Method and system for automatic selection of borehole acoustic events based on a new objective function

Abstract

A method includes obtaining, by a computer processor, acoustic waveforms (220, 320) for each of a plurality of source (108) and receiver (106) locations along a borehole (916) and an acoustic wave propagation velocity of a target event with respect to the plurality of locations. Further, linear moveout corrections are performed on the acoustic waveforms based on the acoustic velocity and the linear moveout corrected waveforms are stacked to generate a stacked waveform (446) at the plurality of locations. The method also includes determining a time of arrival of the target event on the stacked waveform (446) based on an extremum (456) of a first objective function (454) and predicting candidate times of arrival of the target event with respect to the acoustic waveforms at the plurality of locations based on the time of arrival of the target event on the stacked waveform (446) and the acoustic velocity. The method also includes determining a time of arrival of the target event on the acoustic waveforms at the plurality of locations within the borehole based on the candidate times of arrival of the target event and an extremum of a second objective function.

Description

Background Technology

[0001] Engineers and geoscientists working in the oil and gas industry often need to know the propagation characteristics of sound waves in underground rock formations in order to make informed decisions about whether and where to drill to discover and produce hydrocarbons. To determine these characteristics, acoustic instruments can be suspended from the ground on steel cables or attached to a drill string and deployed in a borehole penetrating the underground rock formations. Acoustic instruments typically have at least one sound source for generating sound waves and multiple sound receivers for detecting and recording the sound waves.

[0002] To provide useful information about underground rock formations, acoustic recordings can be processed to reduce noise and determine the characteristics of sound wave propagation, including but not limited to the type of sound wave, the speed of sound propagation, and the time to reach the receiver. Summary of the Invention

[0003] This summary is provided to introduce a series of concepts that will be further described in the following detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to help limit the scope of the claimed subject matter.

[0004] In general, in one aspect, embodiments relate to a method comprising obtaining, via a computer processor, an acoustic waveform for each of a plurality of source and receiver locations along a borehole, and an acoustic propagation velocity of a target event with respect to the plurality of locations. Furthermore, the method includes performing linear time-difference correction on the acoustic waveforms based on the acoustic velocity, and superimposing the linearly time-difference corrected waveforms to generate a superimposed waveform at the plurality of locations. The method further includes determining the arrival time of the target event on the superimposed waveform based on an extremum of a first objective function, and predicting candidate arrival times of the target event with respect to the acoustic waveforms at the plurality of locations based on the arrival time of the target event on the superimposed waveform and the acoustic velocity. The method further includes determining the arrival time of the target event on the acoustic waveform at the plurality of locations within the borehole based on the candidate arrival times of the target event and an extremum of a second objective function.

[0005] In general, in one aspect, embodiments relate to a non-transitory computer-readable medium storing instructions executable by a computer processor, the instructions including functions for obtaining acoustic waveforms with respect to each of a plurality of source and receiver locations along a borehole and acoustic propagation speeds of a target event with respect to the plurality of locations. Furthermore, the instructions include functions for: performing linear time-difference correction on the acoustic waveforms based on the sound speed; and superimposing the linearly time-difference corrected waveforms to generate superimposed waveforms at the plurality of locations. The instructions also include functions for: determining the arrival time of the target event on the superimposed waveform based on an extremum of a first objective function; and predicting candidate arrival times of the target event with respect to the acoustic waveforms at the plurality of locations based on the arrival time of the target event on the superimposed waveform and the sound speed. The instructions further include functions for: determining the arrival time of the target event on the acoustic waveforms at the plurality of locations within the borehole based on the candidate arrival times of the target event and an extremum of a second objective function.

[0006] Other aspects and advantages of the claimed subject matter will become apparent from the following description and the appended claims. Attached Figure Description

[0007] Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying drawings. For consistency, similar elements in the drawings are indicated by similar reference numerals.

[0008] Figure 1 An acoustic logging tool that moves along a borehole according to one or more embodiments is shown.

[0009] Figure 2A , Figure 2B , Figure 2C and Figure 2D The acoustic waveform, spectrum, and sound velocity curve are shown according to one or more embodiments.

[0010] Figure 3A , Figure 3B , Figure 3C and Figure 3D An acoustic waveform according to one or more embodiments is shown.

[0011] Figure 4A and Figure 4B The superimposed waveform and objective function according to one or more embodiments are shown.

[0012] Figure 5A and Figure 5B The acoustic waveform and objective function are shown according to one or more embodiments.

[0013] Figure 6A , Figure 6B , Figure 6Cand Figure 6D The time-pick and QC metrics are illustrated according to one or more embodiments.

[0014] Figure 7 A flowchart according to one or more embodiments is shown.

[0015] Figure 8 A flowchart according to one or more embodiments is shown.

[0016] Figure 9A and Figure 9B A system according to one or more embodiments is shown.

[0017] Figure 10 A computer system according to one or more embodiments is shown. Detailed Implementation

[0018] Numerous specific details are set forth in the following detailed description of embodiments of the present disclosure in order to provide a more thorough understanding of the present disclosure. However, it will be apparent to those skilled in the art that the present disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

[0019] Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as adjectives for elements (i.e., any noun in this application). Unless explicitly disclosed, such as by using the terms “before,” “after,” “single,” and other such terms, the use of ordinal numbers does not imply or create any particular order of elements, nor does it limit any element to a single element. Rather, the use of ordinal numbers is intended to distinguish between elements. As an example, a first element is distinct from a second element, and a first element may contain more than one element and be placed after (or before) the second element in the order of elements.

[0020] The embodiments disclosed in this specification relate to novel methods and systems for obtaining an objective function that is efficient and robust for the automatic selection and tracking of borehole acoustic waveform events. This new objective function integrates four different metrics—similarity, phase, energy ratio, and selection consistency—and serves as the core of a two-pass application of an automatic selection scheme implemented on both stacked waveforms and common receiver gathers. More specifically, the new objective function is formed by a workflow comprising the following steps: First, linear time difference correction is performed on each shot gather to approximate the acoustic waveform in time, and then the approximately aligned acoustic waveform is stacked to highlight the target event. Next, seed points are determined, and using these data points, a first pass of automatic event selection is performed on the stacked waveform to generate a 1D initial selection vector. Subsequently, based on the velocity information of the target wave, an initial 2D event surface is obtained by extending the 1D initial selection vector to each receiver. Finally, a second pass of automatic selection is implemented on the common receiver configuration to produce the final result by optimizing the initial 2D event surface. These steps will be described below with reference to... Figures 1 to 8 Please provide an explanation.

