CN114355451A - Well seismic calibration method based on multi-channel seismic stack - Google Patents

Abstract

The invention discloses a well-seismic calibration method based on multi-channel seismic superposition. The method comprises: obtaining a time domain synthetic record of a well to be calibrated; time shift amount, and use the time shift amount to correct each wellside seismic trace; carry out the correlation coefficient weighted superposition of the corrected well side seismic trace and the reference well side seismic trace to form the initial composite well side seismic trace; Effective signal enhancement processing and/or standardization processing is performed on the initial composite well bypass to obtain a processed composite well bypass; the time domain synthetic record and the processed composite well bypass are compared and processed to realize well seismic calibration . The present invention can significantly improve the accuracy and rationality of well-seismic calibration results when the signal-to-noise ratio of seismic data is low.

Description

A well-seismic calibration method based on multi-channel seismic stacking

technical field

The invention belongs to the technical field of oil and gas exploration.

Background technique

Well-seismic calibration is an important means to connect depth-domain logging data and time-domain seismic data. Accurate well-seismic calibration has an important impact on the results of many key technologies such as reservoir prediction and reservoir characterization.

Seismic data has the characteristics of large coverage area and good plane continuity, but low vertical resolution. On the contrary, logging data has high vertical resolution but no horizontal continuity. Therefore, the two are combined to achieve well-seismic calibration. The advantages of both can be effectively used for in-depth oil and gas exploration.

The process of the conventional well-seismic calibration method mainly includes: obtaining the formation reflection coefficient sequence through the logging data and convolving it with appropriate wavelets to make a synthetic record, and manually adjusting the synthetic record to complete the alignment with the seismic trace next to the borehole; When the noise ratio is high, the conventional method can achieve better calibration, but when the seismic signal-to-noise ratio is low, the calibration accuracy will be greatly reduced.

SUMMARY OF THE INVENTION

In view of the defects of the prior art, the purpose of the present invention is to provide a well-seismic calibration method based on multi-channel seismic superposition, which can solve the problem of inaccurate well-seismic calibration results and difficult calibration process when the signal-to-noise ratio of seismic data is low. The problem.

The technical scheme of the present invention is as follows:

A well-seismic calibration method based on multi-channel seismic stacking, comprising:

Based on the logging data, obtain the time domain synthetic record of the well to be calibrated;

Based on the seismic data, the reference well-side seismic trace is selected according to the logging position, and the time shift between the remaining well-side seismic traces and the reference well-side seismic trace is obtained by using the automatic warping algorithm; Correction is performed to obtain the seismic traces beside the well after correction;

Carrying out the correlation coefficient weighted stacking of the corrected wellside seismic trace and the reference well side seismic trace to form an initial composite well side seismic trace;

Performing effective signal enhancement processing and/or standardization processing on the initial composite well bypass to obtain a processed composite well bypass;

The time domain synthetic record is compared with the processed composite well side channel to realize well seismic calibration.

According to some preferred embodiments of the present invention, the obtaining of the time domain synthetic record includes:

The depth domain reflection coefficient sequence is obtained from the single well sonic time difference log curve and density log curve of the well to be calibrated;

Converting the depth domain reflection coefficient sequence to the time domain to obtain its time domain reflection coefficient sequence;

The time domain reflection coefficient sequence and the seismic wavelet sequence are convolved to obtain the time domain synthetic record sequence of the well to be calibrated.

According to some preferred embodiments of the present invention, the depth domain reflection coefficient sequence is obtained by the following formula:

Ref(i)=Vel(i)*Den(i)

Among them, Ref(i) represents the depth domain reflection coefficient sequence, Vel(i) represents the velocity sequence calculated from the sonic time difference logging curve, Den(i) represents the logging density curve, and i represents the depth domain sampling point.

The time domain synthetic record sequence of the well to be calibrated is obtained by the following formula:

S(t)=Ref(t)*ω(t)

Wherein, S(t) represents the synthetic recording sequence, ω(t) represents the seismic wavelet sequence, Ref(t) represents the reflection coefficient sequence in the time domain, * represents the convolution operation, and t represents the sampling point in the time domain.

