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    • 专利摘要:
    The present invention relates to an improved dispersion analysis method that begins by obtaining a plurality of measured waveforms, for example from two or more receivers of an acoustic logging tool placed in a hole. drilling. The measured waveforms are divided into common groupings, and the waveforms of each common group are improved. The improvement begins with the calculation of a path time curve for a selected target mode of common group waveforms. Using the path time curve, the waveforms of the selected target mode are aligned to have an apparent slowness of zero. The aligned waveforms are filtered to suppress non-target waveforms. The aligned waveforms are then improved, and used to generate an improved dispersion curve of the selected target mode.
    公开号:FR3067745A1
    申请号:FR1854012
    申请日:2018-05-14
    公开日:2018-12-21
    发明作者:Ruijia Wang；Chung Chang
    申请人:Halliburton Energy Services Inc；
    IPC主号:
    专利说明:

    TECHNICAL AREA
    The present technology relates to acoustic logging of borehole waves into an underground borehole and, more specifically, to improved dispersion analysis for target modes of borehole waves.
    BACKGROUND OF THE INVENTION
    Borehole acoustic logging tools are used for a variety of purposes associated with the measurement and characterization of a formation. In general, acoustic logging tools measure different borehole dispersion wave modes propagating along the longitudinal axis of the borehole, and analyze the dispersions of the target modes to determine various geophysical and mechanical properties of the formation through which the particular borehole passes. More specifically, the dispersions characterize the relationships between the slowness of the waves and the number / frequency of the waves, and can be used to provide an overview of the various geometric properties and materials of the borehole and the surrounding formation, such as 3D profiles of slow shear waves in a rock formation and stress distributions around the borehole. In some cases, a particular type of dispersion may be of interest - for example, the aforementioned profiling of the slowness of shear waves in a rock formation is based on an analysis of the dispersions of the bending waves and the dispersions of the helical waves.
    Although it is known that target mode dispersion curves can carry large amounts of information relating to the characteristics of a formation, it is often very difficult to obtain a precise dispersion curve from the start from raw data. of borehole waveform. Many factors can be the cause of significant noise and interference that contaminate the target modes. These factors include, for example, wave scatter due to change in the radius of the borehole, strong anisotropy of the formation, and tool waves not suppressed. In some borehole environments, such as deep water reservoirs and shallow reservoirs, the acoustic signals may be very weak, while other environments may exhibit strong formation anisotropy. In general, a strong heterogeneity of formation invalidates the conventional methods of extraction and analysis of multi-mode dispersion, because these methods all suppose a homogeneous formation in which the slowness of formation does not change along the axis of the hole drilling.
    Further still, whatever the environment of the borehole, the amplitude of excitation of the target modes at certain key frequencies is close to zero, largely due to the physics of the wave propagation of the borehole (for example, the target modes at low frequency asymptotes of the bending waves), which means that the dispersion data at these key frequencies are fundamentally associated with weak signal on noise (S / N). However, this scatter data provides reliable speed information from the surrounding formation, and simply cannot be ignored.
    As such, it can be difficult, even with an ideal acoustic tool consisting of broadband receivers and transmitters, to extract a complete, precise and reliable dispersion curve from raw waveform data. Therefore, it is highly desirable to find an advanced method for improving the raw waveform data in order to suppress the influence of scattering waves, tool waves and other non-target wave modes, and to generate a more precise characterization of the entire dispersion curve, in particular the parts with low S / B.
    BRIEF DESCRIPTION OF THE FIGURES
    In order to describe the manner in which the aforementioned advantages and features and other advantages and features of the disclosure can be obtained, a more specific description of the principles briefly described above will be provided with reference 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 :
    FIG. 1 illustrates a schematic view of a logging operation environment during drilling and / or measurement during drilling of a wellbore;
    Figure 2 illustrates a schematic view of a logging operation environment by transporting a wellbore;
    Figure 3 illustrates a schematic view of an acoustic logging tool;
    Figure 4 illustrates waveform trains from a single depth acquisition of an acoustic logging tool;
    Figure 5 illustrates a schematic view of an acoustic logging tool at various firing positions;
    Figure 6A illustrates a graph of slow shear waves;
    Figure 6B illustrates a graph of journey time curves;
    FIG. 7A illustrates a variable density logging display of trains of waveforms of a grouping with the same offset;
    FIG. 7B illustrates a variable density logging display of aligned waveform trains of a grouping with the same offset;
    FIG. 8A illustrates trains of waveforms of a grouping with the same offset transformed in the F-K domain;
    Figure 8B illustrates the waveform trains of Figure 8A after being filtered;
    FIG. 9 illustrates a fan-shaped F-K filter;
    FIG. 10A illustrates a variable density logging display of trains of 20 filtered waveforms of a grouping with the same offset;
    Figure 10B illustrates the waveform trains of Figure 10A after recovering the original arrival times;
    Figure 11A illustrates the results of a dispersion analysis obtained from unimproved waveform trains;
    Figure 1 IB illustrates the results of a dispersion analysis obtained from improved waveform trains;
    Figure 12 illustrates a graph of improved shear wave slowness;
    Figure 13 illustrates a process diagram of a process of this disclosure;
    Figure 14 illustrates a process diagram of a process of this disclosure;
    FIG. 15A illustrates a conventional architecture of a computer system with a bus system;
    Figure 15B illustrates an example of a chipset architecture.
    DETAILED DESCRIPTION
    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. The specialist in the field 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 disclosed apparatus and methods can be performed using any number of techniques. Disclosure should not in any way be limited to illustrative implementations, drawings and techniques illustrated in this document, but may be modified 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 interaction to 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”, “upward”, “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 more detail below will be readily apparent to those skilled in the art with the aid of this disclosure upon reading the following detailed description, and with reference to the accompanying drawings.
    A dispersion analysis can generally be divided by complexity into basic response products and into advanced response products, both using dispersion curves. The most basic response products, such as estimating the slowness of P waves (primary waves) and S waves (shear waves), use an estimated dispersion curve. For example, low frequency leakage P waves can be used to estimate the slowness of P waves in flexible formation, and low frequency bending waves can be used to estimate slowness of S waves for arbitrary formation. However, a higher quality dispersion curve could produce a corresponding increase in the quality of this slowness estimate. For advanced response products, such as radial profiling of slow shear waves, high quality dispersion curves are essential; reversing the slow radial shear waves will simply not be accurate without a high bandwidth dispersion curve as an input.
    More generally, and more importantly, high quality dispersion curves allow for a wider variety of advanced processing strategies, including data-driven processing methods which introduce multiple adjustable parameters to provide an improved fit between data modeled and measured data, even under extremely difficult conditions. In other words, higher quality dispersion data is essential for the models in order to more closely predict the reality of the properties of a rock formation.
    Conventional model-based processes are often hampered by the need to sweep away theoretical assumptions that are often unrealistic for a real well (for example, the assumption of the homogeneity of a formation, as opposed to the heterogeneity of real world training). Compared to these conventional methods, the method disclosed in the present invention does not need any special hypothesis and greatly increases the reliability of the calculated results.
