CN111610563B - Method and device for identifying multiples - Google Patents
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Abstract
The invention provides a method and a device for identifying multiples, wherein the method comprises the following steps: acquiring time horizon data and logging data of a seismic work area; determining a wave impedance body of the seismic work area according to the time horizon data and the logging data; converting the wave impedance into a primary wave reflectivity; forward modeling and synthesizing a primary wave seismic record and a full wave seismic record according to the primary wave reflectivity and the logging data; and determining multiple interference areas with different interference levels from the seismic work area according to the primary wave seismic record and the full wave seismic record. The method can predict the overall development degree and distribution condition of the multiples in the whole earthquake work area, is used for analyzing potential multiples characteristics, and is applied to the multiple pressing treatment, so that the multiple pressing treatment parameter optimization is realized, and the uncertainty of pressing the multiples is reduced to a certain extent; the method can also be used for evaluating the quality of seismic data and dividing an area with unreliable seismic data, so that the multi-solution of reservoir prediction is reduced, and the risk of well position deployment is reduced.
Description
Technical Field
The invention belongs to the technical field of petroleum exploration and development, and particularly relates to a method and a device for identifying multiples.
Background
In oil exploration, seismic waves propagate through subterranean formations, and when strong reflecting interfaces are encountered, reflected waves of strong energy are generated. When the reflected wave travels back upward and meets a good strong reflection interface, the reflected wave is reflected again and travels downward, and multiple waves are formed by the round trip. Therefore, under the common conditions, multiple waves exist in each exploratory area in China to different degrees, and particularly in the Sichuan basin, the Tarim basin and the Ordos basin, the structures are smooth, strong reflection interfaces are more, and the multiple wave interference is more serious. The multiple waves have the same amplitude with the deep primary waves, the dynamic correction time difference is small, the multiple waves interfere with the deep primary waves and are difficult to identify, and the reliability of seismic interpretation research such as seismic data migration quality, seismic attribute extraction and inversion is influenced.
Due to complex multiple wave cause, the difficulty of identification and suppression in the seismic data processing process is high, the reflected energy of the effective wave is distorted, the reservoir prediction result is wrong, and great risks are brought to oil and gas exploration and development, so that the distribution of the effective wave is required to be identified.
In current seismic processing interpretation, multiples are generally identified on the velocity spectrum, stack section, seismic prestack gather based on the velocity and periodicity characteristics of the multiples: in the prestack stage, a low-speed energy cluster exists in a velocity spectrum, dynamic calibration is insufficient on a CMP gather, a pull-down phenomenon occurs along with the increase of offset distance, and a deep layer and a shallow layer have similar travel periods; in the post-stack stage, multiple waves are identified by stacking the forms and time of the strong reflection interface on the seismic section and the seismic reflection below the strong reflection interface; when the inclination angle of the underground reflection interface is smaller, if another group of reflection event with the same form as the strong reflection interface exists below the strong reflection interface and the occurrence time of the reflection event is less than 2 times of the reflection event, the group of event can be judged to be multiple reflection waves; for inclined formations, the secondary reflection on the stacking section has an inclination of about 2 times its primary reflection.
However, in the prior art, only multiple wave identification on a single observation point (a prestack seismic gather or a seismic velocity spectrum) and an observation line (a stacked seismic section) can be realized, and the overall development degree and distribution condition of multiple waves on a seismic work area plane cannot be obtained. Due to the fact that underground structure and stratum thickness change rapidly, multiple waves have strong heterogeneous characteristics on a plane, results of single points and single lines obviously cannot represent the situation of the whole earthquake work area, and the requirements of multiple wave identification and suppression effect evaluation cannot be met.
Disclosure of Invention
The embodiment of the invention provides a method for identifying multiples, which utilizes a reflectivity forward modeling method to obtain the energy distribution of the multiples on a certain geological layer on a plane, the result of the method can be used for guiding processing personnel to reasonably suppress the multiples existing in seismic data, and can also be used for explaining personnel to evaluate the quality of seismic data, so as to perform reliability evaluation on a reservoir prediction result and reduce the risk of well position deployment in development and exploration, and the method comprises the following steps:
acquiring time horizon data and logging data of a seismic work area;
determining a wave impedance body of the seismic work area according to the time horizon data and the logging data;
converting the wave impedance into a primary wave reflectivity;
forward modeling and synthesizing a primary wave seismic record and a full wave seismic record according to the primary wave reflectivity and the logging data;
and determining multiple interference areas with different interference levels from the seismic work area according to the primary wave seismic record and the full wave seismic record.
The embodiment of the invention also provides a device for identifying multiples, which comprises:
the data acquisition module is used for acquiring time horizon data and logging data of the seismic work area;
the wave impedance body determining module is used for determining a wave impedance body of the seismic work area according to the time horizon data and the logging data;
the primary wave reflectivity conversion module is used for converting the wave impedance body into the primary wave reflectivity;
the forward synthesis module is used for forward synthesizing the primary wave seismic record and the full-wave seismic record according to the primary wave reflectivity and the logging data;
and the multiple interference area determining module is used for determining multiple interference areas with different interference levels from the seismic work area according to the primary wave seismic record and the full wave seismic record.
