Longitudinal and transverse wave matching method and device based on waveform decomposition and computer equipment

Abstract

The invention provides a longitudinal and transverse wave matching method and device based on waveform decomposition and computer equipment. The method comprises the steps of correcting converted wave superposition data from a converted wave time domain to a longitudinal wave time domain to obtain initial converted wave data; obtaining converted wave forward modeling seismic data according to the drilling logging information and the longitudinal wave pre-stack gather data; performing waveform decomposition and reconstruction on the converted wave forward modeling seismic data and the initial converted wave data to obtain a first reconstruction data set and a second reconstruction data set; calculating the waveform similarity between any one piece of reconstructed seismic data in the first reconstructed data set and any one piece of reconstructed data in the second reconstructed data set; and calculating a correction time difference according to the waveform similarity and applying the correction time difference to the initial converted wave data to obtain converted wave data. The method comprises the steps of firstly obtaining initial converted wave data; and a correction time difference for fine correction of the initial converted wave data is obtained by using a waveform decomposition and reconstruction technology, and finally converted wave data with greatly improved matching precision is obtained.

Description

Technical Field

[0001] The embodiments of this specification relate to the field of geophysical exploration technology, and in particular to a method, device and computer equipment for matching longitudinal and transverse waves based on waveform decomposition. Background Art

[0002] At present, seismic exploration in the field of oil and gas field exploration, development and evaluation is usually single-component seismic exploration with P-wave excitation and P-wave reception. As the difficulty of exploration continues to increase, multi-component seismic exploration with P-wave excitation and P- and S-wave joint reception has received more and more attention due to the addition of S-wave information. In multi-component seismic, the signal of P-wave excitation and P-wave reception is called PP wave, or P-wave; the signal of P-wave excitation and S-wave reception is called PS wave, or conversion wave.

[0003] Since the propagation path of the converted wave is different from that of the longitudinal wave, the reflected shear wave velocity is different from that of the longitudinal wave, resulting in different propagation times of the longitudinal wave and the converted wave in the same stratum. In the process of multi-component seismic interpretation, the longitudinal wave and the converted wave of the same stratum need to be corrected to the same time scale. The usual practice is to compress the converted wave data from the converted wave time domain to the longitudinal wave time domain to achieve matching of the longitudinal and shear wave data. Since the peak on the longitudinal wave data does not necessarily correspond to the peak on the converted wave data, and the frequencies of the longitudinal wave and the converted wave are different, matching of the longitudinal and shear waves is often difficult.

[0004] At present, there are two main methods for matching P-waves and converted waves: one is a matching method based on the principle of maximum similarity of the reflection events of P-waves and converted waves; this method has the problem of low matching accuracy because P-waves and converted waves often have obvious differences in reflection characteristics. The other is a matching method based on reflection marker layers; this method can only meet the matching of large sets of strata, and cannot accurately match between marker layers.

[0005] In view of this, the present specification aims to provide a method, apparatus and computer device for longitudinal and transverse wave matching based on waveform decomposition. Summary of the invention

[0006] In view of the above-mentioned problems in the prior art, the purpose of the embodiments of this specification is to provide a longitudinal and transverse wave matching method, device and computer equipment based on waveform decomposition to solve the problem of low matching accuracy of the longitudinal and transverse wave matching method in the prior art.

[0007] In order to solve the above technical problems, the specific technical solutions of the embodiments of this specification are as follows:

[0008] In a first aspect, the embodiments of this specification provide a longitudinal and transverse wave matching method based on waveform decomposition, comprising:

[0009] Acquire drilling logging data and seismic data in the study area, wherein the seismic data includes pre-stack P-wave gather data and converted wave stack data;

[0010] According to the drilling logging data, the converted wave stacking data is corrected from the converted wave time domain to the longitudinal wave time domain to obtain initial converted wave data;

[0011] Obtaining converted wave forward modeling seismic data based on the drilling logging data and the P-wave pre-stack gather data;

[0012] Performing waveform decomposition and reconstruction on the converted wave forward modeling seismic data to obtain a first reconstructed data set consisting of a plurality of reconstructed seismic data;

[0013] Performing waveform decomposition and reconstruction on the initial converted wave data to obtain a second reconstructed data set consisting of a plurality of reconstructed data;

[0014] Calculating waveform similarity between any one of the reconstructed seismic data in the first reconstructed data set and any one of the reconstructed data in the second reconstructed data set;

[0015] Calculating a correction time difference based on the waveform similarity;

[0016] The corrected time difference is applied to the initial converted wave data to obtain converted wave data.

[0017] In some preferred embodiments, performing waveform decomposition on the converted wave forward modeling seismic data further comprises:

[0018] Using the waveform decomposition time window, perform waveform decomposition of the current round on the converted wave forward modeling seismic data after removing the seismic component data of the previous round, obtain the seismic component data of the current round, and repeat the above steps until the preset waveform decomposition round is reached;

[0019] Performing waveform decomposition on the initial converted wave data further comprises:

[0020] Using the time window of waveform decomposition, the initial converted wave data after removing the component data of the previous round is subjected to current round waveform decomposition to obtain the component data of the current round, and the above steps are repeated until the preset waveform decomposition round is reached.

[0021] In some preferred embodiments, reconstructing the converted wave forward modeling seismic data further comprises:

[0022] Reconstruct the current round of seismic component data obtained by decomposing the current round of waveform and all historical rounds of seismic component data obtained by decomposing all historical rounds of waveform to obtain the current round of reconstructed seismic data, and repeat the above steps until a preset reconstruction round is reached;

[0023] Reconstructing the initial converted wave data further includes:

[0024] Reconstruct the current round component data obtained by decomposing the current round waveform and all historical round component data obtained by decomposing all historical round waveforms to obtain current round reconstructed data, and repeat the above steps until a preset reconstruction round is reached.

[0025] In some preferred embodiments, calculating the correction time difference according to the waveform similarity further comprises:

[0026] marking the reconstructed seismic data in the first reconstructed data set and the reconstructed data in the second reconstructed data set associated with the maximum waveform similarity as target reconstructed seismic data and target reconstructed data, respectively;

[0027] Setting the same sliding time window for the target reconstructed seismic data and the target reconstructed data, and determining the maximum time range within which the reconstructed seismic data is allowed to move;

[0028] The center position of the sliding time window is respectively set at the same point to be calculated time shift on the target reconstructed seismic data and the target reconstructed data;

[0029] Moving the sliding time window of the target reconstructed seismic data within the maximum time range allowed for movement of the target reconstructed seismic data, and calculating the correlation between the target reconstructed seismic data and the target reconstructed data within the sliding time window after each movement;

[0030] The movement time corresponding to the maximum correlation is used as the correction time difference of the point to be calculated for the time shift of the target reconstructed data.

