Angle gather conversion method, device and equipment

Abstract

The invention relates to the field of oil-gas exploration and development, in particular to an angle gather conversion method, device and equipment. The angle gather conversion method comprises the following steps: determining the range of a common reflection point surface element based on a common reflection point interval; simulating a propagation path of seismic waves for each shot point and detection point pair; if the reflection point in the seismic wave propagation path is located in the range of the common reflection point surface element, the amplitude value of the seismic wave is extracted and placed in a corresponding trace record in a variable offset VSP common reflection point gather; and superposing the channel records in the preset reflection angle range in the variable-offset VSP common reflection point gather to obtain a variable-offset VSP common reflection point angle gather. According to the embodiment of the invention, seismic wave propagation paths corresponding to different shot points and different detection points can be simulated, corresponding amplitude values in seismic wave records are extracted to directly form a variable offset VSP common reflection point angle gather with a high signal-to-noise ratio, and accurate amplitude data changing along with the angle can be provided for follow-up pre-stack inversion and reservoir prediction of the variable offset VSP.

Description

Technical Field

[0001] The embodiments of the present invention relate to the field of oil and gas exploration and development, and specifically to an angle gather conversion method, device and equipment. Background Art

[0002] VSP is a borehole seismic observation method that receives data in a well by ground excitation. Compared with ground seismic, VSP data has a high signal-to-noise ratio, high vertical resolution, and obvious kinematic and dynamic characteristics of seismic waves. Variable offset VSP is a VSP exploration method in which the shot point is excited along one (or more) straight lines through the well. It has a high number of coverages and can obtain high-quality reflection wave imaging. At the same time, the detector is close to the reservoir, which can obtain more abundant reservoir information. In recent years, borehole seismic technology has developed rapidly, and variable offset VSP has been industrialized. Due to the difference in observation methods, it is difficult to obtain the common angle stacking gathers of variable offset VSP through the method of ground seismic gather conversion. The application of VSP pre-stack wavefield information is still mostly limited to the qualitative analysis of pre-stack wavefield attributes. In addition, pre-stack seismic data contains more frequency information. Pre-stack inversion is currently the mainstream seismic inversion method for predicting reservoir lithology, reservoir physical properties and hydrocarbon content. However, the difference between variable offset VSP and ground seismic observation methods makes it difficult to obtain the angle gathers required for variable offset VSP pre-stack inversion through gather conversion obtained by ground seismic observation.

[0003] In the prior art, some algorithms superimpose VSP records after preliminary processing such as velocity analysis and dynamic correction to obtain AVO gathers whose amplitude varies with offset, and then convert them into angular gathers using the ray relationship between offset and angle; some algorithms obtain common-angle gathers of variable-offset VSP through reverse time migration.

[0004] For the above algorithm, due to the different excitation and reception methods, VSP data cannot obtain common reflection point gathers. And the method of forming a dynamic correction gather after the records of different shot distances are subjected to dynamic correction, and then forming an angle gather by a collection of different angles after angle conversion is often difficult to obtain good results when used in variable offset VSP data. In addition, due to the uneven reception and lateral coverage times in variable offset VSP wells, it is difficult to extend the reverse time migration downward. In addition, it is difficult for the asymmetric observation system to offset the offset arcing phenomenon, and the angle gathers obtained by reverse time migration have serious noise interference and low signal-to-noise ratio, and cannot be used for subsequent processing and interpretation work. Therefore, how to provide a common reflection point angle gather conversion method suitable for the characteristics of variable offset VSP data, and then provide accurate amplitude data that changes with angle for subsequent pre-stack inversion and reservoir prediction of variable offset VSP is a key problem that needs to be solved urgently. Summary of the invention

[0005] The purpose of the embodiments of this specification is to provide an angle gather conversion method, device and equipment to provide a variable offset VSP common reflection point angle gather conversion method suitable for the characteristics of variable offset VSP data, thereby providing accurate amplitude data that varies with angle for subsequent pre-stack inversion and reservoir prediction of variable offset VSP.

[0006] On the one hand, an embodiment of the present specification provides an angle gather conversion method, the method comprising: determining the range of a common reflection point facet based on a common reflection point interval; simulating the propagation path of a seismic wave for each shot point and detection point pair; if a reflection point in the seismic wave propagation path is located within the range of the common reflection point facet, extracting the amplitude value of the seismic wave and placing it in a corresponding trace record in a variable offset VSP common reflection point gather; and superimposing trace records within a preset reflection angle range in the variable offset VSP common reflection point gather to obtain a variable offset VSP common reflection point angle gather.

[0007] On the other hand, the embodiments of the present specification also provide an angle gather conversion method device, the device comprising: a determination module, used to determine the range of the common reflection point facet based on the common reflection point interval; a simulation module, used to simulate the propagation path of the seismic wave for each shot point and detection point pair; an extraction module, used to extract the amplitude value of the seismic wave and place it in the corresponding trace record in the variable offset VSP common reflection point gather if the reflection point in the seismic wave propagation path is located within the range of the common reflection point facet; a superposition module, used to superimpose the trace records within the preset reflection angle range in the variable offset VSP common reflection point gather to obtain the variable offset VSP common reflection point angle gather.

[0008] On the other hand, a computer device is provided, comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor executes the above-mentioned angle gather conversion method.

[0009] It can be seen from the technical solutions provided by the above embodiments of this specification that the embodiments of this specification determine the range of the common reflection point facet based on the common reflection point interval; for each shot point and detection point pair, simulate the propagation path of the seismic wave; if the reflection point in the seismic wave propagation path is located within the range of the common reflection point facet, extract the amplitude value of the seismic wave and place it in the corresponding track record in the variable offset VSP common reflection point gather; superimpose the track records within the preset reflection angle range of the variable offset VSP common reflection point gather to obtain the variable offset VSP common reflection point angle gather. Compared with the existing methods, the angle gather conversion method of the embodiment of this specification does not go through the conversion from the offset domain to the incident angle domain, and can simulate the seismic wave propagation path corresponding to different shot points and different detection points to form a variable offset VSP common reflection point gather, and then extract the corresponding amplitude value in the seismic wave record to directly form a variable offset VSP common reflection point angle gather with a high signal-to-noise ratio. The angle gather conversion method of the embodiment of this specification is more suitable for the conversion of common reflection point angle gathers with the characteristics of variable offset VSP data, and can provide accurate amplitude data that varies with angle for subsequent prestack inversion and reservoir prediction of variable offset VSP. BRIEF DESCRIPTION OF THE DRAWINGS

[0010] In order to more clearly illustrate the technical solutions in the embodiments of this specification or the prior art, the drawings required for use in the embodiments or the prior art description are briefly introduced below.