[0021] Figure 1 A sonic logging tool 102 according to one or more embodiments is shown, located at three different acoustic source activation locations 108 within a borehole penetrating subsurface rock formations. The sonic logging tool 102 may be inserted into the borehole on a wireline cable, on a sliding cable, as part of a bottom-of-the-hole assembly (BHA) of the drill string, on a cable passing through the drill pipe, or on a coil. In the illustrated exemplary embodiment, the sonic logging tool 102 has a single acoustic source 104 for controlled radiating of acoustic waves. In other embodiments, the sonic logging tool 102 may have multiple acoustic sources for controlled radiating of acoustic waves. In the illustrated exemplary embodiment, the sonic tool has thirteen (13) acoustic receivers 106 for detecting and recording propagating acoustic waves. In other embodiments, the sonic logging tool 102 may have more or fewer acoustic receivers. According to one or more embodiments, the acoustic source 104 may be positioned at a single axial location on the sonic logging tool 102. In other embodiments, the sound source 104 may be located at different axial positions on the acoustic logging tool 102. Typically, the acoustic receivers 106 may have uniform spacing 112, between 5 cm and 21 cm (2 inches and 8 inches). However, in other cases, the spacing of the acoustic receivers 106 may be irregular and / or random.

[0022] The acoustic logging tool 102 can be operated by activating a sound source 104 at a specific axial location within the borehole and at a specific activation time. After activation of the sound source 104, sound waves are emitted by the sound source, and these sound waves can subsequently be detected and recorded at each sound receiver 106 within a subsequent time window. More specifically, the time series of sound wave amplitudes is detected and recorded by the sound receiver 106. The acoustic logging tool 102 can then move along the borehole axis and repeat the activation of the sound source 104 and the detection and recording process of the sound receiver 106 at adjacent locations 108 along the borehole. The activation of the sound source 104 and the detection and recording of the sound receiver 106 can occur when the acoustic logging tool 102 is stationary in the borehole, but more typically, they can occur as the acoustic logging tool 102 moves continuously along the borehole axis. Overall, the axial spacing between the sound source activation positions 108 is separated by a uniform increment 110, which can be analogous to the distance between the positions of the sound receivers 106 in the sonic logging tool 102.

[0023] The time series of acoustic perturbation amplitudes recorded by each acoustic receiver 106 for each activation of the sound source 104 is represented as an "acoustic waveform". According to one or more embodiments, the perturbation amplitude recorded by each acoustic receiver 106 may be pressure, or pressure fluctuations caused by the sound waves. In other embodiments, the perturbation amplitude may be particle velocity or particle acceleration.

[0024] Figure 2A An acoustic waveform array 220 according to one or more embodiments is shown. The acoustic perturbation amplitude is shown on grayscale 222A, with the horizontal axis listing the acoustic receiver index 214 and the vertical axis showing the elapsed time after the sound source is activated. Figure 2A Each column shows the waveform recorded by one acoustic receiver, represented by receiver indices 214 that make up the x-axis of the diagram. Acoustic receiver 106 with an index of 1 is located closest to the sound source 104, and acoustic receiver 106 with an index of 13 is located furthest from the sound source 104. Figure 2A In the diagram, the 13 acoustic waveforms 220 shown are recorded by 13 acoustic receivers 106 positioned adjacent to each other on the acoustic logging tool 102. Figure 2A The acoustic waveform 220 shown is caused by a single activation of the sound source. It can be seen that the first arriving sound wave 226 passes through multiple sound receivers, first arriving at receiver 106 with exponent = 1 at approximately 0.9 milliseconds (ms), and finally arriving at receiver 106 with exponent = 13 at approximately 1.3 ms. Later arriving sound waves result in later acoustic waveforms.

[0025] Figure 2B It shows Figure 2AAn exemplary embodiment of the normalized spectral amplitude 230 of one of the acoustic waveforms 220 shown. Figure 2B In the example, the maximum normalized spectral amplitude 230 is located at approximately 7 kHz. In other embodiments, the maximum normalized spectral amplitude 230 may be located at a lower frequency (e.g., 2 kHz or lower) or at a higher frequency (e.g., 20 kHz or higher).

[0026] Figure 2C The diagram shows acoustic waveforms 228 recorded by an acoustic receiver with an exponent of 1 at multiple acoustic source activation locations 108 along the borehole. Figure 2C In the figure, the amplitude of the acoustic disturbance is shown in grayscale 222B, the horizontal axis shows the elapsed time after the sound source 104 is activated, and the vertical axis lists the sound source activation positions 108 along the borehole. Figure 2C Each line shows the waveform of a single emission from sound source 104, recorded by sound receiver 106 with exponent = 1. Figure 2C Each waveform shown corresponds to a source-receiver geometry with the same spatial spacing between the sound source 104 and the sound receiver 106. Since both the sound source 104 and the sound receiver 106 are rigidly attached to the acoustic logging tool 102, the sound receiver 106 moves from one axial position in the borehole to the next at the same rate as the sound source 104 moves from one axial position to the next. Therefore, the spatial distance between the sound source 104 and the sound receiver 106 remains constant.

[0027] In each early acoustic waveform 228, the amplitude of the acoustic disturbance changes smoothly and slowly over time. This represents low-frequency noise on the acoustic waveform. Shortly before 1 ms has elapsed, the characteristics of acoustic waveform 228 change, showing rapid oscillations in amplitude. This rapid oscillation represents the first arriving acoustic wave 232 on acoustic waveform 228. Later in acoustic waveform 228, the amplitude and frequency of the oscillations undergo more subtle changes. These later changes represent the later arriving acoustic waves on acoustic waveform 220.

[0028] Even if the spatial distance between the sound source 104 and the sound wave receiver 106 remains unchanged, as described above, Figure 2C The first arriving sound wave 232, visible above, arrives at different times for different sound source activation locations 108. Therefore, it can be concluded that the variation in the arrival time of the first arriving sound wave 232 is due to the variation in the sound wave propagation velocity 234 of the underground rock strata at different sound source activation locations 108 along the borehole. Figure 2D An exemplary embodiment of the sound wave propagation speed 234 is shown in the figure.

[0029] Figure 3A It shows the relationship with Figure 2AThe same acoustic waveform 320 is shown. In addition to acoustic wave 338, which is visible in the later portion of acoustic waveform 320, low-frequency acoustic noise 340 is visible in the earlier portion of acoustic waveform 320. In many cases, low-frequency noise 340 is also present in the later portion of acoustic waveform 320, but is masked or less visible due to the presence of acoustic wave 338. According to one or more embodiments, acoustic waveform 320 can be bandpass filtered to remove low-frequency noise 340, thereby producing... Figure 3B The bandpass acoustic waveform 342 shown is illustrated.