According to some preferred embodiments of the present invention, obtaining the time shift amount includes:

In the obtained wellbore seismic trace sequence, select the reference well seismic trace sequence, and set a time window, and extract the wellbore seismic trace sequence within the time window range in the direction of the seismic line as the basic wellbore seismic trace sequence;

establishing a calculation model of the amplitude matrix of the reference well seismic side channel sequence and the base well side seismic trace sequence containing moving variables;

Using the time series regularization of the sliding time window, within the range of the maximum seismic trace length beside the well and the total moving width of the moving variable, the amplitude matrix is optimized and accumulated, and the accumulated amplitude matrix is obtained;

The cumulative amplitude matrix is calculated by a regression algorithm, and the sequence of the time shifts is further obtained by a backtracking algorithm.

According to some preferred embodiments of the present invention, the calculation model of the amplitude matrix e _i is as follows:

e _i (t, j)=|T ₀ (t)-T _i (t+j)| ² ,

j=[-J, J], t=[0, M-1],

Among them, e _i (t, j) indicates that when the time series number is t and the time shift amount is j, the reference seismic trace sequence T ₀ (t) and the i-th wellbore seismic trace within the time range of t+i are obtained. The amplitude matrix element calculated by trace T _i (t+j), j represents the time moving variable, its value range parameter J can be selected according to the actual seismic data and underground medium conditions, i represents the seismic trace next to the i-th well , L represents the time window of the number of seismic traces next to the well, and M represents the total number of sampling points in the time series;

The cumulative amplitude matrix E _i is established as follows:

E _i (0, j) = e _i (0, j)

Among them, E _i (0, j) represents the cumulative amplitude matrix element when the time sequence number is 0 and the time shift amount is j, and E _i (t, j) represents the cumulative amplitude matrix with time t and shift variable j element, then E _i (t-1, j-1) represents the cumulative amplitude matrix element whose time series is t-1 and the moving variable is j-1, and E _i (t-1, j) indicates that the time series is t- 1. The cumulative amplitude matrix element with the moving variable j, E _i (t-1, j+1) represents the cumulative amplitude matrix element with the time series number t-1 and the moving variable j+1, e _i (0, j) represents the amplitude matrix element calculated from the sampling points T ₀ (0) and T _i (j) of the reference well-side seismic trace at 0 time when the time series number is 0;

The sequence p _i (t) of the time-shifted quantities is established as follows:

When t=M-1:

p _i (t) = p _i (M-1)

=argmin{E _i (M-1, -J), E _i (M-1, -J+1), ..., E _i (M

-1, 0), ..., E _i (M-1, J-1), E _i (M-1, J)}

When t=0, 1.2, ..., M-2:

Wherein, M=max(t) represents the maximum length of the seismic trace next to the well, and N=2J+1 represents the total moving width.

According to some preferred embodiments of the present invention, the correction performed on each well-side seismic trace according to the obtained time shift is realized by the following correction model:

NewT _i (t)=T _i (t+ _pi (t))

Among them, NewT _i (t) represents the i-th well-side seismic trace after correction, T _i (t) represents the i-th well-side seismic trace before correction, t represents the ordinal number of the sampling point in the time domain, p _i (t) represents the sequence of the time shift amounts.

According to some preferred embodiments of the present invention, the obtaining of the initial composite well-side seismic trace includes:

calculating the correlation coefficient of each sampling point between the corrected well-side seismic trace and the reference well-side seismic trace;

weighted superposition of the correlation coefficients of the sampling points to obtain initial superimposed wellbore seismic traces;

Relative normalization is performed on the initial superimposed wellbore seismic traces to obtain the initial composite wellbore seismic traces.

According to some preferred embodiments of the present invention, the correlation coefficient of each sampling point is obtained by the following formula:

Among them, N represents the number of sampling points in the seismic trace, mT ₀ is the sum and average of each point in the seismic trace T ₀ (t) next to the reference well, and mT _i is the correction of each point in the seismic trace NewT _i (t) beside the well after correction. The points are summed and then averaged, and C _i represents the correlation coefficient between the corrected well-side seismic trace NewT _i (t) and the reference well-side seismic trace T ₀ (t).