[0011] Figure 1 is a flow chart of an angle gather conversion method provided in an embodiment of this specification;

[0012] Figure 2 It is a flow chart of building a formation model provided by the embodiments of this specification;

[0013] Figure 3 It is the forward velocity model of the variable offset VSP in the SG area provided in the embodiment of this specification; the abscissa is the offset (unit: m), the ordinate is the depth (unit: m), and the depth of the color represents different P-wave velocities (unit: m / s);

[0014] Figure 4 It is an upgoing wave after the wave field separation of the seismic wave in the SG area is performed using the median filter provided in the embodiment of this specification; the horizontal axis is the sequence number of the seismic trace; the vertical axis is the time (unit: ms);

[0015] Figure 5 It is a schematic diagram of the seismic wave propagation paths between different shot points and detection point pairs based on Well A in the SG area provided in the embodiments of this specification;

[0016] Figure 6 It is a flow chart of simulating the propagation path of seismic waves provided in the embodiments of this specification;

[0017] Figure 7 It is a variable offset VSP common reflection point gather obtained based on Well A in the SG area provided in the embodiment of this specification;

[0018] Figure 8 It is a variable offset VSP common reflection point angle gather obtained based on Well A in the SG area provided in the embodiment of this specification;

[0019] Fig. 9 It is a schematic diagram of the structure of an angle gather conversion device provided in an embodiment of this specification;

[0020] Fig.10 It is a schematic diagram of the structural composition of a computer device provided in an embodiment of this specification.

[0021] Reference numerals in the above drawings:

[0022] 501, reflective strata;

[0023] 502, common reflection point;

[0024] 503. Depth of strata;

[0025] 504. The first gun point placed on the ground;

[0026] 505. The second gun point placed on the ground;

[0027] 506. The Mth (M>=3)th shot point placed on the ground;

[0028] 507. The depth at which the seismic wave excited by the Mth shot point is received by the geophone in the well;

[0029] 508. The depth at which the seismic wave excited by the second shot point is received by the geophone in the well;

[0030] 509. The depth at which the seismic wave excited by the first shot point is received by the geophone in the well;

[0031] 510, the offset from the first shot point to the well;

[0032] 511, the offset from the second shot point to the well;

[0033] 512, the offset from the Mth shot point to the well;

[0034] 513. The distance from the first shot point to the ground receiving point where the seismic wave it stimulates is reflected from the common reflection point;

[0035] 514. The distance from the second shot point to the ground receiving point where the seismic wave it stimulates is reflected from the common reflection point;

[0036] 515. The distance from the Mth shot point to the ground receiving point where the seismic wave excited by it is reflected from the common reflection point;

[0037] 900, angle gather conversion device;

[0038] 901. Determine module;

[0039] 902, simulation module;

[0040] 903, extraction module;

[0041] 904, superposition module;

[0042] 1000. Computer equipment;

[0043] 1001, network communication port;

[0044] 1002. Processor;

[0045] 1003. Memory. DETAILED DESCRIPTION

[0046] The following will be combined with the drawings in the embodiments of this specification to clearly and completely describe the technical solutions in the embodiments of this specification. Obviously, the described embodiments are only part of the embodiments of this specification, not all of the embodiments. Based on the embodiments in this specification, all other embodiments obtained by ordinary technicians in this field without creative work should fall within the scope of protection of this specification.

[0047] Vertical Seismic Profile (VSP) is the full name of VSP. VSP is a seismic observation method that places seismic detectors at different depths in the well to record seismic signals generated by ground sources, that is, observing the seismic wave field in the well and then generating corresponding ground seismic data. The vertical profile is equivalent to the ground seismic profile.

[0048] Figure 1 The figure is a flow chart of an angle gather conversion method. When implemented, the method includes the following steps:

[0049] S101: Determine the range of the common reflection point bin based on the common reflection point interval.

[0050] In some embodiments, a common reflection point may refer to the same point on a certain underground reflection interface in the ground seismic data, and the reflected wave of this point can be recorded by the shot points and detector points at different positions. Specifically, when the underground reflection interface is horizontal (or approximately horizontal), a number of pairs of excitation points and receiving points are symmetrically arranged on the ground with a certain point as the center, and each reflection received comes from a certain point on the interface directly below the point, which is called a common reflection point. In seismic exploration, when seismic waves encounter underground interfaces (such as stratum interfaces, lithology change interfaces, etc.), reflections will occur. These reflected waves will be received by the detector and recorded. The reflection point surface element is a concept that describes this reflection phenomenon, which represents an area near the underground reflection point. Specifically, the common reflection point surface element may refer to the response surface of a reflection arc segment adjacent to a common reflection point underground in the time and space domain, and all points on this surface element contribute to the imaging of the common reflection point.

[0051] The horizontal interval between the shot point and the receiver point, as well as the depth and dip of the underground reflection layer where the underground reflection interface is located, have a certain influence on the size of the common reflection point interval of the ground seismic data. When the horizontal interval between the shot point and the receiver point decreases, the common reflection point interval can be reduced accordingly, because a denser arrangement can more accurately locate the underground reflection point, thereby reducing the size of the bin; conversely, when the horizontal interval increases, the common reflection point interval can be increased, because a larger interval will cause the projection range of the underground reflection point on the ground to expand, thereby increasing the size of the bin. The deeper the underground reflection layer and the larger the dip, the larger the common reflection point interval can be, and the larger the projection range of the corresponding common reflection point bin on the ground; conversely, the shallower the underground reflection layer and the smaller the dip, the smaller the common reflection point interval can be, and the smaller the projection range of the corresponding variable offset VSP data common reflection point bin on the ground. The common reflection point interval can be determined based on the horizontal interval between the shot point and the receiver point, as well as the depth and dip of the underground reflection layer where the underground reflection interface is located, and then the range of the common reflection point bin of the variable offset VSP data can be determined. For example, a multivariate mapping relationship model between horizontal interval, depth, inclination and common reflection point interval can be constructed, and the actual horizontal interval between the shot point and the receiver point, the depth of the underground reflection layer, and the inclination of the underground reflection layer can be input into the constructed multivariate mapping relationship model to obtain the corresponding common reflection point interval output by the multivariate mapping relationship model, and then the range of the common reflection point bin of the variable offset VSP data can be determined according to the common reflection point interval. The smaller the common reflection point interval, the finer the common reflection point bin, but the corresponding data acquisition cost will also be higher. Specifically, the size of the common reflection point bin width of the variable offset VSP data directly affects the signal-to-noise ratio and resolution of the seismic data. A larger bin width means that more seismic traces participate in the stacking, thereby improving the signal-to-noise ratio, but the stacking effect will smooth out some detail information; on the contrary, a smaller bin width can retain some detail information, but it may reduce the signal-to-noise ratio because the number of seismic traces involved in the stacking is small. When conducting high-resolution exploration in complex geological structures, it may be necessary to use a smaller horizontal interval and a narrower bin width to improve resolution; while when conducting exploration in areas with low signal-to-noise ratios, it may be necessary to use a larger horizontal interval and a wider bin width to improve the signal-to-noise ratio. For example, by obtaining relevant data that can characterize the exploration target and geological conditions, a multivariate mapping relationship model between more specific exploration targets and geological conditions, the horizontal interval between shot points and receiver points, the depth of the underground reflection layer, the inclination of the underground reflection layer, and the common reflection point interval can be constructed to determine the range of the common reflection point bin of the variable offset VSP data, which will not be repeated here.

