Method, device and medium for obtaining near-surface seismic attenuation factor

Abstract

Embodiments of the present application relate to a kind of near-surface seismic attenuation factor acquisition method, device, equipment and medium, according to the near-surface stratification result of field surface investigation, determine the velocity layer of each excitation point in the excitation well and each receiving point of equidistant arrangement in receiving well;From the multi-channel seismic data corresponding to each excitation point in the corresponding velocity layer, extract the first seismic data corresponding to each receiving point in the corresponding velocity layer and the second seismic data corresponding to any other velocity layer;According to the first seismic data and the second seismic data corresponding to each receiving point, determine the initial seismic attenuation factor corresponding to each receiving point based on spectral ratio method, and then calculate the final seismic attenuation factor;According to the final seismic attenuation factor corresponding to each receiving point in each velocity layer and the depth of receiving point, determine the variation curve of near-surface seismic attenuation factor, can obtain more accurate Q value.

Description

Technical Field

[0001] This invention relates to the field of geophysical exploration technology, and in particular to a method, apparatus, equipment and medium for obtaining near-surface seismic attenuation factors. Background Technology

[0002] The seismic attenuation quality factor Q is an important parameter describing the absorption and attenuation of seismic waves. The near-surface loose medium, with its loose structure and severe weathering and erosion, has a particularly important impact on the propagation of seismic waves. Therefore, accurate estimation of the near-surface Q value is of great significance for improving the imaging resolution of seismic data through inverse Q filtering.

[0003] Traditional methods for surveying Q-values ​​in the field generally include refraction logging, single-well micrologging, dual-well micrologging, and multi-well micrologging. Then, based on the survey data, an equivalent Q-value above the high-velocity top interface of the surface survey is obtained using peak frequency shift or spectral ratio methods. However, for the section where the low-velocity zone changes drastically from the surface to the high-velocity top interface, especially when the near-surface velocity exhibits continuously changing medium characteristics, this method cannot accurately describe the Q-value variation trend of each segment.

[0004] Therefore, there is an urgent need for a method that can accurately describe the continuous variation of Q values ​​from the surface to the top of the high-velocity layer, in order to achieve a detailed description of the near-surface. Summary of the Invention

[0005] The embodiments of the present invention provide a method, apparatus, device and medium for obtaining near-surface seismic attenuation factor, so as to solve the technical problem of inaccurate calculation of near-surface Q value.

[0006] In a first aspect, embodiments of the present invention provide a method for obtaining near-surface seismic attenuation factors, comprising: determining near-surface stratification results based on field surface survey data, wherein the near-surface stratification results include different velocity layers and the corresponding thicknesses of different velocity layers; determining the velocity layers in which each excitation point in an excitation well and each receiving point in a receiving well are located based on the near-surface stratification results, wherein each receiving point is equally spaced from the bottom to the top of the receiving well; acquiring multichannel seismic data corresponding to each excitation point in each velocity layer based on each receiving point in the receiving well; extracting a first seismic data corresponding to each receiving point in the corresponding velocity layer and a second seismic data corresponding to any other velocity layer from the multichannel seismic data corresponding to each excitation point in the corresponding velocity layer; determining an initial seismic attenuation factor corresponding to each receiving point based on the spectral ratio method based on the first and second seismic data corresponding to each receiving point; determining a final seismic attenuation factor corresponding to each receiving point based on the initial seismic attenuation factor calculated for each of the multichannel seismic data corresponding to the corresponding velocity layer; and determining a variation curve of the near-surface seismic attenuation factor based on the final seismic attenuation factor corresponding to each receiving point in each velocity layer and the depth of the receiving point.

[0007] In some embodiments, before determining the velocity layer in which each excitation point in the excitation well and each receiving point in the receiving well are located based on the near-surface stratification results, the method further includes: determining the well depths of the excitation well and the receiving well based on the near-surface stratification results; setting excitation points from the bottom to the wellhead of the excitation well according to the well depths, and setting receiving points at equal intervals from the bottom to the wellhead of the receiving well according to the well depths.

[0008] In some embodiments, determining the initial seismic attenuation factor for each receiving point based on the spectral ratio method according to the first and second seismic data corresponding to each receiving point includes: obtaining the first frequency amplitude spectrum of the first seismic data and the second frequency amplitude spectrum of the second seismic data corresponding to the receiving point of the corresponding velocity layer; determining the spectral logarithm between the first and second frequency amplitude spectra, and performing linear fitting based on the spectral logarithm; obtaining the slope of the straight line, and determining the initial seismic attenuation factor for the corresponding receiving point based on the slope.

[0009] In some embodiments, obtaining the first frequency amplitude spectrum of the first seismic data corresponding to the corresponding receiver point of the corresponding velocity layer and the second frequency amplitude spectrum of the second seismic data includes: picking up the first arrival time for each seismic data in the multi-channel seismic data and obtaining the first complete waveform after the first arrival time; performing frequency domain transformation on the complete waveform of the first seismic data and the complete waveform of the second seismic data respectively to obtain the corresponding first frequency amplitude spectrum and second frequency amplitude spectrum.

[0010] In some embodiments, determining the final seismic attenuation factor for each receiver point based on the initial seismic attenuation factor calculated for each of the multichannel seismic data corresponding to the corresponding velocity layer includes: for each receiver point in the corresponding velocity layer, determining the travel time from each excitation point in the corresponding velocity layer to the upper interface, and the travel time to the receiver point; determining the difference between the travel time to the upper interface and the travel time to the receiver point, and performing curve fitting between the travel time difference and the corresponding initial seismic attenuation factor; when the travel time difference is zero, determining the final seismic attenuation factor based on the fitted curve.