[0031] In some preferred embodiments, the seismic data further includes P-wave stacking data, and the step of correcting the converted wave stacking data from the converted wave time domain to the P-wave time domain to obtain initial converted wave data further includes:

[0032] Performing well seismic calibration on the P-wave stacking data and the converted wave stacking data respectively to determine the time depth of the target layer at the P-wave and the converted wave respectively;

[0033] According to the time depths of the target layer at the longitudinal wave and the converted wave, the longitudinal wave horizon interpretation and the converted wave horizon interpretation are performed on the marker layer including the target layer to obtain the horizon interpretation result;

[0034] According to the horizon interpretation result, the converted wave stacking data is corrected from the converted wave time domain to the longitudinal wave time domain to obtain initial converted wave data.

[0035] In some preferred embodiments, the seismic calibration is performed on the P-wave stacking data to determine the time depth of the target layer at the P-wave, further comprising:

[0036] According to the P-wave velocity curve and density curve in the drilling logging data, the P-wave reflection coefficient sequence is calculated;

[0037] Extracting the P-wave stacking data to obtain P-wave seismic wavelet;

[0038] Performing convolution operation on the P-wave seismic wavelet and the P-wave reflection coefficient sequence to obtain a P-wave synthetic record;

[0039] Comparing the P-wave synthetic record with the P-wave near-hole seismic to determine the time depth of the target layer at the P-wave;

[0040] Performing well seismic calibration on the converted wave stacking data to determine the time depth of the target layer at the converted wave further includes:

[0041] Determining the incident angle range of the converted wave according to the seismic data;

[0042] According to the incident angle range of the converted wave, a converted wave reflection coefficient is calculated;

[0043] Extracting the converted wave superposition data to obtain converted wave sub-waves;

[0044] Performing a convolution operation on the converted wavelet and the converted wave reflection coefficient within the incident angle range to obtain a converted wave pre-stack gather;

[0045] superimposing the converted wave pre-stack gathers to generate converted wave synthetic records;

[0046] The converted wave synthetic record is compared with the converted wave near-hole seismic to determine the time depth of the target layer at the time of the converted wave.

[0047] In some preferred embodiments, according to the horizon interpretation result, the converted wave stacking data is corrected from the converted wave time domain to the longitudinal wave time domain to obtain initial converted wave data, further comprising:

[0048] According to the results of horizon interpretation, the P-wave velocity ratio data is calculated by the following formula:

[0049]

[0050] in, is the ratio of longitudinal and transverse wave velocities, Vp is the longitudinal wave velocity, Vs is the transverse wave velocity, PP horizon PS is the result of the longitudinal wave interpretation of the marker layer containing the target layer. horizon The result of the horizon interpretation of the converted wave including the marker layer of the target layer;

[0051] The time of the converted wave data is converted into the longitudinal wave time according to the longitudinal and transverse wave velocity ratio data to obtain the converted wave data.

[0052] In some preferred embodiments, obtaining converted wave forward modeling seismic data based on the drilling logging data and the P-wave pre-stack gather data further comprises:

[0053] Inverting the P-wave pre-stack gather data according to the drilling logging data to obtain the shear wave impedance;

[0054] The initial converted wave data are forward modeled according to the shear wave impedance to obtain the converted wave forward modeled seismic data.

[0055] In a second aspect, this specification also provides a longitudinal and transverse wave matching device based on waveform decomposition, comprising:

[0056] An acquisition module is used to acquire drilling logging data and seismic data in the study area, wherein the seismic data includes pre-stack gather data of longitudinal waves and stacked data of converted waves;

[0057] A first correction module, used for correcting the converted wave superposition data from the converted wave time domain to the longitudinal wave time domain to obtain initial converted wave data;

[0058] A calculation module, used for obtaining converted wave forward modeling seismic data according to the drilling logging data and the P-wave pre-stack gather data;

[0059] A first decomposition and reconstruction module is used to perform waveform decomposition and reconstruction on the converted wave forward modeling seismic data to obtain a first reconstructed data set consisting of a plurality of reconstructed seismic data;

[0060] A second decomposition and reconstruction module is used to perform waveform decomposition and reconstruction on the initial converted wave data to obtain a second reconstructed data set consisting of a plurality of reconstructed data;

[0061] A waveform similarity calculation module, used for calculating the waveform similarity between any one of the reconstructed seismic data in the first reconstructed data set and any one of the reconstructed data in the second reconstructed data set;

[0062] A time difference calculation module, used for calculating the correction time difference according to the waveform similarity;

[0063] The second correction module is used to apply the correction time difference to the initial converted wave data to obtain converted wave data.

[0064] In a third aspect, the present specification also provides a computer device, comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor implements the method provided by the above technical solution when executing the computer program.

[0065] By adopting the above technical scheme, the embodiments of this specification provide a method, device and computer equipment for matching longitudinal and transverse waves based on waveform decomposition, which first corrects the converted wave superposition data from the converted wave time domain to the longitudinal wave time domain to obtain the initial converted wave data, thereby realizing a preliminary conversion; then uses the waveform decomposition and reconstruction technology to perform waveform decomposition and reconstruction on the converted wave forward modeling seismic data obtained by forward modeling and the actual initial converted wave data, and then performs waveform similarity matching and applies the corrected time difference obtained based on the matching result to the initial converted wave data to obtain the finely corrected converted wave data, thereby solving the problem of low matching accuracy caused by large differences in energy, frequency and phase between longitudinal waves and converted waves, improving the matching accuracy between longitudinal waves and converted waves, and having guiding significance for multi-component seismic exploration.

[0066] In order to make the above and other purposes, features and advantages of the embodiments of this specification more obvious and easy to understand, the following specifically cites preferred embodiments and describes them in detail with reference to the accompanying drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0067] In order to more clearly illustrate the embodiments of this specification or the technical solutions in the prior art, the drawings required for use in the embodiments or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of this specification. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying creative work.

[0068] Figure 1 A schematic diagram showing the steps of a longitudinal and transverse wave matching method based on waveform decomposition provided in an embodiment of this specification is shown;

[0069] Figure 2 A schematic diagram of the steps of correcting converted wave stacking data from the converted wave time domain to the longitudinal wave time domain to obtain initial converted wave data according to the drilling logging data in an embodiment of this specification is shown;

[0070] Figure 3 A schematic diagram showing the steps of performing well seismic calibration on P-wave stacking data and determining the time depth of the target layer at the P-wave in an embodiment of this specification;

[0071] Figure 4 (a) and (b) are schematic diagrams of borehole seismic calibration for P-wave stacking data and well seismic calibration for converted wave stacking data, respectively;

[0072] Figure 5 A schematic diagram showing the steps of performing well seismic calibration on converted wave stacking data and determining the time depth of the target layer at the converted wave in an embodiment of this specification;

[0073] Figure 6A schematic diagram of the steps of correcting the converted wave stacking data from the converted wave time domain to the longitudinal wave time domain to obtain the initial converted wave data according to the horizon interpretation result in the embodiment of this specification is shown;