[0052] The common reflection point interval and the range of the common reflection point bin of the variable offset VSP data are determined based on the horizontal interval between the shot points and the receiver points, the depth and inclination of the underground reflection layer where the underground reflection interface is located, the exploration target and geological conditions, which is beneficial to improving the signal-to-noise ratio of the subsequent variable offset VSP common reflection point angle gather data.

[0053] S102: For each shot point and receiver point pair, simulate the propagation path of the seismic wave.

[0054] In some embodiments, for each ground shot point and well detection point pair, the established formation model can be used to simulate the propagation path of the seismic wave after the downgoing wave and the upgoing wave are separated. The propagation path includes the incident angle of the downgoing wave, the position of the reflection point in the underground reflection layer, the reflection angle of the upgoing wave, etc.

[0055] In some embodiments, a formation model can be established based on zero-offset VSP data and logging data; the formation model is used to simulate the propagation path of seismic waves; the formation model includes a depth model, a variable-offset VSP forward velocity model and a density model.

[0056] By establishing a formation model, the distribution, thickness, properties (such as velocity, density, porosity, etc.) of different underground strata and the contact relationship between them can be effectively revealed, thereby better simulating the propagation path of seismic waves in the strata and better converting variable offset VSP common reflection point angle gathers.

[0057] Zero-offset VSP data is an important data type in the field of seismic exploration. Zero-offset VSP technology can be used to arrange detectors in the well and stimulate seismic waves, and record the reflection and refraction wave signals generated by the surrounding strata during the upward propagation of seismic waves along the wellbore. These signals contain high-resolution seismic information of the strata beside the well. These signals can be processed to obtain zero-offset VSP data. Zero-offset VSP technology refers to a seismic exploration method in which the source (shot point) and the detector (detection point) are in the same vertical well section, and the distance between the two (i.e., offset) is zero. Zero-offset VSP data has a higher resolution because the distance between the source and the detector is short and the received seismic signal is less affected by complex surface conditions. Zero-offset VSP data can simultaneously record upgoing and downgoing waves, as well as multiple seismic wave information such as longitudinal waves and conversion waves. It can also extract multiple dynamic parameters closely related to lithology, such as amplitude, frequency, Q value, and wave impedance curve. Zero-offset VSP data can not only be used for stratigraphic comparison and constrained inversion, but also directly identify different types of reservoirs, providing an important basis for oil and gas exploration. Well logging data can be geophysical parameter data obtained by measuring the geophysical properties of rock formations, such as electrochemical properties, conductive properties, acoustic properties, and radioactivity, through logging instruments. Well logging data plays a vital role in the process of oil and gas exploration and development. Well logging data contains a wealth of geological information, which can include at least the following aspects: lithology identification: the lithology of underground rock formations, such as sandstone, mudstone, carbonate rock, etc., can be determined through well logging curves; stratigraphic division: well logging data can be used to divide strata and determine the top and bottom interfaces of different strata; reservoir evaluation: identification and evaluation of reservoirs, including determination of parameters such as porosity, permeability, and oil (gas) saturation; fluid property judgment: judgment of the properties of fluids in rock pores, such as oil, gas, water, etc.; structural analysis: use well logging data to conduct geological structural analysis, such as identification of faults and fractures.

[0058] Zero-offset VSP data contains velocity structure data of the formations near the well. A variable-offset VSP forward velocity model can be constructed based on the zero-offset VSP data, and the variable-offset VSP forward velocity model can be used to simulate the propagation path of seismic waves between each shot point and receiver point pair. Well logging data provides rock physical properties at different depths in the well, such as density, porosity, permeability, etc. Based on these data, accurate depth models and density models can be constructed to simulate the propagation path of seismic waves between each shot point and receiver point pair. A formation model can be established based on zero-offset VSP data and well logging data. The formation model can be used to simulate the propagation path of seismic waves between each shot point and receiver point pair.

[0059] In some embodiments, establishing a formation model based on zero-offset VSP data and logging data may include: matching the depth of the logging data with the depth of the zero-offset VSP data to establish a depth model; establishing a variable-offset VSP forward velocity model based on the first arrival time data of the longitudinal wave in the zero-offset VSP data; and establishing a density model by resampling the density curve in the logging data.

[0060] Figure 2 A flow chart is constructed for a formation model. In specific implementation, the method includes the following steps:

[0061] S201: Match the depth of the logging data with the depth of the zero-offset VSP data to establish a depth model.

[0062] In some embodiments, since the well logging data and zero-offset VSP data are usually acquired at different times or under different conditions, there may be slight differences in their depth scales. Factors such as cable expansion and borehole expansion may lead to inconsistencies in depth. Therefore, depth correction and matching are required. First, under the premise of ensuring that the well logging data and zero-offset VSP data are complete and available, the depth information and related rock physical properties (such as velocity, density, etc.) in the well logging data can be extracted, and the depth information and seismic wave propagation time or velocity information in the zero-offset VSP data can be extracted. Then, the depth of the well logging data and the zero-offset VSP data are directly compared to observe whether there is a significant depth difference. If there is a significant difference, it is necessary to determine the cause of the difference and consider depth correction. The method of depth correction depends on the specific cause of the difference. Common correction methods include linear correction, nonlinear correction or the use of specific correction tools. For example, if the difference is linear (that is, the depth difference increases or decreases uniformly with increasing depth), a linear equation can be used for correction; if the difference is nonlinear, a more complex mathematical model or algorithm may need to be used for correction; in some cases, specific software tools can be used to automatically perform depth correction, which will not be repeated here. After the depth correction is completed, the depth of the well logging data and the zero-offset VSP data are matched, that is, the depth scales of the two can be adjusted to the same benchmark for use in subsequent analysis and modeling. Finally, the matched depth information can be used in combination with the rock physical properties in the well logging data to establish a depth model of the formation. The depth model can be a simple depth-lithology relationship table or a more complex three-dimensional geological model. For example, a two-dimensional depth-lithology table can be constructed, in which one column records the depth information (usually in meters or feet), and another column or columns record the lithology information at the corresponding depth (such as sandstone, mudstone, limestone, etc.). Through the constructed two-dimensional depth-lithology table, the changes of underground lithology with depth can be quickly viewed and understood. For another example, the collected data can be interpreted, corrected and integrated through three-dimensional modeling software or geographic information system tools, and the three-dimensional geological morphological distribution of the formation can be constructed based on the data after eliminating errors and inconsistencies, and the corresponding lithological attributes are assigned. Through the constructed three-dimensional geological morphological distribution, the three-dimensional morphology and lithological distribution of the underground formation can be fully and accurately described.

[0063] By matching the depth of the well logging data with the depth of the zero-offset VSP data to establish a depth model, we can better obtain the structural information of different underground strata, which helps to more accurately simulate the propagation path of seismic waves in underground strata.

[0064] S202: Based on the P-wave first arrival time data in the zero-offset VSP data, a variable-offset VSP forward velocity model is established.