[0011] 6. The method according to claim 3, characterized in that the calculation formula based on the spectral ratio method is as follows:

[0012]

[0013] Where t3 represents the travel time from the excitation point to the receiver point at the same velocity layer, t2 represents the travel time from the excitation point to the upper interface, t1 represents the travel time from the upper interface to the receiver point corresponding to the second seismic data, A0 represents the first frequency amplitude value corresponding to the first seismic data, A represents the second frequency amplitude value corresponding to the second seismic data, Q represents the initial seismic attenuation factor, C is a constant, and f represents the frequency.

[0014] In some embodiments, the second seismic data is surface seismic data collected at a receiving point located at the wellhead of the receiving well.

[0015] Secondly, embodiments of the present invention provide a device for obtaining near-surface seismic attenuation factors, comprising: a first determining module, configured to determine near-surface stratification results based on field surface survey data, wherein the near-surface stratification results include different velocity layers and the corresponding thicknesses of different velocity layers; a second determining module, configured to determine the velocity layers in which each excitation point in an excitation well and each receiving point in a receiving well are located based on the near-surface stratification results, wherein each receiving point is equally spaced from the bottom to the top of the receiving well; a data acquisition module, configured to collect multichannel seismic data corresponding to the excitation of each excitation point in each velocity layer based on each receiving point in the receiving well; and a data extraction module, configured to extract data from each excitation point in the corresponding velocity layer. From the corresponding multichannel seismic data, the first seismic data corresponding to each receiver point in the corresponding velocity layer and the second seismic data corresponding to any other velocity layer are extracted; a first calculation module is used to determine the initial seismic attenuation factor corresponding to each receiver point based on the first and second seismic data corresponding to each receiver point using the spectral ratio method; a second calculation module is used to determine the final seismic attenuation factor corresponding to each receiver point based on the initial seismic attenuation factor calculated for each of the multichannel seismic data corresponding to the corresponding velocity layer; a third determination module is used to determine the variation curve of the near-surface seismic attenuation factor based on the final seismic attenuation factor corresponding to each receiver point in each velocity layer and the receiver point depth.

[0016] Thirdly, embodiments of the present invention provide an electronic device, including a processor, a communication interface, a memory, and a communication bus, wherein the processor, the communication interface, and the memory communicate with each other through the communication bus; the memory is used to store computer programs; and the processor is used to execute the program stored in the memory to implement the steps of the method for obtaining the near-surface seismic attenuation factor as described in any one of the first aspects.

[0017] Fourthly, embodiments of the present invention provide a computer-readable storage medium having a computer program stored thereon, which, when executed by a processor, implements the steps of the method for obtaining the near-surface seismic attenuation factor as described in any of the first aspects.

[0018] The embodiments of the present invention have the following beneficial effects:

[0019] The dual-well microseismic technology employed has receiving points set at equal intervals throughout the entire well section, enabling continuous sampling. Based on the near-surface stratification results, the velocity layer in which each receiving point is located is determined, and the Q value corresponding to each receiving point is calculated layer by layer. This allows for an accurate description of the continuous variation of Q value from the surface to the top interface of the high-velocity layer, thus improving the accuracy of near-surface Q value surveys. Attached Figure Description

[0020] The accompanying drawings, which are incorporated in and form part of this specification, illustrate embodiments consistent with the invention and, together with the description, serve to explain the principles of the invention.

[0021] To more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the drawings used in the description of the embodiments or the prior art will be briefly introduced below. Obviously, for those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0022] Figure 1 A flowchart illustrating a method for obtaining near-surface seismic attenuation factors according to an embodiment of the present invention;

[0023] Figure 2 This is a micro-logging data interpretation diagram provided in an embodiment of the present invention;

[0024] Figure 3 This is a schematic diagram of a dual-well micro-logging system provided in an embodiment of the present invention;

[0025] Figure 4 A schematic diagram of multichannel seismic data provided in an embodiment of the present invention;

[0026] Figure 5 for Figure 1 A detailed flowchart of step S105 in the illustrated embodiment;

[0027] Figure 6 This is a schematic diagram of the first complete waveform after arrival, provided in an embodiment of the present invention;

[0028] Figure 7 A schematic diagram of a frequency amplitude spectrum provided in an embodiment of the present invention;

[0029] Figure 8 This is a schematic diagram of the frequency amplitude spectrum comparison between a certain channel in a well and a surface channel, provided as an embodiment of the present invention.

[0030] Figure 9 for Figure 1 A detailed flowchart of step S106 in the illustrated embodiment;

[0031] Figure 10 An excitation well depth-Q value curve of a receiving channel is provided for an embodiment of the present invention;

[0032] Figure 11 A curve showing the relationship between t2-t3 and Q value provided in an embodiment of the present invention;

[0033] Figure 12 This is a comparison chart of the Q values ​​obtained by a conventional method and the method of this embodiment of the invention;

[0034] Figure 13 A schematic diagram of a device for obtaining near-surface seismic attenuation factors provided in an embodiment of the present invention;

[0035] Figure 14 This is a schematic diagram of the hardware structure of an electronic device provided in an embodiment of the present invention. Detailed Implementation

[0036] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of the present invention.

[0037] During the propagation of seismic waves, the energy of seismic waves will be severely attenuated due to the non-perfectly elastic characteristics of the geological medium, and the corresponding high-frequency components will be severely missing. This will greatly reduce the resolution and imaging accuracy of seismic data. This is especially true for loose near-surface media, which are subject to severe weathering and erosion due to their loose structure.

[0038] The seismic attenuation quality factor Q is an important parameter used to describe the absorption and attenuation of seismic waves. It reflects the strength of the absorption and attenuation of seismic waves by the subsurface medium, serves as the basis for quantitative evaluation of seismic wave absorption and attenuation characteristics, and is also an important parameter for oil and gas detection and reservoir description.

[0039] Extensive practical experience shows that the significant differences between near-surface absorption attenuation and deep strata absorption attenuation are mainly manifested in the following ways:

[0040] (1) The near-surface medium is highly heterogeneous, and its absorption and attenuation effects are stronger than those of the deep strata, resulting in significant changes in the waveform and spectrum of seismic waves. The near-surface lithology changes drastically, and the velocity gradient, absorption and attenuation gradient, and lateral velocity changes are all greater than those of the deep strata.