[0030] According to one or more embodiments, linear time-of-flight correction can be applied to multiple sound wave waveforms 320, 342 resulting from a single activation of sound source 104. Linear time-of-flight correction includes selecting a sound wave propagation speed 234 for a target event. The target event can be the first arriving sound wave 232, or it can be a later arriving and slower-propagating sound wave. The sound wave propagation speed 234 is selected... T The input is specified for linear time difference correction. According to one or more embodiments, v T It can be determined based on previous analysis of acoustic waveforms 320 and 342, or according to other embodiments, v T A set of experimental values ​​for the sound wave propagation speed 234 can be selected. Linear time difference correction can align or approximately align with the target event on each sound wave waveform in time.

[0031] Additionally, according to one or more embodiments, the distance x0 from the reference sound source 104 to the sound receiver 106 can be specified as the input for linear time difference correction. Typically, x0 can be selected as the distance between the sound source 104 and the sound receiver 106, but many other x0 values ​​can be used. Linear time difference correction can then be applied by shifting the elapsed time of each sample of the sound waveform to an earlier time, where, for a sound waveform with exponent = i, the shift duration Δt... i It is given by the following formula:

[0032] Δt i =(x i -x0)v T Equation (1)

[0033] Where x i It is the distance between sound source 104 and the i-th sound wave receiver. Figure 3C It shows that by... Figure 3B The bandpass filtered acoustic waveform shown is obtained by applying linear time difference correction to the acoustic waveform 344. Figure 3C The approximate time alignment of the target event on each acoustic waveform is shown after linear time difference correction.

[0034] According to one or more embodiments, the linearly time-difference-corrected acoustic waveform 344 can be combined in a process referred to as "superposition" to produce a superimposed waveform 346. Many superposition forms are known to those skilled in the art. According to one or more embodiments, a simple implementation of superposition involves summing the nth sample from each waveform to be superimposed to give the value of the nth sample in the superimposed waveform 346. For example, the first sample from each waveform to be superimposed is summed to obtain the first sample in the superimposed waveform 346. Similarly, the eleventh sample from each waveform to be superimposed is summed to obtain the eleventh sample in the superimposed waveform 346.

[0035] In other embodiments, the summation of samples can be replaced by averaging of samples. For example, averaging operations may include, but are not limited to, generating the mean, mode, median, harmonic mean, geometric mean, weighted mean, weighted mode, weighted median, weighted harmonic mean, weighted geometric mean, truncated mean, truncated median, truncated harmonic mean, or truncated geometric mean.

[0036] Figure 3D It shows how to overlay Figure 3C The superimposed waveform 346 is obtained by superimposing the bandpass filtered acoustic waveform after linear time difference correction shown. Figure 3D In the image, the same superimposed waveform 346 is displayed in a side-by-side, 13-fold repeating format to facilitate comparison with... Figure 3A The sound wave waveform 320, Figure 3B The bandpass filtered acoustic waveform 342 and Figure 3C The waveform 344 after linear time difference correction is compared with that in the model.

[0037] According to one or more embodiments, Figure 4A A superimposed waveform 446 is shown at multiple acoustic source activation locations 108 along the borehole. Additionally, according to one or more embodiments, Figure 4AThe diagram illustrates a seed point 448 specified on a selected overlay waveform 446 chosen from a plurality of overlay waveforms 446. The arrival time 452 of a target event is selected on the overlay waveform 446, iteratively progressing from the overlay waveform on which the seed point 448 is selected to overlay waveforms with lower indices (shallower) and higher indices (deeper). The overlay waveform on which the arrival time of the target event is selected can be represented as the current waveform C(it), where it indicates a time sample. After the arrival time 452 of the target event has been selected on the current waveform, the current waveform can be time-shifted to align the target event with target events previously selected on other overlay waveforms 446. The time-shifted current waveform can be added to a set of time-aligned overlay waveforms 446, denoted as a reference waveform R(it, iz), where iz indicates the axial position along the borehole (depth) sample. The arrival times 452 of the target event on each reference waveform are aligned with each other.

[0038] In some embodiments, the current waveform may be selected as the superimposed waveform that is closest to the reference waveform above the reference waveform (at a shallower depth) at the axial drilling location. In other embodiments, the current waveform may be the superimposed waveform that is closest to the reference waveform below the reference waveform (at a deeper depth).

[0039] According to one or more embodiments, a first time window 450 may be selected around the seed point 448, such as Figure 4A As shown. The first time window 450 can be arranged symmetrically around the seed point 448, such that the seed point 448 is located at the center of the first time window 450, or in other embodiments, the first time window 450 can be arranged asymmetrically around the seed point 448. According to one or more embodiments, the duration of the first time window 450 can be selected to be 4 to 6 cycles surrounding the superimposed waveform 446.

[0040] According to one or more embodiments, the first objective function 454 can be formed from samples of the current waveform and a reference waveform. The first objective function 454O1 can be written as:

[0041] O1=(w S1 M S +w P1 M P +w R1 M R )*M C Equation (2)

[0042] Among them, w S1 w P1 and w R1These are scalar weights, which users can choose for themselves. These weights can be chosen to be different from each other, or they can be chosen to be the same as each other. All weights can be chosen to be one.

[0043] Vector M S (dt) quantifies the similarity between the current superimposed waveform C(it) and the reference waveform R(it, iz), and can be written as:

[0044]

[0045] Where dt is the time shift between the current waveform and the reference waveform, and the summation over it includes time samples within the first time window of 450, while the summation over iz includes a portion of the reference waveform. This portion of the reference waveform may include one or more reference waveforms that are closest to the current waveform.

[0046] Vector M P (dt) quantizes the phase consistency between the current superimposed waveform and the reference waveform, and can be written as:

[0047]

[0048] Here, μ is a small pre-whitening scalar introduced to ensure numerical stability, and the summation of it includes time samples within a first time window of 450, while the summation of iz includes a portion of the reference waveform. This portion of the reference waveform may include one or more reference waveforms that are closest to the current waveform.

[0049] Vector M R (dt) quantizes the difference in energy ratio between the current waveform and the reference waveform, and can be written as:

[0050]

[0051] Among them, E R (iz) and E C These are the energy ratios of the reference waveform and the current waveform within the first time window of 450, respectively, and the summation of iz includes a portion of the reference waveform. This portion of the reference waveform may include one or more reference waveforms that are closest to the current waveform.