The embodiment of the invention also provides computer equipment which comprises a memory, a processor and a computer program which is stored on the memory and can run on the processor, wherein the processor executes the computer program to realize the method for identifying multiples.
An embodiment of the present invention further provides a computer-readable storage medium, which stores a computer program for implementing the method for identifying multiples.
According to the method and the device for identifying the multiples, which are provided by the embodiment of the invention, the primary wave seismic record and the full-wave seismic record are synthesized through forward modeling by utilizing a reflectivity forward modeling method by establishing a wave impedance body; the method can predict the overall development degree and distribution condition of the multiples in the whole earthquake work area for analyzing potential multiple characteristics, and is applied to multiple suppression processing, so that the optimization of multiple suppression processing parameters is realized, and the uncertainty of the suppressed multiples is reduced to a certain extent; the embodiment of the invention can also evaluate the quality of the seismic data and divide the area with unreliable seismic data according to the divided multiple interference areas with different interference levels, thereby reducing the multi-solution of reservoir prediction and reducing the risk of well position deployment.
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In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings used in the description of the embodiments or the prior art will be briefly described below, it is obvious that the drawings in the following description are only some embodiments of the present invention, and for those skilled in the art, other drawings can be obtained according to the drawings without creative efforts. In the drawings:
fig. 1 is a schematic diagram of a method for identifying multiples according to an embodiment of the present invention.
Fig. 2 is a schematic diagram showing a result of displaying a wave impedance body established by an application example of the method for identifying multiples on a certain seismic survey line according to the embodiment of the present invention.
FIG. 3 is a seismic profile of a primary seismic record illustrating an application of a method of identifying multiples according to an embodiment of the invention.
FIG. 4 is a flowchart illustrating a method for identifying multiples according to an embodiment of the present invention to determine reflectivity of a full wave.
FIG. 5 is a full wave seismic profile of an example application of a method of identifying multiples according to an embodiment of the present invention.
FIG. 6 is a diagram of multiple seismic records at the same location in an example of an application of a method of identifying multiples in an embodiment of the present invention.
Fig. 7 is a signal-to-noise ratio property slice diagram obtained by an application example of a method for identifying multiples according to an embodiment of the present invention.
Fig. 8 is a schematic diagram of an apparatus for identifying multiples according to an embodiment of the present invention.
Detailed Description
In order to make the objects, technical solutions and advantages of the embodiments of the present invention more apparent, the embodiments of the present invention are further described in detail below with reference to the accompanying drawings. The exemplary embodiments and descriptions of the present invention are provided to explain the present invention, but not to limit the present invention.
The embodiment of the invention provides a method for identifying multiples, which utilizes a reflectivity forward modeling method to obtain the energy distribution of the multiples on a certain geological formation on a plane, wherein the result can be used for guiding processing personnel to reasonably suppress the multiples existing in seismic data, and can also be used for explaining personnel to evaluate the quality of seismic data, so as to perform reliability evaluation on a reservoir prediction result and reduce the risk of well position deployment in development and exploration, as shown in a schematic diagram of the method for identifying the multiples in the embodiment of the invention in figure 1, the method comprises the following steps:
102, determining a wave impedance body of the seismic work area according to the time horizon data and the logging data;
104, forward-modeling and synthesizing a primary wave seismic record and a full-wave seismic record according to the primary wave reflectivity and the logging data;
and 105, determining multiple interference areas with different interference levels from the seismic work area according to the primary wave seismic record and the full wave seismic record.
The embodiment of the invention can predict the overall development degree and distribution condition of the multiple in the whole earthquake work area, is used for analyzing the potential multiple characteristics, and is applied to multiple pressing treatment, thereby realizing the optimization of multiple pressing treatment parameters and reducing the uncertainty of pressing the multiple to a certain extent; the embodiment of the invention can also evaluate the quality of the seismic data and divide the area with unreliable seismic data according to the divided multiple interference areas with different interference levels, thereby reducing the multi-solution of reservoir prediction and reducing the risk of well position deployment.
When the multiple wave identification method is specifically implemented, time horizon data and logging data of a seismic work area need to be acquired at first; then, determining a wave impedance body of the earthquake work area according to the time horizon data and the logging data; then converting the wave impedance into primary wave reflectivity; forward modeling is carried out according to the primary wave reflectivity and the logging data to synthesize a primary wave seismic record and a full wave seismic record; and finally, determining multiple interference areas with different interference levels from the seismic work area according to the forward synthetic primary wave seismic record and the full wave seismic record.