[0041] (2) The excitation and reception effects are closely related to the lithology and the compaction of the strata. The lateral variation of the near-surface strata is large, and the excitation conditions vary greatly. The uneven distribution leads to significant differences in the energy and frequency of the excitation seismic wavelets, resulting in poor consistency.

[0042] As exploration progresses, oil companies demand increasingly higher precision from their exploration targets, requiring the differentiation of small geological features such as thin interbedded layers. This necessitates wide bandwidth and high resolution seismic data. However, as seismic waves propagate through strata, their energy is absorbed and attenuated, leading to frequency reduction and phase distortion. Compared to deep rock formations, the near-surface medium is porous, and its absorption and attenuation significantly reduce the bandwidth and resolution of seismic data. Therefore, obtaining the attenuation factor Q value of the near-surface medium is extremely important.

[0043] Currently, the more traditional methods for investigating Q-values ​​in the field generally include the refraction method, single-well micrologging method, dual-well micrologging method, and multi-well micrologging method. For example, the dual-well micrologging method involves conducting investigations using two shallow wells, one as the excitation well and the other as the receiving well. The two wells are at the same depth. The excitation is performed at certain depth intervals in the order "from the bottom of the well to the top of the well". There is one geophone at the top of the receiving well and one geophone at the bottom of the well. The geophone at the bottom of the well is inserted into the bottom of the receiving well to ensure that the geophone is tightly coupled with the formation at the bottom of the well. The surface geophone and the geophone in the well receive the data simultaneously.

[0044] However, regardless of whether the peak frequency shift method or the spectral ratio method is ultimately used, the final result is an equivalent Q value above the high-velocity top interface of the surface survey. This means that for the section where the low-velocity zone changes drastically from the surface to the high-velocity top interface, especially when the near-surface velocity exhibits continuously changing medium characteristics, it is impossible to accurately describe the Q value change trend of each segment.

[0045] To address the aforementioned technical problems, the technical concept of this invention is as follows: receiving signals at certain intervals throughout the entire well section, waves from the same velocity layer can be received in each velocity layer. In this way, the Q value of each trace can be calculated layer by layer using the seismic wave information from different velocity layers based on the spectral ratio method.

[0046] Figure 1 A flowchart illustrating a method for obtaining near-surface seismic attenuation factors provided in an embodiment of the present invention is shown below. Figure 1 As shown, the method for obtaining the near-surface seismic attenuation factor includes:

[0047] Step S101: Determine the near-surface stratification results based on the field surface survey data. The near-surface stratification results include different velocity layers and the corresponding thicknesses of different velocity layers.

[0048] Specifically, detectors can be installed in a fan shape at the wellhead of the excitation well. Excitation occurs inside the well, and the data is received at the wellhead to obtain surface survey data, also known as micrologging data. This micrologging data is then interpreted to obtain different velocity layers near the surface and their corresponding thicknesses. For example... Figure 2 This invention provides a micro-logging data interpretation diagram, such as... Figure 2As shown, it is divided into 5 velocity layers, where V0 = 515 m / s, thickness H0 = 2.6 m, V1 = 902 m / s, thickness H1 = 5.7 m, V2 = 2725 m / s, thickness H2 = 14.9 m, V3 = 3305 m / s, thickness H3 = 16.3 m, and V4 = 4140 m / s.

[0049] Step S102: Determine the velocity layers where each excitation point in the excitation well and each receiving point in the receiving well are located based on the near-surface stratification results. The receiving points are set at equal intervals from the bottom of the receiving well to the wellhead.

[0050] Figure 3 This is a schematic diagram of a dual-well micro-logging system provided in an embodiment of the present invention, as shown below. Figure 3 As shown, the system includes an excitation well and a receiving well. An excitation point (seismic source) is set in the excitation well, and each excitation point can be excited by an electric spark device. Receiving points (including bottom hole detectors, middle hole detectors, and surface detectors) are set at equal intervals throughout the entire section of the receiving well, thereby realizing continuous sampling from the bottom of the well to the wellhead. Based on the thickness of each velocity layer and the positions of the excitation point and each receiving point, the velocity layer in which each excitation point and each receiving point are located can be determined.

[0051] In some embodiments, before step S102, the method further includes: determining the depth of the excitation well and the receiving well based on the near-surface stratification results; setting excitation points from the bottom of the excitation well to the wellhead based on the well depth; and setting receiving points at equal intervals from the bottom of the receiving well to the wellhead based on the well depth.

[0052] Typically, the excitation well and the receiving well have the same depth and are about 15-20m above the top boundary of the high-velocity layer. Therefore, after obtaining the different velocity layers and their thicknesses according to step S101, these velocity layers can be further divided into low-velocity layers, decreasing-velocity layers, and high-velocity layers. Generally, 400m / s-800m / s is considered a low-velocity layer, 800m / s-1800m / s is considered a decreasing-velocity layer, and more than 1800m / s is considered a high-velocity layer. However, the surface velocities vary greatly. For example, in farmland areas with water table conditions, 1600m / s-1700m / s is generally considered a high-velocity layer velocity. In Gobi gravel areas, 2200m / s-4000m / s is generally considered a high-velocity layer velocity. In mountainous areas with exposed bedrock, high-velocity velocities can reach over 5000m / s.

[0053] In this embodiment, V0 is identified as the low-velocity layer, V1 and V2 as the deceleration layers, and V3 as the high-velocity layer. The top interface of the high-velocity layer is calculated to be approximately 24m using H0+H1+H2, indicating a well depth of approximately 40m. After determining the well depth, considering the construction difficulty and the relatively stable Q-value in deeper layers, the excitation point density of the excitation well gradually increases from deep to shallow. For example, the excitation point density is 1m in deep layers and 0.5m in shallow layers. Considering the continuous sampling of the receiving well, detectors are installed at equal intervals from the bottom to the top of the receiving well.