    In particular, a classic multi-mode dispersion analysis assumes that a training is homogeneous because otherwise the analysis becomes too complex and unreliable to use. In a highly heterogeneous rock formation, there are abrupt change interfaces of acoustic impedance that introduce reflected and converted waves into the measured waveform train, which can lead to the appearance of strong interference. in the dispersion analysis of the desired target modes. In addition, strong heterogeneity can contribute to asymmetric borehole behavior, which subsequently causes excitation of wave displacements of different azimuth orders, resulting in additional interference signals in the dispersion analysis of the target modes. As such, when a classical multi-mode dispersion analysis is used, it is not recommended to separate the target modes from the non-targeted modes in a highly heterogeneous formation. Processing heterogeneously formed waveform trains with conventional multimode dispersion analysis methods is likely to generate ghost modes in the inversion, further blurring the results, or even invalidating them entirely.
    Besides the problems of heterogeneous training, various sources of noise abound. The waves of a tool propagating along the tool, the displacement noises generated by the friction between the shell of a tool and the side wall of the borehole, and other noises of a formation can all contaminate the waveform trains of the desired target modes. In addition, field operations often apply data compression algorithms to reduce the amount of telemetry data that has to be transmitted to the surface over a limited bandwidth cable line. These data compression algorithms generally irretrievably and losslessly introduce more noise into the measured waveform trains. As such, the target mode dispersion curves extracted using conventional dispersion processing are generally considered to be of poor quality due to the complicated drilling environments.
    Some specific borehole modes have low frequency asymptotes which approximate a rock formation volume wave and, as such, can be used for a rock formation volume wave estimate. However, this technique was difficult to practice because, seen in another way, when the slowness of a borehole wave approaches the slowness of a volume wave, the amplitude of excitation of the volume wave is approaching zero. Therefore, these low frequency asymptotes are intrinsically associated with poor S / B and small amplitudes, and are therefore easily biased by noise or other borehole waves, as previously mentioned.
    Consequently, a method is disclosed in the present document which makes it possible both to improve the S / B of the target modes and to remove any non-targeted mode. The disclosed technology addresses this need by using waveform time curves (TT) calculated for each receiver on an acoustic logging tool. Thanks to the use of these calculated TT curves, the trains of measured waveforms which are collected by each receiver can be shifted along the axis of the depth of the borehole to better condition the trains of wave for adaptive filtering purposes. In general, this adaptive filtering is applied to waveform data to improve the S / N of selected target modes while simultaneously removing amplitude (or eliminating) non-target modes and noise. Once the adaptively filtered data is again conditioned with the TT curves, improved dispersion curves can be calculated more precisely than before.
    COLLECTION OF DATA
    The disclosure is now interested in FIG. 1, which illustrates a schematic view of an example of an environment 100 of logging operation during drilling (LWD) and / or measurement during drilling (MWD) on a wellbore, in which the present disclosure can be implemented. 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, the makes it descend through the interior of the drill string 108, through orifices located in the drill bit 114, makes it rise to the surface via the annular space located at the around the drill string 108, and in a retention pit 124. The drilling fluid transports the cuttings from the well bore 116 to the well 124 and participates in maintaining the integrity of the well bore 116. Various materials can be used for drilling fluid, such as oil-based fluids 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 some embodiments, the telemetry fitting 128 communicates with a surface receiver 130 by means of a mud impulse transmission. In other cases, the telemetry fitting 128 does not communicate with the surface, but instead stores the log data for later retrieval at the surface 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 tool 126 may include tools such as those shown in Figures 3 and 4 in order to perform acoustic logging (for example, "sound"). For example, acoustic logging tools may include transmitters (for example, monopole, dipole, quad, etc.) to generate and transmit acoustic signals / waves in the environment of the borehole. Acoustic signals then propagate into and along the borehole and the surrounding formation and create acoustic signal responses or waveforms, which are received / recorded by regularly spaced receivers. These receivers can be networked and can be spaced regularly to facilitate the capture and processing of acoustic response signals at specific intervals. The acoustic response signals are further analyzed to determine the properties and / or characteristics of the borehole and the adjacent formation. 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 / waveforms to operators within the surface or for subsequent access and processing of data for the evaluation of the properties of the formation 118.
    Logging tools 126, including the acoustic logging tool, may also include one or more computing 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 some embodiments, 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 this disclosure can be implemented by a computing device (not shown) at the surface. In some embodiments, the computing device may be included in a surface receiver 130. For example, a surface receiver 130 of an environment 100 of operating a wellbore on the surface may include one or more of a telemetry wireless, processor circuit, or memory facilities, to facilitate substantially real-time processing of data received from one or more of the logging tools 126. In some embodiments, the data is processed some time after data collection, in which data can be stored at the surface at the surface receiver 130, stored downhole in telemetry fitting 128, or both, until it is retrieved for purposes treatment.
    FIG. 2 illustrates a schematic view of a transport logging operation environment 200 on a wellbore (also designated by “cable line” in the field) in which the present disclosure can be implemented. 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 with a transport system 242 to raise or lower equipment, such as the acoustic logging tool 210, in or out of a borehole. The acoustic logging tool 210 can comprise, for example, tools such as those shown in FIGS. 3 to 4. A transport system 242 can allow communication between the acoustic logging tool 210 and a logging installation 244 to the surface. Transport system 242 can include wires (one or more wires), smooth cables, cables, or the like, as well as tubular transport systems such as a coiled tube, a hinge tube, or the like tubular elements, and may include a downhole tractor. In addition, energy can be supplied through the transport system 242 to meet the energy requirement of the tool. The acoustic logging tool 210 may have local electrical power, such as batteries, a downhole generator and the like. When a non-conductive cable, a spiral tube, a drill string, or a downhole tractor is used, communication can be ensured using, for example, wireless protocols (e.g., EM, acoustics, etc. ), and / or the measurements and logging data can be stored in local memory for later retrieval. 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 the formation 218 can be obtained using the acoustic logging tool 210 and processed by a calculation device, such as the calculation device 250. In certain embodiments, the calculation device 250 is equipped to process the information received substantially in real time, while in some embodiments, the computing device 250 may be equipped to store the information received for processing at a later time.
    Figure 3 illustrates a schematic view of an acoustic logging tool 300 capable of implementing the methods and techniques disclosed in this document according to some exemplary embodiments of this disclosure. As can be seen in FIG. 3, the acoustic logging tool 300 comprises at least one transmitter, T, capable of exciting acoustic signals / waves of different azimuth orders, although other transmitters may be provided if desired. The acoustic logging tool 300 also comprises a network of receivers 330 comprising a number of receivers, illustrated here by the thirteen receivers Ri to R13. The receivers can be spaced evenly along the logging tool 300, or can be arranged in other patterns as desired. As shown, Ri to Ru receivers are spaced evenly with a 0.5 foot 340 spacing, as with the Xaminer® Sonic Image Tool (XSI), available from Halliburton Energy Services, Inc.
    As illustrated, the transmitter T is separated from the first receiver Ri by a spacing 320, illustrated here by approximately nine feet. The wide coverage receiver network is capable of capturing an acoustic wave field of different orders of azimuth. In such an acoustic logging tool 300, the axial resolution of the slowness logs 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.