[0074] Figure 7 A schematic diagram of the steps of obtaining converted wave forward modeling seismic data according to drilling logging data and P-wave pre-stack gather data in an embodiment of this specification is shown;

[0075] Figure 8 A schematic cross-sectional view of the shear wave impedance obtained by inverting the P-wave pre-stack gather data is shown;

[0076] Fig. 9 A schematic diagram showing the comparison between the converted wave forward modeling seismic data and the initial converted wave data in the embodiments of this specification;

[0077] Fig.10 A schematic diagram of the steps of calculating the correction time difference according to the waveform similarity in an embodiment of this specification is shown;

[0078] Fig.11 A schematic diagram showing the comparison between the reconstructed seismic data and the reconstructed data related to the maximum waveform similarity;

[0079] Fig.12 A schematic diagram showing the comparison between the initial converted wave data and the converted wave data is shown;

[0080] Fig.13 A schematic diagram of the structure of a longitudinal and transverse wave matching device based on waveform decomposition provided in an embodiment of this specification is shown;

[0081] Fig.14 A schematic diagram of the structure of a computer device provided in an embodiment of this specification is shown.

[0082] Description of the accompanying symbols:

[0083] 131. Get module;

[0084] 132. A first correction module;

[0085] 133. Calculation module;

[0086] 134. A first decomposition and reconstruction module;

[0087] 135. Second decomposition and reconstruction module;

[0088] 136. Waveform similarity calculation module;

[0089] 137. Time difference calculation module;

[0090] 138. A second correction module;

[0091] 1402. Computer equipment;

[0092] 1404, processor;

[0093] 1406. Memory;

[0094] 1408, driving mechanism;

[0095] 1410, input / output module;

[0096] 1412. Input device;

[0097] 1414. Output device;

[0098] 1416. Presentation equipment;

[0099] 1418. Graphical user interface;

[0100] 1420, network interface;

[0101] 1422, communication link;

[0102] 1424. Communication bus. DETAILED DESCRIPTION

[0103] The following will be combined with the drawings in the embodiments of this specification to clearly and completely describe the technical solutions in the embodiments of this specification. Obviously, the described embodiments are only part of the embodiments of this specification, not all of the embodiments. Based on the embodiments in this specification, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of this specification.

[0104] It should be noted that the terms "first", "second", etc. in this specification and claims and the above-mentioned drawings are used to distinguish similar objects, and are not necessarily used to describe a specific order or sequence. It should be understood that the data used in this way can be interchanged where appropriate, so that the embodiments of this specification described herein can be implemented in an order other than those illustrated or described herein. In addition, the terms "including" and "having" and any variations thereof are intended to cover non-exclusive inclusions, for example, a process, method, device, product or equipment that includes a series of steps or units is not necessarily limited to those steps or units clearly listed, but may include other steps or units that are not clearly listed or inherent to these processes, methods, products or equipment.

[0105] In order to solve the above problems, the embodiments of this specification provide a step diagram method, device and computer equipment of a longitudinal and transverse wave matching method based on waveform decomposition, which can solve the problem of low matching accuracy of existing longitudinal and transverse wave matching methods. Figure 1This is a schematic diagram of the steps of a longitudinal and transverse wave matching method based on waveform decomposition provided in the embodiments of this specification. This specification provides the method operation steps described in the embodiments or flow charts, but more or fewer operation steps may be included based on conventional or non-creative labor. The order of steps listed in the embodiments is only one way of executing the steps among many orders, and does not represent the only order of execution. When the actual system or device product is executed, it can be executed in the order of the methods shown in the embodiments or drawings or in parallel. Specifically, Figure 1 As shown, the method may include:

[0106] S110: Acquire drilling logging data and seismic data in the study area, wherein the seismic data includes P-wave pre-stack gather data and converted wave stack data.

[0107] The drilling logging data include but are not limited to P-wave velocity, S-wave velocity, density logging curve, and layered data. Among them, S-wave velocity can be obtained by actual measurement or by P-wave velocity calculation; layered data refers to the layered data of geological interfaces, such as the top interface of the Cretaceous and the top interface of the Permian. For ease of description, the P-wave pre-stack gather data is denoted as CPR, and the converted wave stack data is denoted as PS1.

[0108] S120: According to the drilling logging data, the converted wave stacking data is corrected from the converted wave time domain to the longitudinal wave time domain to obtain initial converted wave data.

[0109] The initial converted wave data is recorded as PS2.

[0110] S130: Obtain converted wave forward modeling seismic data according to the drilling logging data and the P-wave pre-stack gather data.

[0111] The converted wave forward modeling seismic data is denoted as RPS.

[0112] S140: performing waveform decomposition and reconstruction on the converted wave forward modeling seismic data to obtain a first reconstructed data set consisting of a plurality of reconstructed seismic data.

[0113] S150: performing waveform decomposition and reconstruction on the initial converted wave data to obtain a second reconstructed data set consisting of a plurality of reconstructed data.

[0114] S160: Calculate the waveform similarity between any one of the reconstructed seismic data in the first reconstructed data set and any one of the reconstructed data in the second reconstructed data set.

[0115] In the embodiments of this specification, the existing method can be used to perform waveform similarity calculation on any reconstructed seismic data and any reconstructed data.

[0116] S170: Calculate the correction time difference according to the waveform similarity.

[0117] Specifically, the corrected time difference is calculated based on a pair of reconstructed seismic data and reconstructed data associated with maximum waveform similarity.

[0118] S180: Apply the corrected time difference to the initial converted wave data to obtain converted wave data.

[0119] The converted wave data is recorded as PS3, that is, the initial converted wave data PS2 is corrected by using the correction time difference to obtain the final converted wave data PS3 after accurate matching.

[0120] The embodiment of the present specification provides a longitudinal and transverse wave matching method based on waveform decomposition, which first corrects the converted wave superposition data from the converted wave time domain to the longitudinal wave time domain to obtain the initial converted wave data PS2, thereby realizing a preliminary conversion; in order to solve the reflection difference problem between the converted wave forward modeling seismic data RPS obtained by forward modeling and the actual initial converted wave data PS2, waveform decomposition and reconstruction technology is used to improve the waveform similarity between the converted wave forward modeling seismic data RPS obtained by forward modeling and the actual initial converted wave data PS2, and then the converted wave forward modeling seismic data RPS obtained by forward modeling is matched with the actual initial converted wave data PS2, thereby realizing a fine correction of the initial converted wave data PS2 obtained by the preliminary conversion to obtain the final correction result converted wave data PS3, thereby solving the problem of low matching accuracy caused by the large difference in energy, frequency and phase between the longitudinal wave and the converted wave, thereby improving the matching accuracy between the longitudinal wave and the converted wave, which has important guiding significance for multi-component seismic exploration.

