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CN-121995481-A - Well-seismic fusion full-frequency inversion method and device

CN121995481ACN 121995481 ACN121995481 ACN 121995481ACN-121995481-A

Abstract

The embodiment of the application provides a well-seismic fusion full-frequency inversion method and a well-seismic fusion full-frequency inversion device, which relate to the technical field of oil-gas geophysical exploration, and the method comprises the steps of establishing a high-precision layer sequence stratum grid of a preset work area according to second seismic data of a plurality of seismic channels to be inverted and second logging data of a plurality of sample wells to be selected; determining at least two frequency bands according to the high-precision layer sequence stratum grillwork, second seismic data of the seismic channels to be inverted and second well bypass seismic data of the first number of first sample wells, determining full-frequency initial inversion results of the seismic channels to be inverted according to the second well logging data of the first number of first sample wells and the second well bypass seismic data, correcting the full-frequency initial inversion results according to the high-precision layer sequence stratum grillwork and the at least two frequency bands to obtain full-frequency target inversion results of the seismic channels to be inverted, comprehensively utilizing full-frequency band information of earthquakes and well logging to obtain final inversion results, and improving the quality of inversion results.

Inventors

  • HE WENYUAN
  • CHEN XIN

Assignees

  • 中国石油天然气集团有限公司
  • 中国石油国际勘探开发有限公司

Dates

Publication Date
20260508
Application Date
20241107

Claims (20)

