Acquisition parameter determination method and device of seismological observation system

Abstract

The invention provides a method and a device for determining acquisition parameters of a seismological observation system. The corresponding method comprises the following steps: constructing a three-dimensional model of a target work area according to a digital elevation model of the target work area, historical acquisition parameters of the seismological observation system and stratigraphic distribution data; generating a plurality of imaging profiles corresponding to a plurality of acquisition schemes based on the three-dimensional model; wherein the acquisition schemes are in one-to-one correspondence with imaging profiles; and determining current acquisition parameters of the target work area according to the plurality of imaging profiles. The method effectively avoids the defects of large calculation amount, long time consumption, high consumption and the like of an existing seismic observation system acquisition parameter determination method, realizes rapid and accurate design of the seismic observation system acquisition parameters, shortens the seismic observation system design period, reduces the acquisition cost, improves the effective implementation efficiency of seismic acquisition, and has good application prospects. And guarantee is provided for subsequent seismic data processing, interpretation and inversion.

Description

Technical Field

[0001] This application belongs to the technical field of oil and gas exploration, especially the technical field of seismic data acquisition for oil and gas exploration. Specifically, it relates to a method and device for determining acquisition parameters of a seismic observation system. Background Art

[0002] The existing method for determining acquisition parameters of an observation system needs to first use wave equation forward modeling to obtain seismic observation data, and then use depth migration for imaging. It has a large amount of calculation and a long time consumption, and is suitable for the design of long-period observation systems. However, most seismic acquisition observation systems have a short design cycle and high efficiency requirements, so they often can only perform two-dimensional tests. Summary of the Invention

[0003] This invention belongs to the technical field of seismic data processing. One object of this invention is to quickly and accurately obtain the acquisition parameters of an optimal observation system, providing a strong guarantee for the efficient implementation of subsequent seismic acquisition.

[0004] Another object of this invention is to provide a device for determining acquisition parameters of a seismic observation system. Still another object of this invention is to provide an electronic device, which includes a memory and a processor. The memory stores a computer program, and when the processor executes the computer program, the steps of the above method for determining acquisition parameters of a seismic observation system are implemented. Still another object of this invention is to provide a readable medium, on which a computer program is stored, and when the computer program is executed by a processor, the steps of the above method for determining acquisition parameters of a seismic observation system are implemented.

[0005] To solve the technical problems in the background art of this application, this invention provides the following technical solutions:

[0006] In the first aspect, this invention provides a method for determining acquisition parameters of a seismic observation system, including:

[0007] Construct a three-dimensional model of the target work area according to the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data;

[0008] Generate multiple imaging profiles corresponding to multiple acquisition plans based on the three-dimensional model; where the acquisition plan and the imaging profile are in one-to-one correspondence;

[0009] Determine the current acquisition parameters of the target work area according to the multiple imaging profiles.

[0010] In an embodiment of this invention, the constructing a three-dimensional model of the target work area according to the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data includes:

[0011] Construct the surface structure model of the target work area according to the digital elevation model and the historical acquisition parameters;

[0012] Construct the stratigraphic model of the target work area according to the stratigraphic distribution data;

[0013] Construct the three-dimensional model according to the surface structure model and the stratigraphic model.

[0014] In an embodiment of the present invention, the stratigraphic distribution data includes: seismic interpretation horizon data, seismic facies, and fault data; constructing the stratigraphic model of the target work area according to the stratigraphic distribution data includes:

[0015] Determine the seismic facies according to the seismic data of the target work area;

[0016] Construct the stratigraphic model according to the seismic interpretation horizon data, the seismic facies, and the fault data.

[0017] In an embodiment of the present invention, a method for determining the acquisition parameters of a seismic observation system further includes:

[0018] Generate the plurality of acquisition schemes according to the geological target requirements of the target work area.

[0019] In an embodiment of the present invention, generating a plurality of imaging profiles corresponding to the plurality of acquisition schemes based on the three-dimensional model includes:

[0020] Initialize the acquisition parameters corresponding to the plurality of acquisition schemes to determine the bin size, receiver line spacing, coverage, maximum offset, and aspect ratio of each acquisition scheme;

[0021] Generate the imaging profile corresponding to each acquisition scheme based on the three-dimensional model according to the bin size, receiver line spacing, coverage, maximum offset, and aspect ratio of each acquisition scheme.

