Acoustic logging instrument, scale system and borehole correction method

Abstract

The invention discloses an acoustic logging instrument which comprises an acoustic emission acoustic system used for emitting mode waves with different energy levels and different focusing mode combinations to a stratum; the emission acquisition control circuit is used for determining a current emission mode and generating an emission control signal and an energy supply combination mode which are matched with the current emission mode, so that emission energy is provided for the sound wave emission system according to the energy supply combination mode, and the emission control signal is utilized to excite a specified transducer in the sound wave emission system; the sound wave receiving sound system is used for receiving sound wave signals from different directions; and the receiving and collecting control circuit is used for generating acoustic logging data according to the acoustic signals. According to the invention, the precision and accuracy of acoustic logging and acoustic long-distance three-dimensional detection are improved.

Description

Technical Field

[0001] The invention relates to the field of mine geophysical technology, and in particular to an acoustic long-distance three-dimensional well logging instrument, a calibration system and a wellbore correction method. Background Art

[0002] Conventional acoustic logging technology has a shallow detection depth of only tens of centimeters, and can only reflect the formation information around the well wall. It is difficult to evaluate the effectiveness of complex reservoirs such as fractures and caves far away from the wellbore. It is impossible to determine the development and extension of reservoirs outside the well, and it is even more impossible to carry out a detailed description of the three-dimensional geological body, making it difficult to accurately evaluate the three-dimensional body and calculate reserves. The three-dimensional long-distance acoustic detection technology is one of the important directions of the development of logging technology. It is a new generation of acoustic logging technology, an effective means of growing unconventional oil and gas development, and an indispensable method and technology for increasing oilfield reserves and production, detailed reservoir description, cost reduction and efficiency improvement, and optimizing development processes.

[0003] In the existing three-dimensional acoustic wave long-distance detection and imaging technology, longitudinal waves are mostly used for three-dimensional imaging around the well. This imaging method has a narrow frequency band and can detect shallow defects. The detection depth is generally within 20 meters, and the emission is omnidirectional and non-directional.

[0004] In order to implement acoustic detection and description of three-dimensional geological bodies, people began to use long-distance acoustic wave detection instruments, including: longitudinal wave long-distance detection logging instruments and shear wave long-distance detection logging instruments. Both instruments mainly use centered measurement in detection. The characteristic of this instrument is that it can correctly collect surface sliding waves propagating along the well wall only when the wellbore is relatively regular and the lithology of the formation is dense, and then compare them with the reflected waves collected from the anomaly outside the well, and then calculate and determine the direction and shape of the anomaly and other information, providing powerful parameters for formation evaluation. However, these instruments have weak first waves and multiple peaks in irregular boreholes and loose formations. Therefore, it is difficult to obtain reliable sliding direct waves due to the inability to accurately collect the first wave. In addition, there are inconsistencies and errors in the various acoustic wave receivers, transmitters and related acoustic wave processing circuits during measurement, which also causes a significant decrease in the measurement precision and accuracy. Acoustic wave instrument measurement requires the instrument to be located in the center for centered measurement, which cannot be guaranteed in actual measurements in inclined wells and horizontal wells, further reducing the accuracy of the measurement. It is also difficult to determine and calculate the acoustic wave signals reflected from a long distance, and it is even more difficult to determine the direction and identify abnormal bodies outside the well, and it is also difficult to describe and characterize them, let alone complete the acoustic detection and description of three-dimensional geological bodies.

[0005] In addition, in the calibration of the existing acoustic logging instrument, there are usually several implementation methods: the first is to place the acoustic logging instrument flat in a semicircular aluminum tank filled with liquid, and use the arrival time of the first wave to obtain the sound velocity, and then compare the calculated sound velocity with the sound velocity of the aluminum tank. This comparison is only a detection, and its precision and accuracy are low, and it is impossible to complete the calibration and test of the transducer directivity; the second method is to select the free casing to calibrate the acoustic amplitude when performing acoustic amplitude and variable density logging. This calibration has problems. There are three problems: first, free casing is uncontrollable and is not an ideal empty casing; second, human factors are large and there are large errors; third, the instrument cannot guarantee centered measurement, the scale is inaccurate, and it is impossible to complete the calibration and testing of transducer directivity; the third is to place the acoustic logging instrument in a pool for instrument calibration, but this method requires the pool to be large and deep enough, which is difficult to achieve in a workshop environment, and it is impossible to calibrate the sound velocity, nor can it calibrate dipoles and other directional or azimuth acoustic instruments.

[0006] Moreover, traditional acoustic logging instruments (such as dipole / multipole array acoustic logging instruments) are used to measure various types of acoustic signals including monopole, dipole and quadrupole, and extract sound velocity and full wave train information from the collected acoustic signals. Acoustic logging instruments can be used in the petroleum and geological industries, and are used to complete tasks such as calculating porosity, judging lithology and qualitatively identifying gas layers, qualitatively judging fracture development sections, determining geostress direction, calculating rock mechanics parameters, evaluating wellbore stability, predicting and detecting reservoir pressure fracture height and extension direction. However, the measurement process must ensure that the instrument is carried out in the center of the wellbore. Non-centered measurement will cause large errors in sound velocity calculation and anisotropy anomalies, which will reduce the accuracy of later calculation results such as porosity and geostress.

[0007] Nowadays, sonic logging instruments are becoming more and more complex, and the measurement content is increasing, but the problem of instrument calibration has not been effectively solved. In addition, the transmitter and receiver in the sonic logging instrument can only be calibrated by the transmitter and receiver manufacturers, and cannot be regularly tested during the use of the instrument and in the workshop environment. As the instrument is used for a long time, the parameters of the transmitter and receiver will change. If the transmitter and receiver parameters are not corrected and calibrated in time, the accuracy and precision of sonic logging will be adversely affected. In practical applications, with the progress of geological and oil and gas exploration and development, measurement construction in large inclinations and horizontal directions has become more frequent. Therefore, centered measurement is difficult to guarantee under these restrictions. In addition, in the past, the borehole correction of acoustic waves required multi-arm wellbore measurement to obtain more accurate correction results, which increased the amount of on-site construction and increased the construction risk.

[0008] Therefore, the prior art needs to provide a new solution for instrument, scale calibration and borehole correction for acoustic long-distance three-dimensional detection of formations to solve one or more of the above problems, thereby realizing instrument and scale correction for acoustic detection and description of long-distance three-dimensional geological bodies. Summary of the invention

[0009] In order to solve the above technical problems, the present invention provides an acoustic logging instrument, comprising: an acoustic wave transmitting acoustic system, which is used to transmit pattern waves with different energy levels and different focusing mode combinations to the formation; a transmission and acquisition control circuit, which is adjacent to the first end of the acoustic wave transmitting acoustic system, and is used to determine the current transmission mode, generate a transmission control signal and an energy supply combination mode that match the current transmission mode, thereby providing transmission energy to the acoustic wave transmitting system according to the energy supply combination mode, and using the transmission control signal to excite a specified transducer in the acoustic wave transmitting acoustic system; an acoustic wave receiving acoustic system, whose first end is adjacent to the second end of the acoustic wave transmitting acoustic system, and is used to receive acoustic wave signals from different directions; a receiving and acquisition control circuit, which is adjacent to the second end of the acoustic wave receiving acoustic system, and is used to generate acoustic logging data according to the acoustic wave signal.

[0010] Preferably, the transmission and acquisition control circuit includes: a transmission and acquisition control short section, which is connected to the receiving and acquisition control circuit, and is used to receive the transmission control logic signal and generate the transmission control signal and the energy supply combination mode instruction; a plurality of lower energy short sections, which are interconnected in different series-parallel combinations, and are used to form sufficient transmission energy with different lower energy short sections in corresponding series-parallel combinations under the control of the energy supply combination mode instruction.

[0011] Preferably, the sound wave receiving system includes a plurality of groups of sound wave receiving modules, wherein the sound wave receiving module includes a plurality of sound wave receiving units, and the sound wave receiving units in the same sound wave receiving module are evenly distributed along the circumferential direction of the instrument body.

[0012] Preferably, each sound wave receiving unit is connected to the instrument body via a corresponding pair of sliding arms.

[0013] Preferably, during cable logging or drilling tool conveyance logging, the sliding arm is in an unfolded state so that each of the acoustic wave receiving units is in close contact with the well wall.

[0014] Preferably, during logging while drilling, the sliding arm is in a closed state, so that each of the acoustic wave receiving units is embedded in the side wall of the instrument body and forms an isolation channel between the instrument body and the well wall.

[0015] Preferably, the number of sound wave receiving units configured in different groups of sound wave receiving modules is the same, wherein the azimuth angles of the sound wave receiving units in the different groups of sound wave receiving modules are completely staggered.

[0016] Preferably, the sound wave receiving modules are divided into two groups, and one group of sound wave receiving modules is provided with 8 sound wave receiving units.

[0017] Preferably, the sound wave receiving modules are divided into four groups, and one group of sound wave receiving modules is provided with four sound wave receiving units.

[0018] Preferably, the sound wave receiving unit includes a sound wave receiving transducer, a signal amplifying circuit and a bandpass filtering circuit.

[0019] Preferably, the acoustic wave receiving system further comprises: a wellbore detector.

[0020] Preferably, the sound wave receiving system further comprises: a plurality of accelerometers, and the plurality of accelerometers are arranged corresponding to each of the sound wave receiving units.

[0021] Preferably, the sound wave transmitting sound system includes: a near transmitting sound system adjacent to the first end of the sound wave receiving sound system, which is used to transmit high-frequency sound wave signals to the formation; and a far transmitting sound system adjacent to the near transmitting sound system, which is used to transmit low-frequency sound wave signals to the formation.

[0022] Preferably, the near-transmitting sound system includes: a first boosting circuit, which is used to boost the obtained transmission energy to provide the required transmission energy to the high-frequency band sound wave transmission module; the high-frequency band sound wave transmission module has a first transmitting unit, a second transmitting unit and a third transmitting unit, wherein the first transmitting unit, the second transmitting unit and the third transmitting unit form different source distances from near to far with the sound wave receiving sound system in sequence.

[0023] Preferably, the first transmitting unit is a monopole transmitting transducer, and the transmitting frequency range of the first transmitting unit is 20 to 50 kHz; the second transmitting unit is a dipole transmitting transducer, and the transmitting frequency range of the second transmitting unit is 1.2 to 8 kHz; the third transmitting unit is a monopole transmitting transducer, and the transmitting frequency range of the third transmitting unit is 12 to 25 kHz.

[0024] Preferably, the long-range transmitting sound system includes: a second boosting circuit, which is used to boost the obtained transmitting energy to provide the required transmitting energy to the low-frequency band sound wave transmitting module; the low-frequency band sound wave transmitting module has a fourth transmitting unit, a fifth transmitting unit and a sixth transmitting unit, wherein the fourth transmitting unit, the fifth transmitting unit and the sixth transmitting unit form different source distances from near to far with the sound wave receiving sound system in sequence.

[0025] Preferably, the fourth transmitting unit is a monopole transmitting transducer, and the transmitting frequency range of the fourth transmitting unit is 5 to 15 kHz; the fifth transmitting unit is a dipole transmitting transducer, and the transmitting frequency range of the fifth transmitting unit is 0.3 to 3.5 kHz; the sixth transmitting unit is a monopole transmitting transducer, and the transmitting frequency range of the sixth transmitting unit is 1 to 10 kHz.

[0026] Preferably, the azimuth angles of the transducers in the first transmitting unit, the third transmitting unit, the fourth transmitting unit and the sixth transmitting unit are completely staggered.

[0027] Preferably, the azimuth angles of the piezoelectric elements in the second transmitting unit and the fifth transmitting unit are completely staggered.

[0028] Preferably, the receiving and collecting control circuit comprises: an collecting control module, which is used to collect the acoustic wave signals, wellbore measurement signals and acceleration signals obtained from the acoustic wave receiving acoustic system, and perform signal conditioning processing on these signals to form the acoustic wave logging data, wherein the signal conditioning processing includes program-controlled filtering and amplification, amplitude regularization, analog-to-digital conversion and digital signal processing; a communication module, which is used to send the acoustic wave logging data to other downhole instruments for backup storage or transmission to the ground.

[0029] On the other hand, the present invention also provides a calibration system for an acoustic logging instrument, the calibration system comprising: a cylinder; a stabilizer located at the upper part of the cylinder; a standard acoustic transmitter arranged at a first mark on the inner wall of the cylinder; a standard acoustic receiver arranged at a second mark on the inner wall of the cylinder; an acoustic logging instrument as described above, which is located at the center of the cylinder through the stabilizer, wherein the transmitter and the receiver in the logging instrument are aligned with the standard acoustic receiver and the standard acoustic transmitter, respectively; a first control device, which is used to receive and record a first acoustic signal obtained by the standard acoustic receiver in a first test, and to control the standard acoustic transmitter to transmit a second acoustic signal in a second test; a second control device, which is used to control the instrument transmitter to transmit the first acoustic signal in the first test, and to receive and record the second acoustic signal obtained by the instrument receiver in the second test; a data analysis device, which is used to process and analyze the acoustic signals received in the two tests to obtain basic measurement data for calibrating the transmitter and receiver in the logging instrument.

[0030] Preferably, the system further comprises a mobile instrument located on the acoustic logging instrument, wherein the mobile instrument is used to control the movement of each receiving unit in the acoustic wave receiving system so that the acoustic wave receiving unit corresponding to the measured component is aligned with the standard acoustic wave transmitter.

[0031] Preferably, the second control device is also used to control the stop position of the acoustic logging instrument, wherein, when the acoustic logging instrument is at the lower part of the cylinder, the acoustic wave transmitting system is controlled to transmit a reference acoustic wave signal, and then the acoustic wave receiving unit of each component receives and records the obtained reference acoustic wave signal, wherein the data analysis device calibrates the acoustic wave transmitting system and the acoustic wave receiving system by comparing and analyzing the analyzed basic measurement data with the numerical data corresponding to the reference acoustic wave signal.

[0032] Preferably, the upper part of the cylinder is a PPR cylinder, the lower part of the cylinder is a metal cylinder, the bottom of the cylinder is sealed by a wedge sponge rubber, and the top of the cylinder is a detachable metal plate, which is covered with a wedge sponge rubber.

[0033] Preferably, the cylinder is filled with an acoustic wave coupling liquid and the acoustic wave coupling liquid is left to stand for more than 2 hours before the test is carried out, wherein the inner diameter of the cylinder ranges from 200 to 400 mm, and the inner wall of the cylinder is smooth and free of impurities.

[0034] Preferably, the first control device communicates with the second control device via a synchronization signal line, wherein the synchronization signal line is used to transmit a synchronization signal that meets the transmission and reception synchronization requirements in the first test and the second test.

[0035] Preferably, the first control device includes a receiving and communication module, wherein the receiving and communication module includes: a signal receiving and conditioning circuit, which is connected to the standard sound wave receiver, for receiving the first sound wave signal and filtering the signal; a data acquisition circuit, which is connected to the signal receiving and conditioning circuit, for digitally processing the signal output by the signal receiving and conditioning circuit; and a communication interface circuit, which is connected to the data acquisition circuit, for packaging the received digital data and transmitting it to the data analysis device.

[0036] Preferably, the first control device also includes an acoustic wave emission module, wherein the acoustic wave emission module includes: an emission control circuit, which is connected to the data acquisition circuit, and is used to generate an emission control signal after receiving an emission instruction sent by the data acquisition circuit, wherein the emission instruction is issued by the data analysis device and transmitted to the data acquisition circuit through the communication interface circuit; a constant voltage generating circuit, which is used to generate a specified voltage signal required for acoustic wave emission; and an emission driving circuit, which is respectively connected to the emission control circuit, the constant voltage generating circuit and the standard acoustic wave emitter, and is used to convert the specified voltage signal into the second acoustic wave signal under the control of the emission control signal, and apply the second acoustic wave signal to the standard acoustic wave emitter so that the standard acoustic wave emitter emits the acoustic wave signal.