[0121] like Figure 2 As shown, in the embodiment of this specification, the seismic data also includes P-wave stacking data, denoted as PP, step S120: according to the drilling and logging data, the converted wave stacking data is corrected from the converted wave time domain to the P-wave time domain to obtain initial converted wave data, further comprising:

[0122] S210: Performing well seismic calibration on the P-wave stacking data and the converted wave stacking data respectively, and determining the time depth of the target layer at the P-wave and the converted wave respectively.

[0123] In the embodiments of this specification, the target layer also contains oil and gas reservoirs, which are the objects of subsequent exploration and development.

[0124] S220: According to the time depths of the target layer at the longitudinal wave and the converted wave, respectively, a longitudinal wave horizon interpretation and a converted wave horizon interpretation are performed on the marker layer including the target layer to obtain a horizon interpretation result.

[0125] That is, after determining the time depth of the target layer at the longitudinal wave and the converted wave, a suitable marker layer is selected according to the time depth, and the selection of the marker layer should include the target layer; and then the stratigraphic interpretation of the selected marker layer is performed. Exemplarily, if the time depth of the target layer is 1000ms, then the marker layer H1 can be selected with a time depth of 800ms and the marker layer H2 with a time depth of 1200ms, that is, the time depth of the target layer is between the time depths of the marker layer H1 and the marker layer H2. It should be noted that in the embodiments of this specification, there can be multiple target layers, and there can be multiple marker layers accordingly.

[0126] S230: According to the horizon interpretation result, the converted wave stacking data is corrected from the converted wave time domain to the longitudinal wave time domain to obtain initial converted wave data.

[0127] The initial conversion wave data PS2 is as follows Fig. 9 Through the above steps, the initial conversion of the converted wave in the longitudinal wave time domain is achieved, providing a basis for subsequent fine correction.

[0128] like Figure 3 As shown, in step S210, performing well seismic calibration on the P-wave stacking data to determine the time depth of the target layer at the P-wave may include the following steps:

[0129] S310: Calculate and obtain a P-wave reflection coefficient sequence based on the P-wave velocity curve and density curve in the drilling logging data.

[0130] Specifically, the longitudinal wave velocity curve and the density curve are multiplied to obtain the longitudinal wave impedance curve, and then the longitudinal wave reflection coefficient sequence is obtained according to the longitudinal wave impedance curve.

[0131] S320: Extract the P-wave stacking data to obtain P-wave seismic wavelet.

[0132] S330: performing a convolution operation on the P-wave seismic wavelet and the P-wave reflection coefficient sequence to obtain a P-wave synthetic record.

[0133] S340: Compare the P-wave synthetic record with the P-wave near-hole seismic to determine the time depth of the target layer in the P-wave.

[0134] like Figure 4As shown in (a), it is a schematic diagram of borehole seismic calibration of P-wave stacking data. The P-wave synthetic record is compared with the P-wave wellside seismic (i.e., the reflection channel data of the nearest earthquake from the PP seismic data to the drilling position, i.e., the position of the vertical line in the figure) to achieve the best match between the P-wave synthetic record and the P-wave wellside seismic (data). For example, the crest position of the P-wave synthetic record coincides with the crest position of the P-wave wellside seismic, and the trough position of the P-wave synthetic record coincides with the trough position of the P-wave wellside seismic. Thus, a corresponding relationship is established between the data in the depth domain and the data in the time domain, and then the time depth of the target layer in the P-wave can be accurately determined based on the borehole seismic calibration results.

[0135] like Figure 5 As shown, in step S210, performing well seismic calibration on the converted wave stacking data to determine the time depth of the target layer at the converted wave further includes:

[0136] S510: Determine the incident angle range of the converted wave according to the seismic data.

[0137] In the embodiment of this specification, the incident angle range of the converted wave is 0-60 degrees.

[0138] S520: Calculate a converted wave reflection coefficient according to the converted wave incident angle range.

[0139] Specifically, the converted wave reflection coefficient when the incident angle ranges from 0 to 60 degrees is calculated according to the following formula:

[0140]

[0141] Among them, R ps is the converted wave reflection coefficient, θ is the longitudinal wave incident angle, is the incident angle of the converted wave, v s is the average velocity of longitudinal waves, ρ is the average density of the medium, Δv s is the velocity difference of longitudinal waves, Δρ is the density difference, and γ is the ratio of shear wave to longitudinal wave velocities.

[0142] S530: extracting the converted wave superposition data to obtain converted wave sub-waves.

[0143] S540: performing a convolution operation on the converted wavelet and the converted wave reflection coefficient within the incident angle range to obtain a converted wave pre-stack gather.

[0144] S550: Superimposing the converted wave pre-stack gathers to generate converted wave synthetic records.

[0145] S560: Compare the converted wave synthetic record with the converted wave near-hole seismic to determine the time depth of the target layer at the converted wave.

[0146] like Figure 4 (b) is a schematic diagram of borehole seismic calibration of converted wave stacking data. Similar to determining the time depth of the target layer in the longitudinal wave, determining the time depth of the target layer in the converted wave is: comparing the converted wave synthetic record with the converted wave wellside seismic (data) to achieve the best match between the converted wave synthetic record and the converted wave wellside seismic (data). Thus, a corresponding relationship is established between the data in the depth domain and the data in the time domain, and then the time depth of the target layer in the converted wave can be accurately determined based on the borehole seismic calibration results.

[0147] In the embodiment of this specification, step S230: according to the horizon interpretation result, the converted wave stacking data PS1 is corrected from the converted wave time domain to the longitudinal wave time domain to obtain the initial converted wave data PS2, which may include:

[0148] According to the results of horizon interpretation, the P-wave velocity ratio data is calculated by the following formula:

[0149]

[0150] in, is the ratio of longitudinal and transverse wave velocities, Vp is the longitudinal wave velocity, Vs is the transverse wave velocity, PP horizon PS is the result of the longitudinal wave interpretation of the marker layer containing the target layer. horizon The result of the horizon interpretation of the converted wave containing the marker layer of the target layer.

[0151] For example, in the embodiments of this specification, H1, H2, and H3 are strong trough reflections in the longitudinal wave and the converted wave, and can be used as marker layers. Therefore, the H1, H2, and H3 layers are explained in the longitudinal wave and the converted wave data, respectively, such as Figure 6 (a) and Figure 6 as shown in (b).

[0152] According to the longitudinal and transverse wave velocity ratio data, the time of the converted wave data is converted into the longitudinal wave time to obtain the initial converted wave data.

[0153] Align H1, H2, H3 interpreted on the converted wave data with H1, H2, H3 interpreted on the longitudinal wave data to obtain the initial converted wave data, such as Figure 6 as shown in (c).

[0154] Through the above steps, preliminary matching of longitudinal and shear wave data can be achieved.

[0155] like Figure 7 As shown, step S130: obtaining converted wave forward modeling seismic data according to the drilling logging data and the P-wave pre-stack gather data may include the following steps:

[0156] S710: Invert the P-wave pre-stack gather data according to the drilling logging data to obtain the S-wave impedance.