    Figure 4 illustrates an example of waveform trains of a single depth acquisition, as recorded by the thirteen receivers of the acoustic logging tool 300 of Figure 3. At a certain time index less than 0 , the transmitter T generated an acoustic wave in the borehole. The acoustic wave then propagates along the borehole, through the transmitter-receiver separation 320, before first reaching the receiver Ri, as indicated by the fact that the receiver R; is the first to record waveform data. The same acoustic wave continues forward, past receivers R2 through R13, where it is recorded in turn. It should be noted that, although these 13 waveforms are all a consequence of the same original acoustic wave, they are not identical, each train of waveforms containing variations induced by the formation properties ( desirable) and noise (not desirable). As disclosed herein, these raw measured waveform trains can be improved to isolate desired target modes for analysis while removing noise and non-target modes.
    In order to obtain a more complete data set, acquisitions at multiple depths are generally carried out. That is, the acoustic logging tool is moved to various firing positions within the borehole, and acquires depth at each. FIG. 5 illustrates a schematic view of an acoustic logging tool 300 lowered into a wellbore in a formation 550 in order to collect trains of waveforms at a plurality of firing positions. In the context of the disclosure, a firing position refers to a particular depth index within a borehole. As shown in FIG. 5, the acoustic logging tool 300 can be lowered to a first indication of depth in the borehole corresponding to the position indicated by "Shot 1", which is followed by the triggering of the transmitter and capture of waveform trains at each R / to R13 receiver in the receiver network. The acoustic logging tool 300 can then be raised to a second depth index in the borehole corresponding to the position indicated by "Shot 2" and the measurement process repeated. This measurement process can be repeated as many times as desired, so that each receiver Rj to Ri3 measures a train of waveforms at each selected depth index. Although FIG. 5 presents a scenario in which an acoustic logging tool 300 is raised in subsequent firing positions, the acoustic logging tool 300 can start at the position indicated by "Firing 9" and be successively lowered to the position indicated by "Shot 1", or can be moved in any other desired order of measurement positions. In this way, abundant waveform trains can be collected in a borehole. As shown, once the sampling process is complete, the acoustic logging tool 300 will have acquired 117 waveform trains - 13 receivers each acquiring 9 waveform trains. In some embodiments, the measured waveform trains can be organized based on their offset, or distance, from the transmitter T. This is generally known as grouping with the same offset. In some embodiments, the measured waveform trains can be organized based on the position of the receiver where they are received (i.e., a receiver depth position). This is commonly known as grouping by common receiver.
    In the particular case of the acoustic logging tool 300, the receivers Ri to Ri3 are all separated along the longitudinal axis of the logging tool 300 (i.e. they are all at one different distance from the transmitter). In some embodiments, the data captured by the acoustic logging tool 300 can be organized in a grouping with the same offset, which refers to a set of data sent by the same transmitter and captured by the same receiver at various positions. of different depth, that is to say different shots. Various other groupings are also known in the art, and may as well be used in the present disclosure.
    An example of an improved waveform generation method for a single receiver, Rj, is presented below, although the method can be extended to any number of receivers provided on the acoustic logging tool. Similarly, although the figures relate to the specific example of the receiver Ri, it is understood that they are representative of any receiver used according to the present disclosure. Specific reference is made to a grouping with the same COGi offset for the R / receptor, although it is understood that various other groupings known in the art can be used.
    IMPROVEMENT OF THE WAVEFORM TRAINS OF A COMMON GROUPING
    The disclosure now turns to a specific example of improving waveform trains of a common grouping, the common grouping being the grouping of the same COGi offset with the receiver R } . The example uses the logging tool 300, although it will be understood that other logging tools with various transmitter and receiver configurations can be used without departing from the scope of this disclosure. Although the concept of grouping with the same offset is explained above, a visual representation of a grouping with the same offset COGi can be observed on the display VDL 701 of FIG. 7A, discussed in more detail below. This example relates to the calculation of a dispersion of bending waves in the borehole of a flexible formation, although it is understood that the disclosed method can be applied in the same way to any dispersion analysis of drill hole.
    The example assumes that the logging tool 300 (as in Figure 5) was used to take 51 individual depth acquisitions, as described above, at depth indices 1 to 51. Therefore, grouping the same COGi offset consists of 51 trains of waveforms - one for each depth index. (12 other groupings with the same COG2-COG 13 offset can also be registered, although again, this example only concerns only one grouping with the same COGi offset).
    FIG. 6A is a graph 600 of the slowness of the shear waves 510 extracted from the set of measured data, covered by its dispersion metric QC 520. Although the first two digits of each depth measurement have been occulted and replaced by "X", the spacing between consecutive depth labels is constant, for example five feet separate X, X05 from X, X10, which is itself five feet from X, X15, and so on. In the context of the logging tool 300 (as in Figure 5), the graph 600 can be obtained by obtaining measurements at multiple firing positions in the borehole. For example, a single shot with the 13 receivers of the logging tool 300 will extract a slowness value at the specific depth of shot. Repeating the measurement and processing at all depths allows the construction of the graph 600 in order to obtain an extracted shear wave slowness 510, also known as delta-T logging (DTXX), and the QC metric. of dispersion 520. In other words, the graph 600 can be obtained by processing the 13 receivers (or however many receivers are provided on a given logging tool), depth by depth.
    In this example, bending waves are the selected target mode, as their low frequency asymptote approximates the slowness of the shear waves of the surrounding rock formation. Graph 600 presents information of relatively low quality the QC metric of dispersion 620 presents a discontinuity 615 compared to the depth and the slowness of shear waves 610 is unstable - suggests that the measured waveform trains of the grouping of same COG offset; are contaminated by the presence of noise and non-target modes. Taken in combination, discontinuities, instability and missing data are highly undesirable when performing any dispersion analysis, and may make it impossible to perform any advanced processing.
    Graph 600 also shows the effects of heterogeneity in the formation, or of layers with different physical and geological properties. This is most evident through the multiple variations of slowness with depth, since a given wave will propagate either faster or more slowly through various materials. If one remembers, according to FIG. 3, that an acoustic wave travels at a fixed distance 320 (that is to say, a common offset) from the transmitter ^ to the receiver R / in each of the 51 acquisitions, it is better to understand why the heterogeneity of the formation is manifest in this curve of slowness of shear waves 510. For example, the depth 632 indicates an approximate slowness of 180 ps / foot, and the depth 634 indicates an approximate slowness of 225 ps / foot. These slowness values may indicate that the composition of the formation changes between depth 632 and depth 634, as will be appreciated by those skilled in the art.
    However, it may also be desirable to attenuate this effect of heterogeneity of formation by the alignment of the arrival time of the bending waves (that is to say, the waves of the target mode) in the 51 trains of waveforms contained in the grouping of the same COGi offset. Such a process begins with the calculation of travel time curves (TT) for the selected target mode.