The weighted superposition is achieved by the following calculation model:

Wherein, MT(t) represents the initial superimposed well-side seismic trace, and L represents the time window width.

The relative normalization is achieved by the following computational model:

Wherein, NT(t) represents the initial composite well-side seismic trace.

According to some preferred embodiments of the present invention, the obtaining of the composite well bypass after the treatment includes:

Set a judgment threshold, compare the effective signal parameters of each sampling point in the initial composite well-side seismic trace with the judgment threshold, and when the effective signal parameter is greater than or equal to the judgment threshold, the corresponding initial composite well-side The sampling points in the seismic trace are enhanced, and when the effective signal parameter is less than the determination threshold, the corresponding sampling points in the initial composite well-side seismic trace are weakened to obtain a composite well-side seismic trace sequence determined by the threshold;

Standard normalization is performed on the composite well side seismic trace sequence after the threshold determination, to obtain the processed composite well side trace sequence.

According to some preferred embodiments of the present invention, the composite wellbore seismic trace sequence determined by the threshold is obtained by the following determination model:

时，Y(t_k)＝3×NT(t_k)，when

, Y(t _k )=3×NT(t _k ),

时，

when

hour,

Among them, NT(t _k ) is a sampling point of NT(t) at time t=k, T ₀ (t _k ) is a sampling point of T ₀ (t) at time t=k, and NT(t) represents For the initial composite wellbore trace, T ₀ (t) represents its corresponding reference wellbore trace, Y(t) represents the threshold-judged composite wellbore trace, and a represents the judgment threshold.

The standard normalization is achieved by the following normalization model:

Wherein, NY(t) represents the side channel of the composite well after the treatment, max(Y(t)) represents the maximum value in Y(t), min(Y(t)) represents the minimum value in Y(t), N represents the number of sampling points in the seismic trace,

The present invention uses the automatic warping algorithm to correct the remaining seismic traces by using the reference seismic trace as the standard, obtains the cross-correlation coefficient between the corrected multi-trace seismic and the reference trace, and realizes the weighted superposition of the correlation coefficient of the multi-trace seismic. When the signal-to-noise ratio of seismic data is low, the accuracy and rationality of the well-seismic calibration results can be significantly improved. Combined with further subsequent effective signal enhancement, noise reduction processing and other preferred implementations, a compound with excellent calibration accuracy can be formed. Seismic trace information next to the well.

Description of drawings

FIG. 1 is a flow chart of the present invention described in the specific embodiment.

Fig. 2 is the amplitude matrix e that one of the seismic traces beside the well to be corrected and the seismic trace beside the reference well established in Example 1;

Fig. 3 is the cumulative amplitude matrix E established by one of the seismic traces to be corrected and the reference seismic traces beside the well and the sequence p sought by the path backtracking obtained in Example 1;

FIG. 4 is a graph showing the calibration results of composite well-side seismic traces and synthetic records obtained in Example 1. FIG.

Detailed ways

The present invention will be described in detail below with reference to the embodiments and drawings, but it should be understood that the embodiments and drawings are only used to describe the present invention by way of example, but do not limit the protection scope of the present invention. All reasonable transformations and combinations included within the scope of the inventive concept of the present invention fall into the protection scope of the present invention.

According to the technical solution of the present invention, some specific well-seismic calibration methods based on multi-channel seismic stacking include:

S1: For the well to be calibrated, use the preprocessed sonic transit log curve and density log curve to obtain the reflection coefficient sequence, and convolve the reflection coefficient sequence with the wavelet to form the time domain synthetic record of the well.

Further, S1 may include:

S11: Preprocess the logging data of the well to be calibrated, and calculate the depth domain reflection coefficient sequence by using the single-well sonic time difference logging curve and density logging curve, as follows:

Ref(i)=Vel(i)*Den(i)

Among them, Ref(i) represents the reflection coefficient sequence in the depth domain, Vel(i) represents the velocity sequence calculated from the sonic travel log curve, Den(i) represents the log density curve, and i represents the sampling point in the depth domain.