[0157] Furthermore, the process of obtaining the shear wave impedance is:

[0158] According to the P-wave impedance, S-wave impedance and density curves in the drilling and logging data, and the P-wave horizon interpretation result of the marker layer obtained in step S220, a low-frequency model of P-wave impedance, S-wave impedance and density is established;

[0159] Divide the pre-stack gather data of longitudinal waves into several parts and stack them respectively to form several partial stack bodies;

[0160] Carry out well-seismic calibration on each partial stack body and extract the wavelet of each partial stack body;

[0161] The low-frequency model, each partial stack, and the wavelet corresponding to each partial stack are used as input to perform prestack sparse pulse inversion to obtain the shear wave impedance. The shear wave impedance is Figure 8 shown.

[0162] It should be noted that the embodiments of this specification provide a method of using sparse pulses as described above to invert the P-wave prestack gather data to obtain the S-wave impedance. In some other feasible embodiments, other inversion methods may also be used.

[0163] S720: According to the shear wave impedance, forward modeling is performed on the initial converted wave data to obtain the converted wave forward modeled seismic data.

[0164] The specific steps may include:

[0165] Perform well-seismic calibration on the initial converted wave data to extract the seismic wavelet of the initial converted wave data; usually, the given time window in the wavelet extraction process includes the target layer range;

[0166] The seismic wavelet of the initial converted wave data is convolved with the shear wave impedance to obtain the converted wave forward modeling seismic data. In the embodiment of this specification, the converted wave forward modeling seismic data RPS is as follows: Fig. 9 As shown in (a).

[0167] It should be noted that, in addition to the above-mentioned method of using the convolution method to forward model the initial converted wave data to obtain converted wave forward modeled seismic data provided in the embodiments of this specification, other forward modeling methods may also be used, such as wave equations.

[0168] In the embodiment of the present specification, in step S140, waveform decomposition of the converted wave forward modeling seismic data RPS is further performed including:

[0169] By using the waveform decomposition time window, the converted wave forward modeling seismic data after removing the previous round of seismic component data is subjected to the current round of waveform decomposition to obtain the current round of seismic component data, and the above steps are repeated until the preset waveform decomposition round threshold is reached.

[0170] Specifically, according to the time window of waveform decomposition, the waveform data with the largest commonality and amplitude is extracted from the converted wave forward seismic data RPS as the first round of seismic component data;

[0171] Using the waveform decomposition time window, the converted wave forward modeling seismic data after removing the first round of seismic component data is subjected to the current round of waveform decomposition (i.e., the second round of waveform decomposition), and the waveform data with the largest commonality and the largest amplitude is obtained as the current round of seismic component data (i.e., the second round of seismic component data);

[0172] The waveform decomposition time window is used again to perform waveform decomposition of the current round on the converted wave forward modeling seismic data after the previous round of seismic component data (i.e., the second round of seismic component data) is removed, and the waveform data with the largest commonality and the largest amplitude is obtained as the current round of seismic component data (i.e., the third round of seismic component data);

[0173] And so on, until the number of waveform decompositions of the converted wave forward seismic data reaches a preset waveform decomposition round threshold, or the proportion of noise in the converted wave forward seismic data after eliminating the previous round of seismic component data is greater than a preset noise proportion threshold.

[0174] It should be noted that in the embodiments of this specification, the maximum commonality may specifically refer to the maximum commonality of the waveforms, for example, it may indicate that the shapes of the waveforms are closest. The time window used for the above-mentioned waveform decomposition is determined by the interpretation result of the marker layer in the longitudinal wave layer obtained in step S220; in this embodiment, the time window of the waveform decomposition can be set to (H1-30ms, H3+30ms). Thus, through the above-mentioned waveform decomposition steps, the seismic component data of the converted wave forward seismic data RPS are obtained.

[0175] And, in step S140, waveform decomposition of the initial converted wave data PS2 further comprises:

[0176] Using the waveform decomposition time window, the initial converted wave data after removing the previous round of component data is subjected to current round waveform decomposition to obtain the current round component data, and the above steps are repeated until the preset waveform decomposition round threshold is reached.

[0177] Specifically, the time window of waveform decomposition is used to extract the waveform data with the largest commonality and the largest amplitude from the initial converted wave data PS2 as the component data for the current round (i.e., the first round component data); the time window for waveform decomposition of the initial converted wave data is determined based on the interpretation results of the marker layer in the longitudinal wave layer. In the embodiment of this specification, it is preferably (H1-30ms, H3+30ms).

[0178] Using the time window of waveform decomposition, the initial converted wave data after removing the component data of the previous round (i.e., the component data of the first round) is subjected to the current round of waveform decomposition, and the waveform data with the largest commonality and the largest amplitude is obtained as the component data of the current round (i.e., the component data of the second round);

[0179] The time window of waveform decomposition is used again to perform current round waveform decomposition on the initial converted wave data after removing the previous round component data (i.e., the second round component data), and the waveform data with the largest commonality and the largest amplitude is obtained as the current round component data (i.e., the third round component data);

[0180] This process is repeated until the number of waveform decompositions of the initial converted wave data reaches a preset waveform decomposition round threshold, or the proportion of noise in the initial converted wave data after removing the current round component data is greater than a preset noise proportion threshold. Thus, through the above waveform decomposition steps, each component data of the initial converted wave data is obtained.

[0181] It should be noted that the number of waveform decompositions of the converted wave forward modeling seismic data and the number of waveform decompositions of the initial converted wave data may be the same or different.

[0182] In the embodiment of this specification, the waveform decomposition round threshold for waveform decomposition of converted wave forward modeling seismic data and the waveform decomposition round threshold for waveform decomposition of initial converted wave data are both set to 4, taking into account the characteristics of the reflected waveform of the reservoir, the interference of other geological factors in the formation, and the workload of the subsequent reconstruction step, waveform similarity calculation step, etc. The waveform decomposition round threshold for waveform decomposition of converted wave forward modeling seismic data and the waveform decomposition round threshold for waveform decomposition of initial converted wave data are both set to 4. Through four waveform decompositions, it is ensured that the seismic component data representing the reservoir are separated from the converted wave forward modeling seismic data, and the component data are separated from the initial converted wave data, and the remaining waveform data are usually some information representing noise.

[0183] Furthermore, in step S140, reconstructing the converted wave forward modeling seismic data RPS further includes:

[0184] The current round of seismic component data obtained by decomposing the current round of waveform and all historical rounds of seismic component data obtained by decomposing all historical rounds of waveform are reconstructed to obtain the current round of reconstructed seismic data, and the above steps are repeated until a preset reconstruction round threshold is reached.