[0054] It should be noted that the equally spaced geophones in the receiving well facilitate the calculation of parameters such as distance and time difference at different velocity layers, which can facilitate quality control during field implementation. In addition, the uniform injection of sand and soil (as similar as possible to the rock type at the receiving well) into the receiving well ensures the coupling effect of the geophones in the receiving well.

[0055] Step S103: Collect multichannel seismic data corresponding to the excitation point in each velocity layer based on each receiving point in the receiving well.

[0056] Specifically, the excitation points in the excitation well are excited sequentially from deep to shallow. All detectors in the receiving well acquire multichannel seismic data corresponding to each excitation point. Based on the velocity layer where each excitation point is located, multiple multichannel seismic data corresponding to each velocity layer can be determined, such as... Figure 4 This is a schematic diagram of multichannel seismic data provided in an embodiment of the present invention. The horizontal axis represents the record obtained at the detector position (i.e., each channel), and the vertical axis represents time.

[0057] Step S104: Extract the first seismic data corresponding to each receiver point in the corresponding velocity layer and the second seismic data corresponding to any other velocity layer from the multichannel seismic data corresponding to each trigger point in the corresponding velocity layer.

[0058] Specifically, from Figure 4 In the multichannel seismic data shown, seismic data from each detector (i.e., each channel) located in the corresponding velocity layer is extracted, and one channel of seismic data from any other velocity layer is obtained to facilitate the subsequent calculation of the Q value using the spectral ratio method.

[0059] In some embodiments, the second seismic data is surface seismic data collected at a receiving point located at the wellhead of the receiving well. Specifically, typically, one well seismic data and one surface seismic data are extracted, with the excitation point being excited from deep to shallow. The well seismic data located at the same velocity layer as the excitation point is the pre-attenuation data, and the surface seismic data is the post-attenuation data.

[0060] Step S105: Based on the first and second seismic data corresponding to each receiving point, determine the initial seismic attenuation factor corresponding to each receiving point using the spectral ratio method.

[0061] Specifically, from Figure 4 From the multichannel seismic data, the seismic data of a certain channel in the well and the surface channel are extracted. The Q value of the corresponding receiver point is determined based on the spectral ratio method. Similarly, based on the multiple multichannel seismic data of the corresponding velocity layer, multiple Q values ​​of the corresponding receiver point can be calculated.

[0062] Step S106: Determine the final seismic attenuation factor for each receiver point in the corresponding velocity layer based on the initial seismic attenuation factor corresponding to each of the multichannel seismic data in the corresponding velocity layer.

[0063] Specifically, for each receiver point, the final Q value is calculated based on the initial Q value determined from multiple multichannel seismic data within that velocity layer. For example, suppose velocity layer A has two excitation points, excitation point 1 and excitation point 2, from deep to shallow, and three receiver points, receiver point 1, receiver point 2, and receiver point 3, from deep to shallow. First, the first multichannel seismic data corresponding to excitation point 1 and the second multichannel seismic data corresponding to excitation point 2 are acquired. Then, the single-channel seismic data and surface seismic data corresponding to receiver points 1, 2, and 3 are extracted from the first multichannel seismic data corresponding to excitation point 1. Finally, based on the single-channel seismic data and surface seismic data of receiver point 1, the initial Q value corresponding to receiver point 1 is calculated using the spectral ratio method. 11 The initial Q value corresponding to receiver point 2 is calculated based on the single-channel seismic data and surface-channel seismic data of receiver point 2 using the spectral ratio method. 12 The initial Q value corresponding to receiver point 3 is calculated based on the single-channel seismic data and surface-channel seismic data of receiver point 3 using the spectral ratio method. 13 Similarly, from the second multi-channel seismic data corresponding to trigger point 2, the single-channel seismic data and surface seismic data corresponding to receiver points 1, 2, and 3 are extracted; then, based on the single-channel seismic data and surface seismic data of receiver point 1, the initial Q value corresponding to receiver point 1 is calculated using the spectral ratio method. 21 The initial Q value corresponding to receiver point 2 is calculated based on the single-channel seismic data and surface-channel seismic data of receiver point 2 using the spectral ratio method. 22 The initial Q value corresponding to receiver point 3 is calculated based on the single-channel seismic data and surface-channel seismic data of receiver point 3 using the spectral ratio method. 23 Value; then, according to Q 11 Q 21 Determine the final Q value corresponding to receiver point 1, based on Q 12 Q 22 Determine the final Q value corresponding to receiver point 2, based on Q 13 Q 23 Determine the final Q value corresponding to receiver point 3.

[0064] Step S107: Determine the variation curve of the near-surface seismic attenuation factor based on the final seismic attenuation factor and the depth of the receiving point for each receiving point in each velocity layer.

[0065] Specifically, the receiving points in the receiving well are set at equal intervals, making it easy to determine the depth of each receiving point. Then, based on the final Q value of each receiving point obtained in step S106, the entire Q value curve from deep to shallow can be drawn.

[0066] The near-surface seismic attenuation factor acquisition method provided in this embodiment adopts dual-well micrologging technology. The receiving well has receiving points set at equal intervals throughout its entire section, which enables continuous sampling. Based on the near-surface stratification results, the velocity layer in which each receiving point is located is determined, and the Q value corresponding to each receiving point is calculated layer by layer. This allows for an accurate description of the continuous change relationship of Q value from the surface to the top interface of the high-velocity layer, thereby improving the accuracy of near-surface Q value surveys.

[0067] Figure 5 for Figure 1 A detailed flowchart of step S105 in the illustrated embodiment is shown below. Figure 5 As shown, based on the aforementioned embodiments, step S105 includes the following steps:

[0068] Step S1051: Obtain the first frequency amplitude spectrum of the first seismic data corresponding to the corresponding receiver point of the corresponding velocity layer, and the second frequency amplitude spectrum of the second seismic data.