[0052] Vector M C (dt) quantizes the selection consistency between the current superimposed waveform and the reference waveform, and can be written as:

[0053]

[0054] in:

[0055]

[0056] Among them, P R (iz) is the arrival time of the iz-th reference waveform, 452, and dt is the candidate time shift of the current waveform. T c Nz is the duration of one period of the peak frequency of the waveform spectrum, and Nz is the number of waveforms in the portion of the reference waveform included in the sum.

[0057] According to one or more embodiments, the value of a first objective function 454O1 is determined for a range of values ​​of time shift dt. The time shift may include positive and negative time shifts, or may include either positive or negative time shifts. According to one or more embodiments, a maximum value of O1 can be determined, and the value of time shift dt at which this maximum value is located is added to the arrival time of the target event in the reference waveform to determine the arrival time of the target event in the current waveform. The time-shifted current waveform can be added to a previously identified reference waveform, and a new current waveform can be selected.

[0058] Those skilled in the art will readily understand that the first objective function 454 shown in equation (2) can be modified as follows:

[0059]

[0060] Where L is any sufficiently large scalar value. The process of finding the maximum value of O1 given by equation (2) is now completely equivalent to the process of finding the maximum value of the sphere given by equation (9). The process of finding the minimum value. Those skilled in the art will understand that the overall scope of the invention remains unchanged regardless of the variations and / or alternative forms of the objective function that may be employed.

[0061] According to one or more embodiments, Figure 4B The value of the first objective function 454 obtained using equation (2) is shown, along with seed point 448 and a first time window 450 around seed point 448. The values ​​of the objective function are displayed in grayscale. The white line represents the maximum value 456 of the first objective function for each superimposed waveform 446. Figure 4A The target event is plotted with respect to the selected arrival time 452 for each superimposed waveform 446.

[0062] According to one or more embodiments, the arrival time 452T of the target event has been determined for multiple superimposed waveforms 446. st (iz) After that, at each of the multiple acoustic receivers 106, the "candidate" arrival time T of the target event on the acoustic waveform. Cand (j, iz) can be determined as:

[0063] T Cand (j, iz) = T st (iz)+(x j -x0)v TEquation (10)

[0064] Where, x j This refers to the distance from the sound source 104 to the sound receiver 106 for the j-th sound wave receiver, where x0 is the distance from the sound source 104 to the position of the superimposed waveform, and u T It is the velocity of the target event, as described in equation (1). T Cand (j, iz) represents the expected candidate arrival time of the target event on the waveform of the j-th sound receiver 106 for the iz-th sound source activation, based on the arrival time 452 of the target event on the superimposed waveform 446 and the sound wave propagation speed 234 of the selected target event.

[0065] Figure 5A A third acoustic receiver is shown according to one or more embodiments (see Figure 1 The sound wave waveform is 546. Figure 5A The candidate arrival time 548T of the target event on an acoustic waveform 546 with respect to the third acoustic receiver is also shown. Cand . Figure 5A A second time window 550 is also shown. The second time window 550 can be selected to surround the candidate arrival time 548T. Cand ,like Figure 5A As shown. The second time window 550 can be around the candidate arrival time 548T. Cand The symmetrical arrangement results in a candidate arrival time of 548T. Cand Located at the center of the second time window 550, or in other embodiments, the second time window 550 may surround the candidate arrival time 548T. Cand The arrangement is asymmetrical. According to one or more embodiments, the duration of the second time window 550 may be selected to have a shorter duration than that of the first time window 450, although in other embodiments, the second time window 550 may have the same or longer duration as the first time window 450.

[0066] The arrival time 552T of the target event is selected from multiple acoustic waveforms 546 related to the third acoustic receiver. Pick This process can be iterative. According to one or more embodiments, selecting a candidate arrival time 548 of the target event on the acoustic waveform 546 with respect to the third acoustic receiver can initiate an iterative process. Next, either a lower exponent (shallower) acoustic waveform 546 with respect to the third acoustic receiver or a higher exponent (deeper) acoustic waveform 546 with respect to the third acoustic receiver can be selected. To select the arrival time 552T of the target event on it... PickThe acoustic waveform 546 of the third acoustic receiver can be represented as the current waveform C(it), where it indicates the time sample. The arrival time 552T of the target event has already been selected on the current waveform. Pick The current waveform can then be time-shifted to align the arrival time of the target event with that of a previously selected target event on other acoustic waveforms 546 with respect to the third acoustic receiver. The time-shifted current waveform can be added to a set of time-aligned acoustic waveforms, denoted as reference waveform R(it, iz), where iz indicates the sound source location 108 along the borehole. The arrival time 552 of the target event on each reference waveform is aligned with each other.

[0067] In some embodiments, the current waveform may be selected as the acoustic waveform 546 that is closest to the reference waveform with respect to the third acoustic receiver at the axial drilling location, above the reference waveform (at a shallower depth). In other embodiments, the current waveform may be the acoustic waveform 546 that is closest to the reference waveform with respect to the third acoustic receiver, below the reference waveform (at a deeper depth).

[0068] According to one or more embodiments, the second objective function 554 can be formed from samples of the current waveform and the reference waveform. The second objective function 554O2 can be written as:

[0069] O2=(w S2 M S +w P2 M P +w R2 M R )*M C Equation (10)

[0070] Among them, w S2 w P2 w R2 These are scalar weights, which the user can choose. These weights can be chosen to be different from each other, or they can be chosen to be the same as each other. All weights can be chosen to be one. According to one or more embodiments, the weight w S2 w P2 w R2 It can be selected to be weighted separately by w S1 w P1 w R1 The same, or may be chosen to be different in other embodiments. Function M S M P M R and M C The same meanings are retained as those defined in Equations (3), (4), (5), (6) and (7).

[0071] Just as the first objective function 454O1 from equation (2) can be modified to the above equation (9) The second objective function 554O2 can also be modified similarly. Those skilled in the art will understand that the overall scope of the invention remains unchanged regardless of the variations and / or alternatives to the objective function that may be employed.

[0072] According to one or more embodiments, the value of the second objective function 554O2 is determined for a range of values ​​of time shift dt. The time shift may include positive and negative time shifts, or may include either positive or negative time shifts. According to one or more embodiments, a maximum value of O2 can be determined, and the value of the time shift dt at which this maximum value is located is added to the arrival time of the target event in the reference waveform to determine the arrival time 552T of the target event in the current waveform. Pick The current waveform, after time shift, can be added to a previously identified reference waveform, and a new current waveform can be selected.