[0065] Reference Figure 3 As shown, Figure 3 The variable offset VSP forward velocity model established in the SG area is shown. In some embodiments, the P-wave first arrival time data in the zero offset VSP data can be obtained, and the P-wave vertical one-way time when the seismic wave reaches each geophone is calculated based on the obtained P-wave first arrival time data, and finally the P-wave velocity of each layer in the depth model is calculated according to the P-wave vertical one-way time when the seismic wave reaches each geophone, thereby establishing the variable offset VSP forward velocity model.

[0066] For example, the first arrival time data of the P-wave in the zero-offset VSP data can be obtained. p,i , and calculate the corresponding longitudinal wave vertical one-way time t based on formula (1) p,vi .

[0067]

[0068] In the formula, H i is the depth of the ith detector, Offset is the distance from the zero offset VSP shot point to the wellhead, and t p,vi is the vertical one-way time of the ith P-wave. The vertical one-way time of the ith P-wave can be expressed as the time taken by the seismic wave to reach the ith detector in the well after being excited from the ground shot point. The underground can be divided into multiple layers based on the depth model, and the velocity is assumed to be constant in each layer.

[0069] The area between adjacent detectors can be divided into a layer based on the vertical one-way time t of the longitudinal wave. p,vi , the corresponding longitudinal wave velocity V can be calculated by combining the depth data of the geophone with formula (2) p,i .

[0070] V p,i =(H i -H i-1 ) / (t p,vi -t p,vi-1 ) (2)

[0071] In the formula, H i is the depth of the ith detector, H i-1 is the i-1th detector depth, t p,vi is the vertical one-way time of the longitudinal wave of the ith detector, t p,vi-1 When the longitudinal wave of the i-1th detector is vertically one-way, V p,i is the longitudinal wave velocity of the i-th layer. Figure 3 As shown, Figure 3 The variable offset VSP forward velocity model in the SG region established based on formula (1) and formula (2) is shown.

[0072] By constructing a variable-offset VSP forward velocity model, we can better understand the geological structure of the underground strata and the changes in the velocity of seismic waves propagating in the underground strata, which helps to more accurately simulate the propagation path of seismic waves in the underground strata.

[0073] S203: Resample the density curve in the logging data and establish a density model.

[0074] In some embodiments, since the depth sampling frequency of the density curve in the logging data is much smaller than the depth sampling frequency in the zero-offset VSP data, the density curve in the logging data can be resampled so that the sampling frequency of the resampled density curve is equal to the depth sampling frequency in the zero-offset VSP data to establish a density model.

[0075] Density curve data in the logging data and depth data in the zero-offset VSP data can be obtained, and the depth data extracted from the zero-offset VSP data can be used as the sampling position of the new density curve. The corresponding interpolation method is selected to resample the density curve in the logging data based on the sampling position of the new density curve. The interpolation method can be a linear interpolation, a cubic spline interpolation method, etc. For example, after obtaining the density curve data in the logging data and the depth data in the zero-offset VSP data and using the depth data extracted from the zero-offset VSP data as the sampling position of the new density curve, each depth data point in the zero-offset VSP depth data can be traversed by the linear interpolation method. For each depth data point, the two closest depth points are found in the density data of the logging data. The two depth points and their corresponding density values ​​can be used to calculate the density value of the target depth point through the linear interpolation formula. Finally, all the density values ​​obtained by interpolation calculation are combined with the corresponding zero-offset VSP depth points to form a new density curve, and then the density model can be obtained.

[0076] By constructing a density model, we can better understand the geological structure of different underground strata and changes in geological structure, which helps to more accurately simulate the propagation path of seismic waves in underground strata.

[0077] In some embodiments, the seismic waves can be subjected to wave field separation to obtain downgoing waves and upgoing waves; the downgoing waves can represent downgoing seismic waves that propagate downward from the shot point excitation to the reflection point; the upgoing waves can represent upgoing seismic waves that are reflected from the reflection point to the detection point.

[0078] Separating the seismic wave field to obtain downgoing waves and upgoing waves helps to more accurately understand the underground geological structure and better simulate the propagation path of seismic waves, laying a foundation for improving the signal-to-noise ratio of subsequent variable offset VSP common reflection point angle gather data.

[0079] The separation of upgoing waves and downgoing waves is mainly based on the differences in their propagation characteristics, including differences in apparent velocity, frequency, wave number, etc. Based on the variable offset VSP forward velocity model, the seismic waves can be separated into traveling waves and upgoing waves by wave field separation. Downgoing waves can represent downgoing seismic waves that propagate downward from the shot point excitation to the reflection point. As the recording depth increases, the travel time of downgoing waves increases, and the apparent velocity is positive; upgoing waves can represent upgoing seismic waves that are reflected from the reflection point to the detector point. As the recording depth increases, the travel time of upgoing waves decreases, and the apparent velocity is negative. Travel time refers to the time it takes for seismic waves to travel from the excitation source to the observation point. The travel time of downgoing waves that propagate downward directly to the receiving device in the well is the travel time of downgoing waves that propagate downward, and the travel time of upgoing waves that propagate upward after propagating downward to the underground reservoir and then reflecting upward to the receiving device is the travel time of upgoing waves that propagate upward. Different characteristics of upgoing and downgoing wave fields in terms of apparent velocity, frequency, and wave number can be applied to filter in different domains using appropriate methods to obtain completely separated upgoing and downgoing wave fields. For example, median filtering can be used to separate upgoing waves and downgoing waves. First, the initial data can be time-shifted according to the principle of correcting the first arrival time of the longitudinal wave to be equal, so that the downgoing waves are aligned in the vertical direction, that is, median filtering is performed in the vertical direction. At this time, the vertically aligned downgoing waves are enhanced, and the upgoing waves that pass through obliquely are greatly weakened. Then the result of the median filtering is reversely time-shifted according to the original time shift time, and the downgoing wave is subtracted from the initial data to obtain the wave field of the upgoing wave that has been separated from the downgoing wave. For another example, the frequency-wavenumber domain filtering method can be used to separate upgoing waves and downgoing waves. First, the initial data can be transformed from the time-space domain to the frequency-wavenumber domain, and filtering operations can be performed in the frequency-wavenumber domain according to the different characteristics of the upgoing wave and the downgoing wave to separate the upgoing wave and the downgoing wave. Finally, the filtered data can be inversely transformed from the frequency-wavenumber domain back to the time-space domain to obtain the separated upgoing wave and downgoing wave data. Refer to Figure 4 , Figure 4 The figure shows the upgoing waves after wavefield separation of seismic waves in the SG region using median filtering.