[0037] In addition, the present invention provides a borehole correction method for an acoustic logging instrument, the borehole correction method will perform borehole eccentricity correction on the acoustic signal received from the calibration system described above, the borehole correction method comprising: obtaining the first acoustic signal for a first test transmitted from the standard acoustic receiver and recording a first feature of each first acoustic signal, and obtaining the second acoustic signal for a second test obtained from the instrument receiver and recording a second feature of each second acoustic signal, the features including amplitude, phase, spectrum distribution and energy; normalizing each type of feature data within the first feature and the second feature respectively, based on which, performing system normalization correction on the acoustic logging data of each component; calculating the borehole eccentricity correction parameters of the current logging instrument based on the acoustic logging data of each component after system normalization correction, and performing borehole environment correction processing on the actual acoustic logging data of each component based on the borehole eccentricity correction parameters.

[0038] Preferably, the steps of normalizing the various types of feature data in the first feature and the second feature include: normalizing the amplitude feature, phase feature, spectrum distribution feature and energy feature in the first feature, and normalizing the amplitude feature, phase feature, spectrum distribution feature and energy feature in the second feature, to obtain the transmission amplitude correction coefficient, the reception amplitude correction coefficient, the transmission phase correction coefficient, the reception phase correction coefficient, the transmission spectrum correction coefficient and the reception spectrum correction coefficient, respectively.

[0039] Preferably, according to the transmission amplitude correction coefficient and the reception amplitude correction coefficient, the amplitude of the acoustic logging data of each receiving component is systematically normalized and corrected to obtain the amplitude of the acoustic logging data of each component after normalization correction; according to the transmission phase correction coefficient and the reception phase correction coefficient, the phase of the acoustic logging data of each receiving component is systematically normalized and corrected to obtain the phase or arrival time of the acoustic logging data of each component after normalization correction; according to the transmission spectrum correction coefficient and the reception spectrum correction coefficient, a preset normalized bandpass filter is used to systematically normalize and correct the frequency information of the acoustic data of each receiving component to obtain the frequency information of the acoustic logging data of each component after normalization correction, wherein the acoustic data of each component is systematically normalized using the following expression:

[0040] AMP=(AMP / NTA) / NRA

[0041] PHS=PHS-NTP-NRP

[0042] FRQ=FILTER1(FRQ,NTE,NRE)

[0043] Among them, AMP represents the amplitude array of the sound wave data of each receiving component, NTA represents the transmission amplitude correction coefficient, NRA represents the reception amplitude correction coefficient, PHS represents the phase or arrival time array of the sound wave data of each receiving component, NTP represents the transmission phase correction coefficient, NRP represents the reception phase correction coefficient, FRQ represents the frequency information array of the sound wave data of each receiving component, NTE represents the transmission spectrum correction coefficient, NRE represents the reception spectrum correction coefficient, and FILTER1 represents a normalized bandpass filter.

[0044] Preferably, in the step of calculating the borehole eccentricity correction parameters of the current logging instrument based on the acoustic logging data of each component after system normalization correction, and performing borehole environment correction processing on the acoustic logging data of each component according to the borehole eccentricity correction parameters, it includes: obtaining the amplitude array, phase or arrival time array and frequency array of the acoustic data of each component after system normalization correction, based on which, respectively calculating the amplitude eccentricity correction parameters, phase eccentricity correction parameters and frequency eccentricity correction parameters; performing borehole environment correction on the amplitude of the acoustic logging data of each component according to the amplitude array of the acoustic logging data of each component after system normalization correction using the amplitude eccentricity correction parameters and a preset first weighted correction coefficient, and obtaining the acoustic amplitude array after the borehole environment correction processing for each component. According to the phase or arrival time array of the acoustic logging data of each component after the system normalization correction, the phase eccentricity correction parameter and the preset second weighted correction coefficient are used to perform borehole environment correction on the phase or arrival time of the acoustic data of each component, and the acoustic phase or arrival time data after the borehole environment correction is obtained for each component; according to the spectrum information array of the acoustic logging data of each component after the system normalization correction, the frequency eccentricity correction parameter and the preset third weighted correction coefficient are used, and the preset borehole environment correction bandpass filter is used to perform borehole environment correction on the frequency information of the acoustic data of each component, and the acoustic frequency data after the borehole environment correction is obtained for each component, wherein the borehole environment correction is performed on the acoustic data of each component using the following expression:

[0045] AMP′=Ka*AMP / NA

[0046] PHS′=Kp-PHS-NP

[0047] FRQ′=FILTER2(FRQ,Kf(NE))

[0048] Among them, AMP represents the amplitude array of the acoustic logging data of each received component, PHS represents the phase or arrival time array of the acoustic logging data of each received component, FRQ represents the frequency information array of the acoustic logging data of each received component, NA represents the amplitude eccentricity correction parameter, NP represents the phase eccentricity correction parameter, NE represents the frequency eccentricity correction parameter, FILTER2 represents the borehole environment correction bandpass filter, Ka, Kp, Kf represent the first weighted correction coefficient, the second weighted correction coefficient and the third weighted correction coefficient respectively, AMP′ represents the acoustic amplitude array of each component after borehole correction, PHS′ represents the acoustic phase or arrival time array of each component after borehole correction, and FRQ′ represents the acoustic frequency information array of each component after borehole correction.

[0049] Preferably, the maximum amplitude value of the transmitting source is determined from the amplitude characteristic data of each transmitting sound source, and the amplitude characteristic data of each transmitting sound source is divided by the maximum amplitude value of the transmitting source to obtain the transmitting amplitude correction coefficient; the maximum amplitude value of the receiving end is determined from the amplitude characteristic data of each receiving unit, and the amplitude characteristic data of each receiving unit is divided by the maximum amplitude value of the receiving end to obtain the receiving amplitude correction coefficient; the minimum phase value of the transmitting source is determined from the phase characteristic data of each transmitting sound source, and the minimum phase value of the transmitting source is subtracted from the phase characteristic data of each transmitting sound source to obtain the transmitting phase correction coefficient; the minimum phase value of the receiving end is determined from the phase characteristic data of each receiving unit, and the minimum phase value of the receiving unit is subtracted from the phase characteristic data of each receiver. The receiving phase correction coefficient is obtained by performing a subtraction operation on the data; the main peak frequency and the proportion are first determined from the energy characteristic data of each transmitting sound source, so as to form corresponding transmitting characteristic data for each transmitting source, and finally the minimum transmitting characteristic data is screened out from the transmitting characteristic data of each transmitting source, and the transmitting characteristic data of each transmitting sound source is respectively divided by the current minimum transmitting characteristic data to obtain the transmitting spectrum correction coefficient; the main peak frequency and the proportion are first determined from the energy characteristic data of each receiving unit, so as to form corresponding receiving characteristic data for each receiving unit, and finally the minimum receiving characteristic data is screened out from the receiving characteristic data of each receiving unit, and the characteristic data of each receiving unit is respectively divided by the current minimum receiving characteristic data to obtain the receiving spectrum correction coefficient.

[0050] Preferably, according to the amplitude array corresponding to the acoustic wave data of each component after the system normalization correction, the most normalized amplitude data is extracted therefrom, and the normalized amplitude characteristic data of each component is divided by the most normalized amplitude data to obtain the amplitude eccentricity correction parameter; according to the phase or arrival time array corresponding to the acoustic wave data of each component after the system normalization correction, the minimum normalized phase or arrival time data is extracted therefrom, and the minimum normalized phase or arrival time data is subtracted from the normalized phase or arrival time characteristic data of each component to obtain the phase eccentricity correction parameter; first, according to the spectrum information array corresponding to the acoustic wave data of each component after the system normalization correction, the main peak spectrum and proportion are extracted therefrom, and then the designated passband spectrum information corresponding to the designated proportion in the spectrum information corresponding to the actual acoustic logging data of each component is determined, and finally, according to the main peak frequency and proportion and the designated passband spectrum information corresponding to each receiving unit, the normalized frequency characteristic data of each component is filtered based on the designated bandpass range to obtain the frequency eccentricity correction parameter.

[0051] Compared with the prior art, one or more embodiments of the above scheme may have the following advantages or beneficial effects:

[0052] The invention discloses an acoustic logging instrument, a calibration system and a borehole correction method. The acoustic logging instrument arranges near, far, ultra-far and ultra-far monopoles in the transmitting acoustic system, and the radial circumference is evenly staggered and cross-arranged to form a 22.5° transmitting azimuth, which is 11.25° with the receiving acoustic system multiple groups of multi-arm receivers. Six different frequency bands, 16X16 azimuths, and 16 source distances are used to excite monopole, dipole, quadrupole and other modes of sound waves in different excitation modes, enter the formation in an omnidirectional or directional manner, and are received by a broadband high-sensitivity active acoustic receiver. At the same time, a multi-component accelerometer is used to obtain instrument vibration and noise data to effectively eliminate the noise generated by the vibration of the instrument. The acoustic logging instrument disclosed by the invention can be attached to the well wall for measurement, and has higher precision and better accuracy, is more conducive to the reception and collection of reflected waves, and has a longer detection distance and range, and a higher azimuth resolution. In addition, the calibration and borehole correction method proposed by the present invention for the acoustic logging instrument further improves the precision and accuracy of acoustic logging and three-dimensional acoustic long-distance detection, as well as the applicability in horizontal wells and highly deviated wells, and effectively solves the common problems of low precision and inaccurate measurement in horizontal wells and highly deviated wells in acoustic logging. In addition, the transmitter, receiver and line are calibrated through the new calibration system, which greatly improves the measurement precision and accuracy of the instrument, and the borehole eccentricity correction of acoustic logging highly deviated wells and horizontal wells is carried out to effectively finely characterize the fracture-cavity reservoir beside the well, complete the three-dimensional measurement, calibration and borehole correction of acoustic long-distance, and effectively expand the space and scale of acoustic logging technology.

[0053] The acoustic long-distance three-dimensional detection and imaging logging technology proposed in the present invention can provide longitudinal and shear wave time differences, Stoneley wave time differences, full waveforms, cement bonding quality waveforms, including cross-dipole and monopole measurement results at various distances. In addition to axial and azimuthal measurements, radial measurements can also be performed. In addition, long-distance three-dimensional acoustic reflection wave detection and imaging can also be performed. The measurement results can not only provide useful information for evaluating the drilling environment and reservoirs, but also provide important data for decisions such as improving recovery and maximizing production; not only can it provide valuable data for perforating, completion, sand control, well positioning, reservoir evaluation, and production increase measures, but it can also provide comprehensive information for geophysics, rock physics, and post-casing measurement and cementing quality evaluation and analysis, helping to solve a number of problems that plague exploration and development, from unconventional oil and gas exploration to detailed description, evaluation, and reserve calculation of three-dimensional heterogeneous geological bodies.

[0054] Other features and advantages of the present invention will be described in the following description, and partly become apparent from the description, or understood by practicing the present invention. The purpose and other advantages of the present invention can be realized and obtained by the structures particularly pointed out in the description, claims and drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0055] The accompanying drawings are used to provide a further understanding of the present invention and constitute a part of the specification. Together with the embodiments of the present invention, they are used to explain the present invention and do not constitute a limitation of the present invention. In the accompanying drawings:

[0056] Figure 1-a It is a schematic diagram of the overall structure of the first example of the sonic logging instrument in the embodiment of the present application for drilling tool transportation.

[0057] Figure 1-b It is a schematic diagram of the overall structure of the first example of the acoustic logging instrument of the embodiment of the present application.

[0058] Figure 2 It is a schematic diagram of the distribution structure of the acoustic wave receiving acoustic system in the acoustic well logging instrument of the embodiment of the present application.

[0059] Figure 3 It is a schematic diagram of the cross-sectional structure of the acoustic wave receiving acoustic system in the acoustic well logging tool of the embodiment of the present application.

[0060] Figure 4 It is a schematic diagram of the distribution structure of the acoustic wave emission system in the acoustic well logging instrument of the embodiment of the present application.

[0061] Figure 5 It is a schematic diagram of the cross-sectional structure of a monopole emission set in the acoustic emission acoustic system of the acoustic logging tool in the embodiment of the present application.

[0062] Figure 6 It is a schematic diagram of the cross-sectional structure of a dipole emission set within an acoustic emission acoustic system in an acoustic logging tool according to an embodiment of the present application.

[0063] Figure 7 It is a schematic diagram of the structure of the acoustic wave receiving unit in the acoustic wave logging instrument of the embodiment of the present application.

[0064] Figure 8 It is a structural schematic diagram of the receiving and collecting control circuit in the sonic logging instrument of the embodiment of the present application.

[0065] Fig. 9 It is a structural schematic diagram of the transmission and collection control circuit in the sonic logging instrument of the embodiment of the present application.

[0066] Fig.10 It is a schematic diagram of the overall structure of a second example of the sonic logging instrument of an embodiment of the present application.

[0067] Fig.11 It is a schematic diagram of the overall structure of a calibration system for an acoustic well logging instrument according to an embodiment of the present application.

[0068] Fig.12 It is a step diagram of a wellbore correction method for an acoustic logging instrument according to an embodiment of the present application.

[0069] Fig.13 It is a flow chart of a wellbore correction method for an acoustic logging instrument according to an embodiment of the present application.

[0070] Fig.14 It is a waveform diagram of sonic logging in a wellbore correction method for a sonic logging instrument according to an embodiment of the present application. DETAILED DESCRIPTION

[0071] The following will describe the implementation methods of the present invention in detail with reference to the accompanying drawings and embodiments, so that the implementation process of how the present invention applies technical means to solve technical problems and achieve technical effects can be fully understood and implemented accordingly. It should be noted that as long as there is no conflict, the various embodiments of the present invention and the various features in the embodiments can be combined with each other, and the technical solutions formed are all within the protection scope of the present invention.

[0072] In addition, the steps shown in the flowchart of the accompanying drawings can be executed in a computer system such as a set of computer executable instructions. Also, although a logical sequence is shown in the flowchart, in some cases, the steps shown or described can be performed in a sequence different from that here.

[0073] In order to solve one or more technical problems in the above-mentioned background technology, the present application provides an acoustic logging instrument, a calibration system and a borehole correction method. The acoustic instrument is an instrument for three-dimensional long-distance acoustic wave measurement in a wellbore, and at least comprises four parts: a transmitting acoustic system, an acoustic wave transmitting and collecting control circuit, an acoustic wave receiving acoustic system and an acoustic wave receiving and collecting control circuit. The transmitting acoustic system is equipped with near, far, ultra-far and ultra-far monopoles, and the radial circumference is evenly staggered and cross-arranged to form a 22.5° transmitting azimuth, which is 11.25° with the receiving acoustic system's multiple groups of multi-arm free-style receivers, completing the measurement of 11.25° azimuth acoustic wave resolution; the wellbore detector arranged in the instrument effectively obtains the borehole shape, which can be effectively used for the borehole eccentricity correction of acoustic waves, and improves the measurement accuracy of the instrument; the multi-component accelerometer arranged in the instrument obtains the vibration and noise data of the instrument, which can be effectively used to eliminate the noise generated by the vibration of the instrument and improve the measurement accuracy of the instrument.

[0074] In addition, the calibration system and the borehole correction method ensure the consistency of acoustic wave reception and transmission and eliminate instrument errors by calibrating the acoustic wave transmitter, the acoustic wave receiver and its related circuits, further improving the measurement accuracy and consistency, aligning each transmitting sound source in the instrument with the standard transmitting position to calibrate each transmitting source, and recording the first feature of each transmitting sound source, and calibrating each receiving unit by aligning each receiving unit with the standard receiving position, and recording the second feature of each receiver; each type of feature data in the first feature and the second feature is normalized respectively, based on which, the actual acoustic wave logging data of each component is systematically normalized and calibrated; according to the actual acoustic wave logging data of each component after normalization correction, the borehole eccentricity correction parameters of the current logging instrument are calculated, and according to the borehole eccentricity correction parameters, the actual acoustic wave data of each component is subjected to borehole environment correction processing.