    FIG. 6B represents the journey time curves 640 which have been calculated for the 13 receivers Ri to R13, where each receiver has a corresponding calculated journey time curve TTi to TT 13. The first two digits of each measurement have been hidden by an "X", as in FIG. 6A. It should be noted that Figures 6A and 6B share a common vertical axis, for example X, X05 indicates the same depth in both figures. Although the present example relates only to the receiver Ri, it may be desirable, in the interests of time and efficiency, to calculate the travel time curves for all the receivers at the same time. In general, these travel time curves reflect the ability of the formation, at a given depth, to transmit acoustic waves. For example, training is slower, and has a longer journey time, at X, X45 feet than at X, X55 feet. In order to generate the travel time curves, the slowness of the waves is integrated according to the following equation, z = z "„ r = r (z) r = r (z)
    TT n { z ) ~ fs (z) dz + js mud dr + s mud dr r = r ^ z = z-.
    r = r R (1) in which n represents the index of the receiver (for example 1-13), s represents the approximate wavelength of the target mode (for example, the wavelength 510 of FIG. 5A) , and Smud indicates the slowness of the mud, a known property. Zr and Zr represent the depths of the transmitter and the receiver for the acquisition of the instant, respectively, and Γτ and ^ represent the radial positions of the transmitter and the receiver, respectively. indicates radius data corresponding to the measured borehole. Generally, three elements are included in the equation, z = z s „
    J s (z) dz where the one on the left z = z r is the travel time of the wave along the formation, and the two r = r (z) r = r (z) $ s muddr + js mud dr right elements r = rT r = r, i represent the delays of movement of the wave through the fluid of the borehole.
    Once calculated, the displacement path curve TTi can be used to align the bending waves (i.e., target mode waves) of the grouping with the same offset COGi, so that the measured bending waves at each depth index all have the same arrival time, or in other words, have a slowness / zero apparent wave number. In certain embodiments, it may be desirable to simultaneously carry out this alignment on the groupings of the same offset remaining COG 2 to COG13 using the travel time curves TT2 to TT 13.
    We will now specifically refer to FIG. 7A, which presents the measured waveform trains of the grouping of the same offset COGi in a variable density logging display (VDL) 701. Visualized differently, each horizontal band of the display VDL 701 represents a single train of waveforms measured by the Ri receiver, and as shown, has an approximate resolution of 0.5 feet, although other resolutions can be obtained with different configurations of receivers and d sound logging tool. Upon examination, the trailing P waves 710, the flex waves 720, the scattering waves (S waves) 730, and the traveling noise 740 are visible through the 51 waveform trains of the grouping of the same offset COGi. In order to improve the COGi waveform trains, it is desirable to eliminate or reduce the presence of all except 720 mode target mode bending waves.
    In order to do this, the travel time curves 640 are used to compensate for the heterogeneity of the formation by adjusting the arrival time of the bending waves as follows:
    WAV (t, z) = WAV raw (t-TT (z), z) (2) where WAV raw and WA V indicate the waveform trains before and after alignments, t indicates the time index, and z indicates the depth index along the borehole. In this example, equation (2) is applied 51 times, once for each of the waveform trains obtained at the depth index z = 1, ..., 51.
    The results of the alignment of the grouping with the same offset COGi are observed on the display VDL 702 of FIG. 7B. It should be noted that the bending waves are now aligned to have substantially the same arrival time, regardless of the depth index at which a train of waveforms has been recorded (i.e. the black and white wave fronts observed in the area of the bending waves are now substantially vertical and straight, instead of being curved). Indeed, after alignment, the bending waves of the target mode are the waves which have the same arrival time (slowness / zero apparent wave number) at different depths, while all the other non-targeted modes have different arrival times at different depths.
    In order to suppress or eliminate these non-target modes and noise, an adaptive filter is applied to the aligned waveform trains, as described below. However, before applying the adaptive filter, the grouping of the same aligned COGi offset must first be transformed from the time domain into the frequency-wave number (F-K) domain. The transformation can be provided through a two-dimensional fast Fourier transform (FFT) as follows:
    XX {f, k} = fft2 (WAV {t, z}} (3) where fft2 represents the two-dimensional FFT function, WAV (t, z) represents the trains of aligned waveforms from equation (2) , and XX (fk) represents the transformed waveform trains.
    FIG. 8A represents a representation FK 801 of the transformed waveform trains of the grouping of the same offset COGi aligned, that is to say the waveform trains observed on the display VDL 702 of FIG. 7B after have undergone 2D FFT described in equation (3). The bending waves of the target mode 810 form a concentrated clear group along a vertical axis of zero wave number. Two non-target mode wave areas, 714 and 715, are visible on the left and right, respectively, of the bending waves 810. A low-frequency displacement noise 820 is observed in the low frequencies, through a large variety of wave numbers.
    Zero fill can also be applied while performing 2D FFT, especially in cases where a limited number of samples are concerned with depth (i.e., the number of depth indices) is limited. The data may have limited sampling along the depth axis due to the optimizations required to maintain both the accuracy and resolution of the final processing results. This limited depth data manifests itself in the form of scattered spectral data along the wave number axis in the F-K domain. To solve this problem, some embodiments may use zero padding after the main waveform data along the depth axis.
    As soon as the waveform trains of the grouping with the same offset COGi aligned are transformed into the FK domain, the transformed waveform trains can be filtered, in this case by applying a filter adaptive. The adaptive filter is designed to pass all waveform trains having the same arrival time and to decrease the amplitude of the waveform trains having different or random arrival times. In some embodiments, the adaptive filter can be designed to decrease the amplitude of the noise. Various filters can be used to provide a framework for this adaptive filter, including the median filter, the discrete Radon transform (DRT), or the frequency and wave number filter (F-K). An adaptive filter based on the F-K filter is presented below, although it will be understood that other adaptive filters may be used without departing from the scope of this disclosure.
    FIG. 9 represents an example of an FK 900 filter, having a fan-shaped bandwidth 910 and a stop band 920. It should be noted that, of course, the FK 900 filter is presented in the FK domain, rather than in the time domain. The F-K 900 filter can be constructed with the fll (f, k) function, as follows:
    fl if k <max (k Thr , 27rfs Thr ) and k> - max (k Thr , 27rfs Thr ) 0 else (4) where / indicates the frequency, k indicates the wave number (measured here in feet ' 1 ) , ^ rhr indicates a lower threshold of wave number, and Srhr indicates a lower threshold of apparent slowness.
    k ç
    By adjusting the threshold of the wave number Thr and the threshold of apparent slowness Thr , the filter FK 900 can be adapted if necessary or desired in order to filter various trains of transformed waveforms.
    With the F-K 900 filter constructed, XX ’(f k) transformed and filtered waveform trains can be obtained as follows:
    Χ ¥ '(/ λ) = χα (/ λ) * // (/ λ) (5) where XX (f, k) represents the transformed waveform trains of the grouping of the same offset COGj aligned and wire (k ) represents the FK 900 filter as described in equation (4), although it is understood that various other filters may be applied without departing from the scope of this disclosure.