  1. 1. The well-seismic fusion full-frequency inversion method is characterized by comprising the following steps of: Acquiring first seismic data of a plurality of seismic channels to be inverted and first logging data of a plurality of wells, wherein the plurality of seismic channels to be inverted and the plurality of wells are in a preset work area, and the first seismic data of the plurality of seismic channels to be inverted comprise first well side channel seismic data of the plurality of wells; Filtering the first seismic data of the plurality of seismic channels to be inverted to obtain second seismic data of the plurality of seismic channels to be inverted, wherein the second seismic data of the plurality of seismic channels to be inverted comprises second well bypass seismic data of the plurality of wells; cleaning the first logging data of the plurality of wells to obtain second logging data of the plurality of wells; Determining a plurality of sample wells to be selected from the plurality of wells based on second log data for the plurality of wells; establishing a high-precision layer sequence stratum grid of the preset work area according to the second seismic data of the plurality of seismic channels to be inverted and the second logging data of the plurality of sample wells to be selected; Determining a characteristic distance between second seismic data of the seismic channels to be inverted and second well bypass seismic data of each sample well to be selected according to each seismic channel to be inverted; determining a first number of first sample wells with the smallest feature distance among the plurality of sample wells to be selected; Determining at least two frequency bands according to the high-precision sequence stratum grid, the second seismic data of the seismic channels to be inverted and the second well side channel seismic data of the first number of first sample wells; Determining full-frequency initial inversion results of the seismic channels to be inverted according to second logging data of the first number of first sample wells and second well bypass seismic data; And correcting the full-frequency initial inversion result according to the high-precision sequence stratum grillage and the at least two frequency bands to obtain the full-frequency target inversion result of the seismic channel to be inverted.
  2. 2. The method of claim 1, wherein determining a characteristic distance between the second seismic data of the seismic trace to be inverted and the second well side trace seismic data of each sample well to be selected comprises: determining characteristic parameters corresponding to the seismic channels to be inverted according to the second seismic data of the seismic channels to be inverted; determining the characteristic parameters corresponding to the sample wells to be selected according to the second well side channel seismic data of the sample wells to be selected, and determining the distance between the characteristic parameters corresponding to the seismic channels to be inverted and the characteristic parameters corresponding to the sample wells to be selected as the characteristic distance between the second seismic data of the seismic channels to be inverted and the second well side channel seismic data of the sample wells to be selected.
  3. 3. The method of claim 2, wherein the characteristic parameters corresponding to the seismic traces to be inverted include at least two of centroid parameters, average parameters, variance parameters.
  4. 4. A method according to claim 3, wherein the centroid parameter satisfies the following formula 1: Wherein C represents the centroid parameter, N represents the total number of sampling point data in the second seismic data of the seismic trace to be inverted, s (N) represents sampling point data with an index of N in the second seismic data of the seismic trace to be inverted, and sigma represents summation operation.
  5. 5. The method of claim 4, wherein the average parameter satisfies the following equation 2: Wherein, the Representing the average value parameter.
  6. 6. The method of claim 5, wherein the variance parameter satisfies the following equation 3: wherein σ represents the variance parameter.
  7. 7. The method of claim 6, wherein the variational parameter satisfies the following equation 4: Wherein D represents the variance parameter, r (h) represents the average of the sum of squares of the differences between the sampling point data s (N) with index N and the sampling point data s (n+h) with index (n+h) in the case of interval (h-1) sampling point data, and N1 represents the data quantity of interval (h-1) sampling point data in the second seismic data of the seismic trace to be inverted.
  8. 8. The method of any one of claims 1-7, wherein the at least two frequency bands include a low frequency band, a seismic active frequency band, a logging active frequency band, and a high frequency band; The determining at least two frequency bands according to the high-precision layer sequence stratigraphic framework, the second seismic data of the seismic traces to be inverted and the second well bypass seismic data of the first number of first sample wells comprises: Determining an effective low frequency and an effective high frequency of the earthquake according to the high-precision layer sequence stratum grid and the second earthquake data of the earthquake channel to be inverted; selecting the first two target wells with the largest characteristic distance from the first number of first sample wells; Determining logging effective frequency according to the high-precision sequence stratum grillage and second well bypass seismic data of the two target wells; and dividing a first preset frequency band into the low frequency band, the earthquake effective frequency band, the logging effective frequency band and the high frequency band according to the earthquake effective low frequency, the earthquake effective high frequency and the logging effective frequency.
  9. 9. The method of claim 8, wherein determining the low and high seismic effective frequencies from the high-precision sequence stratigraphic framework and the second seismic data for the seismic trace to be inverted comprises: Acquiring seismic data corresponding to a target layer from the second seismic data of the seismic channel to be inverted through the high-precision layer sequence stratum grid; Performing frequency spectrum scanning on the seismic data corresponding to the target layer to obtain amplitude frequency information; And determining a first frequency corresponding to a preset amplitude in the amplitude frequency information as the effective low frequency of the earthquake, and determining a second frequency corresponding to the preset amplitude as the effective high frequency of the earthquake, wherein the first frequency is smaller than the second frequency.