[0075] The present invention ensures the precision and accuracy of acoustic logging by performing regular calibration tests without environmental restrictions during the use of the instrument. The method algorithm is simple, reliable and easy to implement. It can effectively solve the problem of fine detection of acoustic characteristics of geological anomalies around the well, accurately evaluate the azimuth, trend and spatial development of three-dimensional geological anomalies, and can complete azimuth acoustic wave measurement within 200 meters away from the wellbore, realizing fine acoustic measurement of three-dimensional geological bodies. The measurement azimuth resolution can reach 11.25°, and the accurate calculation of azimuth can reach 5.625°.

[0076] FIG1 is a schematic diagram of the overall structure of the first example of an acoustic logging instrument of an embodiment of the present application. FIG1a shows a schematic diagram of the overall structure of the acoustic logging instrument for drilling tool transportation, and FIG1b shows a schematic diagram of the overall structure of the acoustic logging instrument for cable logging. As shown in FIG1 , the acoustic logging instrument is connected in series to the lower part of the drilling tool, and at least includes: an acoustic wave transmitting acoustic system 3, a (acoustic wave) transmitting and collecting control circuit 4, an acoustic wave receiving acoustic system 2, and a (acoustic wave) receiving and collecting control circuit 1. Among them, the transmitting and collecting control circuit 4 is adjacent to the first end of the acoustic wave transmitting acoustic system 3, the first end of the acoustic wave receiving acoustic system 2 is adjacent to the second end of the acoustic wave transmitting acoustic system 3, and the receiving and collecting control circuit 1 is adjacent to the second end of the acoustic wave receiving acoustic system 2.

[0077] The acoustic wave transmitting acoustic system 3 is used to transmit pattern waves with different energy levels and different focusing modes to the formation based on the transmission control signal. The transmission acquisition control circuit 4 is used to determine the current transmission mode, and based on the received transmission control logic signal, generate the transmission control signal and energy supply combination mode that match the current transmission mode, so as to provide sufficient transmission energy to the acoustic wave transmitting system according to the current energy supply combination mode, and use the current transmission control signal to excite the specified transducer in the acoustic wave transmitting acoustic system 3. The acoustic wave receiving acoustic system 2 is used to receive acoustic wave (logging reflection) signals from different directions from the formation. The receiving acquisition control circuit 1 is used to generate acoustic wave logging data according to the acoustic wave signal obtained by the acoustic wave receiving acoustic system 2, and form the above-mentioned transmission control logic signal.

[0078] In addition, the acoustic logging instrument described in the embodiment of the present invention further includes: an upper energy sub 5 and a plurality of lower energy subs 6. The lower energy sub 6 is integrated in the transmitting and collecting control circuit 4. The upper energy sub 5 and the lower energy sub 6 are used to provide energy for the acoustic emission and acoustic reception of the acoustic logging instrument string without interfering with each other. Therefore, the connection order of the first instrument string example formed by the acoustic logging instrument described in the embodiment of the present invention is at least the upper energy sub 5, the acoustic receiving and collecting control circuit 1, the acoustic receiving acoustic system 2, the acoustic transmitting acoustic system 3 (including the near transmitting acoustic system 7 and the far transmitting acoustic system 8 described below in sequence), and the transmitting and collecting control circuit 4 (including the transmitting and collecting control sub 9 and a plurality of lower energy subs 6 in sequence). The acoustic transmitting acoustic system 3 emits an acoustic signal, which is received by the acoustic receiving acoustic system 2 through the formation and stored in the acoustic receiving and collecting control circuit 1 or transmitted by the acoustic receiving and collecting control circuit 1 to other instruments for storage or to a ground computer. In addition, in the embodiment of the present invention, a shock-absorbing and sound-isolating short section (not numbered) may be connected in series at the front end (close to the wellhead end) of the upper energy short section 5 and between the sound wave transmitting acoustic system 3 and the sound wave receiving acoustic system 2 .

[0079] Furthermore, the sound wave transmitting sound system 3 and the sound wave receiving sound system 2 include at least: a supporting metal frame, a transmitting or receiving transducer installed on the metal frame, a sound insulation component connected to the upper and lower parts of the transmitting or receiving transducer respectively, and a sound-transmitting window located on the outside of the transmitting or receiving transducer.

[0080] Figure 2 Schematic diagram of the distribution structure of the acoustic wave receiving system in the acoustic wave logging instrument of the present application embodiment. Figure 2 The internal structure of the acoustic wave receiving system 2 in the acoustic wave logging tool according to the embodiment of the present invention is described.

[0081] In the embodiment of the present invention, the sound wave receiving system 2 includes multiple groups (n groups) of sound wave receiving modules. Different groups of sound wave receiving modules are spaced apart along the axial direction of the instrument body. Each group of sound wave receiving modules includes multiple (m) sound wave receiving units 2.2. In the same sound wave receiving module, each sound wave receiving unit is evenly distributed along the circumferential direction of the instrument body.

[0082] like Figure 2 As shown in the lower part of the figure, this part is the first sound wave system example of the sound wave receiving system 2. In the first sound wave system example, the sound wave receiving modules are configured into 2 groups, and one group of sound wave receiving modules is configured with 8 sound wave receiving units 2.2. Figure 2 As shown in the upper part of the figure, this part is a second sound wave system example of the sound wave receiving system 2. In the second sound wave system example, the sound wave receiving modules are configured into 4 groups, and 4 sound wave receiving units 2.2 are configured in one group of sound wave receiving modules.

[0083] like Figure 2 As shown, the acoustic wave receiving system 2 also includes: multiple pairs of sliding arms 2.1. In the embodiment of the present invention, each acoustic wave receiving unit 2.2 is connected to the instrument body through a corresponding pair of sliding arms 2.1 (that is, each pair of sliding arms 2.1 is provided with an acoustic wave receiving unit 2.2). The sliding arms 2.1 adopt lockable free-style sliding arms. During cable logging or drilling tool conveying logging, each pair of sliding arms 2.1 is in an unfolded state, so that each acoustic wave receiving unit 2.2 is close to the well wall. At this time, after unlocking, the free-style sliding arm automatically opens underground, expands and contracts according to the size of the well wall, and is close to the well wall. During logging while drilling, the sliding arm 2.1 is in a closed state, so that each acoustic wave receiving unit 2.2 is embedded in the side wall of the instrument body, and an isolation channel is formed between the instrument body and the well wall. At this time, the free-style sliding arm is locked, the sliding arm cannot slide, and the sliding arm is embedded in the outer shell of the instrument body and cannot contact the well wall.

[0084] Furthermore, the number of sound wave receiving units 2.2 configured in different groups of sound wave receiving modules is the same. The azimuth angles of the sound wave receiving units 2.2 in different groups of sound wave receiving modules are completely staggered. In addition, the embodiment of the present invention also marks any sound wave receiving unit 2.2 in the sound wave receiving module adjacent to the sound wave transmitting acoustic system 3 as an instrument alignment mark (MARK).

[0085] Figure 3 It is a schematic diagram of the cross-sectional structure of the acoustic wave receiving acoustic system in the acoustic well logging tool of the embodiment of the present application. Figure 3 3-a in the figure shows the radial distribution state of all the sound wave receiving units 2.2 in the first sound wave system example mentioned above. Figure 3 Figure 3-b shows the radial distribution state of all the sound wave receiving units 2.2 in the above second sound wave system example.

[0086] In the first acoustic system example, the eight sliding arms 2.1 corresponding to each group of acoustic wave receiving modules are evenly distributed along the circumference of the instrument at 360°, and the sliding arms 2.1 are 45° apart; the two groups of acoustic wave receiving modules are 4ft apart, with a difference of 22.5°, forming two groups of 16 sliding arms 2.1, which can form a mutual misalignment angle of 22.5°; there are 16 acoustic wave receiving units 2.2 on the 16 sliding arms 2.1 for receiving acoustic wave signals, among which the adjacent acoustic wave receiving modules are Any one of the sound wave receiving units 2.2 in the (lower) sound wave receiving module of the transmitting sound system 3 is marked as an instrument alignment mark (MARK) and is recorded as A1. The other sliding arms (and / or sound wave receiving units) in the same group are marked A2 to A8 in a clockwise direction. The sliding arm (and / or sound wave receiving unit) A9 of the upper sound wave receiving module is 22.5° clockwise from A1. The other sliding arms (and / or sound wave receiving units) are A10 to A16 respectively.

[0087] In the second acoustic system example, the four sliding arms 2.1 corresponding to each group of acoustic wave receiving modules are evenly distributed along the circumference of the instrument at 360°, and the sliding arms 2.1 are 90° apart; the four groups of acoustic wave receiving modules are respectively recorded as the first acoustic wave receiving module, the second acoustic wave receiving module, the third acoustic wave receiving module and the fourth acoustic wave receiving module from bottom to top, and are respectively spaced 4ft apart and 22.5° apart, forming 4 groups with a total of 16 sliding arms 2.1, which can form a mutual misalignment angle of 22.5°; any acoustic wave receiving unit 2.2 in the (first) acoustic wave receiving module adjacent to the acoustic wave transmitting system 3 is marked as the instrument alignment mark (MARK) and recorded as A1, and the other acoustic wave receiving units in the same group are marked as A2. The sliding arms (and / or sound wave receiving units) are marked as A2 to A4 in clockwise direction; the sliding arm (and / or sound wave receiving unit) A5 of the second sound wave receiving module is 22.5° different from A1 in clockwise direction, and the other sliding arms (and / or sound wave receiving units) are A6 to A8 in sequence; the sliding arm (and / or sound wave receiving unit) A9 of the third sound wave receiving module is 45° different from A1 in clockwise direction, and the other sliding arms (and / or sound wave receiving units) are A10 to A12 in sequence; the sliding arm (and / or sound wave receiving unit) A13 of the fourth sound wave receiving module is 67.5° different from A1 in clockwise direction, and the other sliding arms (and / or sound wave receiving units) are A14 to A16 in sequence.

[0088] Reference again Figure 2 The acoustic wave receiving system 2 of the embodiment of the present invention further comprises: a borehole diameter detector 2.3. The borehole diameter detector 2.3 is arranged at the sliding arm 2.1, and is used to detect the radius of the wellbore for logging and generate a corresponding borehole diameter (measurement) signal.

[0089] In addition, the acoustic wave receiving system 2 described in the embodiment of the present invention further includes: a plurality of accelerometers 2.4. The number of accelerometers 2.4 configured is consistent with the number of sliding arms 2.1 and acoustic wave receiving units 2.2. A plurality of accelerometers are provided corresponding to each acoustic wave receiving unit 2.2. Specifically, during cable logging or drilling tool conveying logging, since the vibration noise generated during the measurement is relatively small, the multi-component accelerometer 2.4 can be turned off to reduce the amount of data; during measurement while drilling, the multi-component accelerometer 2.4 is turned on, and the acceleration signals detected by each component accelerometer 2.4 are used to process the vibration noise of drilling.

[0090] Figure 4 Schematic diagram of the distribution structure of the acoustic wave emission system in the acoustic well logging tool of the embodiment of the present application. Figure 4 As shown, the acoustic wave transmitting system 3 described in the embodiment of the present invention includes a near transmitting acoustic system 7 and a far transmitting acoustic system 8. Among them, the near transmitting acoustic system 7 is adjacent to the first end of the acoustic wave receiving acoustic system 2. The near transmitting acoustic system 7 is used to transmit high-frequency acoustic wave signals to the formation. In addition, the far transmitting acoustic system 8 is adjacent to the near transmitting acoustic system 7. The far transmitting acoustic system 8 is used to transmit low-frequency acoustic wave signals to the formation.

[0091] refer to Figure 4 The near-emission acoustic system 7 includes a first boost circuit 7.1 and a high-frequency acoustic wave emission module 7.2. The first boost circuit 7.1 is used to boost the emission energy obtained from the lower energy short section 6 to provide the required emission energy to the high-frequency acoustic wave emission module 7.2. The high-frequency acoustic wave emission module 7.2 has a first emission unit 7.2.1, a second emission unit 7.2.2 and a third emission unit 7.2.3. Among them, the first emission unit 7.2.1, the second emission unit 7.2.2 and the third emission unit 7.2.3 are spaced apart along the axial direction of the instrument body. The first transmitting unit 7.2.1, the second transmitting unit 7.2.2 and the third transmitting unit 7.2.3 form different source distances (intervals) from near to far with the sound wave receiving sound system 2 in sequence, that is, the interval distance between the sound wave receiving sound system 2 and the first transmitting unit 7.2.1 is smaller than the interval distance between it and the second transmitting unit 7.2.2, and the interval distance between the sound wave receiving sound system 2 and the second transmitting unit 7.2.2 is smaller than the interval distance between it and the third transmitting unit 7.2.3.

[0092] The long-range transmission acoustic system 8 at least includes: a second boost circuit 8.1 and a low-frequency acoustic wave transmitting module 8.2. The second boost circuit 8.1 is used to boost the transmitting energy obtained from the lower energy short section 6 to provide the required transmitting energy to the low-frequency acoustic wave transmitting module 8.2. The low-frequency acoustic wave transmitting module 8.2 has a fourth transmitting unit 8.2.1, a fifth transmitting unit 8.2.2 and a sixth transmitting unit 8.2.3. Among them, the fourth transmitting unit 8.2.1, the fifth transmitting unit 8.2.2 and the sixth transmitting unit 8.2.3 are spaced apart along the axial direction of the instrument body. The fourth transmitting unit 8.2.1, the fifth transmitting unit 8.2.2 and the sixth transmitting unit 8.2.3 form different source distances (intervals) from near to far with the sound wave receiving sound system 2 in turn, that is, the interval distance between the sound wave receiving sound system 2 and the fourth transmitting unit 8.2.1 is smaller than the interval distance between it and the fifth transmitting unit 8.2.2, and the interval distance between the sound wave receiving sound system 2 and the fifth transmitting unit 8.2.2 is smaller than the interval distance between it and the sixth transmitting unit 8.2.3.

[0093] Therefore, the near-transmitting acoustic system 7 and the far-transmitting acoustic system 8 described in the embodiment of the present invention, under the control of the transmitting and collecting control short section 9, complete the excitation of the multi-mode acoustic wave signal through the transmitting energy provided by the multiple lower energy short sections 6, and enter the wellbore and the formation. Specifically, the second boost circuit 8.1 boosts the transmitting voltage from the multiple lower energy short sections 6, so that the multi-mode acoustic wave transducer of the multi-mode acoustic wave low-frequency band transmitting module 8.2 can emit different acoustic wave signals into the formation; the first boost circuit 7.1 boosts the transmitting voltage from the multiple lower energy short sections 6, so that the multi-mode acoustic wave transducer of the multi-mode acoustic wave high-frequency band transmitting module 7.2 can emit different acoustic wave signals into the formation.

[0094] In the near-transmitting acoustic system 7, there are two high-frequency monopole transmitting transducers and one high-frequency dipole transmitting transducer. Among them, the first transmitting unit 7.2.1 is a high-frequency monopole transmitting transducer, the third transmitting unit 7.2.3 is a high-frequency monopole transmitting transducer, and the second transmitting unit 7.2.2 is a high-frequency dipole transmitting transducer. Similarly, in the far-transmitting acoustic system 8, there are two low-frequency monopole transmitting transducers and one low-frequency dipole transmitting transducer. Among them, the fourth transmitting unit 8.2.1 is a low-frequency monopole transmitting transducer, the sixth transmitting unit 8.2.3 is a low-frequency monopole transmitting transducer, and the fifth transmitting unit 8.2.2 is a low-frequency dipole transmitting transducer.

[0095] Among them, the four monopole transmitting transducers (including high-frequency monopole transmitting transducers and low-frequency monopole transmitting transducers) are respectively called near monopole, far monopole, ultra-far monopole and extremely far monopole from top (near the wellhead end) to bottom (near the well bottom end). The transmitting frequency range of the first transmitting unit 7.2.1 is 20-50kHz, the transmitting frequency range of the third transmitting unit 7.2.3 is 12-25kHz, the transmitting frequency range of the fourth transmitting unit 8.2.1 is 5-15kHz and the transmitting frequency range of the sixth transmitting unit 8.2.3 is 1-10kHz. Each monopole transmitting transducer is composed of 4 strip-shaped piezoelectric ceramic sheets, each of which is arranged at intervals and 90° apart along the circumferential direction of the instrument body. Power supply excitation electrodes are arranged inside and outside the 4 ceramic sheets respectively. The pulsed high-voltage excitation sound wave signal is applied to the power supply electrode, and the high voltage comes from the boost circuit 7.1 and 8.1.