    The transformed and filtered waveform trains XX ′ (fk) are illustrated in the representation FK 802 in FIG. 8B, where it can be seen that the bending waves 810 passed through the filter without change, although the zones previously present of non-target mode waves 814, 815, and that the motion noise 820 have been suppressed and eliminated. Transformation to the frequency domain allows aligned target mode waveform trains to be identified and stored more efficiently, while also enabling the most efficient filtering and elimination of non-mode waves. targeted and noise.
    In some embodiments, an adaptive FK filter can be constructed based on the set of measured waveforms themselves, using a coherence function. A coherence map between waveforms at different depths can be calculated within the wave number (-k, k) and frequencies (0, f) to form an FK filter based on the coherence wire co h (fk), which passes highly coherent signals and removes incoherent noise:
    ^ (Z) exp (—- 1) <(/> „(/) (6) where f indicates the frequency again and k indicates the wave number, N represents the total number of waveforms, n represents the waveform index, represents
    X * the spectral of the nth waveform in the frequency domain, indicates the complex conjugate of, and a indicates an interval of average sampling depth of the waveform data. The coherence-based FK filter can be added to the fan-shaped 900 FK filter to give an adaptive FK filter that allows only the desired signals (i.e., target mode) and having the best coherence of pass through, as follows (in which * represents the convolution operator):
    The filters described in equations (6) and (7) can be substituted in equation (5) and replace the filter FK 900 when generating the transformed and filtered waveform trains XX '(f, k) . It is further understood that various other filters can be used in conjunction with equation (5) if desired, in substitution for or in addition to the FK900 filter.
    After being filtered, it is no longer necessary for the waveform trains to remain in the F-K domain. The filtered time domain waveform trains can be retrieved from the transformed and filtered waveform trains through an inverse two-dimensional FFT:
    1Κ4Γ (ί, ζ) = ζ # ζ2 (Χ ¥ '(/ Λ)) (8) where WAV' (t, z) represents the filtered waveform trains in the time domain, ifft2 represents the FFT 2D function inverse, and XX '(fk) represents the transformed and filtered waveform trains from equation (5).
    Figure 10A illustrates a VDL 1001 display of the filtered waveform trains described in equation (8). Compared to unfiltered waveform trains that can be seen on the VDL 702 display, the filtered waveform trains no longer contain non-target modes (for example, leakage P waves , scattering waves) and noise (for example, traveling noise). Instead, only the 1020 aligned bending waveforms remain. The bending waveforms 1020 have undergone significant jitter and the other noises have been eliminated, and it is observed that they are much smoother. It should be noted that, although back in the time domain, the filtered waveform trains still contain the alignment of the travel times made by equation (2). As is, it is necessary to recover the original arrival times for the train of bending waveforms at each of the 51 particular depth indices of the grouping with the same offset COGi, which can be done by l application of the corresponding journey time curve (here, TT /) as follows:
    WA V improved (t, z) = WA V '(t + TT (z), z) (9)
    FIG. 10B illustrates a VDL 1002 display of improved waveform trains for the grouping of the same offset COGi, that is to say the original arrival times for each of the 51 waveform trains filtered were recovered via the application of equation (9). The target mode 1021 bending waveform trains remain strongly expressed, but have been significantly improved compared to the measured waveform trains of the VDL display 701 in Figure 7A. At this point, the improvement process for the grouping of the same COGi offset from the receptor Ri is finished, and the disclosure now turns to an improved dispersion analysis.
    IMPROVED DISPERSION ANALYSIS
    After the 13 groupings with the same offset COGi to COG13 have been improved according to the above disclosure, an improved dispersion analysis can be implemented. For example, the dispersion analysis can be performed via an appearance of differential phase frequency.
    FIG. 11A represents the results of the dispersion analysis 1101 obtained with unimproved waveform trains of groupings of the same offset COGi to COG13, while FIG. 11B represents the results of the dispersion analysis 1102 obtained with the improved waveform trains of this disclosure.
    The dispersion analysis results 1101 contain a dispersion curve 1120 which has been fitted to the calculated dispersion data 1121. The dispersion curve 1120 and the dispersion data 1121 are superimposed with a correction map 1115, and it is observed that the correlation is generally not more than 0.7.
    The improved dispersion analysis results 1102 contain an improved dispersion curve 1130 which has been fitted to the improved calculated dispersion data 1131. The improved dispersion curve 1130 and the improved dispersion data 1131 are superimposed with a correction map 1115, and we observe that the correlation systematically reaches values greater than or equal to 0.9.
    This comparison suggests that the signals after improvement according to the present disclosure exhibit a much better correlation, and an improved overall coherence map. More importantly, better, more reliable results are obtained at both low and high frequencies, where the results of conventional 1101 dispersion analysis have been found to be poor.
    For example, the improved dispersion analysis results 1102 suggest that reliable data can be retrieved for frequencies as low as 0.8 kHz. In addition, the traditional 1101 dispersion analysis results are only capable of recovering reliable data up to 1.5 kHz. In addition, the quality of the mitigation assessed for the target modes has also been improved. This further suggests that the whole waveform signals or trains, and their subsequent dispersion analysis results, are greatly improved by the method of the present disclosure.
    Figure 12 shows a graph 1200 of an improved shear slowness curve 1210 produced by improving the slowness curve 610 of Figure 6A according to the method of the present disclosure, where the shear slowness of the rock formation has was calculated from dispersion selection results. As in Figure 6A, the first two digits of each depth measurement have been obscured and replaced by an "X". It should also be noted that Figure 12 shares the same vertical axis as Figures 6A and 6B, for example X, X05 indicates the same depth in the three figures. Compared to the slowness curve 610, obtained using unimproved waveform trains, the improved shear slowness curve 1210 is much cleaner, and is continuous and smooth, which further suggests that the analysis The dispersion has been improved by the method of the present disclosure. In addition, it should be noted that the missing data in discontinuity 615, at a depth of X, X18 feet, has been recovered entirely on the basis of the improved waveform trains of this disclosure.
    The dispersion analyzes presently discussed all suggest that the method of the present disclosure vastly improves the quality of the dispersion analysis, and provides continuous, stable and precise improved dispersion curves, which are essential for both response products. basic and advanced acoustic logging.
    Figure 13 shows a process diagram 1300 detailing a process of the present disclosure. The method begins with a step 1302, in which formation measurement data is obtained (i.e., an acoustic logging tool measures trains of waveforms at various depth indices, as described below. -above). In some embodiments, this data is obtained substantially before the remaining steps 1304 to 1318. In some embodiments, this data is obtained substantially in real time compared to the remaining steps 1304 to 1318.
    The method then proceeds to step 1304, in which a slowness curve is calculated for a target mode. The target mode can be selected in advance, either by further processing, or through human input. In some embodiments, the target mode is calculated in response to receiving data from the specific training. The same wavelength curve can be used for each receiver in the acoustic logging tool, or multiple wavelength curves can be calculated for the various receivers in the acoustic logging tool.
    The method then proceeds to step 1306, in which the slowness curve is integrated (according to equation (1)) to generate a travel time curve for a common grouping of waveform trains. In certain embodiments, the common grouping can be a grouping by common receiver or a grouping with the same offset. Travel time curves can be calculated individually or calculated collectively at one time. Travel time curves can also be calculated if necessary, immediately before proceeding to step 1308, or can be calculated in advance.