[0073] According to one or more embodiments, the arrival time 552T of the target event is determined on multiple acoustic waveforms 546 relating to the third acoustic receiver. Pick After selection, the arrival time T of the target event can be selected on multiple acoustic waveforms with respect to other acoustic receivers (e.g., the first, second, or tenth acoustic receiver). Pick According to one or more embodiments, arrival time 552 can be selected sequentially on each sound receiver, starting with a first sound receiver. In other embodiments, arrival time 552 can be selected on each sound receiver in any order. In other embodiments, arrival time 552T of the target event can be selected simultaneously on multiple sound waveforms with respect to all sound receivers. Pick .

[0074] According to one or more embodiments, Figure 6A The final arrival time of the target event with respect to all acoustic receivers 106 and all acoustic source activation positions 108 along the borehole is shown as 652T. Pick (j, iz), where 1 ≤ j ≤ Nr, Nr represents the total number of axial receiver positions on the acoustic logging tool 102, and 1 ≤ iz ≤ Ns, Ns equals the number of acoustic source activation positions 108 along the borehole. Figure 6A In the example shown, Ns = 1200. Figure 6B The same final selection arrival time 652 for the target event is shown in different formats. Each line shows the final selection arrival time 652 of the target event with respect to a single acoustic receiver 106 at multiple different acoustic source activation positions 108 along the borehole.

[0075] According to one or more embodiments, a quality control metric can be determined for the final selection arrival time of a target event. Figure 6C One such quality control metric is shown. Figure 6C The maximum value of the second objective function 654 is shown for each acoustic receiver 106 and the acoustic source activation position 108 along the borehole. Figure 6C This provides an important quality control metric and indicates the reliability of the final selection arrival time 652 for the target event. Lighter shading indicates larger relative values ​​of the maxima of the second objective function 654, and therefore indicates a reliable final selection arrival time. Conversely, darker shading indicates smaller relative values ​​of the maxima of the second objective function 654, and therefore indicates a less reliable final selection arrival time.

[0076] Figure 6D A statistical quality control metric according to one or more embodiments is shown. The solid curves show the average of the maxima of the second objective function relative to the averaged processing of the acoustic receiver 106 for each acoustic source activation location 108 along the borehole. Figure 6D It is also shown with dashed lines Figure 6C The average value of the second objective function shown is added to and subtracted from twice the standard deviation, 662. The presence of fractures, borehole collapses, and lithological transitions is likely the main reason for the uncertainty in the final selection.

[0077] Figure 7 A flowchart according to one or more embodiments is shown. Specifically, Figure 7 The steps involved in creating the objective function described above are detailed. Furthermore, Figure 7 One or more boxes in the middle can be made as follows Figure 10 The execution is performed by one or more components described herein (e.g., a computing system 1000 including a computer processor 1004 and a communication interface 1008). Although Figure 7 The boxes in the document are presented and described in sequence, but those skilled in the art will understand that some or all of these boxes may be executed in a different order, may be combined or omitted, and may be executed in parallel. Furthermore, these boxes may be executed actively or passively.

[0078] In block 702, acoustic waveforms regarding the locations of multiple sources and receivers in the borehole are obtained from surveys acquired using acoustic logging tools. According to one or more embodiments, in block 704, a bandpass filter may be applied to the acoustic waveforms acquired in block 702. In other embodiments, the acoustic waveforms may not be bandpass filtered.

[0079] In block 706, borehole sound velocity profiles are obtained with respect to multiple source locations in the borehole. In one or more embodiments, the sound velocity profiles can be obtained from the acoustic waveforms obtained in block 702 before or after bandpass filtering. According to other embodiments, the sound velocity profiles can be obtained from other measurements.

[0080] In block 708, linear time-difference correction of the acoustic waveform is performed, at least in part, based on the sound velocity of the target event. Furthermore, in block 708, the time-difference-corrected waveforms can be superimposed to generate superimposed waveforms with respect to each of the multiple locations.

[0081] In box 710, the arrival time on the superimposed waveform for each of the plurality of locations is determined at least in part based on the extrema of the first objective function 454. The determination of the extrema is in... Figure 8 It is described in more detail in the middle, and in Figure 8 Described in the context of [the above].

[0082] According to one or more embodiments, in block 712, candidate arrival times of the target event on the acoustic waveforms at multiple source and receiver locations are predicted, at least in part, based on the superimposed waveform arrival times and the sound velocity of the target event. In a preferred embodiment, the candidate arrival times may be predicted by assuming a linear time difference of the target event on the acoustic receiver array.

[0083] In block 714, according to one or more embodiments, the arrival time of the target event on the acoustic waveform at multiple source and receiver locations is determined based on candidate arrival time selection of the target event and the extremum of a second objective function. According to some embodiments, the second objective function may have the same functional form as the first objective function 454. According to other embodiments, the second objective function may have a different functional form than the first objective function 454. In either case, the first objective function 454 takes the superimposed waveform 446 as an input variable, while the second objective function takes the acoustic waveform as an input variable.

[0084] Figure 8 A flowchart according to one or more embodiments is shown, disclosing steps leading to the determination of the arrival time of a target event using the extrema of an objective function. When the waveform is a superimposed waveform 446, Figure 8 The same applies to the first objective function 454 disclosed in equation (2), and when the waveform is an acoustic waveform, Figure 8 The same applies to the second objective function disclosed in equation (10).

[0085] In block 802, according to one or more embodiments, an initial waveform and the arrival time of the target event on the initial waveform and a time window around the arrival time are selected. Furthermore, the initial waveform is defined as a reference waveform.

[0086] In block 804, according to one or more embodiments, a current waveform adjacent to a reference waveform is selected, an objective function based on the reference waveform and the current waveform is evaluated over multiple time shifts between the reference waveform and the current waveform, and an extremum of the objective function is determined. The extremum can be a maximum or a minimum, depending on the form of the objective function selected as disclosed in equations (2) and (9).

[0087] According to one or more embodiments, in block 806, the arrival time of the target event on the current waveform is identified as the sum of the arrival time on the reference waveform and the time shift of the extremum of the target function.

[0088] In block 808, according to one or more embodiments, the workflow checks to determine whether the current waveform is the final waveform for the arrival time of the target event. If the current waveform is the final waveform, the workflow can terminate in block 810. If the current waveform is not the final waveform for the arrival time of the target event, the workflow can proceed to block 812.

[0089] In block 812, according to one or more embodiments, the current waveform can be time-shifted to align a target event with a target event in a reference waveform, and the time-shifted current waveform can be added to a plurality of reference waveforms.