[0080] In some embodiments, the shot point may also be referred to as an excitation point or a source point, which is a location used to generate seismic waves in seismic exploration. In seismic exploration operations, explosives, air guns or other source devices may be placed at these locations to generate strong downgoing waves, which will then propagate underground and reflect, refract and other phenomena when encountering stratigraphic interfaces of different lithologies. The reflected seismic waves are received and recorded by the detector point for subsequent seismic data processing and interpretation. The selection of the shot point has an important impact on the results of seismic exploration. A reasonable layout of the shot points can ensure that the seismic waves can cover the target exploration area and obtain sufficient seismic data. At the same time, factors such as the number, location, and excitation energy of the shot points also need to be reasonably designed according to specific exploration tasks and geological conditions, which will not be repeated here. The detector point, which may also be referred to as a receiving point or an observation point, is the location of the equipment used to receive seismic waves and record seismic data in seismic exploration. The detector can be pre-placed in the well to capture the upgoing waves excited by the shot point and reflected back through the reflection point of the underground reflection layer. After these upgoing waves are converted and processed by the detectors, they will form a shot gather record for subsequent data processing and interpretation. The number and layout of the detection points are also important parameters in seismic exploration. A sufficient number of detection points can ensure the comprehensiveness and accuracy of seismic wave data, while a reasonable layout can improve the resolution and signal-to-noise ratio of seismic data, which will not be elaborated here. A sufficient number of shot points can be preset on the ground and a sufficient number of detection points can be preset in the well to ensure the comprehensiveness and accuracy of seismic wave data.

[0081] In some embodiments, for each shot point and receiver point pair, the propagation path of the seismic wave is simulated, including: based on the depth model and the density model, the incident angle of the downgoing wave can be determined using the ray tracing method; based on the incident angle of the downgoing wave, the position of the reflection point and the reflection angle of the upgoing wave can be determined using the variable offset VSP forward velocity model; based on the reflection angle of the upgoing wave, the propagation time of the upgoing wave can be determined using the variable offset VSP forward velocity model. Figure 5 , Figure 5 A schematic diagram showing the seismic wave propagation paths between different shot points and receiver point pairs based on the simulation of Well A in the SG area.

[0082] Based on the formation model, it effectively reveals the distribution, thickness, properties (such as velocity, density, porosity, etc.) of different underground strata and the contact relationship between them, accurately simulates the propagation path of seismic waves in the strata, and lays the foundation for establishing more accurate variable offset VSP common reflection point angle gathers.

[0083] Figure 6 This is a flow chart for simulating the propagation path of seismic waves. In specific implementation, the method includes the following steps:

[0084] S601: Based on the depth model and the density model, the incident angle of the downgoing wave can be determined using a ray tracing method.

[0085] In some embodiments, the ray tracing method is an electromagnetic field intensity prediction algorithm based on geometric optics and geometric consistency diffraction theory. Its basic principle is to simulate the path of light waves or other electromagnetic waves propagating in the medium, and use mathematical and physical methods to calculate and predict the propagation trajectory after the ray interacts with the object. In high frequency cases, the wavelength of electromagnetic waves is close to zero, and electromagnetic waves can be approximately equivalent to light. When the rays emitted by the transmitted rays are blocked by obstacles, based on the principles of geometric optics, various rays will be generated, including direct rays, reflected rays, etc. The ray tracing method propagates and traces each ray until it reaches the receiving point or the electric field amplitude value is lower than the threshold value to be considered. The amplitude, power, phase and delay of the receiving point can be calculated by vector superposition of the rays reaching the receiving point. The ray tracing method can be divided into the mirror method, the emission ray method and the ray tube method. The mirror method can obtain a virtual mirror source by determining the mirror point by the law of reflection, thereby determining the propagation path of the ray. The mirror method is a point-to-point ray tracing technology suitable for ray tracing in simple environments. The ray emission method can set a receiving sphere to determine whether the ray reaches the receiving point, and the determination of the receiving sphere radius directly affects the accuracy of the receiving field strength. The ray tube method is an improved method of ray tracing technology based on ray emission, which can simulate the propagation path of electromagnetic waves by dividing the ray tube. For example, for each shot point and detector point pair, the depth model in the formation model can be used to obtain the depth data of the reflecting formation, and then the binary search method can be used, and the ray tube can be divided based on the ray tube method for trial shooting to obtain the incident angle from the excitation point to the first reflecting formation. The incident angle can be the angle between the downlink wave and the normal line of the reflecting formation interface. The density model in the formation model can be used to obtain the density data of the reflecting formation, and based on the density data, the incident angles of all other formations are calculated, and the offset distance of the corresponding ray path is calculated. If this value is greater than the actual offset distance, the incident angle can be reduced and recalculated; if it is less than the actual offset distance, the incident angle can be increased and recalculated until the error between the two is minimized, and the true downlink wave incident angle can be obtained.

[0086] Based on the depth model, the structural information of different underground strata can be better obtained, thereby more accurately simulating the propagation path of seismic waves in underground strata.

[0087] S602: Based on the incident angle of the downgoing wave, the position of the reflection point and the reflection angle of the upgoing wave may be determined using a variable offset VSP forward velocity model.

[0088] In some embodiments, after the incident angle of the downlink wave is determined using the ray tracing method based on the depth model and the density model, the propagation time of the downlink wave can be determined. In combination with the incident angle of the downlink wave and the propagation time of the downlink wave, the variable offset VSP forward velocity model can be used to calculate the depth information of the reflection point and the horizontal information projected on the ground, and then the position of the reflection point can be determined by the depth information and the horizontal information. Specifically, based on the propagation time of the downlink wave, the depth information of the reflection point can be calculated using the longitudinal wave velocity formula of different layers in the variable offset VSP forward velocity model. And the horizontal information of the reflection point projected on the ground can be calculated based on the incident angle of the downlink wave, the propagation time of the downlink wave, and the horizontal position information of the shot point, and then the three-dimensional coordinate position of the reflection point can be determined by the depth information and the horizontal information. When the downlink wave propagates underground and encounters a stratum interface with a large velocity difference, part of the energy will continue to propagate along the interface, while the other part of the energy will return to the original medium according to Snell's law, that is, a reflected uplink wave is generated. The reflection angle and intensity of the uplink wave depend on the incident angle of the downlink wave, the velocity of the rock formations on both sides of the interface, and the physical properties of the rock formations. For example, a prediction model between the incident angle, velocity, physical properties, reflection angle and intensity can be constructed, and the actual incident angle of the downgoing wave, the velocity of the rock layers on both sides of the interface and the physical property data of the rock layers can be input into the constructed prediction model to obtain the output reflection angle and intensity data of the upgoing wave.

[0089] Based on the variable offset VSP forward velocity model, we can better understand the geological structure of the underground strata and the velocity changes of seismic waves propagating in the underground strata, and more accurately simulate the propagation path of seismic waves in the underground strata.

[0090] S603: Based on the reflection angle of the upgoing wave, the propagation time of the upgoing wave may be determined using a variable offset VSP forward velocity model.

[0091] In some embodiments, after the position of the reflection point and the reflection angle of the upgoing wave are determined based on the incident angle of the downgoing wave using the variable offset VSP forward velocity model, the propagation path length of the upgoing wave can be determined. Then, the velocities of different layers in the upgoing wave propagation path can be determined in combination with Snell's law and the variable offset VSP forward velocity model. Snell's law means that when a wave passes through the interface of two isotropic media, the propagation direction of the wave changes and satisfies that the sine of the incident angle divided by the velocity of the wave in the first medium is equal to the sine of the refraction angle divided by the velocity of the wave in the second medium. For example, the longitudinal wave velocity formula of different layers in the variable offset VSP forward velocity model can be used to determine the longitudinal wave velocity of the upgoing wave in all strata, and based on the longitudinal wave velocity and the incident angle, the refraction angle of the upgoing wave in all strata can be determined using Snell's law. Then, the propagation time of the upgoing wave in different layers can be determined according to the refraction angle and the longitudinal wave velocity formula of different layers in the variable offset VSP forward velocity model, and the propagation time of the upgoing wave in different layers can be obtained by summing up the propagation time of the upgoing wave in different layers.