S12: Convert the depth domain reflection coefficient sequence to the time domain, select the appropriate seismic wavelet and convolve the time series, and form the time domain synthetic record sequence of the well, as follows:

S(t)=Ref(t)*ω(t)

Among them, S(t) represents the synthetic recording sequence, ω(t) represents the seismic wavelet sequence, Ref(t) represents the reflection coefficient sequence in the time domain, * represents the convolution operation, and t represents the sampling point in the time domain.

S2: Extract multiple well-side seismic traces near the well logging, take the well-side seismic trace closest to the well as the reference well-side trace, and use the time series automatic warping algorithm to calculate the respective time shifts of the remaining well-side seismic traces and the reference well Then, the corrected seismic traces around the well are weighted and superimposed according to the correlation coefficient to form the initial composite seismic traces next to the well.

Further, S2 may include:

道井旁地震道，记作T_i(t)，其中S21: According to the logging position, select the seismic trace closest to the well point position as the reference seismic trace next to the well, denoted as T ₀ (t). Given the time window L of the number of seismic traces beside the well, extract the seismic traces before and after the reference well in the direction of the seismic line.

Seismic traces beside the well, denoted as T _i (t), where

S22: The amplitude matrix e _i is established by referring to the seismic traces T ₀ (t) and T _i (t) beside the wellbore. The calculation formula of each element in the e _i matrix is as follows:

e _i (t, j)=|T ₀ (t)-T _i (t+j)| ²

Where t is the sampling point of the time series, t=0, 1, 2..., M-1; j is the amount of time shift, j=-J, -J+1,..., J -1, J, then 2J+1 is the time window, J is given according to the actual seismic data and the conditions of the underground medium; T _i (t+j) represents the amplitude value of the seismic trace next to the i-th well when the time is t+j ; e _i represents the amplitude matrix of N rows and M columns, N=2J+1; e _i (t, j) represents when the time is t, the time shift amount is j, and the reference well-side seismic trace T ₀ (t) and The amplitude matrix element calculated by T _i (t+j) can be obtained by traversing the loop in turn with two variables t and j.

S23: Use the time series regularization of the sliding time window to realize the optimal accumulation of the amplitude matrix e _i , and establish the cumulative amplitude matrix E _i , and the calculation formula of each element in the E _i matrix is as follows:

E _i (0, j) = e _i (0, j)

Among them, E _i (0, j) represents the cumulative amplitude matrix element when the time is 0 and the time movement amount is j, E _i (t, j) represents the cumulative amplitude matrix element when the time is t and the movement amount is j, e _i (0, j) represents the amplitude matrix elements calculated from the sampling points T ₀ (0) and T _i (j) at time 0 of the reference well-side seismic trace at time 0.

S24: Let the size of the cumulative amplitude matrix E _i established by S23 be N×M, where: M=max(t), representing the seismic length of the side-hole channel, N=2J+1, representing the size of the total movement, using the regression algorithm Calculate the cumulative amplitude matrix E _i , and find the time shift sequence through the backtracking algorithm, as follows:

_pi (t) = {pi (0), _pi (1), ..., _pi (M-1) _} , as follows:

When t=M-1:

p _i (t) = p _i (M-1)

=argmin{E(M-1,-J),E(M-1,-J+1),...,E(M

-1, 0), ..., E(M-1, J-1), E(M-1, J)}

When t=0, 1, 2, ..., M-2:

where p _i (t) represents the corrected time shift of each time sampling point in the seismic trace next to the i-th well.

S25: Apply the time-shift amount in the sequence p _i (t) to the wellbore seismic trace to be corrected, and obtain the corrected well side seismic trace NewT _i (t) as follows:

NewT _i (t)=T _i (t+ _pi (t)).

Where t is the time series sampling point, t=0, 1, 2..., M-1.

S3: Perform effective signal enhancement, noise signal weakening and standardization on the initial composite wellside seismic trace, compare the composite well side seismic trace with the synthetic record, and realize the calibration of a single well by stretching and compressing the synthetic record.