[0069] Step S1052: Obtain the logarithm of the ratio of the first frequency amplitude spectrum to the second frequency amplitude spectrum, and perform linear fitting based on the logarithm of the ratio.

[0070] Step S1053: Obtain the slope of the fitted straight line and determine the initial seismic attenuation factor corresponding to the receiving point based on the slope.

[0071] Specifically, the spectral ratio method calculates the Q value by analyzing the changes in the amplitude spectrum. The attenuation law of the formation for the signal follows an exponential relationship, and the calculation formula is as shown in (1).

[0072]

[0073] Where A0 is the amplitude before attenuation; A is the amplitude after attenuation; Q is the seismic attenuation quality factor; f represents the frequency in Hertz (Hz); and t is the travel time difference in seconds (s).

[0074] Taking the logarithm of equation (1) gives:

[0075]

[0076] Equation (2) represents the ratio of the amplitude spectra of the signals before and after absorption. By fitting a straight line to the equation and obtaining the slope of the line, the quality factor Q of the seismic attenuation stratum can be obtained. The calculation formula is shown in (3).

[0077]

[0078] Where k represents the slope of the linear ratio of the signal amplitude before and after absorption by the formation. In other words, the Q value can be calculated based on the amplitude ratio before and after attenuation. In this embodiment, based on the characteristics of seismic wave absorption and attenuation in the formation, there is no absorption and attenuation in the same velocity layer because the velocity and medium are the same (ideal state). However, there is absorption and attenuation in different velocity layers. The initial Q value of the receiving point corresponding to the wellbore is calculated by extracting the logarithm of the ratio of the frequency amplitude spectra of two seismic traces (usually borehole traces and surface traces, with the borehole trace being the initial trace and the surface trace being the attenuated trace).

[0079] In some embodiments, step S1051 includes: picking the first arrival time of each seismic data in the multi-channel seismic data and determining the first complete waveform after the first arrival; performing frequency domain transformation on the complete waveform of the first seismic data and the complete waveform of the second seismic data respectively to obtain the first frequency amplitude spectrum and the second frequency amplitude spectrum.

[0080] Specifically, for Figure 4 The multichannel seismic data shown is processed by first-arrival time picking, and then by undercutting at a complete waveform position after the first-arrival position of each channel. Between the first-arrival position and the undercut position, a complete waveform at the starting position of each channel is obtained, as shown below. Figure 6 This is a schematic diagram of the first complete waveform after arrival, provided in this embodiment of the invention. Then, [the following is a description of the waveform]. Figure 6 The two seismic data streams shown are subjected to frequency domain transformations, such as Fourier transforms or generalized S-transforms, to obtain frequency-amplitude spectra, resulting in... Figure 7 The diagram shown is a schematic representation of a frequency amplitude spectrum. Figure 7 The frequency amplitude spectrum of single-channel seismic data corresponding to an excitation point of 120m and a receiving point of 115m.

[0081] Figure 8 This invention provides a schematic diagram of the spectral comparison of the frequency amplitude spectra of the borehole channel and the surface channel, as shown in the embodiment of the invention. Figure 8 As shown, after obtaining the frequency amplitude spectrum of the in-well channel and the frequency amplitude spectrum of the surface channel, the amplitude values ​​of the same frequency are compared and the logarithm is taken to obtain the curve of the spectrum comparison logarithm. The curve is fitted with a straight line to obtain the slope of the straight line, and then an initial Q value of the receiving point corresponding to the in-well channel is obtained according to formula (3).

[0082] Figure 9 for Figure 1A detailed flowchart of step S106 in the illustrated embodiment is shown below. Figure 9 As shown, step S106 includes the following steps:

[0083] Step S1061: For each receiving point in the corresponding velocity layer, determine the travel time from each excitation point in the corresponding velocity layer to the upper interface, and the travel time to the receiving point.

[0084] Step S1062: Determine the difference between the travel time to the upper interface and the travel time to the receiving point, and perform curve fitting on the difference between the travel times and the corresponding initial seismic attenuation factor.

[0085] Step S1063: When the difference in travel time is zero, determine the final seismic attenuation factor based on the fitted curve.

[0086] Taking velocity layer A as an example, for receiver point 1, the initial Q calculated based on the first multi-channel seismic data from trigger point 1 is determined. 11 Obtain the travel time from excitation point 1 to the upper interface, and the travel time from excitation point 1 to receiver point 1, and determine the difference between the two as t. 11 The initial Q calculated based on the second multi-channel seismic data from trigger point 2 is determined. 12 Obtain the travel time from excitation point 2 to the upper interface, and the travel time from excitation point 2 to receiver point 1, and determine the difference between the two as t. 12 In other words, for receiver point 1, (t) can be obtained. 11 Q 11 ), (t 12 Q 12 A binomial fit is performed on the curve, and the value at which t2-t3=0 is obtained to determine the final Q value of receiver point 1; similarly, for receiver point 2, the Q value can be obtained ((t 21 Q 21 ), (t 22 Q 22 )) , thus determining the final Q value of receiver point 2. For receiver point 3, ((t) can be obtained. 31 Q 31 ), (t 22 Q 32 The final Q value of receiving point 3 is determined.

[0087] In some embodiments, the calculation formula based on the spectral ratio method is as follows:

[0088]

[0089]

[0090] Where t3 represents the travel time from the excitation point to the receiver point at the same velocity layer, t2 represents the travel time from the excitation point to the upper interface, t1 represents the travel time from the upper interface to the receiver point corresponding to the second seismic data, A0 represents the first frequency amplitude value corresponding to the first seismic data, A represents the second frequency amplitude value corresponding to the second seismic data, Q represents the initial seismic attenuation factor, C is a constant, and f represents the frequency.