The embodiment of the invention provides an application example adopting a multiple wave identification method, which comprises the following steps: high-yield and enriched carbonate rock solution gas reservoirs are found in four sections of deep seismic denier series lamps in a certain three-dimensional earthquake work area in the Sichuan basin. Well drilling in the middle region reveals that a plurality of reflecting interfaces exist in the middle and shallow layers above the deep lamp shadow group stratum; the Sichuan basin is mainly a sand-shale stratum which is alternately deposited by sea and land from three folds of late to new generations, and is a carbonate stratum which is deposited by a sea-phase carbonate plateau from the seismic denier to the middle three folds; the lithology of the sand shale to the carbonate rock stratum is changed, and a good wave impedance reflection interface in the area is formed; because the number of the strong reflection interfaces is large and the longitudinal time structure has certain change, complex multiple wave interference is generated under the strong reflection interfaces, particularly in the lamp shadow group; the interbed multiples have many sources and complex causes, and the difference between the velocity of the interbed multiples and the velocity of the primary wave is small, so that the primary effective wave and the multiples are difficult to effectively distinguish and identify in seismic data, great trouble is brought to seismic processing, and seismic result data with high signal-to-noise ratio are difficult to obtain; therefore, the method for identifying the multiples provided by the embodiment of the invention can be applied to the earthquake work area to realize the effective identification of the multiples.
In particular implementations, when obtaining time horizon data and logging data for a seismic work area, in one embodiment, the logging data may include a wave impedance curve; determining a wave impedance body of the seismic work area according to the time horizon data and the logging data, which specifically comprises the following steps: and (3) performing three-dimensional spatial interpolation on the wave impedance curve by using time layer data as constraint and utilizing an inverse distance interpolation algorithm to determine a wave impedance body.
In the application example of the embodiment of the invention, the time horizon data of the earthquake work area is obtained from oil fields, geophysical service companies and the like, and the time horizon data comprise three-fold Lexus family river (T) from shallow to deep 3 x 1) and lower three-cascade series flight 4 sections (T) 1 f4 Two-fold series Changxing group (P) 2 ch), longtan group (P) 2 l) and lower two-stacked beam mountain group (P) 1 l), ordovician (O), hanwu Longwanggao group
Qiongzhueqi tumidinoda temple group for cold and wu
Three-section (Z) of jordan series lamp 2 d3 And a group of lamp shadows (Z) 2 d) The 10 temporal level data of the bottom bound are equal.
After acquiring time horizon data and logging data of a seismic work area, performing spatial interpolation on a wave impedance curve by using an initial model building module of seismic inversion interpretation software by taking a time horizon as a constraint to create a wave impedance body, which specifically can be as follows: and importing the obtained time horizon data of the seismic work area into a Jason software Earth Model modeling module, combining a wave impedance curve in the logging data, and performing three-dimensional spatial interpolation on the wave impedance curve by using an inverse distance interpolation algorithm under the constraint of the 10 time horizon data to establish a wave impedance body. Fig. 2 is a schematic diagram showing a result of displaying a wave impedance body established by an application example of the method for identifying multiples on a certain seismic survey line according to the embodiment of the present invention, and fig. 2 also shows the time horizon data.
After the wave impedance body is established, the wave impedance body is converted into a primary wave reflectivity; in one embodiment, the wave impedance may be converted into the primary reflection rate as follows:
wherein r is the primary reflection; PI is a wave impedance; i is the reflectivity sample point number.
The above mentioned expression for converting the wave impedance into the primary reflection rate is an example, and those skilled in the art can understand that, in the implementation, some form of modification and addition of other parameters or data may be performed on the above formula according to needs, or other specific formulas may be provided, and these modifications are all within the scope of the present invention.
After converting the wave impedance into primary reflectivity, in one embodiment, a method of reflectivity forward modeling may be employed to forward synthesize a primary seismic record and a full-wave seismic record based on the primary reflectivity and log data, which may include seismic wavelets. Wherein, according to primary wave reflectivity and logging data, the forward synthetic primary wave seismic record can include: convolution calculation is carried out on the primary wave reflectivity and the seismic wavelets, and the primary wave seismic record is synthesized through forward modeling. In particular implementation, the synthetic primary seismic record may be forward calculated as follows:
wherein Sy is primary wave seismic record; w is a seismic wavelet; r is the primary reflection; i is the serial number of the reflectivity sampling point; n is the seismic wavelet length; j is the sequence number of the sampling point of the seismic wavelet.
While the foregoing expressions for forward synthetic primary seismic records are provided by way of example, those skilled in the art will appreciate that the above equations may be modified and other parameters or data may be added as needed, or other specific equations may be provided, and such modifications are intended to fall within the scope of the present invention.
In the application example of the embodiment of the invention, the main frequency of the actual seismic data is analyzed to be 32Hz, so that 32Hz Rake wavelets are selected as seismic wavelets to be forward. FIG. 3 is a seismic profile of a primary seismic record illustrating an application of a method of identifying multiples according to an embodiment of the invention. As can be seen from FIG. 3, the seismic profile of the primary seismic record obtained by the primary reflectivity and 32Hz Ricker wavelet convolution has good transverse continuity of the theoretical primary seismic reflection, obvious longitudinal strength contrast, and deep layer
Z 2 d3 and the like are clear.