Further, S3 may include:

S31: Calculate the correlation coefficient between the corrected well-side seismic trace NewT _i (t) and the reference well-side seismic trace T ₀ (t), as follows:

Among them, i is the serial number of the seismic trace beside the well,

N为地震道中采样点数，mT₀为对参考井旁地震道T₀(t)的每一个点求和取平均，mT_i为对校正后井旁地震道NewT_i(t)的每一个点求和后再取平均，C_i为校正后井旁地震道NewT_i(t)与参考井旁地震道T₀(t)的相关系数。

N is the number of sampling points in the seismic trace, mT ₀ is the sum and average of each point of the seismic trace T ₀ (t) beside the reference well, mT _i is the calculation of each point of the seismic trace NewT _i (t) beside the well after correction The sum is then averaged, and C _i is the correlation coefficient between the corrected well-side seismic trace NewT _i (t) and the reference well-side seismic trace T ₀ (t).

S32: Perform weighted stacking of the corrected well-side seismic trace NewT _i (t) and the reference well-side seismic trace T ₀ (t) according to the correlation coefficient:

Among them, MT(t) is the composite seismic trace next to the well formed by the superposition of multiple traces.

S33: Perform relative normalization on the composite well-side seismic trace MT(t) formed after multi-trace stacking, as follows:

Among them, NT(t) is the composite seismic trace next to the well formed by the superposition of multiple traces.

则Y(t_k)＝3×NT(t_k)，如果

则

S34: Identify the normalized composite well-side seismic trace NT(t), and determine whether the composite seismic trace formed by stacking multiple traces enhances the effective signal and weakens the noise signal through the threshold; The size of each sampling point in NT(t) and its corresponding T ₀ (t), if

Then Y(t _k )=3×NT(t _k ), if

but

Among them, NT(t _k ) is a sampling point of NT(t) at time t=k; T ₀ (t _k ) is a sampling point of T ₀ (t) at time t=k; Y(t) represents The composite well-side seismic trace formed after threshold determination.

S35: Standardize the composite well-side seismic trace Y(t) after threshold determination, as follows:

Among them, NY(t) is the standard normalized composite well-side seismic trace after threshold judgment, max(Y(t)) is the maximum value in Y(t), and min(Y(t)) is Y( the smallest value in t).

S36: Comparing the composite well-side seismic trace NY(t) after standard normalization with the logging synthetic record, and realizing the calibration of a single well by stretching and compressing the synthetic record.

Example 1

According to the above specific embodiments, taking the test model as an example, the well-seismic calibration based on multi-channel seismic stacking is performed, including:

The first step is to use the logging data to complete the synthetic record production; select the reference well side channel according to the well point position, and take the time window L=10, that is, extract the 5 left and right side well seismic traces to be corrected.

In the second step, using the seismic trace of the reference well A, the value of the time window J of the movement amount is given by expert experience, and when i=-5, the reference seismic trace T ₀ ( ^t ) and the side of the well to be corrected are established. The amplitude matrix e _-5 of track T _-5 (t), as shown in Figure 2, uses the time series regularization of the sliding time window to realize the optimal accumulation of the amplitude matrix e _-5 , and establishes the cumulative amplitude matrix E _-5 , and get the sequence p _-5 (t) through path backtracking, as shown in Figure 3.

In the third step, use the sequence p _-5 (t) to correct T _-5 (t), and repeat the second step to complete i=-4, -3....-1,1...,5 The correction of the remaining 9 well-side seismic traces is performed, and the superposition in S26 is performed to obtain the initial composite well-side seismic trace MT(t).

In the fourth step, the steps in S31 to S35 are performed on the initial composite well-side seismic trace MT(t) to obtain a standard normalized composite well-side seismic trace NY(t).

The fifth step is to use the composite well-side seismic trace NY(t) to complete the calibration with the synthetic record, as shown in Figure 4.

The above embodiments are only preferred embodiments of the present invention, and the protection scope of the present invention is not limited to the above embodiments. All the technical solutions under the idea of the present invention belong to the protection scope of the present invention. It should be pointed out that for those skilled in the art, improvements and modifications without departing from the principles of the present invention should also be regarded as the protection scope of the present invention.