[0096] Furthermore, the azimuth angle of the first transducer in the first transmitting unit 7.2.1 forms a clockwise angle deviation of 11.25° with the azimuth angle of the instrument alignment mark (MARK) in the sound wave receiving acoustic system 2. Moreover, the azimuth angles of the transducers in the first transmitting unit 7.2.1, the third transmitting unit 7.2.3, the fourth transmitting unit 8.2.1 and the sixth transmitting unit 8.2.3 are completely staggered.

[0097] Figure 5 It is a schematic diagram of the cross-sectional structure of a monopole emission set in the acoustic emission acoustic system of the acoustic logging tool in the embodiment of the present application. Figure 5 The radial distribution of each piezoelectric ceramic piece in all monopolar transmitting transducers is shown. Figure 5 As shown, the four piezoelectric ceramics of the near monopole are marked as M1 to M4 in the clockwise direction, and the radial orientation of the M1 piezoelectric ceramic sheet forms a deviation angle of 11.25° in the clockwise direction of the radial orientation of the above-mentioned instrument alignment mark (MARK); similarly, the four piezoelectric ceramics of the far monopole are marked as M5 to M8 in the clockwise direction, and the radial orientation of the M5 piezoelectric ceramic sheet forms a deviation angle of 33.75° in the clockwise direction of the radial orientation of the above-mentioned instrument alignment mark (MARK). The four piezoelectric ceramics of the ultra-far monopole are marked as M9 to M12 in the clockwise direction, and the radial orientation of the M9 piezoelectric ceramic forms a deviation angle of 56.25° in the clockwise direction of the radial orientation of the above-mentioned instrument alignment mark (MARK); the four piezoelectric ceramics of the extremely far monopole are marked as M13 to M16 in the clockwise direction, and the radial orientation of the M13 piezoelectric ceramic forms a deviation angle of 78.75° in the clockwise direction of the radial orientation of the above-mentioned instrument alignment mark (MARK).

[0098] In this way, for the monopole transmission set formed by all monopole transmission transducers, a minimum monopole transmission azimuth resolution of 22.5° and a transmission and reception azimuth resolution of 11.25° can be formed.

[0099] In the two dipole transmitting transducers, from top (close to the wellhead end) to bottom (close to the well bottom end), a high-frequency dipole transmitting transducer 7.2.2 (located at the top) and a low-frequency dipole transmitting transducer 8.2.2 (located at the bottom) are respectively arranged. The transmitting frequency range of the second transmitting unit 7.2.2 is 1.2-8kHz, and the transmitting frequency range of the fifth transmitting unit 8.2.3 is 0.3-3.5kHz. Each dipole transmitting transducer is composed of 4 groups of strip-shaped three-layer piezoelectric ceramics, each group of piezoelectric ceramics is arranged at intervals and 90° apart along the circumferential direction of the instrument body, and the 4 groups of piezoelectric ceramics are provided with power supply excitation electrodes, and pulsed high-voltage excitation sound wave signals are applied to the power supply electrodes, and the high voltage comes from the booster modules 7.1 and 8.1.

[0100] Furthermore, the azimuth angle of the first transducer in the second transmitting unit 7.2.1 is consistent with the azimuth angle of the instrument alignment mark (MARK) in the sound wave receiving acoustic system 2. Moreover, the azimuth angles of the piezoelectric elements in the second transmitting unit 7.2.2 and the fifth transmitting unit 8.2.2 are completely staggered.

[0101] Figure 6 It is a schematic diagram of the cross-sectional structure of a dipole emission set within an acoustic emission acoustic system in an acoustic logging tool according to an embodiment of the present application. Figure 6 The radial distribution of each piezoelectric ceramic element in all dipole emission transducers is shown. Figure 6 As shown, the four groups of piezoelectric ceramic components of high-frequency dipole piezoelectric ceramics are marked as D1 to D4 in the clockwise direction, and the radial orientation of the piezoelectric ceramic component D1 forms a deviation angle of 0° with the radial orientation of the alignment mark (MARK) of the above-mentioned instrument; the four groups of piezoelectric ceramic components of low-frequency dipole piezoelectric ceramics are marked as D5 to D8 in the clockwise direction, and the radial orientation of the piezoelectric ceramic component D5 forms a deviation angle of 45° along the clockwise direction of the radial orientation of the alignment mark (MARK) of the above-mentioned instrument.

[0102] Therefore, under the control of the emission and collection control short section 9, the acoustic wave emission system 3 can respectively perform forward or reverse excitation of a single monopole piezoelectric ceramic piece alone, or forward or reverse excitation of a combination of multiple piezoelectric ceramic pieces, and can also perform forward or reverse excitation of a single dipole triplex piezoelectric ceramic piece alone, or forward or reverse excitation of a combination of multiple dipole triplex piezoelectric ceramic pieces, thereby effectively exciting different modes of waves including longitudinal waves, transverse waves, quadrupole waves, etc., with different energy levels and different focusing modes, to enter the formation.

[0103] In addition, in the embodiment of the present invention, the above-mentioned remote transmission acoustic system 8 further includes: a temperature detection module 8.3. The temperature detection module 8.3 is arranged in the side wall of the instrument body to which the remote transmission acoustic system belongs, and is used to detect the ambient temperature information of the wellbore in real time, and generate a corresponding temperature (environmental measurement) signal, so that the transmission and collection control circuit 4 adjusts the transmission mode according to the real-time detected temperature information.

[0104] Furthermore, the sound wave transmission and collection control circuit 4 and the sound wave reception and collection control circuit 1 are both composed of a pressure-bearing metal shell and a circuit core.

[0105] Fig. 9 1 is a schematic diagram of the structure of the transmission and acquisition control circuit in the acoustic logging instrument of the embodiment of the present application. Fig. 9 The transmission and acquisition control circuit 4 described in the embodiment of the present invention at least includes a transmission and acquisition control short section 9 and multiple lower energy short sections 6. The transmission and acquisition control short section 9 is electrically connected to the receiving and acquisition control circuit 1, and is used to receive the transmission control logic signal, and generate the transmission control signal and the energy supply combination mode instruction. The multiple lower energy short sections 6 are connected to each other in different series-parallel combinations. The multiple lower energy short sections 6 are used to form sufficient transmission energy in the corresponding series-parallel combination mode of different lower energy short sections under the control of the above-mentioned energy supply combination mode instruction, so as to utilize the generated transmission energy to meet the energy supply requirements of different transmission modes, thereby ensuring the high-power transmission of multi-mode sound waves, effectively penetrating the distant formation and reflecting back.

[0106] Furthermore, the number of lower energy short sections 6 is at least two. The lower energy short sections 6 switch between series and parallel combinations through the energy supply combination mode instruction sent by the emission collection control short section 9, providing emission energy of different energy levels, thereby stimulating different emission modes, wherein each lower energy short section 6 needs to provide a stable supply of DC energy of not less than 20V and more than 3A.

[0107] Further, the emission acquisition control short section 9 includes: a low-voltage power supply module 9.1, an acquisition and emission control module 9.2, an emission drive module 9.3 and an emission relay module 9.4. Specifically, the low-voltage power supply module 9.1 is used to convert the high-voltage direct current provided by the upper energy short section 5 into the low-voltage direct current power required by the acquisition and control module 9.2, the emission drive module 9.3 and the emission relay module 9.4, and its accuracy error is less than one percent. The acquisition and emission control module 9.2 is used to first use the internal signal conditioning circuit to perform signal conditioning on the temperature measurement signal (environmental signal) from the temperature detection module 8.3 in the acoustic emission sound system 8 under the power supply support of the low-voltage power supply module 9.1, and then use the internal ADC to perform digital processing under the control of the FPGA, and finally generate a transmission control signal containing the emission mode information matching the current ambient temperature according to the current temperature environment data under the emission logic control signal generated by the acoustic wave receiving acquisition control circuit 1, and transmit the current emission control signal to the emission drive module 9.3. The transmitting drive module 9.3 is used to boost the transmitting control signal generated by the acquisition and transmission control module 9.2 under the power supply support of the low-voltage power supply module 9.1, and then control the transmitting relay module 9.4 and multiple lower energy short sections 6 to provide the transmitting energy and transmitting mode instructions required for the transmission of the acoustic wave signal to the acoustic wave transmitting acoustic system 3. In addition, the transmitting relay module 9.4 is used to drive the series and parallel combination of multiple lower energy short sections 6 under the power supply support of the low-voltage power supply module 9.1 and the control of the acquisition and transmission control module 9.2 to power the different transmission modes of the acoustic wave transmitting acoustic system 3, so that the acoustic wave transmitting acoustic system 3 excites different mode waves. Different mode waves include: forward and / or reverse excitation of multiple monopole transducers and / or a specified single monopole transducer and / or a specified single dipole transmitting transducer and / or multiple dipole transmitting transducers.

[0108] Furthermore, the far-transmitting acoustic system 8 is used to be responsible for the excitation and emission state of the multi-mode low-frequency acoustic wave signal, and to receive the borehole temperature environment signal, so that the emission acquisition control short section 9 adjusts the high-frequency and / or low-frequency excitation mode of the acoustic wave signal according to the temperature environment condition. In addition, the near-transmitting acoustic system 7 is responsible for the excitation of the multi-mode high-frequency acoustic wave signal.

[0109] Furthermore, the energy subs 5 and 6 are responsible for providing sufficient energy for the instrument string of the acoustic logging instrument. The lower energy sub 6 meets the high-power transmission power supply requirements of the multi-mode acoustic signal, and the upper energy sub 5 meets the high-precision reception power supply requirements of the acoustic signal. The low-voltage control line in the transmission acquisition control sub 9 is also provided by the upper energy sub 5. In the entire instrument string, from top to bottom, the upper energy sub 5 transmits the power supply energy through the acoustic reception acquisition control line 1, the acoustic reception acoustic system 2, and the acoustic transmission acoustic system 3 through the power supply cable core to the transmission acquisition control sub 9. The upper energy sub 5 needs to provide a stable supply of direct current not less than 32V and greater than 200mA. The upper energy sub 5 and the lower energy sub 6 provide energy for acoustic transmission and acoustic reception and collection respectively. The two are independent and do not interfere with each other, which greatly reduces the pulsation interference of the acoustic signal during the acoustic transmission process, especially the weak acoustic reflection wave from the distant formation during the reception and collection.

[0110] Figure 8 Schematic diagram of the structure of the receiving and collecting control circuit in the acoustic logging instrument of the embodiment of the present application. Figure 8 The sound wave receiving and collecting control circuit 1, on the one hand, forms a transmitting logic control signal and transmits the transmitting logic control signal to the transmitting and collecting control short section 9, and also filters, conditions, digitizes and performs corresponding digital processing, storage and control on the sound wave signal from the sound wave receiving acoustic system 2. On the other hand, it is used for data communication and transmission with other instruments.

[0111] Furthermore, the receiving acquisition control circuit 1 includes: a high-precision low-voltage power supply module 1.1, a communication module 1.2 and an acquisition control module 1.3. Specifically, the high-precision low-voltage power supply module 1.1 is used to power other modules in the acoustic wave receiving acquisition control circuit 1. The acquisition control module 1.3 is used to collect the acoustic wave (receiving) signal, the wellbore measurement signal and the acceleration measurement signal obtained from the acoustic wave receiving acoustic system 2, and perform signal conditioning processing on these signals to form acoustic wave logging data. Among them, the signal conditioning processing includes program-controlled filtering and amplification, amplitude regularization, analog-to-digital conversion and digital signal processing. The communication module 1.2 is used to transmit the digitized acoustic wave logging data. Specifically, the communication module 1.2 is used to send the acoustic wave logging data to other downhole instruments for backup or transmit it to the ground.

[0112] like Figure 8 As shown, the high-precision low-voltage power supply module 1.1 is responsible for converting the high-voltage direct current from the upper energy short section 5 into the high-precision low-ripple low-voltage direct current power required by the communication module 1.2, the acquisition control module 1.3 and the sound wave receiving acoustic system 2, and its accuracy error is less than one thousandth.

[0113] The acquisition control module 1.3 at least includes: a programmable preamplifier and filter circuit 1.3.1, a signal conditioning circuit 1.3.2, an ADC circuit 1.3.3, an FPGA control circuit 1.3.4, a digital signal processing circuit 1.3.5 and a data storage circuit 1.3.6. Under the power supply of the high-precision low-voltage power supply module 1.1, the acquisition control module 1.3 generates a transmission logic control signal and transmits the signal to the transmission acquisition control short section 9, and first transmits the acoustic wave signal, the borehole diameter signal and / or the acceleration signal from the formation to the program-controlled pre-amplification and filtering circuit 1.3.1 for filtering and amplification processing, and then enters the signal conditioning circuit 1.3.2 for amplitude regularization. Then, under the control of the FPGA control circuit 1.3.4, the ADC circuit 1.3.3 performs digital processing on the signal after amplitude regularization processing, and then under the control of the FPGA control circuit 1.3.4, the digital signal processing circuit 1.3.5 and the data storage circuit 1.3.6 perform digital signal processing and data storage on the digitized signal, and form double backup acoustic logging data underground. Among them, the digital signal processing includes: power supply main frequency and harmonic 1 / f digital limiting, sampling integration and bandpass digital filtering.

[0114] The communication module 1.2, powered by the high-precision low-voltage power supply module 1.1, is responsible for driving the acoustic logging data or part of the data collected and processed by the acquisition control module 1.3, and sending it to other instruments to form a third backup acoustic logging data or transmitting it to the ground logging system through cables via other instruments to form ground acoustic logging data or acoustic logging monitoring data.

[0115] Figure 7 Schematic diagram of the structure of the acoustic wave receiving unit in the acoustic wave logging instrument of the embodiment of the present application. Figure 7 As shown, the sound wave receiving unit 2.2 includes: a sound wave receiving transducer 2.2.1, a power supply filter circuit 2.2.2, a signal amplifying circuit 2.2.3 and a bandpass filter circuit 2.2.4.

[0116] The acoustic wave receiving unit 2.2 is used to receive acoustic wave signals, which are excited by the acoustic wave transmitting acoustic system 3 and enter the formation. The acoustic wave signals are attenuated, phase shifted, and frequency converted in the formation, and are received by the acoustic wave receiving transducer 2.2.1 in the acoustic wave receiving unit 2.2, and filtered and amplified. The acoustic wave receiving unit 2.2 is an active acoustic wave receiver, and the frequency coverage range of the acoustic wave receiving transducer 2.2.1 is 0-60Khz. The low-voltage DC power supply of the acoustic wave receiving unit 2.2 comes from the high-precision low-voltage power supply module 1.1 in the acoustic wave receiving acquisition control circuit 1. The low-voltage DC power supply is purified by the power supply filter circuit 2.2.2 and provided to the high-sensitivity amplifier circuit 2.2.3, the bandpass filter circuit 2.2.4 and the acoustic wave receiving transducer 2.2.1. After receiving the acoustic wave signal from the formation, the acoustic wave receiving transducer 2.2.1 sends the acoustic wave signal to the high-sensitivity amplifying circuit 2.2.3, which amplifies the received acoustic wave signal and then sends it to the bandpass filtering circuit 2.2.4. Finally, the acoustic wave signal after preliminary signal processing is sent to the acquisition control module 1.3 in the acoustic wave receiving acquisition control circuit 1 for acquisition, digitization and data storage.