After the forward modeling is carried out to synthesize the primary wave seismic record, the forward modeling is carried out to synthesize the full wave seismic record; in one embodiment, forward-acting synthesizing full-wave seismic records from primary reflectivity and log data may include: and determining the reflectivity of the full wave according to the reflectivity of the primary wave, performing convolution calculation on the reflectivity of the full wave and the seismic wavelets, and performing forward modeling to synthesize the full wave seismic record. In the specific implementation of determining the full-wave reflectivity according to the primary wave reflectivity, the primary wave reflectivity (r) and the number of sampling points (M) thereof can be input, and the full-wave reflectivity (r') is calculated according to a flow chart of determining the full-wave reflectivity shown in fig. 4 of a method for identifying multiples according to an embodiment of the present invention:
first by i =0,dw 0 Setting the starting point time to 0 by =1, setting the initial downlink wave energy to 1, setting the initial uplink wave energy to 0 by up =0, j = i, and then setting the initial uplink wave energy to 0 according to dw j+1 ＝-r j *up+(1-r j )*dw j Calculating the downstream reflection wave of j time according to up = r j *dw j +(1+r j ) Calculating the uplink reflection wave of j time by up, then circularly iterating from time i-0 until j is less than 0, and then passing through dw 0 Setting initial downlink wave energy as 0 through r =0,i = i + 1' i And = up, the reflected wave energy at the time i is obtained, then iteration is carried out from time 0 to M in a circulating mode until i is larger than M-1, and finally r' is output to obtain the full-wave reflectivity.
Wherein r is the primary reflection; m is the number of primary wave reflectivity sampling points; r' is the full wave reflectivity; up is the up-going wave; dw is the traveling wave.
In the process of calculating the full-wave reflectivity, the formula and the expression are used as examples, and those skilled in the art can understand that, in the implementation, some forms of modification and addition of other parameters or data may be performed on the formula and the expression as needed, or other specific formulas may be provided, and these modifications all fall into the scope of the present invention.
After determining the full wave reflectivity, the composite full wave seismic record is forward calculated. In one embodiment, when forward synthesis of the full-wave seismic record is implemented, convolution calculation is carried out on the full-wave reflectivity and the seismic wavelets, and the full-wave seismic record is forward synthesized; further, the composite full-wave seismic record may be forward calculated as follows:
wherein Sy' is a full wave seismic record; w is a seismic wavelet; r' is the full wave reflectivity; i is the serial number of the reflectivity sampling point; n is the seismic wavelet length, and j is the seismic wavelet sampling point number.
The aforementioned expressions for forward-synthetic full-wave seismic records are exemplary, and it will be understood by those skilled in the art that the above formulas may be modified in some form and other parameters or data may be added or other specific formulas may be provided as required, and such modifications are intended to fall within the scope of the present invention.
In the foregoing application examples of the present inventionSimilar to the forward synthetic primary seismic wave record, selecting the same 32Hz rake wavelets as seismic wavelets, performing convolution calculation with full wave reflectivity to obtain a full wave seismic record, and referring to FIG. 5, a full wave seismic record seismic section diagram of an application example of the method for identifying multiples according to the embodiment of the invention is shown in FIG. 5, and after down reflection is considered, the seismic section also comprises multiple wave reflection except for primary reflection, and relative to the primary wave synthetic seismic section, the overall signal-to-noise ratio of the full wave synthetic seismic section is reduced and continuity is deteriorated; influenced by multiple wave interference, deep layer
Z 2 d3 and other 3 interfaces are all obviously weakened to different degrees, Z 2 d3 reflection is not easily recognized as a whole, and the left side of the seismic profile of FIG. 5
Strong reflections are severely shielded to become weak reflections; by comparing the forward synthetic seismic section diagrams of fig. 5 and fig. 3, the development degree of the multiple waves in the deep light shadow group and the influence degree on the seismic reflection amplitude can be clearly seen.
After the primary wave seismic record and the full-wave seismic record are synthesized through forward modeling, determining multiple wave interference areas with different interference levels from the seismic work area according to the primary wave seismic record and the full-wave seismic record; in one embodiment, the determining multiple interference regions of different interference levels from a seismic work area based on the primary wave seismic record and the full wave seismic record may include: determining a multiple seismic record according to the primary wave seismic record and the full wave seismic record; determining a signal-to-noise ratio attribute slice according to the primary wave seismic record and the multiple wave seismic record; and determining multiple interference areas with different interference levels from the seismic work area according to the signal-to-noise ratio attribute slice.
Wherein the determining of the multiple seismic records from the primary seismic records and the full wave seismic records may include, in one embodiment: subtracting the primary wave seismic record from the full wave seismic record to obtain a multiple wave seismic record; in specific implementation, the multiple seismic records can be determined as follows:
ΔSy＝Sy'-Sy
wherein: Δ Sy is a multiple seismic record; sy' is full wave seismic record; and Sy is primary wave seismic record.
While the foregoing expressions for determining multiple seismic records are provided by way of example, those skilled in the art will appreciate that the above equations may be modified and other parameters or data may be added as needed, or other specific equations may be provided, and such modifications are intended to fall within the scope of the present invention.
Fig. 6 is a multiple seismic record diagram of the same position in the application example of the multiple recognition method according to the embodiment of the present invention, as shown in fig. 6, it can be seen more clearly that the multiple energy changes at different time horizon energy, especially that the multiple with strong energy mainly appears in qiongzhuang family
The difference in intensity in the transverse direction across the four lamp zones between the three lamp zones (Z2 d 3) of the seismic series has a large effect on the seismic reservoir prediction.