Claims (10)

1. a well-seismic calibration method based on multi-channel seismic superposition, is characterized in that, it comprises: Based on the logging data, obtain the time domain synthetic record of the well to be calibrated; Based on the seismic data, the reference well-side seismic trace is selected according to the logging position, and the time shift between the remaining well-side seismic traces and the reference well-side seismic trace is obtained by using the automatic warping algorithm; Correction is performed to obtain the seismic traces beside the well after correction; Carrying out the correlation coefficient weighted stacking of the corrected wellside seismic trace and the reference well side seismic trace to form an initial composite well side seismic trace; Performing effective signal enhancement processing and/or standardization processing on the initial composite well bypass to obtain a processed composite well bypass; The time domain synthetic record is compared with the processed composite well side channel to realize well seismic calibration. 2. The well-seismic calibration method according to claim 1, wherein the obtaining of the time domain synthetic record comprises: The depth domain reflection coefficient sequence is obtained from the single well sonic time difference log curve and density log curve of the well to be calibrated; Converting the depth domain reflection coefficient sequence to the time domain to obtain its time domain reflection coefficient sequence; The time domain reflection coefficient sequence and the seismic wavelet sequence are convolved to obtain the time domain synthetic record sequence of the well to be calibrated. 3. The well-seismic calibration method according to claim 2, wherein, the depth domain reflection coefficient sequence is obtained by the following formula: Ref(i)=Vel(i)*Den(i) Wherein, Ref(i) represents the depth domain reflection coefficient sequence, Vel(i) represents the velocity sequence calculated from the sonic time difference logging curve, Den(i) represents the logging density curve, and i represents the depth domain sampling point; The time domain synthetic record sequence of the well to be calibrated is obtained by the following formula: S(t)=Ref(t)*ω(t) Wherein, S(t) represents the synthetic recording sequence, ω(t) represents the seismic wavelet sequence, Ref(t) represents the reflection coefficient sequence in the time domain, * represents the convolution operation, and t represents the sampling point in the time domain. 4. The well-seismic calibration method according to claim 1, wherein the obtaining of the time shift comprises: In the obtained wellbore seismic trace sequence, select the reference well seismic trace sequence, and set a time window, and extract the wellbore seismic trace sequence within the time window range in the direction of the seismic line as the basic wellbore seismic trace sequence; establishing a calculation model of the amplitude matrix of the reference well seismic side channel sequence and the base well side seismic trace sequence containing moving variables; Using the time series regularization of the sliding time window, within the range of the maximum seismic trace length beside the well and the total moving width of the moving variable, the amplitude matrix is optimized and accumulated, and the accumulated amplitude matrix is obtained; The cumulative amplitude matrix is calculated by a regression algorithm, and the sequence of the time shifts is further obtained by a backtracking algorithm. 5. well-seismic calibration method according to claim 4, is characterized in that, wherein, the calculation model of described amplitude difference matrix is as follows: e _i (t, j)=|T ₀ (t)-T _i (t+j)| ² , j=[-J, J], t=[0, M-1],

Among them, e _i (t, j) indicates that when the time series number is t and the time shift amount is j, the reference seismic trace sequence T ₀ (t) and the i-th wellbore seismic trace within the time range of t+j are obtained. The amplitude matrix element calculated by trace T _i (t+j), j represents the time moving variable, its value range parameter J can be selected according to the actual seismic data and underground medium conditions, i represents the seismic trace next to the i-th well , L represents the time window of the number of seismic traces next to the well, and M represents the total number of sampling points in the time series; The cumulative amplitude matrix is established as follows: E _i (0, j) = e _i (0, j)