[0117] Furthermore, the n groups of m sliding arms 2.1 in the acoustic wave receiving acoustic system 2 are evenly distributed along the instrument body and pushed toward the wellbore wall at a certain angle so as to make it close to the wellbore wall to effectively receive various acoustic wave signals; the upper energy short section 5 provides high-voltage direct current to the high-precision low-voltage power supply module 1.1 in the acoustic wave receiving acquisition control circuit 1, and generates a high-precision low-ripple low-voltage direct current power supply to provide to the communication module 1.2, the acquisition control module 1.3 and the acoustic wave receiving unit 2.2 in the acoustic wave receiving acoustic system 2 in the acoustic wave receiving acquisition control circuit 1; the acoustic wave signal from the formation is received by the acoustic wave receiving transducer 2.2.1 in the acoustic wave receiving acoustic system 2, and after amplification and filtering, it is transmitted to the acquisition control module 1.3 in the acoustic wave receiving acquisition control circuit 1 through a shielded line for filtering, amplification, conditioning, digitization, digital signal processing and storage, etc., and the signal processed by the acquisition control module 1.3, part or all of the data enters the communication module 1.2, and after transmission drive , sent to other instruments or transmitted to the ground logging system through cables via other instruments; the caliper measurement signal from the caliper detector 2.3 is transmitted to the acquisition control module 1.3 in the acoustic wave receiving acquisition control circuit 1 through a shielded line for filtering, amplification, conditioning, digitization, digital signal processing and storage, etc., and the signal processed by the acquisition control module 1.3 enters the communication module 1.2, and after transmission drive, it is sent to other instruments or transmitted to the ground logging system through cables via other instruments, which can be used for wellbore correction; the acceleration signal from the multi-component accelerometer 2.4 is transmitted to the acquisition control module 1.3 in the acoustic wave receiving acquisition control circuit 1 through a shielded line for filtering, amplification, conditioning, digitization, digital signal processing and storage, etc., and the signal processed by the acquisition control module 1.3 enters the communication module 1.2, and after transmission drive, it is sent to other instruments or transmitted to the ground logging system through cables via other instruments.

[0118] Fig.10 Schematic diagram of the overall structure of the second example of the acoustic logging tool of the embodiment of the present application. Fig.10In the embodiment of the present invention, the acoustic logging instrument is connected in series to the lower part of the drill collar for measurement while drilling. The bottom of the instrument is the drill bit. The multiple groups of lockable free-style sliding arms 2.1 in the acoustic wave receiving acoustic system 2 are in a closed state. The sliding arms 2.1 cannot be opened and are embedded in the shell of the instrument or the drill collar, and do not contact the well wall. During the measurement while drilling, the two ends of the instrument string are connected to the drill collar and the drill bit respectively. From top to bottom, they are the drill collar, the shock-absorbing and sound-isolating short section 10, the upper energy short section 5, the acoustic wave receiving and collecting control circuit 1, the acoustic wave receiving acoustic system 2, the shock-absorbing and sound-isolating short section 10, the acoustic wave transmitting acoustic system 3 (near transmitting acoustic system 7, far transmitting acoustic system 8), the acoustic wave transmitting and collecting control circuit 4 (transmitting and collecting control short section 9, multiple lower energy short sections 6), the shock-absorbing and sound-isolating short section 10 and the drill bit. Among them, the shock-absorbing and sound-isolating short section 10 is used to attenuate the measurement-irrelevant noise generated by the vibration of the drill bit and the noise generated by the friction of the guiding and straightening device against the well wall and transmit the direct-coupled acoustic wave signal.

[0119] Based on the above-mentioned acoustic logging instrument, an embodiment of the present invention further provides a calibration system for the acoustic logging instrument. It should be noted that in the embodiment of the calibration system, the "surface" and "downhole" are not the actual surface scene and the actual downhole scene corresponding to the actual application environment state of the wellbore, but are expressions used to distinguish different acoustic wave transmission paths in a simulated scene. The acoustic logging calibration system described in the embodiment of the present invention is a solution that can also realize calibration measurement in a factory workshop environment.

[0120] Fig.11 Schematic diagram of the overall structure of the calibration system for the acoustic logging tool in the embodiment of the present application. Fig.11 The calibration system described in the embodiment of the present invention at least includes: a cylinder 29, a stabilizer 28, an acoustic logging instrument (device) 24, a standard acoustic wave transmitter 34, a standard acoustic wave receiver 33, a first control device 22, a second control device 27 and a data analysis device (not shown).

[0121] In the embodiment of the present invention, the acoustic logging instrument (device) 24 is a logging instrument that currently needs to be calibrated. The acoustic logging instrument 24 is the above-mentioned acoustic logging instrument. The space formed by the acoustic cylinder 29 and the stabilizer 28 is used to simulate the environment in which the acoustic logging instrument 24 to be tested (to be calibrated) is located during the actual logging application process. The cylinder 29 is a calibrated cylinder, which is used to simulate the wellbore. The inner wall of the cylinder 29 is smooth and has no burrs (no impurities). In order to ensure good transmission and reception of the acoustic signal, the interior of the cylinder 29 is filled with an acoustic coupling liquid 25 (the acoustic coupling liquid 25 is used to simulate the fluid in the wellbore), and before the calibration test is implemented, the filled acoustic coupling liquid needs to be left to stand for more than 2 hours. The acoustic coupling liquid 25 in the cylinder 29 fills the interior of the cylinder 29 as much as possible. In addition, the diameter range of the interior of the cylinder is 200 to 400 mm, and the outer shell of the cylinder is made of high-strength corrosion-resistant metal material.

[0122] Further, the cylinder 29 is divided into an upper and lower part. The upper part 30 of the cylinder 29 is a PPR cylinder, the lower part 31 of the cylinder 29 is a metal cylinder, the bottom 32 of the cylinder 29 is sealed by a wedge sponge rubber, and the top 11 of the cylinder 29 is a detachable metal plate, which is covered with a wedge sponge rubber. Specifically, the lower part 31 is a metal cylinder and adopts a high sound velocity material, the upper part 30 is a PPR cylinder and adopts a low sound velocity material, the bottom 32 is sealed by a sound-absorbing and shock-absorbing wedge sponge rubber material, and the top 11 is a detachable sound-absorbing and shock-absorbing wedge sponge rubber covered with a metal plate. In the metal plate, a circular hole is provided so that the current sonic logging instrument 24 to be detected passes through this circular hole. In addition, the upper part 30 of the cylinder 29 is connected to the lower part 31 of the cylinder 29 through a joint hoop seal.

[0123] Furthermore, the centralizer 28 is used to centralize and fix the position of the sonic logging tool 24 , so that the sonic logging tool 24 is located at the center of the cylinder 29 through the centralizer 28 .

[0124] Further, a first mark and a second mark are provided on the inner wall of the upper part 30 of the cylinder 29. The standard sound wave transmitter 34 is provided at the first mark of the inner wall of the cylinder 29; and the standard sound wave receiver 33 is provided at the second mark of the inner wall of the cylinder 29. Specifically, the standard sound wave transmitter 34 and the standard sound wave receiver 33 are respectively embedded in the first mark and the second mark of the inner wall of the upper part 30 of the cylinder 29. Among them, the standard sound wave transmitter 34 is isolated from the inner wall of the cylinder by a sealed sound-permeable material, and the standard sound wave receiver is also isolated from the inner wall of the cylinder by a sealed sound-permeable material. It should be noted that in the embodiment of the present invention, since the standard sound wave transmitter 34 and the standard sound wave receiver 33 are respectively placed at the first mark and the second mark, in the actual application process, it is necessary to isolate the two standard sound wave devices from the sound wave coupling liquid 25 and ensure electrical insulation. Preferably, the first mark position is 50CM or more away from the second mark position, and the angles of the two mark positions based on the cylinder cross section differ by 180 degrees. In addition, the standard sound wave transmitter 34 and the standard sound wave receiver 33 will not work at the same time.

[0125] The acoustic logging instrument 24 is located at the center of the cylinder 29 through the centralizer 28. In actual application, the acoustic logging instrument 24 is usually equipped with a logging instrument transmitter (i.e., the transmitting transducer in the acoustic logging instrument) and logging instrument receivers under multiple azimuth components (i.e., the receiving transducer in the acoustic receiving unit in the acoustic logging instrument). Each component is equipped with a corresponding logging instrument receiver.

[0126] In order to obtain the basic measurement data for completing the calibration of the logging instrument transmitter and each logging instrument receiver, it is necessary to construct two types of downhole acoustic wave transmission paths. The first type of downhole acoustic wave transmission path is the acoustic wave transmission path required for obtaining the basic measurement data (i.e., the first data body) for calibrating the logging instrument transmitter, and the first type of downhole acoustic wave transmission path includes the logging instrument transmitter and the standard acoustic wave receiver in sequence. The second type of downhole acoustic wave transmission path is the acoustic wave transmission path required for obtaining the basic measurement data (i.e., the second data body) for calibrating the logging instrument receiver of each component, and the second type of downhole acoustic wave transmission path includes the standard acoustic wave transmitter and the logging instrument receiver corresponding to the component to be measured in sequence. Therefore, in order to ensure the smoothness of the above two pathways and to allow the transmitted acoustic wave signal to be transmitted in the corresponding pathway with the principle of minimum attenuation, in the embodiment of the present invention, it is necessary to align the transmitter in the logging instrument with the standard acoustic wave receiver, and align the logging instrument receiver to be measured with the standard acoustic wave transmitter through the mobile instrument (not shown) configured in the logging instrument 24.

[0127] In the embodiment of the present invention, before the first test is implemented, the acoustic logging instrument 24 needs to be connected, a centralizer 28 is installed in the cylinder 29 to ensure that the instrument 24 is located at the center of the cylinder 29, and the instrument 24 is pushed into the upper part 30 of the cylinder 29, so that the logging instrument transmitter of the instrument 24 is aligned with the standard acoustic wave receiver 33 in the cylinder 29 to start the first test. The first test is a test for collecting (obtaining) basic measurement data required for calibrating the logging instrument transmitter. In the first test, after the first acoustic wave signal is emitted from the logging instrument transmitter, the first acoustic wave signal is transmitted in the first type of downhole acoustic wave transmission path according to the corresponding transmission path, so that the transmitted first acoustic wave signal is received by the standard acoustic wave receiver.

[0128] In the embodiment of the present invention, after the first test is completed and before the second test is implemented, it is necessary to align the logging instrument receiver corresponding to the current component to be measured in the instrument 24 with the standard acoustic wave transmitter 34 on the upper part 30 of the scale cylinder 29 by moving the instrument to start the second test. The second test is a test for collecting (obtaining) the basic measurement data required for calibrating the logging instrument receiver. In the second test, after the second acoustic wave signal is emitted from the standard acoustic wave transmitter, the second acoustic wave signal is transmitted in the second type of downhole acoustic wave transmission path according to the corresponding transmission path, so that the logging instrument receiver under the azimuth component to be measured receives the transmitted second acoustic wave signal. Next, continue to align the logging instrument receiver corresponding to the next component to be measured in the instrument 24 with the standard acoustic wave transmitter 34 on the upper part 30 of the scale cylinder 29 by moving the instrument to start the second test again until the second test of the logging instrument receiver for all components is completed. Therefore, in the embodiment of the present invention, the acoustic logging calibration system of the present invention also includes a mobile instrument located on the acoustic logging instrument 24. The mobile instrument is used to control the movement (position shift) of the logging instrument receiver under each azimuth component, so that the logging instrument receiver corresponding to the currently measured component is aligned with the standard acoustic wave transmitter 34 .

[0129] Further, the first control device 22 is connected to the standard acoustic wave transmitter 34 and the standard acoustic wave receiver 33 respectively. The first control device 22 is used to receive and record the first acoustic wave signal obtained by the first test (transmission calibration test), and to control the emission of the second acoustic wave signal required to be emitted by the second test (reception calibration test). The second control device 27 is connected to the acoustic logging instrument 24, and further the second control device 27 is respectively connected to the logging instrument transmitter in the acoustic logging instrument 24 and the logging instrument receiver under each component. In an embodiment of the present invention, the second control device 27 is integrated with a logging system for controlling the logging instrument 24 to perform logging construction through the logging system. Further, the second control device 27 is used to control the emission of the first acoustic wave signal required to be emitted by the first test, and to receive and record the second acoustic wave signal obtained by the second test.

[0130] Furthermore, during the implementation of the first test, the second control device 27 is used to control the logging instrument transmitter to transmit the first acoustic wave signal required for the current test in the first test, and the first acoustic wave signal is directly transmitted to the standard acoustic wave receiver 33 via the logging instrument transmitter. At this time, the first control device 22 is used to receive and record the first acoustic wave signal obtained by the standard acoustic wave receiver 33 in the first test. During the implementation of the second test, the first control device 22 is used to control the standard acoustic wave transmitter to transmit the second acoustic wave signal required for the current test in the second test, and the second acoustic wave signal is directly transmitted to the logging instrument receiver corresponding to the current azimuth component to be measured via the standard acoustic wave transmitter 34. At this time, the second control device 27 is used to receive and record the second acoustic wave signal obtained by the logging instrument receiver corresponding to the current azimuth component to be measured in the second test. In this way, after the collection (acquisition) of the second acoustic wave signals of all components is completed, the above-mentioned first test and second test are completed.

[0131] The data analysis device (not shown) includes a first analysis module and a second analysis module. The second analysis module is integrated in the second control device 27. Fig.11 , the first analysis module 23 is connected to the first control device 22. In the embodiment of the present invention, the data analysis device is used to process and analyze the first acoustic wave signal received by the above-mentioned first test and the second acoustic wave signal received by the second test to obtain basic measurement data for calibrating the transmitter and receiver in the logging instrument. Specifically, the first analysis module 23 is used to perform data processing and analysis on the received first acoustic wave signal, and after the first acoustic wave signal is digitized, the characteristic information such as the amplitude, phase and spectrum of the digitized first acoustic wave signal is extracted to obtain the first data body. At the same time, the second analysis module is used to perform data processing and analysis on the received second acoustic wave signal, and after the second acoustic wave signal is digitized, the characteristic information such as the amplitude, phase and spectrum of the digitized second acoustic wave signal is extracted to obtain the second data body. In this way, the embodiment of the present invention obtains all the basic measurement data required for qualitative and quantitative calibration of the acoustic logging instrument 24, namely the first data body and the second data body.

[0132] In addition, the second control device 27 described in the embodiment of the present invention is also used to control the stop position of the acoustic logging instrument 24. When obtaining the basic measurement data required for the instrument calibration (in the first test and the second test stage), the second control device 27 controls the acoustic logging instrument 24 to stay in the upper part 30 of the cylinder 29; when obtaining the reference data required for the instrument calibration, the second control device 27 needs to control the acoustic logging instrument 24 to stay in the lower part 31 of the cylinder 29. That is to say, after obtaining the basic measurement data, it is necessary to enter the reference data collection stage. At this time, the acoustic logging instrument 24 needs to be pushed into the lower part 31 of the calibration cylinder 29, so that the logging system configured in the second control device 27 can control the emission and reception of the reference acoustic wave signal of the logging instrument 24.

[0133] Furthermore, when the acoustic logging instrument 24 is located in the lower part 31 of the cylinder 29, the second control device 27 is used to control the logging instrument transmitter to transmit a reference acoustic wave signal through the logging system, and then the logging instrument receivers of each azimuth component receive and record the obtained reference acoustic wave signal. Then, the second analysis module in the second control device 27 is also used to perform data processing and analysis on the received reference acoustic wave signal, and after the reference acoustic wave signal is digitized, characteristic information such as amplitude, phase and spectrum of the digitized reference acoustic wave signal is extracted to obtain reference acoustic wave data. Among them, the first analysis module 23 in the data analysis device performs calibration calibration on the transmitter and receiver in the logging instrument by comparing and analyzing the basic measurement data analyzed above with the digitized data (reference acoustic wave data) corresponding to the received reference acoustic wave signal.