After determining the multiple seismic record, determining a signal-to-noise ratio attribute slice according to the primary seismic record and the multiple seismic record; in one embodiment, when the determining the signal-to-noise ratio attribute slice is implemented, the method may include: extracting attribute values of the primary wave seismic record (Sy) along a time horizon to obtain a primary wave along-horizon attribute slice (At); extracting attribute values of the multiple seismic records (delta Sy) along a time horizon to obtain multiple along-horizon attribute slices (delta At); from the primary along-layer property slice (At) and the multiple along-layer property slice (Δ At), a signal-to-noise ratio property Slice (SN) is determined. Further, when the extraction of the attribute value is specifically implemented, it can be understood by those skilled in the art that any one or more of the following calculation methods may be adopted, including: and calculating the conventional seismic attributes such as root mean square value calculation, maximum value calculation, positive value average calculation, wave trough average calculation, amplitude absolute value calculation, energy calculation and the like.
After determining the primary wave along-layer attribute slice and the multiple along-layer attribute slice, determining a signal-to-noise ratio attribute slice; in one implementation, determining the snr attribute slice may include: the ratio of the primary along-layer property slice (At) to the multiple along-layer property slice (Δ At) is determined as the signal-to-noise property Slice (SN).
After the signal-to-noise ratio attribute slice is determined, determining multiple interference areas with different interference levels from the earthquake work area according to the signal-to-noise ratio attribute slice; in particular implementations, determining multiple interference zones of different interference levels from a seismic work area may include, in one embodiment:
determining a multiple interference area with the value of the signal-to-noise ratio attribute slice larger than 2 as a multiple interference area of a first interference level in the earthquake work area;
determining a multiple interference area with the value of the signal-to-noise ratio attribute slice larger than 1 and smaller than 2 as a multiple interference area of a second interference level in the seismic work area;
determining a multiple interference area with the value of the signal-to-noise ratio attribute slice smaller than 1 as a multiple interference area of a third interference level in the seismic work area;
the first interference level is less than the second interference level, and the second interference level is less than the third interference level.
In the divided multiple interference areas with different interference levels, the reliability of the seismic data quality of the multiple interference area with the first interference level is high, and the seismic reflection can effectively reflect the characteristics of a reservoir; the reliability of the seismic data of the multiple interference area of the second interference level is general, the interference wave is close to the effective wave energy, and the reservoir stratum predicted by the earthquake has stronger multi-solution; the interfering wave energy of the multiple interference area of the third interference level is stronger than that of the effective wave, and at the moment, the seismic reflection cannot effectively reflect the characteristics of the reservoir.
In the application example of the embodiment of the present invention, fig. 7 is a signal-to-noise ratio attribute slice diagram obtained by the application example of the method for identifying multiples according to the embodiment of the present invention, and in fig. 7, a multiple interference area of a first interference level is divided into I-type multiple weak interference areas, which indicates that the reliability of seismic data quality is high, and seismic reflection can effectively reflect the characteristics of a reservoir; the multiple interference area of the second interference level is divided into interference areas in class II multiple waves, the reliability of seismic data is indicated to be general, the interference waves are close to effective wave energy, and the reservoir stratum is predicted by using the earthquake to have stronger multi-solution; and dividing a multiple interference area of the third interference level into a type III multiple strong interference area, indicating that the energy of interference waves is stronger than effective waves, and at the moment, the seismic reflection can not effectively reflect the characteristics of a reservoir stratum. In the application example of the embodiment of the invention, four segments of the E-type lamps are main force gas reservoirs, so that the E-type tumidinoda temple group can be used for Gangwu qiongensis
Amplitude root mean square attribute extraction calculation is carried out on data between two time horizons of three sections (Z2 d 3) of the lamp to the earthquake denier series, and finally a signal-to-noise ratio attribute slice of four sections of the lamp shown in figure 7 is obtained. As shown in fig. 7, in the three-dimensional earthquake work area, the multiple interference is not distributed uniformly in space, the strong interference is mainly located in the north of the work area near the four sections of the main-force gas-bearing layer lamp, and the south multiple interference is relatively weak, so that there is a strong risk that well location deployment is performed by means of earthquake in the north area.
The embodiment of the invention also provides computer equipment which comprises a memory, a processor and a computer program which is stored on the memory and can run on the processor, wherein the processor executes the computer program to realize the method for identifying multiples.
An embodiment of the present invention further provides a computer-readable storage medium, which stores a computer program for implementing the method for identifying multiples.
The embodiment of the invention also provides a device for identifying multiples, which is described in the following embodiment. Because the principle of the device for solving the problems is similar to a method for identifying multiples, the implementation of the device can refer to the implementation of the method for identifying multiples, and repeated parts are not repeated.
