion map for each waveform data set;
    stacking 2D slow frequency similarity maps to generate a stacked 2D similarity map;
    extracting a dispersion curve from the stacked 2D similarity map to generate an extracted dispersion curve; and determining a volume wavelength from the extracted dispersion curve.
    [15" id="c-fr-0015]
    15. The apparatus of claim 14, wherein the non-transient computer readable storage medium further contains a set of instructions which, when executed by the at least one processor, cause the at least one processor to:
    obtain already known characteristics of a borehole; generating a dispersion model based on the already known characteristics of the borehole;
    generating a self-adaptive weighting function based on the dispersion model and the extracted dispersion curve;
    applying the self-adaptive weighting function to the data of the frequency domain of the extracted dispersion curve to generate a weighted dispersion curve;
    adjusting, using an inversion procedure, the weighted dispersion curve and the dispersion model; and determining a volume wavelength which minimizes the poor fit between the weighted dispersion curve and the dispersion model.
    [16" id="c-fr-0016]
    The apparatus of claim 15, wherein the guided borehole waves are selected from the group consisting of bending waves, helical waves, and trailing P waves.
    [17" id="c-fr-0017]
    17. Apparatus according to claim 15, in which the characteristics already known of the borehole are selected from the group consisting of the type of fluid of the borehole, the diameter of the borehole, the density of the formation, the slowness compression, and any combination thereof.
    [18" id="c-fr-0018]
    18. System comprising:
    an acoustic logging tool disposed in a borehole, the acoustic logging tool having an array of receivers and being adapted to acquire a plurality of waveform data sets corresponding to a target formation area, in which each waveform data set is acquired at a different firing position;
    at least one processor in communication with the acoustic logging tool, in which the processor is coupled to a non-transient computer-readable storage medium on which instructions are stored which, when they are executed by the at least one processor, bring the at least one processor to:
    selecting a target axial resolution based on the size of an array of receivers;
    obtaining a plurality of waveform data sets corresponding to a target training area, wherein each waveform data set is acquired at a different firing position;
    calculating a 2D frequency similarity dispersion map for each waveform data set;
    stacking 2D slow frequency similarity maps to generate a stacked 2D similarity map;
    extracting a dispersion curve from the stacked 2D similarity map to generate an extracted dispersion curve; and determining a volume wavelength from the extracted dispersion curve.
    [19" id="c-fr-0019]
    The system of claim 18, wherein the non-transient computer readable storage medium further contains a set of instructions which, when executed by the at least one processor, cause the at least one processor to:
    obtain already known characteristics of a borehole; generating a dispersion model based on the already known characteristics of the borehole;
    generating a self-adaptive weighting function based on the dispersion model and the extracted dispersion curve;
    applying the self-adaptive weighting function to the data of the frequency domain of the extracted dispersion curve to generate a weighted dispersion curve;
    adjusting, using an inversion procedure, the weighted dispersion curve and the dispersion model; and determining a volume wavelength which minimizes the poor fit between the weighted dispersion curve and the dispersion model.
    [20" id="c-fr-0020]
    20. The system of claim 19, wherein the already known characteristics of the borehole are selected from the group consisting of the type of fluid of the borehole, the diameter of the borehole, the density of the formation, the slowness compression, and any combination thereof.
    1/1
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    引用文献:
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    法律状态:
    2018-07-18| PLFP| Fee payment|Year of fee payment: 2 |
    2019-09-26| PLFP| Fee payment|Year of fee payment: 3 |
    2020-04-24| PLSC| Search report ready|Effective date: 20200424 |
    2021-05-07| RX| Complete rejection|Effective date: 20210330 |
    优先权:
    申请号 | 申请日 | 专利标题
    PCT/US2016/058659|WO2018080450A1|2016-10-25|2016-10-25|Enhanced-resolution rock formation body wave slowness determination from borehole guided waves|
    IBWOUS2016058659|2016-10-25|
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