[0134] In an embodiment of the present invention, the first analysis module 23 in the data analysis device adopts an industrial computer equipped with data analysis software, which is not only used to process and analyze the received first acoustic wave signal to obtain a first data body, but also to obtain and collect the second data body and reference acoustic wave data from the second control device 27, and further compare and analyze the basic measurement data with the reference acoustic wave data and perform normalization calculations to obtain scale correction parameters including acoustic wave amplitude, acoustic wave phase, acoustic wave spectrum and acoustic wave time difference, so as to use the scale correction parameters obtained by the current scale measurement to calibrate the scale of the logging instrument transmitter and the logging instrument receiver of the logging instrument 24 during the actual logging application process.

[0135] Furthermore, the acoustic logging calibration system described in the embodiment of the present invention further includes: a synchronization signal line 26. In the embodiment of the present invention, the first control device 22 communicates with the second control device 27 via the synchronization signal line 26. The synchronization signal line is used to transmit synchronization signals that meet the synchronization requirements of transmission and reception in the first test and the second test. In other words, since the control object of the acoustic wave transmission is different from the control object of the acoustic wave reception in the first test and the second test, in order to ensure the time synchronization of transmission and reception, the embodiment of the present invention ensures the synchronization of transmission and reception by transmitting the synchronization signal between the first control device 22 and the second control device 27.

[0136] Furthermore, in the embodiment of the present invention, the normal communication between the first control device 22 and the second control device 27 is also guaranteed through the synchronization signal line 26, so as to complete the mutual transmission of data, signals and instructions. Therefore, in the embodiment of the present invention, the second control device 27 is also used to transmit the obtained second data body and / or reference sound wave data to the first control device 22 through the synchronization signal line 26, and then the first control device 22 forwards the second data body and / or reference sound wave data to the first analysis module 23, so that the first analysis module 23 uses it to perform data analysis to obtain the corresponding scale correction parameters.

[0137] Further reference Fig.11 The first control device 22 of the embodiment of the present invention includes a receiving and communication module (not numbered) and an acoustic wave transmitting module (not numbered). The receiving and communication module includes: a signal receiving and conditioning circuit 22.1, a data acquisition circuit 22.5 and a communication interface circuit 22.6.

[0138] Specifically, the signal receiving and conditioning circuit 22.1 is connected to the standard sound wave receiver 33. The signal receiving and conditioning circuit 22.1 adopts a program-controlled receiving amplification and attenuation filtering circuit, which is used to receive the first sound wave signal obtained in the first test process, and perform signal amplification and attenuation filtering processing on the first sound wave signal. The data acquisition circuit 22.5 is connected to the signal receiving and conditioning circuit 22.1. The data acquisition circuit 22.5 adopts a DSP acquisition and control circuit, which is used to perform DSP digital processing on the signal output from the signal receiving and conditioning circuit 22.1. The communication interface circuit 22.6 is connected to the data acquisition circuit 22.5. The communication interface circuit 22.6 adopts a network communication interface circuit, which is used to package the digital data output from the data acquisition circuit 22.5 and transmit it to the data analysis device (first analysis module 23).

[0139] During the first test, the acoustic logging instrument 24 supplies power to the logging instrument transmitter through the logging system 27 and controls it to emit acoustic signals. The standard acoustic receiver 33 receives the acoustic signals, and the received acoustic signals are sent to the program-controlled receiving amplification and attenuation filtering circuit 22.1 for signal attenuation processing. Then the signal enters the DSP acquisition and control circuit 22.5 for digital processing. The digitized signal is packaged by the network communication interface circuit 22.6 and transmitted to the first analysis module 23 for recording and analysis processing.

[0140] Further, the acoustic wave emission module includes: an emission control circuit 22.4, a constant voltage generating circuit 22.3 and an emission driving circuit 22.2. The emission control circuit 22.4 is connected to the data acquisition circuit 22.5. The emission control circuit 22.4 adopts a CPLD emission control circuit, which is used to generate an emission control signal for scale after receiving the emission instruction sent by the data acquisition circuit 22.5. Among them, the emission instruction is issued by the first analysis module 23 in the data analysis device and transmitted to the data acquisition circuit 22.5 through the communication interface circuit 22.6. The constant voltage generating circuit 22.3 is used to generate a specified voltage signal required for acoustic wave emission. The emission driving circuit 22.2 is respectively connected to the emission control circuit 22.4, the constant voltage generating circuit 22.3 and the standard acoustic wave transmitter 34. The emission driving circuit 22.2 is used to convert the specified voltage signal into a second acoustic wave signal under the control of the emission control signal for scale, and apply the second acoustic wave signal to the standard acoustic wave transmitter 34, so that the acoustic wave signal is emitted by the standard acoustic wave transmitter 34.

[0141] In the second test process, the first analysis module 23 sends the emission instruction to the DSP acquisition and control circuit 22.5 through the network communication interface circuit 22.6, and the circuit controls the CPLD emission control circuit 22.4 to generate an emission control signal for calibration. After the emission control signal for calibration is driven by the emission drive circuit 22.2, the specified voltage generated by the constant voltage emission circuit 23 is applied to the standard acoustic wave transmitter 34 in the upper part 30 of the scale cylinder 29 to emit an acoustic wave signal, and the acoustic wave logging instrument is synchronously controlled to receive and collect the acoustic wave signal, which is recorded by the logging system 27 and analyzed and processed by the second analysis module.

[0142] Based on the above-mentioned acoustic logging instrument and calibration system, an embodiment of the present invention further provides a borehole correction method for a three-dimensional remote detection acoustic logging instrument. The borehole correction method performs borehole eccentricity correction according to the first acoustic wave signal and the second acoustic wave signal received from the above-mentioned calibration system, and then uses the obtained borehole eccentricity correction parameters to perform borehole eccentricity correction on actual logging data.

[0143] Fig.12 It is a step diagram of a wellbore correction method for an acoustic logging instrument according to an embodiment of the present application. Fig.13 1 is a flow chart of a wellbore correction method for an acoustic well logging tool according to an embodiment of the present application. Fig.12 and Fig.13 The wellbore correction method described in the embodiment of the present invention is described.

[0144] Step S1201 obtains the first acoustic wave signal for the first test (transmitting calibration test) transmitted from the standard acoustic wave receiver, and records the first feature of each first acoustic wave signal (each instrument transmitter of the acoustic logging instrument is used as a corresponding transmitting sound source, and a first acoustic wave signal is formed when the first test is performed), and obtains the second acoustic wave signal for the second test (receiving calibration test) obtained from the instrument receiver, and records the second feature of each second acoustic wave signal (each instrument receiver of the acoustic logging instrument is used as a corresponding receiving component, and a second acoustic wave signal is formed when the second test is performed). Among them, the first feature and the second feature both contain multiple types of features, and the number of types of features contained in the first feature and the second feature are the same and the type content is also the same. Further, the first feature and the second feature both include amplitude features, phase features, spectrum features and energy features.

[0145] It should be noted that, in an embodiment of the present invention, the spectral characteristics of each transmitting sound source or receiver are preferably the frequency and energy relationship characteristics corresponding to different data points in the sound wave signal spectrum curve obtained over a period of time, and the energy characteristics of each transmitting sound source or receiver are preferably the time and energy relationship characteristics corresponding to different data points in the sound wave signal time curve obtained over a period of time.

[0146] In step S1201, firstly, any transmitting source in the acoustic logging instrument is placed at the standard transmitting position, and the amplitude, phase, spectrum and energy of the monopole and dipole transmitting sound sources in the current transmitting direction are calibrated. Specifically, the transmitting direction corresponding to the first monopole and / or dipole transmitting sound source is selected to be aligned with the transmitting scale mark (standard transmitting position), the first monopole and / or dipole transmitting sound source transmits a standard measuring sound wave signal, and the receiver at the standard receiving position receives the measuring sound wave signal emitted by the standard transmitting position, thereby measuring and recording the amplitude (characteristic) TA1, phase (characteristic) TP1, spectrum distribution information (characteristic) TF1 and energy (characteristic) TE1 of the current first transmitting sound source; then, the instrument is rotated so that the transmitting direction corresponding to the second monopole and / or dipole transmitting sound source is aligned with the transmitting scale mark, and the second monopole and / or dipole transmitting sound source transmits the standard The receiver at the standard receiving position receives the measuring sound wave signal emitted by the standard transmitting position, thereby measuring and recording the amplitude (characteristic) TA2, phase (characteristic) TP2, spectrum distribution information (characteristic) TF2 and energy (characteristic) TE2 of the current second transmitting sound source; repeat the above steps to complete the measurement and recording of the first characteristics of other transmitting sound sources in turn; finally, the rotating instrument completes the scale of the transmitting direction corresponding to the last single and / or dipole sound source, and measures and records the amplitude (characteristic) TAn, phase (characteristic) TPn, spectrum distribution information (characteristic) TFn and energy (characteristic) TEn of the last transmitting sound source. Wherein, n represents the total number of transmitting sound sources (transmitting directions) in the instrument.

[0147] After completing the measurement of the transmitting sound source, the acoustic wave receiving capability of each receiving detector must be measured in step S1201. Place any group of component receivers in the acoustic logging instrument at the receiving scale mark position (standard receiving position), and calibrate the amplitude, phase, spectrum and energy of the multi-component receivers respectively. Specifically, the instrument is rotated so that the receiver of the first component is aligned with the receiving scale mark (standard receiving position), the acoustic wave transmitter at the standard transmitting position transmits a standard measuring acoustic wave signal, and the first receiver at the standard receiving position receives the measuring acoustic wave signal emitted by the standard transmitting position, thereby measuring and recording the amplitude (characteristic) RA1, phase (characteristic) RP1, spectrum distribution information (characteristic) RF1 and energy (characteristic) RE1 of the current first receiver; the instrument is rotated so that the receiver of the second component is aligned with the receiving scale mark (standard receiving position), the acoustic wave transmitter at the standard transmitting position transmits a standard measuring acoustic wave signal, and the second receiver at the standard receiving position receives the measuring acoustic wave signal emitted by the standard transmitting position. The instrument is rotated to align the receiver of the last component with the receiving scale mark (standard receiving position), and the sound wave transmitter at the standard transmitting position transmits the standard measuring sound wave signal, and the last receiver at the standard receiving position receives the measuring sound wave signal emitted by the standard transmitting position, thereby measuring and recording the amplitude (characteristic) RAm, phase (characteristic) RPm, spectrum distribution information (characteristic) RFm and energy (characteristic) REm of the current last receiver. Wherein, m represents the total number of receivers in the instrument.

[0148] Fig.14 Schematic diagram of the waveform of acoustic logging in the borehole correction method for acoustic logging tool in the embodiment of the present application. Fig.14 As shown, the five waveform diagrams are respectively original sound wave signals received by five component receivers obtained from the second test of the calibration system.

[0149] After obtaining the calibration results of all the transmitters and receivers in the instrument, refer to Fig.12 Step S1202 normalizes each type of feature data in the first feature of each transmitting sound source and the second feature of each receiver recorded in step S1201, and performs system normalization correction on the actual acoustic logging data of each receiving component based on the normalization processing result of each type of feature data.

[0150] Further, in step S1202, it is necessary to normalize the amplitude characteristics, phase characteristics, spectral distribution characteristics and energy characteristics within the first characteristics of each transmitting sound source recorded in step S1201, and normalize the amplitude characteristics, phase characteristics, spectral distribution characteristics and energy characteristics within the second characteristics of each receiver recorded in step S1201, and calculate the transmitting amplitude correction coefficient, receiving amplitude correction coefficient, transmitting phase correction coefficient, receiving phase correction coefficient, transmitting spectrum correction coefficient and receiving spectrum correction coefficient based on various types of characteristic data, so as to use this information to perform systematic normalization correction on the acoustic logging data of each component.

[0151] Further, in the embodiment of the present invention, when calculating the emission amplitude, it is necessary to first obtain the amplitude characteristic data of each emission sound source, and determine the maximum amplitude value (of the emission source) therefrom, and then divide the amplitude characteristic data of each emission sound source by the current maximum amplitude value of the emission source to obtain the emission amplitude correction coefficient required currently. The emission amplitude correction coefficient is calculated according to the following expression:

[0152] TA=MAX(TA1, TA2, ..., TAn) (1)

[0153] NTA=(TA1 / TA, TA2 / TA, ……,TAn / TA) (2)

[0154] Among them, MAX represents a function for obtaining the maximum value within a specified range; NTA represents a transmission amplitude correction coefficient; TA1, TA2, ..., TAn respectively represent amplitude characteristic data corresponding to different transmission sound sources.

[0155] Further, in the embodiment of the present invention, when calculating the receiving amplitude correction coefficient, it is necessary to first obtain the amplitude characteristic data of each receiver, and determine the (receiving end) maximum amplitude value therefrom, and then divide the amplitude characteristic data of each receiver by the current receiving end maximum amplitude value to obtain the currently required receiving amplitude correction coefficient. The receiving amplitude correction coefficient is calculated according to the following expression:

[0156] RA=MAX(RA1,RA2,…,RAm) (3)

[0157] NRA=(RA1 / RA, RA2 / RA, ……, RAm / RA) (4)

[0158] Among them, NRA represents the receiving amplitude correction coefficient; RA1, RA2, ..., RAm represent the amplitude characteristic data corresponding to different receivers respectively.

[0159] Further, in the embodiment of the present invention, when calculating the transmission phase correction coefficient, it is necessary to first obtain the phase characteristic data of each transmission sound source, and determine the (transmission source) minimum phase value therefrom, and then, subtract the current transmission source minimum phase value from the phase characteristic data of each transmission sound source to obtain the currently required transmission phase correction coefficient. The transmission phase correction coefficient is calculated according to the following expression:

[0160] TP=MIN(TP1, TP2, ..., TPn) (5)

[0161] NTP=(TP-TP1, TP-TP2..., TP-TPn) (6)

[0162] Among them, NTP represents the transmission phase correction coefficient; TP1, TP2, ..., TPn respectively represent the phase characteristic data corresponding to different transmission sound sources.

[0163] Further, in the embodiment of the present invention, when calculating the receiving phase correction coefficient, it is necessary to first obtain the phase characteristic data of each receiver, and determine the (receiving end) minimum phase value therefrom, and then, subtract the current receiving end minimum phase value from the phase characteristic data of each receiver respectively, to obtain the currently required receiving phase correction coefficient. The receiving phase correction coefficient is calculated according to the following expression:

[0164] RP=MIN (RP1, RP2, ..., RPm) (7)

[0165] NRP=(RP-RP1, RP-RP2, ..., RP-RPm) (8)

[0166] Among them, NRP represents the receiving phase correction coefficient; RP1, RP2, ..., RPm respectively represent the phase characteristic data corresponding to different receivers.

[0167] Further, in the embodiment of the present invention, when calculating the emission spectrum correction coefficient, it is necessary to first obtain the energy characteristic data of each emission sound source, and determine the corresponding (emission source) main peak spectrum and proportion therefrom, so as to form corresponding emission characteristic data for each emission source, and finally, filter out the minimum emission characteristic data from the emission characteristic data of each emission source, and divide the emission characteristic data of each emission sound source by the current minimum emission characteristic data, respectively, to obtain the emission spectrum correction coefficient required currently. Among them, the emission spectrum correction coefficient is calculated according to the following expression:

[0168] TE=FMIN (TE1, TE2,..., TEn) (9)

[0169] NTE=(TE1 / TE, TE2 / TE,…, TEn / TE) (10)

[0170] Among them, NTE represents the emission spectrum correction coefficient; TE1, TE2, ..., TEn respectively represent the emission characteristic data corresponding to different emission sound sources, that is, the main peak spectrum and proportion; FMIN represents the function for obtaining the (minimum) value.

[0171] Further, in the embodiment of the present invention, when calculating the received spectrum correction coefficient, it is necessary to first obtain the energy characteristic data of each receiver, and determine the corresponding (receiving end) main peak spectrum and proportion therefrom, so as to form corresponding receiving characteristic data for each receiver, and finally, filter out the minimum receiving characteristic data from the receiving characteristic data of each receiver, and divide the receiving characteristic data of each receiver by the current minimum receiving characteristic data, so as to obtain the currently required receiving spectrum correction coefficient. The receiving spectrum correction coefficient is calculated according to the following expression:

[0172] RE=FMIN (RE1, RE2,…, REm) (11)

[0173] NRE=(RE1 / RE,RE2 / RE,…,REm / RE) (12)

[0174] Among them, NRE represents the receiving spectrum correction coefficient; RE1, RE2, ..., REm respectively represent the receiving characteristic data corresponding to different receivers, that is, the main peak spectrum and proportion.