[0091] Specifically, formula (4) is for the spectral ratio method of any two velocity layers, and for a certain excitation point of a receiver point, from such... Figure 4 Extracting the receiver and attenuation channels from the multichannel seismic data shown, we can determine t1+t2, t3, A, and A0. Substituting these values ​​into formula (4), we can calculate the Q value. By analogy, we can determine the Q values ​​corresponding to multiple excitation points and fit the results as shown. Figure 10 The excitation well depth-Q value curve is shown; then, by further transforming formula (4), formula (5) is obtained. From formula (5), it can be seen that the final Q value can be obtained when t2 = t3.

[0092] For example, suppose we use Figure 2 In a certain receiving channel (initial channel) of the 3305 m / s velocity layer, there are 15 excitation points corresponding to the same velocity layer (located at 24 m-38 m from the wellhead, with one sampling point every 1 m). According to formula (4), the excitation well depth-Q value curve fitted by these 15 sampling points is obtained, and the relationship curve between t2-t3 and Q value can be fitted as follows: Figure 10 , Figure 11 .like Figure 11 When t2-t3 is 0, the Q value at this receiving point is 6.13. Similarly, the Q values ​​for all receiving points in the 24m-38m section can be derived. Likewise, by changing to another velocity layer, the Q value of that other velocity layer can be calculated, ultimately obtaining a Q value curve for the entire well section.

[0093] Based on the aforementioned embodiments, by obtaining the first frequency amplitude spectrum of the first seismic data corresponding to the corresponding receiver point of the corresponding velocity layer, and the second frequency amplitude spectrum of the second seismic data; determining the spectral logarithm between the first and second frequency amplitude spectra, and performing linear fitting based on the spectral logarithm; obtaining the slope of the straight line, and determining the initial seismic attenuation factor of the corresponding receiver point based on the slope, the initial Q value of each trace is calculated layer by layer; then, for each receiver point in the corresponding velocity layer, the travel time from each excitation point in the corresponding velocity layer to the upper interface, and the travel time to the receiver point are determined; the difference between the travel time to the upper interface and the travel time to the receiver point is determined, and curve fitting is performed on the difference in travel time and the corresponding initial seismic attenuation factor; when the difference in travel time is zero, the final seismic attenuation factor is determined based on the fitted curve, thus realizing the calculation of the final Q value of each receiver point based on multiple trace seismic data in the layer.

[0094] To further understand the embodiments of the present invention, the present invention will now be described in detail.

[0095] Step 1: Obtain micrologging data from the geophone installed at the wellhead of the excitation well. Based on the micrologging data, determine the depth of the excitation well and the receiving well for conducting near-surface attenuation factor Q value surveys, as well as the precise surface stratification results at that point, i.e., the velocity and thickness data of each layer.

[0096] The second step is to design excitation points with gradually increasing density from deep to shallow according to the well depth, and set receiving points at equal intervals according to the well depth to achieve one sampling point at the wellhead and one sampling point at the bottom of the well, thus achieving continuous sampling from the wellhead to the bottom of the well.

[0097] Step 3: Based on the surface layering results, determine the velocity layer corresponding to each channel in the receiving well and the velocity layer where each excitation point in the excitation well is located.

[0098] Step 4: The excitation well is activated from deep (bottom) to shallow (head), and each geophone in the well receives the data simultaneously to obtain multichannel seismic data for each shot and determine the multichannel seismic data corresponding to each velocity layer.

[0099] Step 5: Pick the first arrival time of the acquired multi-channel seismic data, pick the undercut at the complete waveform position after the first arrival position of each channel, and obtain a complete waveform at the starting position of each channel between the first arrival position and the undercut position.

[0100] Step 6: Perform frequency domain transformation on each complete waveform obtained from the starting position to obtain the frequency-amplitude spectrum.

[0101] Step 7: Based on the frequency amplitude spectrum of the corresponding receiving point in the corresponding velocity layer in the well and the spectral logarithm of the frequency amplitude spectrum of the surface channel, perform linear fitting, calculate the slope of the line, and then calculate the initial Q value of each receiving point.

[0102] Step 8: Based on the multiple initial Q values ​​calculated from multiple multichannel seismic data in the corresponding velocity layer for each receiver point, perform binomial fitting to obtain the final Q value.

[0103] Step 9: Based on the calculated final Q value at each receiving point, plot the entire Q value curve from dark to light.

[0104] Figure 12 This is a comparison chart of Q values ​​obtained by a conventional method and the method of this embodiment of the invention. Figure 10 As can be seen, the conventional method calculates an equivalent Q value at the top interface of the high-velocity layer, while this embodiment calculates the Q value of each receiving point layer by using detectors that are equally spaced throughout the entire well section of the receiving well. This allows for a more accurate description of the curve of Q value variation with the formation.

[0105] Figure 13 This is a schematic diagram of a device for obtaining near-surface seismic attenuation factors provided in an embodiment of the present invention, as shown below. Figure 13 As shown, the device includes:

[0106] The first determining module 1301 is used to determine the near-surface stratification results based on field surface survey data, wherein the near-surface stratification results include different velocity layers and the corresponding thicknesses of different velocity layers; the second determining module 1302 is used to determine the velocity layers in which each excitation point in the excitation well and each receiving point in the receiving well are located based on the near-surface stratification results, wherein each receiving point is equally spaced from the bottom to the top of the receiving well; the data acquisition module 1303 is used to collect multichannel seismic data corresponding to the excitation of each excitation point in each velocity layer based on each receiving point in the receiving well; the data extraction module 1304 is used to extract phase data from the multichannel seismic data corresponding to each excitation point in the corresponding velocity layer. The system comprises: a first seismic data source corresponding to each receiver point in the velocity layer and a second seismic data source corresponding to any other velocity layer; a first calculation module 1305, used to determine the initial seismic attenuation factor corresponding to each receiver point based on the first and second seismic data source corresponding to each receiver point using the spectral ratio method; a second calculation module 1306, used to determine the final seismic attenuation factor corresponding to each receiver point based on the initial seismic attenuation factor calculated for each of the multiple seismic data source sources corresponding to the corresponding velocity layer; and a third determination module 1307, used to determine the variation curve of the near-surface seismic attenuation factor based on the final seismic attenuation factor corresponding to each receiver point in each velocity layer and the receiver point depth.