[0185] Specifically, the first round of seismic component data obtained by the first round of waveform decomposition is reconstructed to obtain the first round of reconstructed seismic data, which is recorded as RPS(1);

[0186] Reconstruct the second-round seismic component data obtained by the second-round waveform decomposition and the first-round seismic component data (i.e., all historical-round seismic component data) obtained by the first-round waveform decomposition to obtain the second-round reconstructed seismic data, denoted as RPS(2);

[0187] Reconstruct the third round of seismic component data obtained by the third round of waveform decomposition, and the first round of seismic component data and the second round of seismic component data (i.e., all historical rounds of seismic component data) obtained by the first and second rounds of waveform decomposition (all historical rounds of waveform decomposition) to obtain the third round of reconstructed seismic data, denoted as RPS(3); and

[0188] The fourth round of seismic component data obtained by the fourth round of waveform decomposition is reconstructed with the first round of seismic component data, the second round of seismic component data and the third round of seismic component data to obtain the fourth round of reconstructed seismic data, denoted as RPS(4).

[0189] Through the above steps, a first reconstructed data set consisting of a plurality of reconstructed seismic data is obtained, and it can be known that the reconstruction round threshold should be less than or equal to the waveform decomposition round threshold for waveform decomposition of the converted wave forward modeling seismic data. In the embodiment of this specification, the reconstruction round threshold is also set to 4.

[0190] Reconstructing the initial converted wave data PS2 further comprises:

[0191] The current round component data obtained by decomposing the current round waveform and all historical round component data obtained by decomposing all historical round waveforms are reconstructed to obtain the current round reconstructed data, and the above steps are repeated until a preset reconstruction round threshold is reached.

[0192] Correspondingly, the reconstruction round threshold for reconstructing the component data of each round is also set to 4, and the specific process is as follows:

[0193] Reconstruct the first-round component data obtained by the first-round waveform decomposition to obtain the first-round reconstructed data, which is recorded as PS(1);

[0194] Reconstruct the second-round component data and the first-round component data obtained by the second-round waveform decomposition to obtain the second-round reconstructed data, which is recorded as PS(2);

[0195] Reconstructing the third-round component data obtained by the third-round waveform decomposition, the first-round component data, and the second-round component data to obtain third-round reconstructed data, denoted as PS(3); and

[0196] The fourth-round component data obtained by decomposing the fourth-round waveform are reconstructed with the first-round component data, the second-round component data and the third-round component data to obtain fourth-round reconstructed data, which is recorded as PS(4).

[0197] Through the above steps, a second reconstructed data set consisting of a plurality of reconstructed data is obtained.

[0198] Considering that the seismic data of the target layer contains data generated by reservoir reflection, it also contains data generated by interference from other geological factors such as overlying strata and underlying strata. In order to perform fine correction later, the converted wave forward seismic data can be subjected to waveform decomposition to obtain multiple seismic component data, and the initial converted wave data can be subjected to waveform decomposition to obtain multiple component data; and then reconstructed to eliminate the influence of data generated by other interferences, so that the obtained waveform data can better reflect the reflection interface.

[0199] Furthermore, if Fig.10 As shown, step S170: calculating the correction time difference according to the waveform similarity may include the following steps:

[0200] S1010: Mark the reconstructed seismic data in the first reconstructed data set and the reconstructed data in the second reconstructed data set that are associated with the maximum waveform similarity as target reconstructed seismic data and target reconstructed data, respectively.

[0201] That is, waveform similarity calculation is performed on the reconstructed seismic data RPS(i) and the reconstructed data PS2(j); wherein i and j are rounds; the value of i is 1 to 4, and the value of j is 1 to 4.

[0202] The waveform similarities of each pair of reconstructed seismic data RPS(i) and reconstructed data PS2(j) calculated are compared to obtain a pair of reconstructed seismic data RPS(i) and reconstructed data PS2(j) corresponding to the maximum waveform similarity, as shown in FIG. Fig.11 (a) and Fig.11 (b) is a schematic diagram showing a comparison of target reconstructed seismic data RPS(i) and target reconstructed data PS2(j) related to maximum waveform similarity. In the embodiment of this specification, the target reconstructed seismic data and the target reconstructed data are RPS(2) and PS2(2), respectively.

[0203] S1020: Setting the same sliding time window for the target reconstructed seismic data and the target reconstructed data, and determining the maximum time range within which the reconstructed seismic data is allowed to move.

[0204] Generally, the maximum time range allowed for movement of the reconstructed seismic data is usually less than 10 ms.

[0205] S1030: setting the center position of the sliding time window at the same point to be calculated for time shift on the target reconstructed seismic data and the target reconstructed data respectively.

[0206] S1040: Move the sliding time window of the target reconstructed seismic data within the maximum time range allowed for movement of the target reconstructed seismic data, and calculate the correlation between the target reconstructed seismic data and the target reconstructed data within the sliding time window after each movement.

[0207] S1050: Using the movement time corresponding to the maximum correlation as the correction time difference of the point to be calculated for the time shift of the target reconstructed data.

[0208] Repeat the above steps S1030 to S1050 to calculate the correction time difference of each point on the target reconstructed data PS(2) for which the time shift is to be calculated. Then, the calculated correction time difference of each point is applied to each corresponding point on the initial converted wave data PS2 to obtain the finely corrected converted wave data PS3. For example, the calculation is Fig.12 In (a), the correction time difference of the peak position indicated by the arrow in the target reconstructed data PS(2) is -5ms. When the correction time difference is applied to the initial converted wave data PS2, the same point on the initial converted wave data PS2 is moved upward by 5ms, and the following is obtained: Fig.12 The converted wave data PS3 shown in (b) shows that the distance between the peak position indicated by the arrow and the marker layer H2 is relatively Fig.12 The peak position indicated by the arrow in (a) is close to the marker layer H2. Fig.12 In (b), the longitudinal and transverse wave matching method based on waveform decomposition provided in the embodiments of this specification can greatly improve the matching accuracy between the longitudinal wave and the converted wave.

[0209] like Fig.13 As shown, the embodiment of this specification also provides a longitudinal and transverse wave matching device based on waveform decomposition, including:

[0210] An acquisition module 131 is used to acquire drilling logging data and seismic data in a study area, wherein the seismic data includes pre-stack gather data of longitudinal waves and stacked data of converted waves;

[0211] A first correction module 132 is used to correct the converted wave superposition data from the converted wave time domain to the longitudinal wave time domain to obtain initial converted wave data;

[0212] A calculation module 133 is used to obtain converted wave forward modeling seismic data based on the drilling logging data and the P-wave pre-stack gather data;

[0213] A first decomposition and reconstruction module 134 is used to perform waveform decomposition and reconstruction on the converted wave forward modeling seismic data to obtain a first reconstructed data set consisting of a plurality of reconstructed seismic data;

[0214] A second decomposition and reconstruction module 135 is used to perform waveform decomposition and reconstruction on the initial converted wave data to obtain a second reconstructed data set consisting of a plurality of reconstructed data;

[0215] A waveform similarity calculation module 136, used for calculating the waveform similarity between any one of the reconstructed seismic data in the first reconstructed data set and any one of the reconstructed data in the second reconstructed data set;

[0216] A time difference calculation module 137, used to calculate the correction time difference according to the waveform similarity;

[0217] The second correction module 138 is configured to apply the corrected time difference to the initial converted wave data to obtain converted wave data.