    In a next step 1308, waveform trains of a common grouping are selected, and target mode waveform trains are shifted to have zero apparent slowness. In other words, the arrival times of the target mode waveform trains are aligned. This process can be implemented using equation (2).
    In step 1310, the aligned waveform trains are transformed into the F-K domain via a two-dimensional FFT, as described by equation (3).
    In a subsequent step 1312, an adaptive filter is applied to the transformed waveform trains from step 1310, the adaptive filter letting through the target modes while suppressing or eliminating non-target modes or noise.
    The method consists of a step 1303 for constructing the adaptive filter, which can be implemented at any time after step 1302 and before step 1312. In certain embodiments, the adaptive filter can be built as a parallel operation to steps 1304 to 1310 to generate trains of aligned waveforms in the FK domain. In other embodiments, step 1303 can be inserted into the process diagram between steps 1302 and 1312. The adaptive filter can be constructed, for example, according to equations (4), (6), and ( 7) described above.
    A step 1312 then applies the adaptive filter to the trains of waveforms aligned in the F-K domain, which eliminates the non-targeted modes and the noises but lets the target mode pass. The adaptive filter can be applied according to equation (5).
    As soon as the adaptive filter has been applied, a step 1314 is implemented to transform the filtered waveform trains originating from step 1312 in order to bring them back into the time domain via a two-dimensional inverse FFT, as described by equation (8). In some embodiments, steps 1310 and / or 1314 can be combined with the filtering step, so that 2D FFT and reverse 2D FFT can be applied as part of the filtering process.
    Step 1316 takes an input of the filtered time domain waveform trains from step 1312 and exits from the improved waveform trains. The filtered time domain waveform trains still contain target mode data that has been aligned to have a common arrival time. It is desirable to eliminate this alignment, by applying the same travel time curve as that in step 1308. More specifically, the original arrival time of target mode waveform trains can be retrieved via equation (9), which generates improved waveform trains as an output, with non-target modes and noise suppressed and improved target modes.
    In step 1318, the improved waveform trains are received as input and used to perform an improved dispersion analysis, as detailed above. Dispersion analysis can be performed using a variety of methods and techniques, such as DPFS.
    Figure 14 shows a flow diagram 1400 which can be combined with flow diagram 1300 to implement an alternative workflow method. With this process, the waveform trains for a given common grouping are treated piece by piece, rather than in a continuous group or in a batch. In certain embodiments, steps 1402 to 1406 can be inserted between steps 1302 and 1304 of the process diagram 1300, in order to allow this processing piece by piece.
    The method begins with a step 1402 in which a range of intervals is selected. This interval determines the number of additional waveform trains to be used to effectively frame the selected waveform train for processing. For example, an interval range of two is applied to the depth index 10, then the waveform trains corresponding to the depth indices 8 to 12 will be used to implement the improvement method for the depth index 10.
    In a following step 1404, the depth index for the treatment is selected (that is to say, the selection of the depth index 10). In some embodiments, steps 1402 and 1404 can be implemented at the same time, or in any desired order. In other embodiments, a new range of intervals can be selected in step 1402 whenever desired to select a new depth index in step 1404.
    In a step 1406, the appropriate waveform trains are collected, corresponding to the depth index and the interval range selected. For example, with a depth index of 10 and an interval range of 2, the trains waveforms from depth indices 8 to 12 will be collected and output for processing.
    In a step 1408, the method proceeds to step 1304 of the process diagram 1300, so that the collected waveform trains from step 1406 include the training data obtained in step 1302. At this At the moment, the collected waveform trains coming from step 1406 are processed as described previously, according to steps 1304 to 1314. Step 1314 leaves filtered and improved time domain waveform trains corresponding to l 'selected depth index and the framing depth indices which form the interval range.
    In step 1410, an output is generated for the depth index selected from step 1404. In some embodiments, this is accomplished by selecting a train of waveforms from the median depths or from a middle portion of the filtered and improved time domain waveform trains from step 1408. This train of waveforms is then output as an improved waveform train corresponding to the depth index 10.
    In a step 1412, the improved waveform train for the selected depth index is added to a current or cumulative result, and the method returns to step 1402, where a new depth index is selected. Steps 1402 to 1412 can be repeated for all depth indices contained in the common grouping of waveform trains, until an improved waveform train has been generated for each depth index of the joint grouping. Once the entire common pool has been improved, the process can proceed to step 1316, where all of the improved common pool is released.
    In some embodiments, steps 1408 may instead cause the process to proceed to steps 1308 through 1314, which means that the wavelength and travel time curves do not have to be calculated for each treatment. piece by piece of a range of waveform train intervals. This corresponds to the embodiments previously discussed, in which the travel time curves can be calculated collectively, and in advance.
    The embodiments of the present disclosure provide a new and improved method for improving the S / N of selected target modes and for suppressing untargeted modes and noise. In this way, both measured waveform trains and any subsequent dispersion analysis are improved. Conventional methods can increase the data quality in the source-receiver offset dimension with a simple filter, and therefore improve the data quality of any waveform with good consistency. However, these methods are often inappropriate in complex borehole environments. Furthermore, these methods use a relatively limited network size and do not provide any possibility of automatically suppressing non-target waves. Therefore, they have a limited ability to increase the quality of waveform data. The present disclosure provides an acoustic logging tool and method that operates in the dimension along the depth axis of a borehole, rather than in the conventional dimension of the transmitter-receiver offset. Along the depth axis of a borehole, the present disclosure allows the creation of an appropriate adaptive filter and a technique for improving and reconstructing waveforms with this filter. Thanks to the stacking of waveform trains in the depth axis, S / B is greatly improved and non-target modes are greatly eliminated. The disclosed method significantly increases the quality of response and dispersion analysis, and provides precise and stable dispersion curves for both basic and advanced borehole acoustic data analysis applications.
    FIG. 15A and FIG. 15B illustrate embodiments of systems given as examples. 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. 15A illustrates a conventional architecture of calculation system with bus system 1500, in which the components of the system are in electrical communication with each other by means of a bus 1505. The system 1500 given as example comprises a unit of processing (CPU or processor) 1510 and a system bus 1505 which couples various components of the system, in particular the memory of the system 1515, such as a read-only memory (ROM) 1520 and a random access memory (RAM) 1525, with the processor 1510. The 1500 system can include a high speed memory cache directly connected to, very close to or integrated into the 1510 processor. The 1500 system can copy data from the 1515 memory and / or the 1530 storage device to the 1512 cache for quick access by the processor 1510. In this way, the cache can provide an increase in performance which prevents the processor 1510 from delaying while waiting for data. These and other modules can control or be configured to control the 1510 processor to perform various actions. Another system memory 1515 may also be available for use. Memory 1515 can include multiple different types of memory with different performance characteristics. Processor 1510 can include any universal processor and a hardware or software module, such as module 1 1532, module 2 1534, and module 3 1536 stored in storage device 1530, configured to control processor 1510 as well as a specialized processor where software instructions are incorporated into the design of the processor. The processor 1510 can essentially be a completely autonomous computer system, containing multiple cores or processors, a bus, a memory controller, a cache, etc. A multicore processor can be symmetrical or asymmetrical.