[0092] Based on the density model, we can better understand the geological structure and changes of different underground strata, and more accurately simulate the propagation path of seismic waves in underground strata.

[0093] S103: If the reflection point in the seismic wave propagation path is located within the range of the common reflection point bin, extract the amplitude value of the seismic wave and place it in a corresponding trace record in the variable offset VSP common reflection point gather.

[0094] In some embodiments, if the reflection point in the seismic wave propagation path is located within the range of the common reflection point facet, the time point when the upgoing wave passes through the reflection point and reaches the detection point can be calculated; the amplitude value of the upgoing wave at the said time point can be extracted from the shot gather record; the reflection angle of the upgoing wave at the said reflection point can be obtained; and the amplitude value can be placed in the trace record of the said reflection angle of the variable offset VSP common reflection point trace gather.

[0095] By extracting the amplitude value of the upgoing wave at the corresponding time point in the shot gather record and placing it in the variable offset VSP common reflection point gather, the intensity information of the upgoing wave at different time points can be obtained from the trace records in the variable offset VSP common reflection point gather, laying the foundation for the conversion of the variable offset VSP common reflection point angle gather.

[0096] The time point when the upgoing wave reaches the detection point after passing through the reflection point can be calculated based on the propagation time of the upgoing wave and the time point when the upgoing wave reaches the reflection point calculated by the variable offset VSP forward velocity model. And according to the calculated time point when the upgoing wave reaches the detection point, the amplitude value of the upgoing wave at the same time point can be retrieved in the shot gather record. The shot gather record is the original data recorded in the seismic exploration. It contains the amplitude information of the upgoing wave at different time points and different detection points after the shot point excites the seismic wave. According to the time point corresponding to the calculated reflection point position, the amplitude value at this time point is found from the shot gather record. The amplitude value reflects the intensity of the upgoing wave reaching the detection point after reflection at this time point. Specifically, the larger the amplitude value, the stronger the vibration of the upgoing wave when it reaches the detection point, that is, the greater the intensity of the upgoing wave; conversely, the smaller the amplitude value, the weaker the vibration of the upgoing wave when it reaches the detection point, that is, the smaller the intensity of the upgoing wave. The incident angle of the downgoing wave, the velocity of the rock formations on both sides of the interface, and the physical property data of the rock formations can be obtained, and the reflection angle of the upgoing wave can be obtained based on the variable offset VSP forward velocity model and the corresponding prediction model, and the amplitude value obtained from the shot gather record is placed in the trace record corresponding to the upgoing wave reflection angle in the variable offset VSP common reflection point gather. The variable offset VSP common reflection point gather is a seismic data gather that gathers together the variable offset VSP seismic signals from the same reflection point. In this gather, each trace represents the upgoing wave information under a specific reflection angle or incident angle. According to the extracted amplitude value and the corresponding reflection angle, this amplitude value can be placed in the trace record of the corresponding reflection angle in the variable offset VSP common reflection point gather. After placing all the corresponding amplitude values ​​of the upgoing wave in the trace record of the corresponding reflection angle in the variable offset VSP common reflection point gather, the variable offset VSP common reflection point gather can be subjected to dynamic correction. Dynamic correction can correct the arrival time of reflection waves from the same point on the same interface on each channel with different shot offsets to the vertical reflection time at the common center point, so as to ensure that the reflection waves of each channel can be superimposed in phase during superposition, which will not be elaborated here. After dynamic correction of the variable offset VSP common reflection point gather, because the seismic signal has been realigned according to the reflection point, the time window range of the variable offset VSP common reflection point gather can be determined. The upgoing wave signals on the variable offset VSP common reflection point gather can be observed, and the time window range of the variable offset VSP common reflection point gather can be determined based on the arrival time points and duration of these upgoing waves. Each time sampling point within the time window range of the variable offset VSP common reflection point gather corresponds to the upgoing wave information of a certain common reflection point. Based on the track records in the variable offset VSP common reflection point gather and the time window range of the variable offset VSP common reflection point gather, a schematic diagram of the variable offset VSP common reflection point gather can be drawn. Refer to Figure 7 As shown, Figure 7 The variable offset VSP common reflection point gathers obtained from Well A in the SG area were drawn.

[0097] S104: superimposing the trace records within the preset reflection angle range in the variable offset VSP common reflection point gather to obtain the variable offset VSP common reflection point angle gather.

[0098] In some embodiments, the reflection angle range in the variable offset VSP common reflection point gather can be divided; and the trace records in the same reflection angle range in the variable offset VSP common reflection point gather can be superimposed to obtain the variable offset VSP common reflection point angle gather.

[0099] The variable offset VSP common reflection point angle gather is obtained by superimposing the trace records within the same reflection angle range in the variable offset VSP common reflection point gather, which effectively reduces the amplitude of random noise in the variable offset VSP common reflection point gather data and improves the signal-to-noise ratio of the variable offset VSP common reflection point angle gather, which helps to more accurately identify the information of the underground strata.

[0100] Dividing the reflection angle range in the variable offset VSP common reflection point gather helps to analyze the underground structure more finely, especially when it comes to formation tilt, velocity changes, lithology differences, and possible fluid presence. For example, if the goal is to identify small changes in the formation interface, a narrower reflection angle range may be required; if the goal is to evaluate the underground velocity structure or perform AVO (amplitude variation with offset) analysis, a wider reflection angle range may be required to cover different incident angles. For another example, the more complex the geological structure (such as the presence of multiple inclined strata, faults, folds, etc.), a more detailed reflection angle division may be required to distinguish the responses of different geological bodies; areas with large underground velocity changes also require more detailed divisions, because velocity changes will directly affect the size of the reflection angle; when the data signal-to-noise ratio is high and the coverage is uniform, a finer reflection angle range can be divided; when the data quality is poor, a wider reflection angle range may need to be merged to improve the signal-to-noise ratio. Therefore, it is necessary to comprehensively consider factors such as research objectives, underground geological complexity, and data quality to divide. For example, based on the direct division of the incident angle, the reflection angle can be directly divided into several fixed ranges (0°-10°, 10°-20°, 20°-30°, 30°-40°, 40°-50°). For another example, based on the offset distance, indirect division can be performed, and a multi-classification model between the offset distance and the incident angle interval can be constructed. The horizontal distance between the actual shot point and the detection point, that is, the offset distance, can be used as the input of the multi-classification model to obtain the corresponding incident angle interval classification result output by the multi-classification model.