[0218] The beneficial effects obtained by the device provided in the embodiments of this specification are consistent with the beneficial effects obtained by the above method and will not be repeated here.

[0219] like Fig.14 As shown, a computer device provided by an embodiment of this specification, the longitudinal and transverse wave matching device based on waveform decomposition in this specification can be a computer device in this embodiment, executing the above method of this specification. The computer device 1402 may include one or more processors 1404, such as one or more central processing units (CPUs), and each processing unit may implement one or more hardware threads. The computer device 1402 may also include any memory 1406, which is used to store any kind of information such as code, settings, data, etc. Non-restrictive, for example, the memory 1406 may include any one or more combinations of the following: any type of RAM, any type of ROM, flash memory device, hard disk, optical disk, etc. More generally, any memory can use any technology to store information. Further, any memory can provide volatile or non-volatile retention of information. Further, any memory can represent a fixed or removable component of the computer device 1402. In one case, when the processor 1404 executes an associated instruction stored in any memory or a combination of memories, the computer device 1402 can perform any operation of the associated instruction. The computer device 1402 also includes one or more drive mechanisms 1408 for interacting with any storage, such as a hard disk drive mechanism, an optical disk drive mechanism, etc.

[0220] The computer device 1402 may also include an input / output module 1410 (I / O) for receiving various inputs (via input devices 1412) and for providing various outputs (via output devices 1414). A specific output mechanism may include a presentation device 1416 and an associated graphical user interface (GUI) 1418. In other embodiments, the input / output module 1410 (I / O), input device 1412, and output device 1414 may not be included, and the computer device 1402 may be used as a computer device in a network. The computer device 1402 may also include one or more network interfaces 1420 for exchanging data with other devices via one or more communication links 1422. One or more communication buses 1424 couple the components described above together.

[0221] The communication link 1422 may be implemented in any manner, for example, through a local area network, a wide area network (e.g., the Internet), a point-to-point connection, etc., or any combination thereof. The communication link 1422 may include any combination of hardwired links, wireless links, routers, gateway functions, name servers, etc. governed by any protocol or combination of protocols.

[0222] Corresponding to Figures 1 to 3 , Figure 5 , Figure 7 and Fig.10 In addition to the method shown, an embodiment of the specification also provides a computer-readable storage medium, on which a computer program is stored, and when the computer program is executed by a processor, the steps of the above method are executed.

[0223] The embodiment of the present specification also provides a computer-readable instruction, wherein when the processor executes the instruction, the program therein causes the processor to execute the following Figures 1 to 3 , Figure 5 , Figure 7 and Fig.10 The method shown.

[0224] The embodiments of the present specification also provide a computer program product, including at least one instruction or at least one program, wherein the at least one instruction or the at least one program is loaded and executed by a processor to implement the following Figures 1 to 3 , Figure 5 , Figure 7 and Fig.10 The method shown.

[0225] It should be understood that in the various embodiments of this specification, the size of the serial numbers of the above-mentioned processes does not mean the order of execution. The execution order of each process should be determined by its function and internal logic, and should not constitute any limitation on the implementation process of the embodiments of this specification.

[0226] It should also be understood that in the embodiments of this specification, the term "and / or" is only a description of the association relationship of the associated objects, indicating that three relationships can exist. For example, A and / or B can represent: A exists alone, A and B exist at the same time, and B exists alone. In addition, the character " / " in this specification generally indicates that the associated objects before and after are in an "or" relationship.

[0227] Those of ordinary skill in the art will appreciate that the units and algorithm steps of each example described in conjunction with the embodiments disclosed in this specification can be implemented in electronic hardware, computer software, or a combination of the two. In order to clearly illustrate the interchangeability of hardware and software, the composition and steps of each example have been generally described in the above description according to function. Whether these functions are performed in hardware or software depends on the specific application and design constraints of the technical solution. Professional and technical personnel can use different methods to implement the described functions for each specific application, but such implementation should not be considered to be beyond the scope of this specification.

[0228] Those skilled in the art can clearly understand that, for the convenience and brevity of description, the specific working processes of the systems, devices and units described above can refer to the corresponding processes in the aforementioned method embodiments and will not be repeated here.

[0229] In the several embodiments provided in this specification, it should be understood that the disclosed systems, devices and methods can be implemented in other ways. For example, the device embodiments described above are only schematic. For example, the division of the units is only a logical function division. There may be other division methods in actual implementation, such as multiple units or components can be combined or integrated into another system, or some features can be ignored or not executed. In addition, the mutual coupling or direct coupling or communication connection shown or discussed can be an indirect coupling or communication connection through some interfaces, devices or units, or it can be an electrical, mechanical or other form of connection.

[0230] The units described as separate components may or may not be physically separated, and the components shown as units may or may not be physical units, that is, they may be located in one place or distributed on multiple network units. Some or all of the units may be selected according to actual needs to achieve the purpose of the embodiments of this specification.

[0231] In addition, each functional unit in each embodiment of this specification may be integrated into one processing unit, or each unit may exist physically separately, or two or more units may be integrated into one unit. The above integrated unit may be implemented in the form of hardware or in the form of software functional units.

[0232] If the integrated unit is implemented in the form of a software functional unit and sold or used as an independent product, it can be stored in a computer-readable storage medium. Based on this understanding, the technical solution of this specification is essentially or the part that contributes to the prior art, or all or part of the technical solution can be embodied in the form of a software product, and the computer software product is stored in a storage medium, including a number of instructions to enable a computer device (which can be a personal computer, a server, or a network device, etc.) to perform all or part of the steps of the method described in each embodiment of this specification. The aforementioned storage medium includes: U disk, mobile hard disk, read-only memory (ROM, Read-Only Memory), random access memory (RAM, Random Access Memory), disk or optical disk and other media that can store program codes.

[0233] Specific embodiments are used in this specification to illustrate the principles and implementation methods of this specification. The description of the above embodiments is only used to help understand the methods and core ideas of this specification. At the same time, for those skilled in the art, according to the ideas of this specification, there will be changes in the specific implementation methods and application scope. In summary, the content of this specification should not be understood as a limitation on this specification.

Claims

1. A longitudinal and transverse wave matching method based on waveform decomposition, characterized in that: include: Acquire drilling logging data and seismic data in the study area, wherein the seismic data includes pre-stack P-wave gather data and converted wave stack data; According to the drilling logging data, the converted wave stacking data is corrected from the converted wave time domain to the longitudinal wave time domain to obtain initial converted wave data; Obtaining converted wave forward modeling seismic data based on the drilling logging data and the P-wave pre-stack gather data; Performing waveform decomposition and reconstruction on the converted wave forward modeling seismic data to obtain a first reconstructed data set consisting of a plurality of reconstructed seismic data; Performing waveform decomposition and reconstruction on the initial converted wave data to obtain a second reconstructed data set consisting of a plurality of reconstructed data; Calculating waveform similarity between any one of the reconstructed seismic data in the first reconstructed data set and any one of the reconstructed data in the second reconstructed data set; Calculating a correction time difference based on the waveform similarity; The corrected time difference is applied to the initial converted wave data to obtain converted wave data.