Among them, E _i (0, j) represents the cumulative amplitude matrix element when the time sequence number is 0 and the time shift amount is j, and E _i (t, j) represents the cumulative amplitude matrix with time t and shift variable j element, then E _i (t-1, j-1) represents the cumulative amplitude matrix element whose time series is t-1 and the moving variable is j-1, and E _i (t-1, j) indicates that the time series is t- 1. The cumulative amplitude matrix element with the moving variable j, E _i (t-1, j+1) represents the cumulative amplitude matrix element with the time series number t-1 and the moving variable j+1, e _i (0, j) represents the amplitude matrix element calculated from the sampling points T ₀ (0) and T _i (j) of the reference well-side seismic trace at 0 time when the time series number is 0; The sequence of the time shift amounts p _i (t) is established as follows: When t=M-1: p _i (t) = p _i (M-1) =argmin{ _Ei (M-1,-J), _Ei (M-1,-J+1),..., _Ei (M-1,0),... , E _i (M-1, J-1), E _i (M-1, J)} When t=0, 1, 2, ..., M-2:

Wherein, M=max(t) represents the maximum length of the seismic trace next to the well, and N=2J+1 represents the total moving width. 6. well-seismic calibration method according to claim 5, is characterized in that, the described correction that each well-side seismic trace is carried out according to the obtained time shift is realized by following correction model: NewT _i (t)=T _i (t+ _pi (t)); Among them, NewT _i (t) represents the i-th well-side seismic trace after correction, T _i (t) represents the i-th well-side seismic trace before correction, t represents the ordinal number of the sampling point in the time domain, p _i (t) represents the sequence of the time shift amounts. 7. The well-seismic calibration method according to claim 1, wherein the acquisition of the initial composite well-side seismic trace comprises: calculating the correlation coefficient of each sampling point between the corrected well-side seismic trace and the reference well-side seismic trace; weighted superposition of the correlation coefficients of the sampling points to obtain initial superimposed wellbore seismic traces; Relative normalization is performed on the initial superimposed wellbore seismic traces to obtain the initial composite wellbore seismic traces. 8. The well-seismic calibration method according to claim 7, wherein, the correlation coefficient of each sampling point is obtained by the following formula:

Among them, N represents the number of sampling points in the seismic trace, mT ₀ is the sum and average of each point in the seismic trace T ₀ (t) next to the reference well, and mT _i is the correction of each point in the seismic trace NewT _i (t) beside the well after correction. The points are summed and then averaged, and C _i represents the correlation coefficient between the corrected well-side seismic trace NewT _i (t) and the reference well-side seismic trace T ₀ (t), that is, the correlation coefficient of the sampling point i; The weighted superposition is achieved by the following calculation model:

Among them, MT(t) represents the initial superimposed well-side seismic trace, and L represents the time window width; The relative normalization is achieved by the following computational model:

Wherein, NT(t) represents the initial composite well-side seismic trace. 9. The well-seismic calibration method according to claim 1, wherein the obtaining of the composite well bypass after the processing comprises: Set a judgment threshold, compare the effective signal parameters of each sampling point in the initial composite well-side seismic trace with the judgment threshold, and when the effective signal parameter is greater than or equal to the judgment threshold, the corresponding initial composite well-side The sampling points in the seismic trace are enhanced, and when the effective signal parameter is less than the determination threshold, the corresponding sampling points in the initial composite well-side seismic trace are weakened to obtain a composite well-side seismic trace sequence determined by the threshold; Standard normalization is performed on the composite well side seismic trace sequence after the threshold determination, to obtain the processed composite well side trace sequence. 10. The well-seismic calibration method according to claim 9, wherein, the composite well-side seismic trace sequence after the threshold judgment is obtained by the following judgment model: when

, Y(t _k )=3×NT(t _k ), when

hour,

Among them, NT(t _k ) is a sampling point of NT(t) at time t=k, T ₀ (t _k ) is a sampling point of T ₀ (t) at time t=k, and NT(t) represents For the initial composite well-side seismic trace, T ₀ (t) represents its corresponding reference well-side seismic trace, Y(t) represents the composite well-side seismic trace after threshold determination, and a represents the determination threshold; The standard normalization is achieved by the following normalization model:

Wherein, NY(t) represents the composite well bypass channel after the treatment, max(Y(t)) represents the maximum value in Y(t), min(Y(t)) represents the minimum value in Y(t), N represents the number of sampling points in the seismic trace.

Images