[0101] Seismic waves can be excited multiple times at the same shot point, and then the corresponding data in the variable offset VSP common reflection point gather can be overlaid multiple times. Multiple overlays can obtain more seismic information, increase data redundancy, and facilitate subsequent data processing and interpretation. The trace records in the same reflection angle range in the variable offset VSP common reflection point gather can be superimposed to obtain the variable offset VSP common reflection point angle gather. The stacking can be a simple arithmetic average or a more complex weighted stacking, depending on the data quality and research needs. Arithmetic mean stacking is the simplest and most common stacking method. All seismic traces in the selected gather can be taken at the same time sample point to generate a stacked seismic trace. Arithmetic mean stacking assumes that all seismic traces are statistically similar and that noise is random, so they can cancel each other out through averaging. Weighted stacking is a more complex stacking method that takes into account the differences between seismic traces and assigns a weight factor to each seismic trace. These weight factors can be determined based on a variety of factors, such as the signal-to-noise ratio, amplitude, phase difference, offset, etc. of the seismic trace, which will not be described here. For each reflection point, repeat the above process to generate a series of common reflection point angle gathers corresponding to different reflection angle ranges. Figure 8 As shown, Figure 8 The variable offset VSP common reflection point angle gathers obtained from Well A in the SG area were plotted.

[0102] It can be seen from the technical solution provided by the above-mentioned embodiment of this specification that the embodiment of this specification determines the range of the common reflection point facet based on the common reflection point interval; for each shot point and detection point pair, simulates the propagation path of the seismic wave; if the reflection point in the seismic wave propagation path is located within the range of the common reflection point facet, extracts the amplitude value of the seismic wave and places it in the corresponding track record in the variable offset VSP common reflection point gather; superimposes the track records within the preset reflection angle range of the variable offset VSP common reflection point gather to obtain the variable offset VSP common reflection point angle gather. Compared with the existing method, the angle gather conversion method of the embodiment of this specification does not go through the conversion from the offset domain to the incident angle domain, and can simulate the seismic wave propagation path corresponding to different shot points and different detection points to form a variable offset VSP common reflection point gather, and then extracts the corresponding amplitude value in the seismic wave record to directly form a variable offset VSP common reflection point angle gather with a high signal-to-noise ratio. The angle gather conversion method of the embodiment of this specification is more suitable for the conversion of common reflection point angle gathers with the characteristics of variable offset VSP data, and can provide accurate amplitude data that varies with angle for subsequent prestack inversion and reservoir prediction of variable offset VSP.

[0103] Based on the above angle gather conversion method, this specification also proposes an embodiment of an angle gather conversion device. Fig. 9 As shown, the angle gather conversion device 900 may specifically include the following modules:

[0104] A determination module 901 may be used to determine a range of a common reflection point bin based on a common reflection point interval;

[0105] A simulation module 902 may be used to simulate the propagation path of seismic waves for each shot point and receiver point pair;

[0106] The extraction module 903 may be used to extract the amplitude value of the seismic wave and place it in a corresponding trace record in the variable offset VSP common reflection point gather if the reflection point in the seismic wave propagation path is within the range of the common reflection point bin;

[0107] The stacking module 904 can be used to stack the trace records within a preset reflection angle range in the variable offset VSP common reflection point gather to obtain the variable offset VSP common reflection point angle gather.

[0108] In some embodiments, the simulation module 902 can be specifically used to establish a formation model based on zero-offset VSP data and logging data; the formation model is used to simulate the propagation path of seismic waves; the formation model includes a depth model, a variable-offset VSP forward velocity model and a density model.

[0109] In some embodiments, the simulation module 902 can also be used to match the depth of the logging data with the depth of the zero-offset VSP data to establish a depth model; to establish a variable-offset VSP forward velocity model based on the first arrival time data of the longitudinal wave in the zero-offset VSP data; and to resample the density curve in the logging data to establish a density model.

[0110] In some embodiments, the simulation module 902 can also be used to perform wave field separation on the seismic waves to obtain downgoing waves and upgoing waves; the downgoing waves represent downgoing seismic waves that propagate downward from the shot point excitation to the reflection point; the upgoing waves represent upgoing seismic waves that are reflected from the reflection point to the detection point.

[0111] In some embodiments, the simulation module 902 may be specifically used to determine the incident angle of the downgoing wave using a ray tracing method based on the depth model and the density model; determine the position of the reflection point and the reflection angle of the upgoing wave using a variable offset VSP forward velocity model based on the incident angle of the downgoing wave; and determine the propagation time of the upgoing wave using a variable offset VSP forward velocity model based on the reflection angle of the upgoing wave.

[0112] In some embodiments, the extraction module 903 can be specifically used to calculate the time point when the upgoing wave passes through the reflection point and reaches the detection point; extract the amplitude value of the upgoing wave at the time point from the shot gather record; obtain the reflection angle of the upgoing wave at the reflection point; and place the amplitude value in the trace record of the reflection angle of the variable offset VSP common reflection point trace gather.

[0113] In some embodiments, the stacking module 904 can be specifically used to divide the reflection angle range; stack the trace records within the same reflection angle range to obtain the variable offset VSP common reflection point angle trace gather.

[0114] It should be noted that the units, devices or modules described in the above embodiments can be implemented by computer chips or entities, or by products with certain functions. For the convenience of description, the above devices are described separately by functions divided into various modules. Of course, when implementing this specification, the functions of each module can be implemented in the same or more software and / or hardware, or the modules that implement the same function can be implemented by a combination of multiple sub-modules or sub-units. The device embodiments described above are only schematic. For example, the division of the units is only a logical function division. There may be other division methods in actual implementation, such as multiple units or components can be combined or integrated into another system, or some features can be ignored or not executed. Another point is that the mutual coupling or direct coupling or communication connection shown or discussed can be through some interfaces, indirect coupling or communication connection of devices or units, which can be electrical, mechanical or other forms.

[0115] As can be seen from the above, the angle gather conversion device provided in the embodiment of this specification can simulate the seismic wave propagation paths corresponding to different shot points and different detection points to form a common reflection point gather, and then extract the corresponding amplitude values ​​in the seismic wave record to directly form a high signal-to-noise ratio variable offset VSP common reflection point angle gather, which can provide accurate amplitude data that changes with angle for subsequent pre-stack inversion and reservoir prediction of the variable offset VSP.

[0116] The embodiment of the present specification also provides a computer device for an angle gather conversion method, including a processor and a memory for storing instructions executable by the processor. When the processor is implemented, the following steps can be performed according to the instructions: based on the common reflection point interval, the range of the common reflection point surface element is determined; for each shot point and detection point pair, the propagation path of the seismic wave is simulated; if the reflection point in the seismic wave propagation path is within the range of the common reflection point surface element, the amplitude value of the seismic wave is extracted and placed in the corresponding trace record in the variable offset VSP common reflection point gather; the trace records within the preset reflection angle range in the variable offset VSP common reflection point gather are superimposed to obtain the variable offset VSP common reflection point angle gather.

[0117] In order to complete the above instructions more accurately, refer to Fig.10As shown, the embodiment of this specification also provides another specific computer device 1000, wherein the computer device 1000 includes a network communication port 1001, a processor 1002 and a memory 1003, and the above structures are connected through internal cables so that each structure can perform specific data interaction.

[0118] The network communication port 1001 can be used to obtain zero-offset VSP data and logging data.