  10. 10. The method of claim 8, wherein determining a logging effective frequency from the high-precision sequence stratigraphic framework and second well bypass seismic data for the two target wells comprises: For each target well, acquiring second well bypass seismic data corresponding to a target layer of the target well from the second well bypass seismic data of the target well through the high-precision layer sequence stratum grid; transforming the second well side channel seismic data corresponding to the target layer from a time domain to a frequency domain to obtain a transformation result; determining differential amplitude correlation coefficients corresponding to a plurality of frequencies in the effective frequency ranges according to the frequency domain data corresponding to the effective frequency ranges of the two target wells; And determining the frequency meeting the first condition in the plurality of frequencies as the logging effective frequency according to the differential amplitude correlation coefficient corresponding to the plurality of frequencies.
  11. 11. The method of claim 10, wherein the two target wells comprise a first target well and a second target well, wherein frequency domain data corresponding to an effective frequency range of the first target well comprises first amplitudes corresponding to the plurality of frequencies, and wherein frequency domain data corresponding to an effective frequency range of the second target well comprises second amplitudes corresponding to the plurality of frequencies; According to the frequency domain data corresponding to the effective frequency ranges corresponding to the two target wells, determining differential amplitude correlation coefficients corresponding to a plurality of frequencies in the effective frequency ranges comprises: and determining the difference value of the correlation coefficient between the first amplitude and the second amplitude corresponding to the frequency and the correlation coefficient between the first amplitude and the second amplitude corresponding to the next frequency as the differential amplitude correlation coefficient corresponding to the frequency.
  12. 12. The method of claim 10, wherein the first condition is expressed as the following equation 5: Wherein w 3 represents the logging effective frequency, argmax represents the maximum value calculation, w represents the frequency in the effective frequency range, dρ 12 (w) represents the differential amplitude correlation coefficient corresponding to w, the absolute value is represented, and a represents the first preset value.
  13. 13. The method of any of claims 1-7, wherein the determining full frequency initial inversion results for the seismic traces to be inverted from second log data and second well bypass seismic data for the first number of first sample wells comprises: determining reservoir model structure variation functions corresponding to a plurality of sample wells to be selected according to second logging data and second well side channel seismic data of the plurality of sample wells to be selected; and determining the full-frequency initial inversion result of the seismic channel to be inverted according to the reservoir model structure variation function corresponding to the first number of first sample wells in the plurality of sample wells to be selected.
  14. 14. The method of claim 13, wherein a reservoir model structural variation function corresponding to an X-th candidate well of the plurality of candidate wells satisfies equation 6 below: W1F X (dS)＝a X ×(dS) 2 +b X ×(dS)+b X (formula 6); Wherein W1 represents a seismic wavelet, F X represents a reservoir model structure variation function corresponding to the xth sample well, a X ,b X ,c X represents a convolution operation, a X ,b X ,c X represents a coefficient in the reservoir model structure variation function corresponding to the xth sample well, dS represents differential data between second well side channel seismic data of the xth sample well and second well side channel seismic data of the Y sample well in the plurality of sample wells, X is different from Y, and X represents a multiplication operation.
  15. 15. The method of claim 13, wherein determining full-frequency initial inversion results for the seismic traces to be inverted based on reservoir model structure varistors corresponding to the first number of first sample wells of the plurality of sample wells to be selected comprises: Solving a reservoir model structure variation function corresponding to each first sample well through Markov chain Monte Carlo random simulation to obtain a plurality of feasible solutions corresponding to the first sample well; and carrying out Bayesian model averaging on the front second number of feasible solutions with the maximum probability to obtain the full-frequency initial inversion result of the seismic channel to be inverted.
  16. 16. The method of any one of claims 1-7, wherein the at least two frequency bands include a low frequency band, a seismic active frequency band, a logging active frequency band, and a high frequency band; correcting the full-frequency initial inversion result according to the high-precision sequence stratum grillage and the at least two frequency bands to obtain a full-frequency target inversion result of the seismic channel to be inverted, wherein the full-frequency target inversion result comprises the following steps: Acquiring a first root mean square velocity corresponding to the seismic channel to be inverted; determining first impedance data corresponding to the seismic channel to be inverted according to the first root mean square speed corresponding to the seismic channel to be inverted and the second logging data of the plurality of sample wells to be selected; determining data corresponding to the low frequency band in the full-frequency initial inversion result through the high-precision layer sequence stratigraphic framework, and correcting the data corresponding to the low frequency band in the full-frequency initial inversion result through the data corresponding to the low frequency band in the first impedance data to obtain first corrected full-frequency inversion data; Determining second impedance data corresponding to the seismic channel to be inverted according to the second seismic data of the seismic channel to be inverted, and the second logging data of the first number of first sample wells and the second well bypass seismic data; Determining data corresponding