[0175] Continue to refer Fig.12 After calculating the system normalization correction coefficients including the transmission amplitude, the receiving amplitude correction coefficient, the transmission phase, the receiving phase correction coefficient, the transmission spectrum and the receiving spectrum correction coefficient, these coefficient data are used to perform system normalization correction on the sound wave data of each component.

[0176] Specifically, first, according to the calculated transmission amplitude correction coefficient and reception amplitude correction coefficient, the following expression (13) is used to normalize and correct the amplitude of the acoustic logging data of each receiving component, and the amplitude of the acoustic logging data of each component after normalization correction is obtained; then, according to the calculated transmission phase correction coefficient and reception phase correction coefficient, the following expression (14) is used to normalize and correct the phase of the acoustic logging data of each receiving component, and the phase or arrival time of the acoustic logging data of each component after normalization correction is obtained; finally, according to the calculated transmission spectrum correction coefficient and reception spectrum correction coefficient, the following expression (15) is used to use a preset normalized bandpass filter to normalize and correct the frequency information of the acoustic logging data of each receiving component, and the frequency information of the acoustic logging data of each component after normalization correction is obtained. Among them, the acoustic data of each component is systematically normalized using the following expression:

[0177] AMP=(AMP / NTA) / NRA (13)

[0178] PHS=PHS-NTP-NRP (14)

[0179] FRQ=FILTER1(FRQ,NTE,NRE) (15)

[0180] Wherein, AMP represents the amplitude array of the acoustic logging data of each receiving component (i.e., in the actual application process, the array obtained by normalizing and correcting the amplitude data of the original acoustic signal actually received and measured by the acoustic logging instrument); PHS represents the phase or arrival time array of the acoustic logging data of each receiving component (i.e., in the actual application process, the array obtained by normalizing and correcting the phase or arrival time data of the original acoustic signal actually received and measured by the acoustic logging instrument); FRQ represents the spectrum information array of the acoustic logging data of each receiving component (i.e., in the actual application process, the array obtained by normalizing and correcting the spectrum information of the original acoustic signal actually received and measured by the acoustic logging instrument, wherein the spectrum information is the height or proportion information of the acoustic signal in a preset specific frequency range); FILTER1 represents a normalized bandpass filter. Preferably, FILTER1 is a weighted bandpass filter, and the passband frequency range of the filter is between the transmission spectrum and the reception spectrum correction coefficient.

[0181] In this way, the present invention can effectively complete the system normalization processing of the sound wave data acquired in real time in terms of amplitude, phase or arrival time, and spectrum information through the above-mentioned step S1202, thereby entering step S1203.

[0182] Step S1203 calculates the borehole eccentricity correction parameters of the current logging instrument based on the actual acoustic logging data of each component after system normalization correction obtained in step S1202, and performs borehole environment correction processing on the actual acoustic logging data of each component obtained by the acoustic logging instrument during the actual logging process based on the calculated borehole eccentricity correction parameters, thereby obtaining the final acoustic logging data of each component.

[0183] Further, refer to Fig.12 In step S1203, it is necessary to first obtain the amplitude array, phase or arrival time array and spectrum information array of the normalized actual acoustic logging data of each component obtained in step S1202, and calculate the amplitude eccentricity correction parameter, phase eccentricity correction parameter and frequency eccentricity correction parameter according to these array information, so as to use these eccentricity correction parameters to further perform wellbore environment correction on the actual acoustic logging data of each component.

[0184] Further, in the embodiment of the present invention, when calculating the amplitude eccentricity correction parameter, it is necessary to first obtain the amplitude array (recorded as normalized amplitude characteristic data) corresponding to the actual acoustic logging data after system normalization correction under each component, and extract the maximum normalized amplitude data therefrom, and then, divide the normalized amplitude characteristic data under each component by the current maximum normalized amplitude data respectively to obtain the currently required amplitude eccentricity correction parameter. Among them, the amplitude eccentricity correction parameter is calculated according to the following expression:

[0185] A=MAX(AMP1, AMP, ..., AMPm) (16)

[0186] NA=(AMP1 / A, AMP2 / A, ..., AMPm / A) (17)

[0187] Wherein, NA represents the amplitude eccentricity correction parameter; AMP1, AMP 2, ... AMP m represent the amplitude arrays corresponding to the actual acoustic logging data after system normalization correction under each component.

[0188] Further, in the embodiment of the present invention, when calculating the phase eccentricity correction parameter, it is necessary to first obtain the phase or arrival time array (recorded as normalized phase or arrival time characteristic data) corresponding to the actual acoustic logging data after normalization correction under each component, and extract the minimum normalized phase or arrival time data therefrom, and then, subtract the normalized phase or arrival time characteristic data under each component from the current minimum normalized phase or arrival time data, respectively, to obtain the phase eccentricity correction parameter currently required. Among them, the phase eccentricity correction parameter is calculated according to the following expression:

[0189] P=MIN(PHS1, PHS2, ..., PHSm) (18)

[0190] NP=(P-PHS1, P-PHS2, ..., P-PHSm) (19)

[0191] Wherein, NP represents the phase eccentricity correction parameter; PHS1, PHS2, ..., PHSm represent the phase or arrival time array corresponding to the actual acoustic logging data after normalization correction under each component.

[0192] Further, in an embodiment of the present invention, when calculating the frequency eccentricity correction parameter, it is necessary to first obtain the spectrum information array corresponding to the actual acoustic logging data after normalization correction under each component (recorded as normalized spectrum characteristic data), and extract the main peak spectrum and proportion therefrom, and then determine the spectrum information corresponding to the specified proportion in the spectrum information corresponding to the actual acoustic logging data of each component, so as to form corresponding specified passband spectrum information for each component, that is, the minimum passband frequency value of the following receiver bandpass filter, and finally, according to the main peak spectrum and proportion, and the specified passband frequency information corresponding to each component receiving unit, the receiver bandpass filter is used to perform filtering processing based on the specified bandpass range on the normalized frequency characteristic data under each component, so as to obtain the currently required frequency eccentricity correction parameter. Among them, the frequency eccentricity correction parameter is calculated according to the following expression:

[0193] F=FMIN (FRQ1, FRQ2,…, FRQm) (20)

[0194] NE=(FILTER0(E1,F),FILTER0(E2,F),…,FILTER0(Em,F)) (21)

[0195] Wherein, NE represents the frequency eccentricity correction parameter; FRQ1, FRQ2, ..., FRQm represent the frequency information array corresponding to the actual acoustic logging data after normalization correction under each component; FILTER0 represents the receiver bandpass filter; E1, E2, ..., Em represent the spectrum information corresponding to the specified proportion in the spectrum information corresponding to the actual acoustic logging data of each component; F represents the minimum passband frequency value of the current receiver bandpass filter. Preferably, FILTER0 is a weighted bandpass filter, and the passband frequency range of each receiver bandpass filter is between E1 ... Em and F.

[0196] Continue to refer Fig.12 After calculating the normalization correction coefficients including amplitude eccentricity correction parameters, phase eccentricity correction parameters and frequency eccentricity correction parameters, these coefficient data are used to perform system normalization correction on the acoustic logging data of each component.

[0197] Specifically, first, according to the amplitude array of the acoustic logging data of each received component after normalization correction, the calculated amplitude eccentricity correction parameter and the preset first weighted correction coefficient are used to perform borehole environment correction on the normalized corrected amplitude array under each component through the following expression (22), and the acoustic amplitude data after the borehole environment correction is obtained for each component; according to the phase or arrival time array of the acoustic logging data of each component after normalization correction, the calculated phase eccentricity correction parameter and the preset second weighted correction coefficient are used to perform the following expression (23): The normalized corrected phase or arrival time of each component is corrected for the borehole environment, and the acoustic wave phase or arrival time data after the borehole environment correction is obtained for each component; finally, according to the spectrum information array of the acoustic logging data of each component after the normalization correction, the calculated frequency eccentricity correction parameter and the preset third weighted correction coefficient are used, and the preset borehole environment correction bandpass filter is used to perform the borehole environment correction on the normalized corrected spectrum information of each component through the following expression (24), and the acoustic wave frequency data after the borehole environment correction is obtained for each component. Among them, the borehole environment correction is performed on the acoustic logging data of each component using the following expression:

[0198] AMP′=Ka*AMP / NA (22)

[0199] PHS′= Kp-PHS-NP (23)

[0200] FRQ′=FILTER2(FRQ,Kf(NE)) (24)

[0201] Among them, FILTER2 represents the borehole environment correction bandpass filter; Ka, Kp, Kf represent the first weighted correction coefficient, the second weighted correction coefficient and the third weighted correction coefficient respectively; AMP′ represents the acoustic amplitude array of each component after borehole correction, PHS′ represents the acoustic phase or arrival time array of each component after borehole correction, and FRQ′ represents the acoustic spectrum information array of each component after borehole correction.

[0202] Therefore, the present invention performs a systematic normalization process on the real-time acoustic logging data obtained by the instrument in step S1203, and then further performs a borehole environment correction process on the normalization result, thereby making a systematic and unified correction for instrument eccentricity, borehole irregularity and the like.

[0203] In summary, the present invention provides an acoustic logging instrument, a calibration system and a borehole correction method. The acoustic instrument arranges near, far, ultra-far and ultra-far monopoles in the transmitting acoustic system, and the radial circumference is evenly staggered and cross-arranged to form a 22.5° transmitting azimuth, which is 11.25° with the multiple groups of multi-arm receivers in the receiving acoustic system. Six different frequency bands, 16X16 azimuths, and 16 source distances are used to excite monopole, dipole, quadrupole and other modes of sound waves in different excitation modes, enter the formation in an omnidirectional or directional manner, and are received by a wide-band high-sensitivity active acoustic receiver. At the same time, a multi-component accelerometer is used to obtain instrument vibration and noise data to effectively eliminate the noise generated by instrument vibration. The acoustic logging instrument disclosed in the present invention can be measured against the well wall, and its precision is higher and its accuracy is better, which is more conducive to the reception and collection of reflected waves, and the detection distance and range are farther, and the azimuth resolution is higher. In addition, the calibration and borehole correction method proposed by the present invention for the acoustic logging instrument further improves the precision and accuracy of acoustic logging and three-dimensional acoustic long-distance detection, as well as the applicability in horizontal wells and highly deviated wells, and effectively solves the common problems of low precision and inaccurate measurement in horizontal wells and highly deviated wells in acoustic logging. In addition, the transmitter, receiver and line are calibrated through the new calibration system, which greatly improves the measurement precision and accuracy of the instrument, and the borehole eccentricity correction of acoustic logging highly deviated wells and horizontal wells is carried out to effectively finely characterize the fracture-cavity reservoir beside the well, so as to achieve a breakthrough in acoustic logging from tens of centimeters to hundreds of meters, complete three-dimensional acoustic long-distance measurement, calibration and borehole correction, and effectively expand the space and scale of acoustic logging technology, which is of great significance.

[0204] The three-dimensional long-distance acoustic wave detection and imaging logging technology proposed in the present invention can provide longitudinal and shear wave time differences, Stoneley wave time differences, full waveforms, cement bonding quality waveforms, including cross-dipole and monopole measurement results at various distances. In addition to axial and azimuthal measurements, radial measurements can also be performed. In addition, long-distance three-dimensional acoustic wave reflection wave detection and imaging can also be performed. The measurement results can not only provide useful information for evaluating the drilling environment and reservoirs, but also provide important data for decisions such as improving recovery and maximizing production; not only can it provide valuable data for perforating, completion, sand control, well positioning, reservoir evaluation, and production increase measures, but it can also provide comprehensive information for geophysics, rock physics, and post-casing measurement and cementing quality evaluation and analysis, helping to solve a number of problems that plague exploration and development, from unconventional oil and gas exploration to detailed description, evaluation, and reserve calculation of three-dimensional heterogeneous geological bodies.

[0205] The above is only a preferred specific embodiment of the present invention, but the protection scope of the present invention is not limited thereto. Any changes or substitutions that can be easily thought of by any person familiar with the technology within the technical scope disclosed by the present invention should be included in the protection scope of the present invention. Therefore, the protection scope of the present invention should be based on the protection scope of the claims.

[0206] It should be understood that the embodiments disclosed in the present invention are not limited to the specific structures, processing steps or materials disclosed herein, but should be extended to equivalent substitutions of these features understood by ordinary technicians in the relevant field. It should also be understood that the terms used herein are only used for the purpose of describing specific embodiments and are not meant to be limiting.

[0207] The "one embodiment" or "embodiment" mentioned in the specification means that the specific features, structures or characteristics described in conjunction with the embodiment are included in at least one embodiment of the present invention. Therefore, the phrases "one embodiment" or "embodiment" appearing in various places throughout the specification do not necessarily refer to the same embodiment.

[0208] Although the embodiments disclosed in the present invention are as above, the contents described are only embodiments adopted for facilitating the understanding of the present invention and are not intended to limit the present invention. Any technician in the technical field to which the present invention belongs can make any modifications and changes in the form and details of the implementation without departing from the spirit and scope disclosed in the present invention, but the patent protection scope of the present invention shall still be subject to the scope defined in the attached claims.

Claims

1. An acoustic logging tool, characterized in that: include: An acoustic wave transmitting system is used to transmit mode waves with different energy levels and different focusing modes to the formation; A transmission collection control circuit, which is adjacent to the first end of the acoustic wave transmission system, is used to determine the current transmission mode, generate a transmission control signal and an energy supply combination method that matches the current transmission mode, thereby providing transmission energy to the acoustic wave transmission system according to the energy supply combination method, and using the transmission control signal to excite a specified transducer in the acoustic wave transmission system; A sound wave receiving acoustic system, a first end of which is adjacent to the second end of the sound wave transmitting acoustic system, and is used to receive sound wave signals from different directions; A receiving and collecting control circuit is adjacent to the second end of the acoustic wave receiving system and is used to generate acoustic wave logging data according to the acoustic wave signal.

2. The sonic logging tool according to claim 1, characterized in that: The transmission and acquisition control circuit comprises: A transmission collection control short section, which is connected to the receiving collection control circuit, is used to receive the transmission control logic signal and generate the transmission control signal and energy supply combination mode instruction; A plurality of lower energy short sections are interconnected in different series-parallel combinations, and are used to form sufficient emission energy by combining different lower energy short sections in corresponding series-parallel combinations under the control of the energy supply combination instructions.

3. The sonic logging tool according to claim 2, characterized in that: The sound wave receiving system includes a plurality of groups of sound wave receiving modules, wherein the sound wave receiving module includes a plurality of sound wave receiving units, and the sound wave receiving units in the same sound wave receiving module are evenly distributed along the circumferential direction of the instrument body.

4. The sonic logging tool according to claim 3, characterized in that: Each sound wave receiving unit is connected to the instrument body through a corresponding pair of sliding arms.

5. The sonic logging tool according to claim 4, characterized in that: During cable logging or drilling tool conveying logging, the sliding arm is in an unfolded state, so that each of the acoustic wave receiving units is in close contact with the well wall.

6. The sonic logging tool according to claim 4 or 5, characterized in that: During logging while drilling, the sliding arm is in a closed state, so that each of the acoustic wave receiving units is embedded in the side wall of the instrument body and forms an isolation channel between the instrument body and the well wall.

7. The sonic logging tool according to any one of claims 3 to 6, characterized in that: The number of the sound wave receiving units configured in different groups of sound wave receiving modules is the same, wherein the azimuth angles of the sound wave receiving units in the different groups of sound wave receiving modules are completely staggered.

8. The sonic logging tool according to claim 7, characterized in that: The sound wave receiving modules are divided into two groups, and one group of sound wave receiving modules is provided with 8 sound wave receiving units.