Fig. 8 is a schematic diagram of an apparatus for identifying multiples according to an embodiment of the present invention, and as shown in fig. 8, the apparatus may include:
the data acquisition module 801 is used for acquiring time horizon data and logging data of a seismic work area;
the wave impedance body determining module 802 is used for determining a wave impedance body of the seismic work area according to the time horizon data and the logging data;
a primary reflection ratio conversion module 803, configured to convert the wave impedance into a primary reflection ratio;
a forward synthesis module 804, configured to forward synthesize a primary seismic record and a full-wave seismic record according to the primary reflectivity and the logging data;
and a multiple interference area determining module 805, configured to determine multiple interference areas with different interference levels from the seismic work area according to the primary wave seismic record and the full-wave seismic record.
In one embodiment, the logging data acquired by the data acquisition module includes a wave impedance curve;
the wave impedance body determining module determines a wave impedance body of a seismic work area according to time horizon data and logging data, and comprises the following steps:
and (3) performing three-dimensional spatial interpolation on the wave impedance curve by using time layer data as constraint and utilizing an inverse distance interpolation algorithm to determine a wave impedance body.
In one embodiment, the primary reflectivity conversion module converts the wave impedance into the primary reflectivity as follows:
wherein r is the primary reflection index; PI is a wave impedance; i is the reflectivity sample point number.
In one embodiment, the logging data acquired by the data acquisition module includes seismic wavelets;
the forward synthesis module forward synthesizes the primary wave seismic record according to the primary wave reflectivity and the logging data, and comprises:
convolution calculation is carried out on the primary wave reflectivity and the seismic wavelets, and the primary wave seismic record is synthesized through forward modeling.
In one embodiment, the logging data acquired by the data acquisition module includes seismic wavelets;
the forward synthesis module forward synthesizes a full-wave seismic record according to the primary wave reflectivity and the logging data, and comprises:
determining the reflectivity of the full wave according to the reflectivity of the primary wave;
convolution calculation is carried out on the full-wave reflectivity and the seismic wavelets, and the full-wave seismic record is synthesized through forward modeling.
In one embodiment, the multiple interference zone determination module determines multiple interference zones of different interference levels from the seismic work area based on the primary seismic record and the full-wave seismic record, and comprises:
determining a multiple seismic record according to the primary wave seismic record and the full wave seismic record;
determining a signal-to-noise ratio attribute slice according to the primary wave seismic record and the multiple wave seismic record;
and according to the signal-to-noise ratio attribute slice, determining multiple interference areas with different interference levels from the seismic work area.
In one embodiment, the multiple interference zone determination module determines a multiple seismic record based on the primary seismic record and the full wave seismic record, comprising:
and subtracting the primary wave seismic record from the full wave seismic record to obtain a multiple wave seismic record.
In one embodiment, the multiple interference zone determination module determines the snr attribute slice based on the primary and multiple seismic records, including:
extracting attribute values of the primary wave seismic record along the time horizon to obtain primary wave along-horizon attribute slices;
extracting attribute values of the multiple seismic record along time horizon to obtain multiple along-horizon attribute slices;
and determining the signal-to-noise attribute slice according to the primary wave along-layer attribute slice and the multiple along-layer attribute slice.
In one embodiment, the determining the signal-to-noise ratio attribute slice by the multiple interference region determining module according to the primary and multiple along-layer attribute slices comprises:
and determining the ratio of the primary wave along-layer attribute slice to the multiple wave along-layer attribute slice as a signal-to-noise ratio attribute slice.
In one embodiment, the determining module for multiple interference regions determines multiple interference regions of different interference levels from a seismic work area according to a signal-to-noise ratio attribute slice, and the determining module comprises:
determining a multiple interference area with the value of the signal-to-noise ratio attribute slice larger than 2 as a multiple interference area of a first interference level in the earthquake work area;
determining a multiple interference area with the value of the signal-to-noise ratio attribute slice larger than 1 and smaller than 2 as a multiple interference area of a second interference level in the earthquake work area;
determining a multiple interference area with the value of the signal-to-noise ratio attribute slice smaller than 1 as a multiple interference area of a third interference level in the earthquake work area;
the first interference level is less than the second interference level, and the second interference level is less than the third interference level.
In summary, according to the method and the device for identifying multiples provided by the embodiment of the invention, a primary wave seismic record and a full wave seismic record are synthesized through forward modeling by using a reflectivity forward modeling method by establishing a wave impedance body; compared with the identification method of single points and single lines of multiple waves in the prior art, the embodiment of the invention can predict the overall development degree and distribution condition of multiple waves in the whole earthquake work area, is used for analyzing the potential multiple wave characteristics, and is applied to multiple wave pressing treatment, thereby realizing the optimization of multiple wave pressing treatment parameters and reducing the uncertainty of pressed multiple waves to a certain extent; the embodiment of the invention can also evaluate the quality of the seismic data and divide the area with unreliable seismic data according to the divided multiple interference areas with different interference levels, thereby reducing the multi-solution of reservoir prediction and reducing the risk of well position deployment. The embodiment of the invention only needs time horizon data, logging data and conventional inversion software, does not need the participation of seismic processing software and processing personnel, and has simple realization process and high efficiency. The embodiment of the invention can obtain the signal-to-noise ratio plane distribution of each geological layer, is directly applied to well position deployment and has strong practicability.