to the earthquake effective frequency band in the first corrected full-frequency inversion data through the high-precision layer sequence stratum trellis, and correcting the data corresponding to the earthquake effective frequency band in the first corrected full-frequency inversion data through the data corresponding to the earthquake effective frequency band in the second impedance data to obtain second corrected full-frequency inversion data; Determining third impedance data corresponding to the seismic channels to be inverted according to the second seismic data of the plurality of seismic channels to be inverted; determining data corresponding to the logging effective frequency band in the second corrected full-frequency inversion data through the high-precision layer sequence stratum trellis, and correcting the data corresponding to the logging effective frequency band in the second corrected full-frequency inversion data through the data corresponding to the logging effective frequency band in the third impedance data to obtain third corrected full-frequency inversion data; determining fourth impedance data corresponding to the seismic channel to be inverted according to the second seismic data of the seismic channel to be inverted, the second logging data of the first number of first sample wells and the second well bypass seismic data; And determining data corresponding to the logging effective frequency band in the second corrected full-frequency inversion data through the high-precision sequence stratum trellis, and correcting data corresponding to the high frequency band in the third corrected full-frequency inversion data through data corresponding to the high frequency band in the fourth impedance data to obtain the full-frequency target inversion result.
  17. 17. The method of claim 16, wherein determining first impedance data corresponding to the seismic trace to be inverted based on the first root mean square velocity corresponding to the seismic trace to be inverted and the second log data of the plurality of sample wells to be selected comprises: aiming at each sample well to be selected, converting DT in second logging data of the sample well to be selected into logging layer speed corresponding to the sample well to be selected; Interpolating the logging layer speeds corresponding to the plurality of sample wells to be selected into logging layer speeds corresponding to the seismic channels to be inverted; carrying out full three-dimensional velocity enhancement processing on the first root mean square velocity to obtain a second root mean square velocity corresponding to the seismic channel to be inverted; Converting the second root mean square velocity into a first layer velocity corresponding to the seismic channel to be inverted through a Dix formula; According to the logging layer velocity corresponding to the seismic channel to be inverted, carrying out well control layer velocity background trend correction on the first layer velocity to obtain a second layer velocity corresponding to the seismic channel to be inverted; and converting the second layer speed into first impedance data corresponding to the seismic channel to be inverted.
  18. 18. The method of claim 16, wherein determining second impedance data corresponding to the seismic trace to be inverted based on the second seismic data of the seismic trace to be inverted and the second log data and second well bypass seismic data of the first number of first sample wells comprises: determining a maximum amplitude spectrum corresponding to the seismic channel to be inverted according to the second seismic data of the seismic channel to be inverted; Determining a first characteristic parameter corresponding to the seismic channel to be inverted according to the maximum amplitude spectrum corresponding to the seismic channel to be inverted; For each first sample well, determining a maximum amplitude spectrum corresponding to the first sample well according to second well bypass seismic data of the first sample well, and determining a second characteristic parameter corresponding to the first sample well according to the maximum amplitude spectrum corresponding to the first sample well; According to the first characteristic parameters corresponding to the seismic channels to be inverted and the second characteristic parameters corresponding to the first number of first sample wells, performing efficient simulated annealing cluster analysis to obtain the second characteristic parameters with the largest characteristic distance from the first characteristic parameters; and determining second impedance data corresponding to the seismic channel to be inverted according to second logging data of the first sample well corresponding to the second characteristic parameter with the largest characteristic distance from the first characteristic parameter.
  19. 19. The method of claim 18, wherein determining a maximum amplitude spectrum corresponding to the seismic trace to be inverted from the second seismic data of the seismic trace to be inverted comprises: Acquiring a plurality of amplitude spectrums corresponding to the seismic channels to be inverted according to the second seismic data of the seismic channels to be inverted; Extracting a plurality of maximum amplitudes and frequencies corresponding to the plurality of maximum amplitudes from the plurality of amplitude spectrums; and combining the maximum amplitudes and frequencies corresponding to the maximum amplitudes into a maximum amplitude spectrum corresponding to the seismic channel to be inverted according to the sequence from small to large.
  20. 20. The method of claim 16, wherein determining third impedance data corresponding to the seismic trace to be inverted from the second seismic data of the seismic trace to be inverted comprises: determining a seismic data differential space according to the second seismic data of the plurality of seismic channels to be inverted; acquiring an impedance difference space corresponding to the seismic data difference space; Obtaining a reservoir model structure variation function corresponding to each first sample well; Constructing an objective function based on the reservoir model structure variation function corresponding to each first sample well; inputting the objective function according to the elements in the impedance difference, and carrying out optimization solution on the objective function to obtain the coefficients of the objective function and the minimum elements in the impedance difference space; And determining third impedance data corresponding to the seismic channel to be inverted according to the coefficient of the objective function and the minimum element.