[0090] Figure 9A and Figure 9B A system according to one or more embodiments is shown. Figure 9A As shown, the drilling system 900 may include a top drive rig 910 arranged around a drill bit logging tool 920. The top drive rig 910 may include a top drive 911, which is suspended in a derrick 912 via a traveling block 913. At the center of the top drive 911, a drive shaft 914 may be threaded to the top casing of the drill string 915, for example. The top drive 911 allows the drive shaft 914 to rotate, causing the drill string 915 and the drill bit logging tool 920 to cut rock at the bottom of the wellbore 916. A power cable 917 supplying power to the top drive 911 may be protected within one or more maintenance circuits 918 coupled to a control system 944. Drilling mud can then be pumped into the wellbore 916 via mud lines, the drive shaft 914, and / or the drill string 915.

[0091] Additionally, during well completion, a casing can be inserted into the wellbore 916. The sides of the wellbore 916 may require support, so the casing can be used to support these sides. This allows cement to be injected into the space between the casing and the untreated sides of the wellbore 916 to hold the casing in place. Cement can be forced through the lower end of the casing and into the annulus between the casing and the walls of the wellbore 916. More specifically, a cement plug can be used to expel cement from the casing. For example, the cement plug can be a rubber plug used to separate the cement slurry from other fluids, thereby reducing contamination and maintaining predictable cement slurry performance. A displacement fluid (e.g., water) or appropriately weighted drilling mud can be pumped into the casing above the cement plug. This displacement fluid can be a pressurized fluid used to push the cement plug downwards through the casing to expel cement from the casing outlet and return it upwards into the annulus.

[0092] like Figure 9A As further shown, sensor 921 may be included in sensor assembly 923, which is located adjacent to drill bit 924 and coupled to drill string 915. Sensor 921 may also be coupled to processor assembly 923, which includes a processor, memory, and analog-to-digital converter 922 to process sensor measurements. For example, sensor 921 may include acoustic sensors, such as accelerometers, measuring microphones, contact microphones, and hydrophones. Similarly, sensor 921 may include other types of sensors, such as transmitters and receivers for measuring resistivity, gamma ray detectors, etc. Sensor 921 may include hardware and / or software for generating different types of logging logs (e.g., acoustic logging logs or density logging logs), which can provide well data about the wellbore, including porosity of wellbore sections, gas saturation, formation boundaries in geological formations, fractures in the wellbore or completion cement, and many other information about the formation. If such well data is acquired during drilling operations (i.e., logging while drilling), this information can be used to adjust drilling operations in real time. Such adjustments can include the rate of penetration (ROP), drilling direction, changes in drilling fluid density, and many other drilling parameters.

[0093] In some embodiments, an acoustic sensor may be installed in the drilling fluid circulation system of the drilling system 900 to record acoustic drilling signals in real time. The acoustic drilling signals can be transmitted via drilling fluid for recording by the acoustic sensor located in the drilling fluid circulation system. The recorded acoustic drilling signals can be processed and analyzed to determine well data, such as the lithology and rock physical properties of the formation. This well data can be used for various applications, such as using geological steering to maneuver the drill bit, casing shoe positioning, etc.

[0094] The control system 944 may be coupled to the sensor assembly 923 to execute various programmed functions for the vertical and horizontal guidance of the drill bit 924 through the wellbore 916. More specifically, the control system 944 may include hardware and / or software that geologically guides the drill bit through formations in a lateral well using sensor signals (e.g., drilling acoustic signals or resistivity measurements). For example, the formation may be a reservoir region, such as an oil-producing layer, bedrock, or caprock.

[0095] Turning to geosteering, geosteering can be used to position the drill bit 924 or drill string 915 relative to the boundaries between different subsurface formations (e.g., overlying, underlying, and lateral formations of the producing layer) during drilling operations. Specifically, measuring rock properties during drilling can provide the drilling system 900 with the ability to maneuver the drill bit 924 in the direction of desired hydrocarbon concentrations. Thus, the geosteering system can use various sensors located inside or adjacent to the drill string 915 to determine different rock formations within the wellbore path. In some geosteering systems, the drilling tools can use resistivity or acoustic measurements to guide the drill bit 924 during horizontal or lateral drilling.

[0096] Go to Figure 9B , Figure 9B Examples of using a geological steering system 990 to maneuver a drill bit through lateral oil-producing layers are shown. For example... Figure 9B As shown, the geological guidance system 990 may include Figure 9A The drilling system 900. Specifically, the geological steering system 990 may include functionality for monitoring various sensor characteristics (e.g., acoustic characteristics from acoustic sensors) that change gradually or abruptly as the well path traverses the caprock 930, the producing layer 940, and the bedrock 950. For example, due to the abrupt change in lithology between the caprock 930 and the producing layer 940, the sensor characteristics of the producing layer 940 may differ from those of the caprock 930. When the drill bit 924 drills out of the producing layer 940 and into the caprock 930, the amplitude spectrum detected by a particular sensor type may change abruptly between two different sensor characteristics. Conversely, when drilling down from the producing layer 940 into the bedrock 950, the detected amplitude spectrum may change gradually.

[0097] During lateral drilling of wellbore 916, the preliminary upper and lower boundaries of the formation thickness can be derived from geophysical surveys and / or offset wells obtained prior to drilling wellbore 916. If the vertical section 935 of the well is being drilled, the actual and lower boundaries of the formation (i.e., the actual producing layer boundaries (A, A')) and the producing layer thickness at vertical section 935 (i.e., A to A') can be determined. Based on this well data, the operator can manipulate drill bit 924 in real time through the lateral section 960 of wellbore 916. In particular, logging tools can monitor sensor features detected near drill bit 924, where the detected sensor features can be continuously compared with, for example, previous sensor features of caprock 930, producing layer 940, and bedrock 950, respectively. Thus, if the detected sensor features of the drilled rock are the same as or similar to the sensor features of producing layer 940, drill bit 924 may still be drilling in producing layer 940. In this situation, drill bit 924 can be operated to continue drilling along its current path at a predetermined distance (0.5h) from the formation boundary. If the detected sensor features are the same as or similar to the previous sensor features of caprock 930 or bedrock 950, control system 944 can determine that drill bit 924 has drilled out of oil-producing layer 940 and entered the upper or lower boundary of oil-producing layer 940. At this time, the vertical position of drill bit 924 at this lateral position within wellbore 916 can be determined, and the upper and lower boundaries of oil-producing layer 940 can be updated (e.g., Figure 9B (Positions B and C in the middle). In some embodiments, the vertical positions at the relative boundaries, such as positions B' and C', can be estimated based on a predetermined thickness of the oil-producing layer 940.

[0098] Although Figure 9A and Figure 9B Various configurations of the components are shown, but other configurations may be used without departing from the scope of this disclosure. For example, Figure 9A and Figure 9B Various components can be combined to create a single component. As another example, a function performed by a single component can be performed by two or more components.