[0107] In some embodiments, the second determining module 1302 is further configured to: determine the depth of the excitation well and the receiving well based on the near-surface stratification results; set an excitation point from the bottom of the excitation well to the wellhead based on the well depth; and set receiving points at equal intervals from the bottom of the receiving well to the wellhead based on the well depth.

[0108] In some embodiments, the first calculation module 1305 is specifically used to: obtain the first frequency amplitude spectrum of the first seismic data corresponding to the corresponding receiver point of the corresponding velocity layer, and the second frequency amplitude spectrum of the second seismic data; determine the spectral logarithm between the first frequency amplitude spectrum and the second frequency amplitude spectrum, and perform linear fitting based on the spectral logarithm; obtain the slope of the straight line, and determine the initial seismic attenuation factor of the corresponding receiver point based on the slope.

[0109] In some embodiments, the first calculation module 1305 is specifically used to: pick up the first arrival time for each of the multi-channel seismic data and obtain the first complete waveform after the first arrival time; and perform frequency domain transformation on the complete waveform of the first seismic data and the complete waveform of the second seismic data respectively to obtain the corresponding first frequency amplitude spectrum and second frequency amplitude spectrum.

[0110] In some embodiments, the second calculation module 1306 is specifically configured to: for each receiving point in the corresponding velocity layer, determine the travel time from each excitation point in the corresponding velocity layer to the upper interface, and the travel time to the receiving point; determine the difference between the travel times of each excitation point to the upper interface and the receiving point, and perform curve fitting between the difference in travel times and the initial seismic attenuation factor; when the difference in travel times is zero, determine the final seismic attenuation factor based on the fitted curve.

[0111] In some embodiments, the calculation formula based on the spectral ratio method is as follows:

[0112]

[0113] Where t3 represents the travel time from the excitation point to the receiver point in the same velocity layer, t2 represents the travel time from the excitation point to the upper interface, t1 represents the travel time from the upper interface to the receiver point corresponding to the second seismic data, A0 represents the first amplitude value corresponding to the first seismic data, A represents the second amplitude value corresponding to the second seismic data, Q represents the initial seismic attenuation factor, C is a constant, and f represents the frequency.

[0114] In some embodiments, the second seismic data is surface seismic data collected by a geophone installed at the wellhead of the receiving well.

[0115] Those skilled in the art will clearly understand that, for the sake of convenience and brevity, the specific working process and corresponding beneficial effects of the near-surface seismic attenuation factor acquisition device described above can be found in the corresponding process in the aforementioned method example, and will not be repeated here.

[0116] Figure 14 This is a schematic diagram of the hardware structure of an electronic device provided in an embodiment of the present invention, such as... Figure 14 As shown, the electronic device includes: a processor 1401, a communication interface 1402, a memory 1403, and a communication bus 1404, wherein the processor 1401, the communication interface 1402, and the memory 1403 communicate with each other through the communication bus 1404.

[0117] Memory 1403 is used to store computer programs;

[0118] In one embodiment of this application, when the processor 1401 executes the program stored in the memory 1403, it implements the steps of the method for obtaining the near-surface seismic attenuation factor provided in any of the foregoing method embodiments.

[0119] The electronic device provided in this application embodiment has a similar implementation principle and technical effect to the above embodiments, and will not be described again here.

[0120] The aforementioned memory 1403 may be an electronic memory such as flash memory, EEPROM (Electrically Erasable Programmable Read-Only Memory), EPROM, hard disk, or ROM. Memory 1403 has storage space for program code used to perform any of the method steps described above. For example, the storage space for program code may include individual program codes for implementing the various steps in the methods described above. This program code can be read from or written to one or more computer program products. These computer program products include program code carriers such as hard disks, optical discs (CDs), memory cards, or floppy disks. Such computer program products are typically portable or fixed storage units. The storage unit may have storage segments or storage spaces arranged similarly to the memory 1403 in the aforementioned electronic device. The program code may, for example, be compressed in a suitable form. Typically, the storage unit includes programs for performing the method steps according to the embodiments of this application, i.e., code that can be read by a processor such as 1401, which, when run by the electronic device, causes the electronic device to perform the various steps in the methods described above.

[0121] Embodiments of this application also provide a computer-readable storage medium. The computer-readable storage medium stores a computer program, which, when executed by a processor, implements the steps of the method for obtaining the near-surface seismic attenuation factor as described above.

[0122] The computer-readable storage medium may be included in the device / apparatus described in the above embodiments; or it may exist independently and not assembled into the device / apparatus. The computer-readable storage medium carries one or more programs that, when executed, implement the method according to the embodiments of this application.

[0123] According to embodiments of this application, the computer-readable storage medium can be a non-volatile computer-readable storage medium, such as including but not limited to: portable computer disks, hard disks, random access memory (RAM), read-only memory (ROM), erasable programmable read-only memory (EPROM or flash memory), portable compact disk read-only memory (CD-ROM), optical storage devices, magnetic storage devices, or any suitable combination thereof. In this application, the computer-readable storage medium can be any tangible medium containing or storing a program that can be used by or in conjunction with an instruction execution system, apparatus, or device.

[0124] It should be noted that, in this document, relational terms such as "first" and "second" are used merely to distinguish one entity or operation from another, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. Without further limitations, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes said element.

[0125] The above description is merely a specific embodiment of this application, enabling those skilled in the art to understand or implement this application. Various modifications to these embodiments will be readily apparent to those skilled in the art, and the general principles defined herein may be implemented in other embodiments without departing from the spirit or scope of this application. Therefore, this application is not to be limited to the embodiments shown herein, but is to be accorded the widest scope consistent with the principles and novel features claimed herein.