Description

Well-seismic fusion full-frequency inversion method and device Technical Field The embodiment of the application relates to the technical field of oil and gas geophysical exploration, in particular to a well-seismic fusion full-frequency inversion method and device. Background The essence of seismic inversion is to predict a high-resolution reservoir model structure at a non-drilled place in the whole three-dimensional seismic range by combining three-dimensional seismic data and three-dimensional logging data. Currently, common seismic inversion methods include sparse pulse inversion and geostatistical inversion. Sparse pulse inversion is based on a seismic convolution model, and inversion is achieved by convolving longitudinal wave impedance data and seismic wavelets in log data to obtain seismic data. In the convolution process, the high-resolution longitudinal wave impedance data is sampled to a resolution consistent with the seismic data, so that the inversion result of the high resolution in the longitudinal direction cannot be obtained. Geostatistical inversion can obtain inversion results with high resolution in the longitudinal direction by randomly simulating logging data, but the variation in geostatistical inversion is usually a fixed constant (for example, 1000 meters or 800 meters, etc.), and the generated underground attribute distribution may not be enough to reflect the small-scale change in the transverse direction of the reservoir model structure, that is, geostatistical inversion cannot obtain inversion results with high resolution in the transverse direction. Therefore, neither sparse pulse inversion nor geostatistical inversion can obtain inversion results with good quality. How to obtain high-quality inversion results is a technical problem to be solved. Disclosure of Invention The embodiment of the application provides a well-seismic fusion full-frequency inversion method and device, which are used for solving the technical problem of how to obtain a high-quality inversion result and improving the quality of the obtained inversion result. In a first aspect, an embodiment of the present application provides a method for well-seismic fusion full-frequency inversion, including: Acquiring first seismic data of a plurality of seismic channels to be inverted and first logging data of a plurality of wells, wherein the plurality of seismic channels to be inverted and the plurality of wells are in a preset work area, and the first seismic data of the plurality of seismic channels to be inverted comprise first well side channel seismic data of the plurality of wells; Filtering the first seismic data of the plurality of seismic channels to be inverted to obtain second seismic data of the plurality of seismic channels to be inverted, wherein the second seismic data of the plurality of seismic channels to be inverted comprises second well bypass seismic data of the plurality of wells; cleaning the first logging data of the plurality of wells to obtain second logging data of the plurality of wells; Determining a plurality of sample wells to be selected from the plurality of wells based on second log data for the plurality of wells; establishing a high-precision layer sequence stratum grid of the preset work area according to the second seismic data of the plurality of seismic channels to be inverted and the second logging data of the plurality of sample wells to be selected; Determining a characteristic distance between second seismic data of the seismic channels to be inverted and second well bypass seismic data of each sample well to be selected according to each seismic channel to be inverted; determining a first number of first sample wells with the smallest feature distance among the plurality of sample wells to be selected; Determining at least two frequency bands according to the high-precision sequence stratum grid, the second seismic data of the seismic channels to be inverted and the second well side channel seismic data of the first number of first sample wells; Determining full-frequency initial inversion results of the seismic channels to be inverted according to second logging data of the first number of first sample wells and second well bypass seismic data; And correcting the full-frequency initial inversion result according to the high-precision sequence stratum grillage and the at least two frequency bands to obtain the full-frequency target inversion result of the seismic channel to be inverted. In some embodiments, determining a characteristic distance between the second seismic data of the seismic trace to be inverted and the second well bypass seismic data of each sample well to be selected comprises: determining characteristic parameters corresponding to the seismic channels to be inverted according to the second seismic data of the seismic channels to be inverted; determining the characteristic parameters corresponding to the sample wells to be selected according to the sec