As will be appreciated by one skilled in the art, embodiments of the present invention may be provided as a method, system, or computer program product. Accordingly, the present invention may take the form of an entirely hardware embodiment, an entirely software embodiment or an embodiment combining software and hardware aspects. Furthermore, the present invention may take the form of a computer program product embodied on one or more computer-usable storage media (including, but not limited to, disk storage, CD-ROM, optical storage, and the like) having computer-usable program code embodied therein.
The present invention is described with reference to flowchart illustrations and/or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of the invention. It will be understood that each flow and/or block of the flow diagrams and/or block diagrams, and combinations of flows and/or blocks in the flow diagrams and/or block diagrams, can be implemented by computer program instructions. These computer program instructions may be provided to a processor of a general purpose computer, special purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, create means for implementing the functions specified in the flowchart flow or flows and/or block diagram block or blocks.
These computer program instructions may also be stored in a computer-readable memory that can direct a computer or other programmable data processing apparatus to function in a particular manner, such that the instructions stored in the computer-readable memory produce an article of manufacture including instruction means which implement the function specified in the flowchart flow or flows and/or block diagram block or blocks.
These computer program instructions may also be loaded onto a computer or other programmable data processing apparatus to cause a series of operational steps to be performed on the computer or other programmable apparatus to produce a computer implemented process such that the instructions which execute on the computer or other programmable apparatus provide steps for implementing the functions specified in the flowchart flow or flows and/or block diagram block or blocks.
The above-mentioned embodiments are intended to illustrate the objects, technical solutions and advantages of the present invention in further detail, and it should be understood that the above-mentioned embodiments are only exemplary embodiments of the present invention, and are not intended to limit the scope of the present invention, and any modifications, equivalent substitutions, improvements and the like made within the spirit and principle of the present invention should be included in the scope of the present invention.
Claims (20)
1. A method of identifying multiples, comprising:
acquiring time horizon data and logging data of a seismic work area;
determining a wave impedance body of the seismic work area according to the time horizon data and the logging data;
converting the wave impedance into a primary wave reflectivity;
forward modeling and synthesizing a primary wave seismic record and a full wave seismic record according to the primary wave reflectivity and the logging data;
determining multiple wave interference areas with different interference levels from the earthquake work area according to the primary wave earthquake record and the full wave earthquake record;
wherein, according to primary wave seismic record and full wave seismic record, confirm the multiple interference area of different interference levels from the earthquake work area, include:
determining a multiple seismic record according to the primary wave seismic record and the full wave seismic record;
determining a signal-to-noise ratio attribute slice according to the primary wave seismic record and the multiple wave seismic record;
and according to the signal-to-noise ratio attribute slice, determining multiple interference areas with different interference levels from the seismic work area.
2. The method of claim 1, wherein the well log data comprises a wave impedance curve;
determining a wave impedance of the seismic work area according to the time horizon data and the logging data, comprising:
and (3) performing three-dimensional spatial interpolation on the wave impedance curve by using time layer data as constraint and utilizing an inverse distance interpolation algorithm to determine a wave impedance body.
3. The method of claim 1, wherein the wave impedance is converted to primary reflectivity as follows:
wherein r is the primary reflection index; PI is a wave impedance body; i is the reflectivity sample point number.
4. The method of claim 1, wherein the well log data comprises seismic wavelets;
forward modeling a synthetic primary seismic record based on the primary reflectivity and the log data, comprising:
convolution calculation is carried out on the primary wave reflectivity and the seismic wavelets, and the primary wave seismic record is synthesized through forward modeling.
5. The method of claim 1, wherein the well log data comprises seismic wavelets;
forward modeling a synthetic full-wave seismic record from the primary reflectivity and the log data, comprising:
determining the reflectivity of the full wave according to the reflectivity of the primary wave;
convolution calculation is carried out on the full-wave reflectivity and the seismic wavelets, and the full-wave seismic record is synthesized through forward modeling.
6. The method of claim 1, wherein determining a multiple seismic record from the primary seismic record and the full-wave seismic record comprises:
and subtracting the primary wave seismic record from the full wave seismic record to obtain a multiple wave seismic record.
7. The method of claim 1, wherein determining a signal-to-noise attribute slice from the first and multiples seismic records comprises:
extracting attribute values of the primary wave seismic record along time horizon to obtain primary wave along-horizon attribute slices;
extracting attribute values of the multiple seismic record along time horizon to obtain multiple along-horizon attribute slices;
and determining the signal-to-noise attribute slice according to the primary wave along-layer attribute slice and the multiple along-layer attribute slice.
8. The method of claim 7, wherein determining a signal-to-noise attribute slice from a primary along-layer attribute slice and a multiple along-layer attribute slice comprises:
and determining the ratio of the primary wave along-layer attribute slice to the multiple along-layer attribute slice as a signal-to-noise ratio attribute slice.