[0119] In this embodiment, the network communication port 1001 can be a virtual port that is bound to different communication protocols so that different data can be sent or received. For example, the network communication port can be a port responsible for web data communication, a port responsible for FTP data communication, or a port responsible for email data communication. In addition, the network communication port can also be a physical communication interface or communication chip. For example, it can be a wireless mobile network communication chip, such as GSM, CDMA, etc.; it can also be a Wifi chip; it can also be a Bluetooth chip.

[0120] The processor 1002 can be specifically used to determine the range of the common reflection point surface element based on the common reflection point interval; for each shot point and detection point pair, simulate the propagation path of the seismic wave; if the reflection point in the seismic wave propagation path is located within the range of the common reflection point surface element, extract the amplitude value of the seismic wave and place it in the corresponding track record in the variable offset VSP common reflection point gather; superimpose the track records within the preset reflection angle range in the variable offset VSP common reflection point gather to obtain the variable offset VSP common reflection point angle gather.

[0121] In this embodiment, the processor 1002 may be implemented in any appropriate manner. For example, the processor may take the form of a microprocessor or processor and a computer-readable medium storing a computer-readable program code (such as software or firmware) executable by the (micro)processor, a logic gate, a switch, an application specific integrated circuit (ASIC), a programmable logic controller, and an embedded microcontroller, etc. This specification does not limit this.

[0122] The memory 1003 may be specifically used to store corresponding instruction programs.

[0123] In this embodiment, the memory 1003 may include a volatile memory and a non-volatile memory. In a digital system, anything that can store binary data can be a memory; in an integrated circuit, a circuit with a storage function without a physical form is also called a memory, such as RAM, FIFO, etc.; in a computer system, a storage device with a physical form is also called a memory, such as a memory stick, TF card, etc.

[0124] Those skilled in the art will appreciate that embodiments of the present invention may be provided as methods, systems, or computer program products. Therefore, the present invention may take the form of a complete hardware embodiment, a complete software embodiment, or an embodiment combining software and hardware. Moreover, the present invention may take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0125] The present invention is described with reference to flowcharts and / or block diagrams of methods, devices (systems), and computer program products according to embodiments of the present invention. It should be understood that each process and / or block in the flowchart and / or block diagram, as well as the combination of processes and / or blocks in the flowchart and / or block diagram, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing device to produce a machine, so that the instructions executed by the processor of the computer or other programmable data processing device generate instructions for implementing the processes in the flowchart and / or block diagram. Figure 1 A process or multiple processes and / or boxes Figure 1 A device that provides the functions specified in a block or multiple blocks.

[0126] These computer program instructions may also be stored in a computer-readable memory capable of directing a computer or other programmable data processing device to operate in a specific manner, so that the instructions stored in the computer-readable memory produce an article of manufacture comprising an instruction device, which implements the process Figure 1 A process or multiple processes and / or boxes Figure 1 A function specified in one or more boxes.

[0127] These computer program instructions can also be loaded onto a computer or other programmable data processing device so that a series of operating steps are executed on the computer or other programmable device to produce a computer-implemented process, thereby providing instructions for implementing the process. Figure 1 A process or multiple processes and / or boxes Figure 1 A step that specifies a function in one or more boxes.

[0128] The specific embodiments described above further illustrate the objectives, technical solutions and beneficial effects of the present invention in detail. It should be understood that the above description is only a specific embodiment of the present invention and is not intended to limit the scope of protection of the present invention. Any modifications, equivalent substitutions, improvements, etc. made within the spirit and principles of the present invention should be included in the scope of protection of the present invention.

Claims

1. A method for converting angle gathers, characterized in that: include: Based on the common reflection point interval, determining the range of the common reflection point surface element; For each shot point and receiver point pair, simulate the propagation path of seismic waves; If the reflection point in the seismic wave propagation path is located within the range of the common reflection point bin, extract the amplitude value of the seismic wave and place it in the corresponding trace record in the variable offset VSP common reflection point gather; The trace records within the preset reflection angle range in the variable offset VSP common reflection point gather are superimposed to obtain the variable offset VSP common reflection point angle gather.

2. The method according to claim 1, characterized in that The method further comprises: A formation model is established based on zero-offset VSP data and logging data; the formation model is used to simulate the propagation path of seismic waves; The formation model includes a depth model, a variable offset VSP forward velocity model and a density model.

3. The method according to claim 2, characterized in that The step of establishing a formation model based on zero-offset VSP data and logging data includes: Match the depth of the logging data with the depth of the zero-offset VSP data to establish a depth model; Based on the P-wave first arrival time data in zero-offset VSP data, a variable-offset VSP forward velocity model is established. Resample the density curve in the logging data and establish a density model.

4. The method according to claim 1, characterized in that: The method further comprises: The seismic waves are subjected to wave field separation to obtain downgoing waves and upgoing waves; the downgoing waves represent downgoing seismic waves that propagate downward from the shot point excitation to the reflection point; the upgoing waves represent upgoing seismic waves that are reflected from the reflection point to the detection point.

5. The method according to claim 4, characterized in that The blast point is placed on the ground; the blast point is used to excite the downgoing wave; the detection point is placed in the well, and each detection point is preset with a detector; the detector is used to detect the upgoing wave reflected by the reflection point.

6. The method according to claim 4, characterized in that For each shot point and receiver point pair, simulating the propagation path of the seismic wave includes: Based on the depth model and the density model, determining the incident angle of the downgoing wave using a ray tracing method; Based on the incident angle of the downgoing wave, a variable offset VSP forward velocity model is used to determine the position of the reflection point and the reflection angle of the upgoing wave; Based on the reflection angle of the upgoing wave, the travel time of the upgoing wave is determined using a variable offset VSP forward velocity model.

7. The method according to claim 4, characterized in that If the reflection point in the seismic wave propagation path is located within the range of the common reflection point bin, extracting the amplitude value of the seismic wave and placing it in the trace record of the corresponding reflection angle in the variable offset VSP common reflection point gather, comprises: Calculate the time point when the upgoing wave passes through the reflection point and reaches the detection point; extracting the amplitude value of the upgoing wave at the time point from the shot gather record; Acquire the reflection angle of the upgoing wave at the reflection point; The amplitude value is placed in the trace record of the reflection angle in the variable offset VSP common reflection point gather.

8. The method according to claim 4, characterized in that The trace records within the preset reflection angle range of the stacked variable offset VSP common reflection point gather include: Divide the reflection angle range; The trace records within the same reflection angle range are superimposed to obtain the variable offset VSP common reflection point angle gather.

9. An angle gather conversion device, characterized in that: The device comprises: A determination module, used to determine the range of the common reflection point surface element based on the common reflection point interval; A simulation module, used to simulate the propagation path of seismic waves for each shot point and receiver point pair; An extraction module, configured to extract the amplitude value of the seismic wave and place it in a corresponding trace record in a variable offset VSP common reflection point gather if the reflection point in the seismic wave propagation path is within the range of the common reflection point bin; The stacking module is used to stack the trace records within the preset reflection angle range in the variable offset VSP common reflection point gather to obtain the variable offset VSP common reflection point angle gather.

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

Images