2. The method according to claim 1, characterized in that: Performing waveform decomposition on the converted wave forward modeling seismic data further includes: Using the waveform decomposition time window, perform waveform decomposition of the current round on the converted wave forward modeling seismic data after removing the seismic component data of the previous round, obtain the seismic component data of the current round, and repeat the above steps until the preset waveform decomposition round is reached; Performing waveform decomposition on the initial converted wave data further comprises: Using the time window of waveform decomposition, the initial converted wave data after removing the component data of the previous round is subjected to current round waveform decomposition to obtain the component data of the current round, and the above steps are repeated until the preset waveform decomposition round is reached.

3. The method according to claim 2, characterized in that Reconstructing the converted wave forward modeling seismic data further includes: Reconstruct the current round of seismic component data obtained by decomposing the current round of waveform and all historical rounds of seismic component data obtained by decomposing all historical rounds of waveform to obtain the current round of reconstructed seismic data, and repeat the above steps until a preset reconstruction round is reached; Reconstructing the initial converted wave data further includes: Reconstruct the current round component data obtained by decomposing the current round waveform and all historical round component data obtained by decomposing all historical round waveforms to obtain current round reconstructed data, and repeat the above steps until a preset reconstruction round is reached.

4. The method according to claim 1, characterized in that: Calculating the correction time difference according to the waveform similarity further comprises: marking the reconstructed seismic data in the first reconstructed data set and the reconstructed data in the second reconstructed data set associated with the maximum waveform similarity as target reconstructed seismic data and target reconstructed data, respectively; Setting the same sliding time window for the target reconstructed seismic data and the target reconstructed data, and determining the maximum time range within which the reconstructed seismic data is allowed to move; The center position of the sliding time window is respectively set at the same point to be calculated time shift on the target reconstructed seismic data and the target reconstructed data; Moving the sliding time window of the target reconstructed seismic data within the maximum time range allowed for movement of the target reconstructed seismic data, and calculating the correlation between the target reconstructed seismic data and the target reconstructed data within the sliding time window after each movement; The movement time corresponding to the maximum correlation is used as the correction time difference of the point to be calculated for the time shift of the target reconstructed data.

5. The method according to claim 1, characterized in that The seismic data also includes P-wave stacking data, and the converted wave stacking data is corrected from the converted wave time domain to the P-wave time domain to obtain initial converted wave data, further comprising: Performing well seismic calibration on the P-wave stacking data and the converted wave stacking data respectively to determine the time depth of the target layer at the P-wave and the converted wave respectively; According to the time depths of the target layer at the longitudinal wave and the converted wave, the longitudinal wave horizon interpretation and the converted wave horizon interpretation are performed on the marker layer including the target layer to obtain the horizon interpretation result; According to the horizon interpretation result, the converted wave stacking data is corrected from the converted wave time domain to the longitudinal wave time domain to obtain initial converted wave data.

6. The method according to claim 5, characterized in that Performing well seismic calibration on the P-wave stacking data to determine the time depth of the target layer at the P-wave further includes: According to the P-wave velocity curve and density curve in the drilling logging data, the P-wave reflection coefficient sequence is calculated; Extracting the P-wave stacking data to obtain P-wave seismic wavelet; Performing convolution operation on the P-wave seismic wavelet and the P-wave reflection coefficient sequence to obtain a P-wave synthetic record; Comparing the P-wave synthetic record with the P-wave near-hole seismic to determine the time depth of the target layer at the P-wave; Performing well seismic calibration on the converted wave stacking data to determine the time depth of the target layer at the converted wave further includes: Determining the incident angle range of the converted wave according to the seismic data; According to the incident angle range of the converted wave, a converted wave reflection coefficient is calculated; Extracting the converted wave superposition data to obtain converted wave sub-waves; Performing a convolution operation on the converted wavelet and the converted wave reflection coefficient within the incident angle range to obtain a converted wave pre-stack gather; superimposing the converted wave pre-stack gathers to generate converted wave synthetic records; The converted wave synthetic record is compared with the converted wave near-hole seismic to determine the time depth of the target layer at the time of the converted wave.

7. The method according to claim 5, characterized in that According to the horizon interpretation result, the converted wave stacking data is corrected from the converted wave time domain to the longitudinal wave time domain to obtain initial converted wave data, further comprising: According to the results of horizon interpretation, the P-wave velocity ratio data is calculated by the following formula: in, is the ratio of longitudinal and transverse wave velocities, Vp is the longitudinal wave velocity, Vs is the transverse wave velocity, PP horizon PS is the result of the longitudinal wave interpretation of the marker layer containing the target layer. horizon The result of the horizon interpretation of the converted wave including the marker layer of the target layer; The time of the converted wave data is converted into the longitudinal wave time according to the longitudinal and transverse wave velocity ratio data to obtain the converted wave data.

8. The method according to claim 1, characterized in that Obtaining converted wave forward modeling seismic data according to the drilling logging data and the P-wave pre-stack gather data, further comprising: Inverting the P-wave pre-stack gather data according to the drilling logging data to obtain the shear wave impedance; The initial converted wave data are forward modeled according to the shear wave impedance to obtain the converted wave forward modeled seismic data.

9. A longitudinal and transverse wave matching device based on waveform decomposition, characterized in that: include: An acquisition module is used to acquire drilling logging data and seismic data in the study area, wherein the seismic data includes pre-stack gather data of longitudinal waves and stacked data of converted waves; A first correction module, used for correcting the converted wave superposition data from the converted wave time domain to the longitudinal wave time domain to obtain initial converted wave data; A calculation module, used for obtaining converted wave forward modeling seismic data according to the drilling logging data and the P-wave pre-stack gather data; A first decomposition and reconstruction module is used to perform waveform decomposition and reconstruction on the converted wave forward modeling seismic data to obtain a first reconstructed data set consisting of a plurality of reconstructed seismic data; A second decomposition and reconstruction module is used to perform waveform decomposition and reconstruction on the initial converted wave data to obtain a second reconstructed data set consisting of a plurality of reconstructed data; A waveform similarity calculation module, used for calculating the waveform similarity between any one of the reconstructed seismic data in the first reconstructed data set and any one of the reconstructed data in the second reconstructed data set; A time difference calculation module, used for calculating the correction time difference according to the waveform similarity; The second correction module is used to apply the correction time difference to the initial converted wave data to obtain converted wave data.

10. A computer device comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that: When the processor executes the computer program, the method according to any one of claims 1 to 8 is implemented.

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