    To allow user interaction with the computing device 1500, an input device 1545 can represent any number of input mechanisms, such as a microphone for speech, a touch screen for gestural or graphic input, a keyboard, a mouse, motion input, speech and so on. An output device 1535 may 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 1500. The communication interface 1540 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 1530 is non-volatile memory, and can be a hard drive or other type of computer-readable medium that can store data that is accessible by a computer, such as magnetic tapes, flash memory cards, solid state memory devices, versatile digital disks, cartridges, random access memory (RAM) 1525, read only memory (ROM) 1520, and their hybrids.
    The storage device 1530 can include software modules 1532, 1534, 1536 for controlling the processor 1510. Other hardware or software modules are envisaged. The storage device 1530 can be connected to the system bus 1505. In one aspect, a hardware module that performs a particular function can include the software component stored in a computer-readable medium in connection with the necessary hardware components, such as the processor 1510 , bus 1505, display 1535, and so on, to perform the function.
    FIG. 15B illustrates an example of a computer system 1550 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 1550 is an example of computer hardware, software, and firmware that can be used to implement the disclosed technology. The 1550 system may include a 1555 processor, representative of any number of physically and / or logically distinct resources capable of executing software, firmware, and hardware configured to perform identified calculations. The processor 1555 can communicate with a chipset 1560 which can control input to and output from the processor 1555. In this example, the chipset 1560 outputs information to the output device 1565, such as a display, and can read and write information to a 1570 storage device, which can include magnetic media, and solid state media, for example. The 1560 chipset can also read data from and write data to the 1575 RAM. A 15150 bridge for interfacing with various 15155 user interface components can be provided for interfacing with the 1560 chipset. These user interface components 15155 can include a keyboard, a microphone, a touch sensing and processing circuit, a pointing device, such as a mouse, and so on. In general, inputs to the 1550 system can come from a variety of sources, generated by a machine and / or generated by a human.
    The 1560 chipset can also interface with one or more 1590 communication interfaces 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 1555 analyzing the data stored in storage 1570 or 1575. In addition, the machine can receive input from a user through the user interface components 15155 and perform appropriate functions, such as interpretation navigation functions of these inputs using the 1555 processor.
    It can be understood that the exemplary 1500 and 1550 systems may have more than one 1510 processor or be part of a group or grouping of networked computing devices together to provide greater processing capacity.
    For clarity of explanation, in some cases, the present technology can be presented as comprising individual function blocks comprising function blocks comprising devices, device components, steps or routines in a process incorporated in software, or combinations of hardware and software.
    In some embodiments, the computer-readable storage devices, media and memories may include a cable or wireless signal containing a bit stream 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 methods according to the examples described above can be implemented using computer executable instructions which are stored or otherwise available from computer readable media. Such instructions may include, for example, instructions and data that cause or otherwise configure a universal computer, a specialized computer, or a universal computing device to implement a certain function or group of functions. Parts of the IT resources used can be accessed over a network. The computer-executable instructions can be, for example, binary instructions of intermediate form, such as an assembly language, firmware or source code. Examples of computer readable media which can be used to store instructions, information used and / or information created in the methods according to the examples described include magnetic or optical discs, flash memory, USB devices with a non-volatile memory, networked storage devices, and so on.
    The devices implementing the methods according to these disclosures can include hardware, firmware and / or software, and can take any various form factor. Typical examples of such form factors include laptops, smartphones, 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 executing in a single device, as an additional example.
    The instructions, the media to route these instructions, the computer resources to execute them, and the other structures to support these computer resources are means for providing the functions described in these disclosures.
    Although various examples and other information have been used to explain aspects within the scope of the appended claims, no limitation of the claims is suggested based on the particular features and arrangements of these examples, as the specialist in the field will be able to use these examples to derive a wide variety of implementations. Furthermore and although certain subjects may have been described in a language specific to the examples of structural characteristics and / or process steps, it is understood that the subject defined in the appended claims is not necessarily limited to these characteristics or described acts. For example, such functionality may be distributed differently or run in components other than those identified in this document. Instead, the features and steps described are disclosed as examples of system and process components within the scope of the appended claims. In addition, the language of the claims mentioning "at least one of" a set indicates that a member of the set or multiple members of the set satisfy the claim.
    DISCLOSURE STATEMENTS INCLUDE:
    Statement 1: An improved dispersion analysis method, the method comprising: obtaining, from two or more two receivers of an acoustic logging tool in a borehole, a plurality of waveforms measured; dividing the plurality of measured waveforms into two or more of two common groupings of grouped waveforms, and improving each common grouping by: calculating a travel time curve for a target mode selected grouped waveforms; aligning the selected target mode waveforms based on the travel time curve to generate aligned waveforms having zero apparent slowness; adaptive filtering of aligned waveforms to suppress waves not belonging to the target mode; and generating improved target mode waveforms based on the filtered waveforms and the travel time curve, the improved target mode waveforms including improved common grouping; and generating an improved dispersion curve of the selected target mode from the two or more of two improved common groupings.
    Statement 2: The method according to Statement 1, in which the acoustic logging tool is moved through a plurality of depth indices in the borehole, so that each of the two or more of two receivers measures a waveform at each depth index of a plurality of depth indices.
    Statement 3: The method according to statement 1, in which the calculation of the travel time curve consists in integrating an estimated slowness curve of the selected target mode.
    Statement 4: The method according to statement 1, in which the adaptive filtering of aligned waveforms involves the application of a median filter, a discrete Radon transform (DRT), or a frequency filter and wave number (FK).
    Statement 5: The method according to statement 4, further comprising the application of a coherence-based FK filter, the coherence-based FK filter being generated by the calculation of a coherence map between forms of wave at different depth indices.
    Statement 6: The process according to statement 4, in which the frequency and wave number filter is fan-shaped in the frequency-wave number domain.
    Statement 7: The method according to statement 1, further comprising transforming the waveforms aligned in the frequency-wave number domain before they are subjected to adaptive filtering, and transforming the waveforms wave filtered in the time domain before generation of the improved target mode waveforms.
    Statement 8: The method according to statement 1, further comprising applying a differential phase frequency appearance to the improved receiver waveform sets to generate the improved dispersion curve of the selected target mode.
    Statement 9: The process according to statement 1, in which the improved target mode waveforms and the improved dispersion curve are generated substantially in real time.
    Statement 10: The process according to statement 1, in which the acoustic logging tool is supplied via a transport system or a drill string.
    Statement 11: The process according to statement 1, in which the common grouping is a grouping with the same offset.