[0022] In an embodiment of the present invention, generating the imaging profile corresponding to each acquisition scheme based on the three-dimensional model according to the bin size, receiver line spacing, coverage, maximum offset, and aspect ratio of each acquisition scheme includes:

[0023] Generate the reflection coefficient model and the point spread function corresponding to each acquisition scheme according to the bin size, receiver line spacing, coverage, maximum offset, and aspect ratio of each acquisition scheme;

[0024] Generate the imaging profile corresponding to each acquisition scheme according to the reflection coefficient model and the point spread function corresponding to each acquisition scheme.

[0025] In one embodiment of the present invention, determining the current acquisition parameters of the target work area according to the plurality of imaging profiles includes:

[0026] Comparing the plurality of imaging profiles to select the optimal imaging profile;

[0027] Determining the current acquisition parameters according to the acquisition scheme corresponding to the optimal imaging profile.

[0028] In a second aspect, the present invention provides an acquisition parameter determination device for a seismic observation system, and the device includes:

[0029] A three-dimensional model construction module, configured to construct a three-dimensional model of the target work area according to the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data;

[0030] An imaging profile generation module, configured to generate a plurality of imaging profiles corresponding to a plurality of acquisition schemes based on the three-dimensional model; wherein, the acquisition scheme and the imaging profile are in one-to-one correspondence;

[0031] A current acquisition parameter determination module, configured to determine the current acquisition parameters of the target work area according to the plurality of imaging profiles.

[0032] In one embodiment of the present invention, the three-dimensional model construction module includes:

[0033] A surface structure model construction unit, configured to construct a surface structure model of the target work area according to the digital elevation model and the historical acquisition parameters;

[0034] A formation model construction unit, configured to construct a formation model of the target work area according to the formation distribution data;

[0035] A three-dimensional model construction unit, configured to construct the three-dimensional model according to the surface structure model and the formation model.

[0036] In one embodiment of the present invention, the formation distribution data includes: seismic interpretation horizon data, seismic facies, and fault data; the formation model construction unit includes:

[0037] A seismic facies determination unit, configured to determine the seismic facies according to the seismic data of the target work area;

[0038] A formation model construction subunit, configured to construct the formation model according to the seismic interpretation horizon data, the seismic facies, and the fault data.

[0039] In one embodiment of the present invention, an acquisition parameter determination device for a seismic observation system further includes:

[0040] A plurality of acquisition scheme generation modules, configured to generate the plurality of acquisition schemes according to the geological target requirements of the target work area.

[0041] In an embodiment of the present invention, the imaging profile generation module includes:

[0042] An acquisition parameter initialization unit, configured to initialize the acquisition parameters corresponding to the plurality of acquisition schemes to determine the bin size, receiver line spacing, coverage, maximum offset, and aspect ratio of each acquisition scheme;

[0043] An imaging profile generation unit, configured to generate the imaging profile corresponding to each acquisition scheme based on the three-dimensional model according to the bin size, receiver line spacing, coverage, maximum offset, and aspect ratio of each acquisition scheme.

[0044] In an embodiment of the present invention, the imaging profile generation unit includes:

[0045] A function model generation unit, configured to generate the reflection coefficient model and the point spread function corresponding to each acquisition scheme according to the bin size, receiver line spacing, coverage, maximum offset, and aspect ratio of each acquisition scheme;

[0046] An imaging profile generation subunit, configured to generate the imaging profile corresponding to each acquisition scheme according to the reflection coefficient model and the point spread function corresponding to each acquisition scheme.

[0047] In an embodiment of the present invention, the current acquisition parameter determination module includes:

[0048] An optimal imaging profile selection unit, configured to compare the plurality of imaging profiles to select the optimal imaging profile;

[0049] A current acquisition parameter determination unit, configured to determine the current acquisition parameters according to the acquisition scheme corresponding to the optimal imaging profile.