[0099] The embodiments can be implemented on a computer system. Figure 10This is a block diagram of a computer system 1002 according to a specific implementation for providing computing functions associated with algorithms, methods, functions, procedures, flows, and programs as described in this disclosure. The computer 1002 shown is intended to encompass any computing device, such as a server, desktop computer, laptop / notebook computer, wireless data port, smartphone, personal data assistant (PDA), tablet computing device, one or more processors within these devices, or any other suitable processing device, including physical or virtual instances (or both) of computing devices. Additionally, the computer 1002 may include: input devices, such as a keypad, keyboard, touchscreen, or other devices capable of accepting user information; and output devices that transmit information associated with the operation of the computer 1002, including digital data, visual or audio information (or a combination of information); or a GUI.

[0100] Computer 1002 may function as a client, network component, server, database, or other persistent storage, or any other component (or combination of roles) in a computer system for performing the subjects described in this disclosure. The illustrated computer 1002 is communicatively coupled to network 1030. In some specific implementations, one or more components of computer 1002 may be configured to operate within an environment including a cloud-based environment, a local environment, a global environment, or other environments (or combinations thereof).

[0101] At a higher level, computer 1002 is an electronic computing device capable of receiving, transmitting, processing, storing, or managing data and information associated with the described subject. Depending on some specific implementations, computer 1002 may also include, or be communicatively coupled to, application servers, email servers, web servers, cache servers, streaming media data servers, business intelligence (BI) servers, or other servers (or combinations thereof).

[0102] Computer 1002 may receive requests from client applications (e.g., executing on another computer 1002) via network 1030 and respond to the requests by processing the received requests in a suitable software application. Additionally, requests may also be sent to computer 1002 from internal users (e.g., from a command console or via other suitable access methods), external or third parties, other automated applications, and any other suitable entity, individual, system, or computer.

[0103] Each component of computer 1002 can communicate using system bus 1003. In some specific implementations, any or all components (hardware or software (or a combination of hardware and software)) of computer 1002 can interact with each other or with interface 1004 (or a combination of both) on system bus 1003 using application programming interface (API) 1012 or service layer 1013 (or a combination of API 1012 and service layer 1013). API 1012 may include descriptions of routines, data structures, and object classes. API 1012 may be independent of or dependent on a computer language and refers to a complete interface, a single function, or even a set of APIs. Service layer 1013 provides software services to computer 1002 or other components (whether shown or not) communicatively coupled to computer 1002. The functionality of computer 1002 is accessible to all service consumers using the service layer. Software services (such as those provided by service layer 1013) provide reusable, defined business functions through defined interfaces. For example, the interface may be software written in JAVA, C++, or other suitable languages ​​that provide data in Extensible Markup Language (XML) format or other suitable formats. Although shown as an integrated component of computer 1002, alternative concrete implementations may be shown as API 1012 or service layer 1013 as a separate component relative to or communicatively coupled to other components of computer 1002 (whether shown or not). Furthermore, any or all portions of API 1012 or service layer 1013 may be implemented as a submodule or sub-module of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.

[0104] Computer 1002 includes interface 1004. Although shown as a single interface 1004 in Figure 9, two or more interfaces 1004 may be used depending on specific needs, expectations, or a particular implementation of computer 1002. Interface 1004 is used by computer 1002 to communicate with other systems in a distributed environment connected to network 1030. Generally, interface 1004 includes logic encoded in software or hardware (or a combination of software and hardware) and operable to communicate with network 1030. More specifically, interface 1004 may include software supporting one or more communication protocols associated with the communication, enabling the hardware of network 1030 or the interface to operate to transmit physical signals both inside and outside computer 1002.

[0105] Computer 1002 includes at least one computer processor 1005. Although in Figure 10The computer 1002 is shown as a single computer processor 1005, but two or more processors may be used depending on specific needs, expectations, or a particular implementation of the computer 1002. Generally, the computer processor 1005 executes instructions and manipulates data to perform the operations of the computer 1002 and any algorithms, methods, functions, procedures, flows, and programs as described in this disclosure.

[0106] Computer 1002 also includes memory 1006, which stores data for computer 1002 or other components (or a combination of both) that can be connected to network 1030. For example, memory 1006 may be a database storing data consistent with this disclosure. Although in Figure 10 The memory 1006 is shown as a single memory 1006, but two or more memories may be used depending on specific needs, expectations, or a particular implementation of the computer 1002 and the functions described. Although the memory 1006 is shown as an integrated component of the computer 1002, in alternative implementations, the memory 1006 may be external to the computer 1002.

[0107] Application 1007 is an algorithmic software engine that provides functionality (particularly with respect to the functionality described in this disclosure) for a specific need, expectation, or specific implementation of computer 1002. For example, application 1007 can be used as one or more components, modules, applications, etc. Furthermore, although shown as a single application 1007, application 1007 can be implemented as multiple applications 1007 on computer 1002. Additionally, although shown as integrated with computer 1002, in alternative specific implementations, application 1007 may be located outside of computer 1002.

[0108] Any number of computers 1002 may exist, associated with or outside the computer system containing computer 1002, wherein each computer 1002 communicates on network 1030. Furthermore, the terms "client," "user," and other suitable sets of terms may be used interchangeably where appropriate without departing from the scope of this disclosure. Moreover, this disclosure envisions a plurality of users using one computer 1002, or a single user using multiple computers 1002.

[0109] Although only a few exemplary examples have been described in detail above, those skilled in the art will readily understand that many modifications can be made to the exemplary examples without substantially departing from the invention. Therefore, all such modifications are intended to be included within the scope of this disclosure as defined by the appended claims. In the claims, the means-plus-function clause is intended to cover structures described herein as performing the listed functions and equivalent structures thereof. Similarly, any means-plus-function clause in the claims is intended to cover actions described herein as performing the listed functions and equivalent actions thereof.