9. The method of claim 1, wherein determining multiple interference regions of different interference levels from the seismic work area based on the signal-to-noise attribute slices comprises:
determining a multiple interference area with the value of the signal-to-noise ratio attribute slice larger than 2 as a multiple interference area of a first interference level in the earthquake work area;
determining a multiple interference area with the value of the signal-to-noise ratio attribute slice larger than 1 and smaller than 2 as a multiple interference area of a second interference level in the earthquake work area;
determining a multiple interference area with the value of the signal-to-noise ratio attribute slice smaller than 1 as a multiple interference area of a third interference level in the earthquake work area;
the first interference level is less than the second interference level, and the second interference level is less than the third interference level.
10. An apparatus for identifying multiples, comprising:
the data acquisition module is used for acquiring time horizon data and logging data of the earthquake work area;
the wave impedance body determining module is used for determining a wave impedance body of the seismic work area according to the time horizon data and the logging data;
the primary wave reflectivity conversion module is used for converting the wave impedance body into the primary wave reflectivity;
the forward synthesis module is used for forward synthesizing the primary wave seismic record and the full-wave seismic record according to the primary wave reflectivity and the logging data;
the multiple interference area determining module is used for determining multiple interference areas with different interference levels from the earthquake work area according to the primary wave earthquake record and the full wave earthquake record;
wherein, the multiple interference area confirms the module according to primary wave seismic record and full wave seismic record, confirms the multiple interference area of different interference levels from the earthquake work area, includes:
determining a multiple wave seismic record according to the primary wave seismic record and the full wave seismic record;
determining a signal-to-noise ratio attribute slice according to the primary wave seismic record and the multiple wave seismic record;
and according to the signal-to-noise ratio attribute slice, determining multiple interference areas with different interference levels from the seismic work area.
11. The apparatus of claim 10, wherein the logging data acquired by the data acquisition module comprises a wave impedance curve;
the wave impedance body determining module determines a wave impedance body of a seismic work area according to time horizon data and logging data, and comprises the following steps:
and (3) performing three-dimensional spatial interpolation on the wave impedance curve by using time layer data as constraint and utilizing an inverse distance interpolation algorithm to determine a wave impedance body.
12. The apparatus of claim 10, wherein the primary reflectivity conversion module converts the wave impedance to primary reflectivity as follows:
wherein r is the primary reflection; PI is a wave impedance; i is the reflectivity sample point number.
13. The apparatus of claim 10, wherein the log data acquired by the data acquisition module comprises seismic wavelets;
the forward synthesis module is used for forward synthesizing the primary wave seismic record according to the primary wave reflectivity and the logging data, and comprises the following steps:
convolution calculation is carried out on the primary wave reflectivity and the seismic wavelets, and the primary wave seismic record is synthesized through forward modeling.
14. The apparatus of claim 10, wherein the log data acquired by the data acquisition module comprises seismic wavelets;
the forward synthesis module forward synthesizes a full-wave seismic record according to the primary wave reflectivity and the logging data, and comprises:
determining the reflectivity of the full wave according to the reflectivity of the primary wave;
convolution calculation is carried out on the full-wave reflectivity and the seismic wavelets, and the full-wave seismic record is synthesized through forward modeling.
15. The apparatus of claim 10, wherein the multiple interference zone determining module determines the multiple seismic record based on the first seismic record and the full wave seismic record, comprising:
and subtracting the primary wave seismic record from the full wave seismic record to obtain a multiple wave seismic record.
16. The apparatus of claim 10, wherein the multiple interference zone determination module determines a signal-to-noise attribute slice from the primary seismic records and the multiple seismic records, comprising:
extracting attribute values of the primary wave seismic record along time horizon to obtain primary wave along-horizon attribute slices;
extracting attribute values of the multiple seismic record along time horizon to obtain multiple along-horizon attribute slices;
and determining the signal-to-noise ratio attribute slice according to the primary wave along-layer attribute slice and the multiple along-layer attribute slice.
17. The apparatus of claim 16, wherein the multiples interference region determination module determines the signal-to-noise attribute slice based on the primaries along-layer attribute slice and the multiples along-layer attribute slice, comprising:
and determining the ratio of the primary wave along-layer attribute slice to the multiple wave along-layer attribute slice as a signal-to-noise ratio attribute slice.
18. The apparatus of claim 10, wherein the multiple interference region determining module determines multiple interference regions of different interference levels from the seismic work area based on the signal-to-noise ratio property slice, comprising:
determining a multiple interference area with the value of the signal-to-noise ratio attribute slice larger than 2 as a multiple interference area of a first interference level in the earthquake work area;
determining a multiple interference area with the value of the signal-to-noise ratio attribute slice larger than 1 and smaller than 2 as a multiple interference area of a second interference level in the earthquake work area;
determining a multiple interference area with the value of the signal-to-noise ratio attribute slice smaller than 1 as a multiple interference area of a third interference level in the earthquake work area;
the first interference level is less than the second interference level, and the second interference level is less than the third interference level.
19. A computer device comprising a memory, a processor and a computer program stored on the memory and executable on the processor, the processor implementing the method for identifying multiples according to any one of claims 1 to 9 when the computer program is executed.
20. A computer-readable storage medium storing a computer program for executing the method of recognizing multiples according to any one of claims 1 to 9.
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