    Statement 12: A system comprising: an acoustic logging tool comprising an array of receivers containing two or more than two receivers, the acoustic logging tool being configured to acquire a plurality of measured waveforms; 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 executed by Tau at least one processor, bring Tau at least one processor: dividing the plurality of measured waveforms into two or more than two common groupings of grouped waveforms; calculating a journey time curve for a selected target mode of each of the two or more of two common groupings; aligning the waveforms of the selected target mode based on the travel time curve to generate aligned waveforms having zero apparent slowness; adaptively filter aligned waveforms to remove non-target waves and generate filtered waveforms; generating improved target mode waveforms based on the filtered waveforms and the travel time curve, the improved target mode waveforms can be divided into two or more than two common groupings of forms improved target mode wave; and generating an improved dispersion curve of the selected target mode from the two or more of two improved common groupings.
    Statement 13: The system according to statement 12, in which the instructions cause the at least one processor to adaptively filter the aligned waveforms by applying a median filter, a transform transform filter of Discrete radon (DRT), or a frequency and wave number filter (FK).
    Statement 14: The system according to statement 13, wherein the non-transient computer-readable storage medium further contains a set of instructions which, when executed by the at least one processor, further bring the least one processor to: generate an FK filter based on coherence by calculating a coherence map between waveforms at different depth indices; and apply the coherence-based F-K filter to aligned waveforms.
    Statement 15: The system according to statement 12, wherein the non-transient computer-readable storage medium further contains a set of instructions which, when executed by the at least one processor, further bring the minus one processor to: transform the aligned waveforms in the frequency-wave number domain before they are subjected to adaptive filtering; and transform the filtered time domain waveforms before the generation of improved target mode waveforms.
    Statement 16: The system according to statement 12, wherein the non-transient computer-readable storage medium further contains a set of instructions which, when executed by the at least one processor, further bring the minus one processor to: apply a differential phase frequency appearance to the improved receiver waveform sets to generate the improved dispersion curve of the selected target mode.
    Statement 17: An apparatus comprising: an acoustic logging tool having an array of receivers containing two or more than two receivers, the acoustic logging tool being configured to acquire a plurality of measured waveforms; 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: divide the plurality of measured waveforms into two or more of two common groupings of grouped waveforms; calculating a journey time curve for a selected target mode of each of the two or more of two common groupings; aligning the waveforms of the selected target mode based on the travel time curve to generate aligned waveforms having zero apparent slowness; adaptively filter aligned waveforms to remove non-target waves and generate filtered waveforms; and generating improved target mode waveforms based on the filtered waveforms and the travel time curve, the improved target mode waveforms can be divided into two or more of two common groupings of improved target mode waveforms.
    Item 18: The apparatus according to item 17, in which the instructions cause the at least one processor to adaptively filter the aligned waveforms by applying a median filter, a transform filter Discrete Radon (DRT), or a frequency and wave number filter (FK).
    Item 19: The apparatus according to item 17, wherein the non-transient computer-readable storage medium further contains a set of instructions which, when executed by the at least one processor, further bring the at least one processor to: transform the aligned waveforms in the frequency-wave number domain before they are subjected to adaptive filtering; and transform the filtered time domain waveforms before the generation of improved target mode waveforms.
    Item 20: The system according to item 17, in which the acoustic logging tool is moved through a plurality of depth indices in the borehole, so that each of the two or more of two receivers measures a waveform at each depth index of a plurality of depth indices.
    权利要求:
    Claims (10)
    [1" id="c-fr-0001]
    1. Method (1300) of improved dispersion analysis, the method comprising:
    obtaining, from two or more than two receivers (330) of an acoustic logging tool (126; 210; 300) in a borehole, a plurality of measured waveforms (1302);
    dividing the plurality of measured waveforms into two or more of two common groupings of grouped waveforms, and improving each common grouping by:
    calculating a travel time curve for a selected target mode of the grouped waveforms (1304);
    aligning the selected target mode waveforms based on the travel time curve to generate aligned waveforms with zero apparent slowness (1308);
    adaptive filtering of aligned waveforms to suppress waves outside the target mode and generate filtered waveforms (1312); and generating improved target mode waveforms based on the filtered waveforms and the travel time curve, the improved target mode waveforms including improved common grouping (1316); and generating an improved dispersion curve of the selected target mode from the two or more of two improved common groupings (1318).
    [2" id="c-fr-0002]
    The method (1300) according to claim 1, wherein the acoustic logging tool (126; 210; 300) is moved through a plurality of depth indices in the borehole, so that each of the two or more than two receivers (330) measure a waveform at each depth index of a plurality of depth indices.
    [3" id="c-fr-0003]
    3. Method (1300) according to claim 1, in which the computation of the travel time curve consists in integrating an estimated slowness curve of the selected target mode.
    [4" id="c-fr-0004]
    The method (1300) of claim 1, wherein the adaptive filtering of the aligned waveforms comprises applying a median filter, a discrete Radon transform (DRT), or a frequency filter and wave number (FK).
    [5" id="c-fr-0005]
    5. Method (1300) according to claim 4, further comprising the application of a coherence-based FK filter, the coherence-based FK filter being generated by the calculation of a coherence map between forms of wave at different depth indices.
    [6" id="c-fr-0006]
    6. Method (1300) according to claim 4, in which the F-K filter is fan-shaped in the frequency-wave number range.
    [7" id="c-fr-0007]
    7. The method (1300) of claim 1, further comprising transforming the waveforms aligned in the frequency-wave number domain before they are subjected to adaptive filtering (1310), and transforming the time domain filtered waveforms before generation of the improved target mode waveforms (1314).
    [8" id="c-fr-0008]
    The method (1300) of claim 1, further comprising applying a differential phase frequency appearance to the improved receiver waveform sets to generate the improved dispersion curve of the selected target mode;
    wherein the improved target mode waveforms and the improved dispersion curve of the selected target mode are generated substantially in real time;
    wherein the acoustic logging tool (126; 210; 300) is supplied via a transport system (242) or a drill string (108), and the common grouping is a grouping with the same offset.
    [9" id="c-fr-0009]
    9. An improved dispersion analysis system (1500; 1550) comprising:
    an acoustic logging tool (126; 210; 300) having an array of receivers (330) containing two or more than two receivers, the acoustic logging tool being configured to acquire a plurality of measured waveforms;
    at least one processor (1510; 1555) in communication with the acoustic logging tool, in which the processor is coupled to a non-transient computer-readable storage medium on which are stored instructions which, when executed by the at least one processor, cause the at least one processor to carry out the method (1300) according to claims 1 to 8.
    [10" id="c-fr-0010]
    10. An improved dispersion analysis apparatus comprising:
    5 an acoustic logging tool (126; 210; 300) comprising an array of receivers (300) containing two or more than two receivers, the acoustic logging tool being configured to acquire a plurality of measured waveforms;
    at least one processor (1510; 1555) in communication with the acoustic logging tool, in which the processor is coupled to a storage medium not
    10 computer-readable transient on which instructions are stored which, when executed by the at least one processor, cause the at least one processor to carry out the method (1300) according to claims 1 to 8.
    类似技术:
    公开号 | 公开日 | 专利标题
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    优先权:
    申请号 | 申请日 | 专利标题
    IBWOUS2017037614|2017-06-15|
    PCT/US2017/037614|WO2018231234A1|2017-06-15|2017-06-15|Enhanced waveform analysis for target modes of borehole waves|
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