Claims

1. A method for automatically selecting borehole acoustic events, the method comprising: The computer processor (1005) obtains acoustic waveforms (220, 228) for each of the multiple source and receiver locations along the borehole. The computer processor (1005) obtains the acoustic propagation speed of the target event with respect to the multiple source and receiver locations along the borehole (234). The computer processor (1005) performs linear time difference correction on the acoustic waveform based at least in part on the acoustic propagation speed (234) of the target event with respect to the multiple source and receiver locations along the borehole; The computer processor (1005) superimposes the linear time-difference corrected acoustic waveforms to generate superimposed waveforms at the locations of the plurality of sources and receivers along the borehole. The computer processor (1005) determines the arrival time of the target event on the superimposed waveform (446) with respect to each of the plurality of source and receiver locations along the borehole, based at least in part on the extrema of a first objective function (454), wherein the first objective function (454) includes a first scalar weight selected by the user. Using a computer processor (1005), at least in part, a candidate arrival time (548) of the target event with respect to the acoustic waveforms (220, 228) at the plurality of source and receiver locations is predicted with respect to the arrival time of the target event on the superimposed waveform (446) with respect to the plurality of source and receiver locations within the borehole. The computer processor (1005) determines the arrival time of the target event on the acoustic waveforms (220, 228) at the plurality of source and receiver locations within the borehole, based at least in part on the candidate arrival time (548) of the target event and the extreme values ​​of the second objective function (554), wherein the second objective function (554) includes a second scalar weight selected by the user. The computer processor (1005) uses the acoustic waveforms (220, 228) to determine the well path through the underground area of ​​interest; and The drilling and logging of the well path are performed using the drilling system (900).

2. The method according to claim 1, in, Obtaining acoustic waveforms (220, 228) about multiple source and receiver locations along the borehole via a computer processor (1005) also includes bandpass filtering of the acoustic waveforms.

3. The method according to claim 1, in, Obtaining the sound wave propagation speed (234) of the target event with respect to multiple locations along the borehole via the computer processor (1005) further includes: The acoustic propagation speed of the target event is determined from the acoustic waveforms of the multiple source and receiver locations along the borehole (234).

4. The method according to claim 1, in, The first objective function (454) is based at least in part on one or more reference superimposed waveforms and the current superimposed waveform for which the arrival time of the objective event is to be determined.

5. The method according to claim 1, in, The extreme values ​​of the first objective function (454) and the second objective function (554) are selected from the group consisting of the maximum and minimum values ​​of the objective function.

6. The method according to claim 4, in, The first objective function (454) further includes one or more terms that quantify the similarity, phase consistency, energy ratio and time selection consistency between the reference superimposed waveform and the current superimposed waveform.

7. The method according to claim 1, in, Obtaining acoustic waveforms (220, 228) regarding the locations of multiple sources and receivers within the borehole via a computer processor (1005) also includes: Obtain the initial arrival time and the time window surrounding the initial arrival time.

8. The method according to claim 7, in, The first objective function (454) is based at least in part on a portion of the superimposed waveform (446) within a first time window (450) surrounding the initial arrival time.

9. The method according to claim 1, in, Predicting candidate arrival times (548) of the acoustic waveforms (220, 228) at the plurality of source and receiver locations by the computer processor (1005) based at least in part on the arrival times of the superimposed waveforms (446) with respect to the plurality of locations further includes: The arrival time on the superimposed waveform (446) is selected by increasing the product of the sound wave propagation speed (234) of the target event and the distance between the position of the sound wave waveform (220, 228) and the position of the superimposed waveform (446).

10. The method according to claim 1, in, The second objective function (554) is based at least in part on one or more reference acoustic waveforms and the current acoustic waveform for which the arrival time is to be determined.

11. The method according to claim 1, in, The second objective function (554) also includes terms that quantify one or more of the following: similarity, phase consistency, energy ratio, and time selection consistency between one or more reference acoustic waveforms and the current acoustic waveform.

12. The method according to any one of claims 10 to 11, in, The second objective function (554) is based at least in part on a portion of the reference acoustic waveform within a second time window (550) surrounding the candidate arrival time (548).

13. A non-transitory computer-readable medium storing instructions executable by a computer processor (1005) to automatically select borehole acoustic events, the instructions comprising the following functions: Obtain acoustic waveforms (220, 228) for each of the multiple source and receiver locations along the borehole. Obtain the acoustic propagation speed of the target event with respect to the multiple source and receiver locations along the borehole (234); A linear time difference correction is performed on the acoustic waveform based at least in part on the acoustic propagation velocity (234) of the target event with respect to the multiple source and receiver locations along the borehole; The linear time difference corrected acoustic waveforms are superimposed to generate superimposed waveforms at the locations of the plurality of sources and receivers along the borehole (446). The arrival time of the target event on the superimposed waveform (446) with respect to each of the plurality of source and receiver locations along the borehole is determined at least in part based on the extrema of a first objective function (454), wherein the first objective function (454) includes a first scalar weight selected by the user. Based at least in part on the arrival time of the target event on the superimposed waveform (446) with respect to the plurality of locations and the acoustic propagation velocity (234) of the target event with respect to the plurality of source and receiver locations within the borehole, a candidate arrival time (548) of the target event with respect to the acoustic waveforms (220, 228) at the plurality of source and receiver locations is predicted; and The arrival time of the target event on the acoustic waveforms (220, 228) at the plurality of source and receiver locations within the borehole is determined at least in part based on the candidate arrival time (548) of the target event and the extreme value of the second objective function (554), wherein the second objective function (554) includes a second scalar weight selected by the user; The computer processor (1005) uses the acoustic waveforms (220, 228) to determine the well path through the underground area of ​​interest; and The drilling and logging of the well path are performed using the drilling system (900).

14. The non-transitory computer-readable medium according to claim 13, in, Obtaining acoustic waveforms (220, 228) with respect to multiple source and receiver locations along the borehole also includes bandpass filtering of the acoustic waveforms.

15. The non-transitory computer-readable medium according to claim 13, in, The first objective function (454) is based at least in part on one or more reference superimposed waveforms and the current superimposed waveform for which the arrival time of the objective event is to be determined.

16. The non-transitory computer-readable medium according to claim 15, in, The first objective function (454) further includes one or more terms that quantify the similarity, phase consistency, energy ratio and time selection consistency between the reference superimposed waveform and the current superimposed waveform.

17. The non-transitory computer-readable medium according to claim 13: in, Predicting candidate arrival times (548) of the acoustic waveforms (220, 228) at the plurality of source and receiver locations based at least in part on the arrival times over the superimposed waveforms (446) with respect to the plurality of locations further includes: The arrival time on the superimposed waveform (446) is selected by adding the product of the sound wave propagation speed (234) of the target event and the distance between the position of the sound wave waveform (220, 228) and the position of the superimposed waveform (446).

18. The non-transitory computer-readable medium according to claim 13, in, The second objective function (554) is based at least in part on one or more reference acoustic waveforms and the current acoustic waveform (220, 228) for which the arrival time is to be determined.

19. The non-transitory computer-readable medium according to any one of claims 13 to 18, in, The second objective function (554) also includes terms that quantify one or more of the following: similarity, phase consistency, energy ratio, and time selection consistency between one or more reference acoustic waveforms and the current acoustic waveform.

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