Claims

1. A method for obtaining near-surface seismic attenuation factors, characterized in that, include: The near-surface stratification results are determined based on field surface survey data, and the near-surface stratification results include different velocity layers and the corresponding thicknesses of different velocity layers. Based on the near-surface stratification results, the velocity layers in which each excitation point in the excitation well and each receiving point in the receiving well are located are determined, and each receiving point is set at equal intervals from the bottom of the receiving well to the wellhead. Based on each receiving point in the receiving well, multichannel seismic data corresponding to the excitation point in each velocity layer is collected. From the multichannel seismic data corresponding to each trigger point in the corresponding velocity layer, extract the first seismic data corresponding to each receiver point in the corresponding velocity layer and the second seismic data corresponding to any other velocity layer; Based on the first and second seismic data corresponding to each receiving point, the initial seismic attenuation factor corresponding to each receiving point is determined using the spectral ratio method. Based on the initial seismic attenuation factor calculated for each of the multichannel seismic data corresponding to the corresponding velocity layer, the final seismic attenuation factor corresponding to each receiving point is determined. Based on the final seismic attenuation factor and receiver depth corresponding to each receiver point in each velocity layer, the variation curve of the near-surface seismic attenuation factor is determined.

2. The method according to claim 1, characterized in that, Before determining the velocity layers where each excitation point in the excitation well and each receiving point in the receiving well are located based on the near-surface stratification results, the method further includes: The depths of the excitation well and the receiving well are determined based on the near-surface stratification results. An excitation point is set from the bottom of the excitation well to the wellhead according to the well depth, and a receiving point is set at equal intervals from the bottom of the receiving well to the wellhead according to the well depth.

3. The method according to claim 1 or 2, characterized in that, The step of determining the initial seismic attenuation factor for each receiving point based on the first and second seismic data corresponding to each receiving point, using the spectral ratio method, includes: Obtain the first frequency amplitude spectrum of the first seismic data corresponding to the corresponding receiver point of the corresponding velocity layer, and the second frequency amplitude spectrum of the second seismic data. Determine the spectral logarithm between the first frequency amplitude spectrum and the second frequency amplitude spectrum, and perform linear fitting based on the spectral logarithm; The slope of the straight line is obtained, and the initial seismic attenuation factor of the corresponding receiving point is determined based on the slope.

4. The method according to claim 3, characterized in that, The process of obtaining the first frequency amplitude spectrum of the first seismic data corresponding to the corresponding receiver point of the corresponding velocity layer, and the second frequency amplitude spectrum of the second seismic data, includes: The first arrival time is picked up for each of the multiple seismic data channels, and the first complete waveform after the first arrival time is obtained; Frequency domain transformations were performed on the complete waveforms of the first and second seismic data to obtain the corresponding first and second frequency amplitude spectra.

5. The method according to claim 3, characterized in that, The step of determining the final seismic attenuation factor for each receiving point based on the initial seismic attenuation factor calculated for each of the multichannel seismic data corresponding to the corresponding velocity layer includes: For each receiving point in the corresponding velocity layer, determine the travel time from each excitation point in the corresponding velocity layer to the upper interface, and the travel time to the receiving point. The difference between the travel time to the upper interface and the travel time to the receiving point is determined, and the difference between the travel time and the corresponding initial seismic attenuation factor are curve-fitted. When the difference in travel time is zero, the final seismic attenuation factor is determined based on the fitted curve.

6. The method according to claim 5, characterized in that, The calculation formula based on the spectral ratio method is as follows: Where t3 represents the travel time from the excitation point to the receiver point at the same velocity layer, t2 represents the travel time from the excitation point to the upper interface, t1 represents the travel time from the upper interface to the receiver point corresponding to the second seismic data, A0 represents the first frequency amplitude value corresponding to the first seismic data, A represents the second frequency amplitude value corresponding to the second seismic data, Q represents the initial seismic attenuation factor, C is a constant, and f represents the frequency.

7. The method according to claim 1 or 2, characterized in that, The second seismic data is the surface seismic data collected at the receiving point set at the wellhead of the receiving well.

8. A device for obtaining near-surface seismic attenuation factors, characterized in that, include: The first determining module is used to determine the near-surface stratification results based on field surface survey data. The near-surface stratification results include different velocity layers and the thicknesses corresponding to different velocity layers. The second determining module is used to determine the velocity layer in which each excitation point in the excitation well and each receiving point in the receiving well are located based on the near-surface stratification results. The receiving points are set at equal intervals from the bottom of the receiving well to the wellhead. The data acquisition module is used to collect multichannel seismic data corresponding to the excitation point in each velocity layer based on each receiving point in the receiving well; The data extraction module is used to extract the first seismic data corresponding to each receiver point in the corresponding velocity layer and the second seismic data corresponding to any other velocity layer from the multi-channel seismic data corresponding to each excitation point in the corresponding velocity layer. The first calculation module is used to determine the initial seismic attenuation factor for each receiving point based on the spectral ratio method, according to the first and second seismic data corresponding to each receiving point. The second calculation module is used to determine the final seismic attenuation factor for each receiving point based on the initial seismic attenuation factor calculated for each of the multichannel seismic data corresponding to the corresponding velocity layer. The third determination module is used to determine the variation curve of the near-surface seismic attenuation factor based on the final seismic attenuation factor and the depth of the receiving point for each receiving point in each velocity layer.

9. An electronic device, characterized in that, It includes a processor, a communication interface, a memory, and a communication bus, wherein the processor, the communication interface, and the memory communicate with each other through the communication bus; Memory, used to store computer programs; When a processor executes a program stored in a memory, it implements the steps of the method for obtaining the near-surface seismic attenuation factor as described in any one of claims 1-7.

10. A computer-readable storage medium having a computer program stored thereon, characterized in that, When the computer program is executed by the processor, it implements the steps of the method for obtaining the near-surface seismic attenuation factor as described in any one of claims 1-7.

Images