9. The sonic logging tool according to claim 7, characterized in that: The sound wave receiving modules are divided into four groups, and one group of sound wave receiving modules is provided with four sound wave receiving units.

10. The sonic logging tool according to any one of claims 3 to 9, characterized in that: The sound wave receiving unit includes a sound wave receiving transducer, a signal amplifying circuit and a bandpass filtering circuit.

11. The sonic logging tool according to any one of claims 3 to 10, characterized in that: The acoustic wave receiving system also includes: a wellbore detector.

12. The sonic logging tool according to any one of claims 3 to 10, characterized in that: The sound wave receiving system further includes: a plurality of accelerometers, and the plurality of accelerometers are arranged corresponding to each of the sound wave receiving units.

13. The sonic logging tool according to any one of claims 1 to 12, characterized in that: The acoustic wave emission system comprises: A near-transmitting acoustic system adjacent to the first end of the acoustic wave receiving acoustic system, which is used to transmit high-frequency acoustic wave signals to the formation; The far-transmitting acoustic system adjacent to the near-transmitting acoustic system is used to transmit low-frequency acoustic wave signals to the stratum.

14. The sonic logging tool according to claim 13, characterized in that: The near-emission acoustic system comprises: A first boosting circuit, which is used to boost the obtained transmission energy to provide the required transmission energy to the high-frequency band sound wave transmission module; The high-frequency band sound wave transmitting module comprises a first transmitting unit, a second transmitting unit and a third transmitting unit, wherein the first transmitting unit, the second transmitting unit and the third transmitting unit sequentially form different source distances from near to far with the sound wave receiving sound system.

15. The sonic logging tool according to claim 14, characterized in that: The first transmitting unit is a monopole transmitting transducer, and the transmitting frequency range of the first transmitting unit is 20 to 50 kHz; The second transmitting unit is a dipole transmitting transducer, and the transmitting frequency range of the second transmitting unit is 1.2 to 8 kHz; The third transmitting unit is a monopole transmitting transducer, and the transmitting frequency range of the third transmitting unit is 12 to 25 kHz.

16. The sonic logging tool according to any one of claims 13 to 15, characterized in that: The far-transmitting acoustic system comprises: A second boost circuit, which is used to boost the obtained transmission energy to provide the required transmission energy to the low-frequency band sound wave transmission module; The low-frequency band sound wave transmitting module comprises a fourth transmitting unit, a fifth transmitting unit and a sixth transmitting unit, wherein the fourth transmitting unit, the fifth transmitting unit and the sixth transmitting unit sequentially form different source distances from near to far with the sound wave receiving sound system.

17. The sonic logging tool according to claim 16, characterized in that: The fourth transmitting unit is a monopole transmitting transducer, and the transmitting frequency range of the fourth transmitting unit is 5 to 15 kHz; The fifth transmitting unit is a dipole transmitting transducer, and the transmitting frequency range of the fifth transmitting unit is 0.3 to 3.5 kHz; The sixth transmitting unit is a monopole transmitting transducer, and the transmitting frequency range of the sixth transmitting unit is 1 to 10 kHz.

18. The sonic logging tool according to claim 16 or 17, characterized in that: The azimuth angles of the transducers in the first transmitting unit, the third transmitting unit, the fourth transmitting unit and the sixth transmitting unit are completely staggered.

19. The sonic logging tool according to any one of claims 16 to 18, characterized in that: The azimuth angles of the piezoelectric elements in the second transmitting unit and the fifth transmitting unit are completely staggered.

20. The sonic logging tool according to any one of claims 1 to 19, characterized in that: The receiving and collecting control circuit comprises: An acquisition control module, which is used to acquire the acoustic wave signal, the wellbore measurement signal and the acceleration signal obtained from the acoustic wave receiving acoustic system, and perform signal conditioning processing on these signals to form the acoustic wave logging data, wherein the signal conditioning processing includes program-controlled filtering and amplification, amplitude regularization, analog-to-digital conversion and digital signal processing; The communication module is used to send the acoustic logging data to other downhole instruments for backup storage or transmission to the surface.

21. A calibration system for an acoustic logging tool, characterized in that: The scale system comprises: Cylinder; a centralizer located at the upper portion of the cylinder; A standard sound wave transmitter is arranged at a first mark on the inner wall of the cylinder; a standard sound wave receiver, which is arranged at a second mark on the inner wall of the cylinder; An acoustic logging tool as claimed in any one of claims 1 to 20, which is located at the center of the cylinder through the centralizer, wherein a transmitter and a receiver in the logging tool are aligned with the standard acoustic receiver and the standard acoustic transmitter, respectively; a first control device, which is used to receive and record a first sound wave signal obtained by the standard sound wave receiver in a first test, and to control the standard sound wave transmitter to transmit a second sound wave signal in a second test; A second control device, which is used to control the instrument transmitter to transmit the first sound wave signal in the first test, and to receive and record the second sound wave signal obtained by the instrument receiver in the second test; The data analysis device is used for processing and analyzing the acoustic wave signals received by the two tests to obtain basic measurement data for calibrating the transmitter and receiver in the logging tool.

22. The graduation system according to claim 21, characterized in that The system also includes a mobile instrument located on the sonic logging tool, wherein: The mobile instrument is used to control the movement of each receiving unit in the sound wave receiving system so that the sound wave receiving unit corresponding to the measured component is aligned with the standard sound wave transmitter.

23. The graduation system according to claim 21 or 22, characterized in that The second control device is also used to control the stop position of the acoustic logging instrument, wherein, when the acoustic logging instrument is at the lower part of the cylinder, the acoustic wave transmitting system is controlled to transmit a reference acoustic wave signal, and then the acoustic wave receiving units of each component receive and record the obtained reference acoustic wave signal, wherein, The data analysis device performs calibration correction on the sound wave transmitting system and the sound wave receiving system by comparing and analyzing the analyzed basic measurement data with the numerical data corresponding to the reference sound wave signal.

24. The graduation system according to any one of claims 21 to 23, characterized in that: The upper part of the cylinder is a PPR cylinder, the lower part of the cylinder is a metal cylinder, the bottom of the cylinder is sealed by a wedge sponge rubber, and the top of the cylinder is a detachable metal plate, which is covered with a wedge sponge rubber.

25. The graduation system according to any one of claims 21 to 24, characterized in that: The cylinder is filled with an acoustic wave coupling liquid and the acoustic wave coupling liquid is left to stand for more than 2 hours before the test is carried out, wherein the diameter of the cylinder is in the range of 200 to 400 mm, and the inner wall of the cylinder is smooth and free of impurities.

26. The graduation system according to any one of claims 21 to 25, characterized in that The first control device communicates with the second control device via a synchronization signal line, wherein the synchronization signal line is used to transmit synchronization signals that meet transmission and reception synchronization requirements in the first test and the second test.

27. A graduation system according to any one of claims 21 to 26, characterized in that: The first control device includes a receiving and communication module, wherein the receiving and communication module includes: A signal receiving and conditioning circuit, connected to the standard sound wave receiver, for receiving the first sound wave signal and filtering the signal; A data acquisition circuit, connected to the signal receiving and conditioning circuit, for digitally processing the signal output by the signal receiving and conditioning circuit; The communication interface circuit is connected to the data acquisition circuit and is used for packaging the received digital data and transmitting it to the data analysis device.

28. The graduation system according to claim 27, characterized in that The first control device further includes a sound wave transmitting module, wherein the sound wave transmitting module includes: an emission control circuit connected to the data acquisition circuit, and configured to generate an emission control signal after receiving an emission instruction sent by the data acquisition circuit, wherein the emission instruction is issued by the data analysis device and transmitted to the data acquisition circuit through the communication interface circuit; A constant voltage generating circuit, which is used to generate a specified voltage signal required for sound wave emission; The transmitting driving circuit is respectively connected to the transmitting control circuit, the constant voltage generating circuit and the standard sound wave transmitter, and is used for converting the specified voltage signal into the second sound wave signal under the control of the transmitting control signal, and applying the second sound wave signal to the standard sound wave transmitter so that the standard sound wave transmitter transmits the sound wave signal.

29. A borehole calibration method for an acoustic logging tool, characterized in that: The borehole correction method performs borehole eccentricity correction on the acoustic wave signal received from the calibration system according to any one of claims 21 to 28, and the borehole correction method comprises: Obtaining the first acoustic wave signal for a first test transmitted from the standard acoustic wave receiver and recording a first feature of each first acoustic wave signal, and obtaining the second acoustic wave signal for a second test obtained from an instrument receiver and recording a second feature of each second acoustic wave signal, the feature including amplitude, phase, spectrum distribution and energy; Normalizing each type of feature data in the first feature and the second feature, and based on this, performing a system normalization correction on the acoustic logging data of each component; According to the acoustic logging data of each component after system normalization correction, the borehole eccentricity correction parameters of the current logging instrument are calculated, and according to the borehole eccentricity correction parameters, the actual acoustic logging data of each component is subjected to borehole environment correction processing.

30. The wellbore correction method according to claim 29, characterized in that: The step of respectively normalizing each type of feature data in the first feature and the second feature includes: The amplitude characteristics, phase characteristics, spectrum distribution characteristics and energy characteristics in the first characteristics are normalized respectively, and the amplitude characteristics, phase characteristics, spectrum distribution characteristics and energy characteristics in the second characteristics are normalized respectively to obtain the transmission amplitude correction coefficient, the reception amplitude correction coefficient, the transmission phase correction coefficient, the reception phase correction coefficient, the transmission spectrum correction coefficient and the reception spectrum correction coefficient respectively.

31. The wellbore correction method according to claim 30, characterized in that: According to the transmission amplitude correction coefficient and the reception amplitude correction coefficient, the amplitude of the acoustic logging data of each receiving component is systematically normalized and corrected to obtain the amplitude of the acoustic logging data of each component after normalization correction; According to the transmission phase correction coefficient and the reception phase correction coefficient, the phase of the acoustic logging data of each receiving component is systematically normalized and corrected to obtain the phase or arrival time of the acoustic logging data of each component after normalization correction; According to the transmission spectrum correction coefficient and the reception spectrum correction coefficient, a preset normalized bandpass filter is used to perform system normalization correction on the frequency information of the acoustic wave data of each receiving component to obtain the frequency information of the acoustic wave logging data of each component after normalization correction, wherein: The acoustic wave data of each component is systematically normalized using the following expression: AMP=(AMP / NTA) / NRA PHS=PHS-NTP-NRP FRQ=FILTER1(FRQ,NTE,NRE) Among them, AMP represents the amplitude array of the sound wave data of each receiving component, NTA represents the transmission amplitude correction coefficient, NRA represents the reception amplitude correction coefficient, PHS represents the phase or arrival time array of the sound wave data of each receiving component, NTP represents the transmission phase correction coefficient, NRP represents the reception phase correction coefficient, FRQ represents the frequency information array of the sound wave data of each receiving component, NTE represents the transmission spectrum correction coefficient, NRE represents the reception spectrum correction coefficient, and FILTER1 represents a normalized bandpass filter.

32. The wellbore correction method according to any one of claims 29 to 31, characterized in that: The step of calculating the borehole eccentricity correction parameter of the current logging instrument according to the acoustic logging data of each component after system normalization correction, and performing borehole environment correction processing on the acoustic logging data of each component according to the borehole eccentricity correction parameter includes: Obtaining the amplitude array, phase or arrival time array and frequency array of the sound wave data of each component after system normalization correction, based on which, respectively calculate the amplitude eccentricity correction parameter, the phase eccentricity correction parameter and the frequency eccentricity correction parameter; According to the amplitude array of the acoustic logging data of each component after the system normalization correction, the amplitude eccentricity correction parameter and the preset first weighted correction coefficient are used to perform wellbore environment correction on the amplitude of the acoustic logging data of each component, and the acoustic amplitude data after the wellbore environment correction is obtained for each component; According to the phase or arrival time array of the acoustic logging data of each component after system normalization correction, the phase eccentricity correction parameter and the preset second weighted correction coefficient are used to perform borehole environment correction on the phase or arrival time of the acoustic data of each component, so as to obtain the acoustic phase or arrival time data after the borehole environment correction for each component; According to the spectrum information array of the acoustic logging data of each component after system normalization correction, the frequency eccentricity correction parameter and the preset third weighted correction coefficient are used, and the preset borehole environment correction bandpass filter is adopted to perform borehole environment correction on the frequency information of the acoustic data of each component, and the acoustic frequency data after the borehole environment correction is obtained for each component, wherein, The following expression is used to perform borehole environment correction on the acoustic wave data of each component: AMP′=Ka*AMP / NA PHS′=Kp-PHS-NP FRQ′=FILTER2(FRQ,Kf(NE)) Among them, AMP represents the amplitude array of the acoustic logging data of each received component, PHS represents the phase or arrival time array of the acoustic logging data of each received component, FRQ represents the frequency information array of the acoustic logging data of each received component, NA represents the amplitude eccentricity correction parameter, NP represents the phase eccentricity correction parameter, NE represents the frequency eccentricity correction parameter, FILTER2 represents the borehole environment correction bandpass filter, Ka, Kp, Kf represent the first weighted correction coefficient, the second weighted correction coefficient and the third weighted correction coefficient respectively, AMP′ represents the acoustic amplitude array of each component after borehole correction, PHS′ represents the acoustic phase or arrival time array of each component after borehole correction, and FRQ′ represents the acoustic frequency information array of each component after borehole correction.

33. The wellbore correction method according to claim 30 or 31, characterized in that: Determine the maximum amplitude value of the emission source from the amplitude characteristic data of each emission sound source, divide the amplitude characteristic data of each emission sound source by the maximum amplitude value of the emission source, and obtain the emission amplitude correction coefficient; Determine the maximum amplitude value of the receiving end from the amplitude characteristic data of each receiving unit, divide the amplitude characteristic data of each receiving unit by the maximum amplitude value of the receiving end, and obtain the receiving amplitude correction coefficient; Determine the minimum phase value of the transmitting source from the phase characteristic data of each transmitting sound source, and perform subtraction operation on the minimum phase value of the transmitting source from the phase characteristic data of each transmitting sound source to obtain the transmitting phase correction coefficient; Determine the minimum phase value of the receiving end from the phase characteristic data of each receiving unit, and subtract the minimum phase value of the receiving unit from the phase characteristic data of each receiver to obtain the receiving phase correction coefficient; First, the main peak frequency and proportion are determined from the energy characteristic data of each emission sound source, so as to form corresponding emission characteristic data for each emission source, and finally the minimum emission characteristic data is screened out from the emission characteristic data of each emission source, and the emission characteristic data of each emission sound source is divided by the current minimum emission characteristic data to obtain the emission spectrum correction coefficient; First, the main peak frequency and proportion are determined from the energy characteristic data of each receiving unit, so as to form corresponding receiving characteristic data for each receiving unit. Finally, the minimum receiving characteristic data is screened out from the receiving characteristic data of each receiving unit, and the characteristic data of each receiving unit is divided by the current minimum receiving characteristic data to obtain the receiving spectrum correction coefficient.

34. The method for borehole correction according to claim 32, characterized in that: According to the amplitude array corresponding to the sound wave data of each component after system normalization correction, the maximum normalized amplitude data is extracted therefrom, and the normalized amplitude characteristic data of each component is divided by the maximum normalized amplitude data to obtain the amplitude eccentricity correction parameter; According to the phase or arrival time array corresponding to the sound wave data of each component after system normalization correction, the minimum normalized phase or arrival time data is extracted therefrom, and the minimum normalized phase or arrival time data is subtracted from the normalized phase or arrival time characteristic data of each component respectively to obtain the phase eccentricity correction parameter; First, according to the spectrum information array corresponding to the acoustic wave data of each component after system normalization correction, the main peak spectrum and proportion are extracted therefrom, and then the designated passband spectrum information corresponding to the designated proportion in the spectrum information corresponding to the actual acoustic logging data of each component is determined, and finally, according to the main peak frequency and proportion and the designated passband spectrum information corresponding to each receiving unit, the normalized frequency characteristic data of each component is filtered based on the designated passband range to obtain the frequency eccentricity correction parameter.

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