[0050] In a third aspect, the present invention provides a computer program product, including a computer program / instructions, which when executed by a processor, implement the steps of a method for determining acquisition parameters of a seismic observation system.

[0051] In a fourth aspect, the present invention provides an electronic device, including a memory, a processor, and a computer program stored on the memory and executable on the processor, and the processor implements the steps of the method for determining acquisition parameters of a seismic observation system when executing the program.

[0052] In a fifth aspect, the present invention provides a computer-readable storage medium, on which a computer program is stored, and the computer program implements the steps of the method for determining acquisition parameters of a seismic observation system when executed by a processor.

[0053] As can be seen from the above description, the embodiments of the present invention provide a method and apparatus for determining acquisition parameters of a seismic observation system. The corresponding method for determining acquisition parameters of a seismic observation system includes: First, a three-dimensional model of the target work area is constructed according to the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data; Then, a plurality of imaging profiles corresponding to a plurality of acquisition schemes are generated based on the three-dimensional model; where the acquisition scheme and the imaging profile are in one-to-one correspondence; Finally, the current acquisition parameters of the target work area are determined according to the plurality of imaging profiles.

[0054] The corresponding apparatus for determining acquisition parameters of a seismic observation system includes: a three-dimensional model construction module, configured to construct a three-dimensional model of the target work area according to the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data; an imaging profile generation module, configured to generate a plurality of imaging profiles corresponding to a plurality of acquisition schemes based on the three-dimensional model; where the acquisition scheme and the imaging profile are in one-to-one correspondence; a current acquisition parameter determination module, configured to determine the current acquisition parameters of the target work area according to the plurality of imaging profiles.

[0055] The method and apparatus for determining acquisition parameters of a seismic observation system provided by the embodiments of the present invention effectively avoid the deficiencies of the existing methods for determining acquisition parameters of a seismic observation system, such as large computational amount, long time consumption, and high cost. It realizes the rapid and accurate design of the acquisition parameters of the seismic observation system, shortens the design cycle of the seismic observation system, thereby reducing the acquisition cost, improving the efficiency of effective implementation of seismic acquisition, and providing guarantee for subsequent seismic data processing, interpretation, and inversion. BRIEF DESCRIPTION OF THE DRAWINGS

[0056] In order to more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the following will briefly introduce the drawings required for the description of the embodiments or the prior art. Obviously, the drawings in the following description are some embodiments of the present invention. For those of ordinary skill in the art, other drawings can be obtained based on these drawings without creative efforts.

[0057] Figure 1 It is a schematic flowchart of a method for determining acquisition parameters of a seismic observation system in an embodiment of the present invention;

[0058] Figure 2 It is a schematic flowchart of step 100 of the method for determining acquisition parameters of a seismic observation system in an embodiment of the present invention;

[0059] Figure 3 It is a schematic flowchart of step 102 of the method for determining acquisition parameters of a seismic observation system in an embodiment of the present invention;

[0060] Figure 4Another schematic flowchart of the method for determining acquisition parameters of the seismic observation system in the embodiments of the present invention;

[0061] Figure 5 Schematic flowchart of step 200 of the method for determining acquisition parameters of the seismic observation system in the embodiments of the present invention;

[0062] Figure 6 Schematic flowchart of step 202 of the method for determining acquisition parameters of the seismic observation system in the embodiments of the present invention;

[0063] Figure 7 Schematic flowchart of step 300 of the method for determining acquisition parameters of the seismic observation system in the embodiments of the present invention;

[0064] Figure 8 Schematic flowchart of the method for determining acquisition parameters of the seismic observation system in the specific embodiments of the present invention;

[0065] Figure 9 Schematic diagram of the high-precision three-dimensional model in the specific embodiments of the present invention;

[0066] Figure 10 Schematic diagram of the observation system obtained by initializing the acquisition parameters of the seismic observation system in the specific embodiments of the present invention;

[0067] Figure 11 Schematic comparison diagram of the imaging profile and the velocity model in the specific embodiments of the present invention;

[0068] Figure 12 Block diagram of the device for determining acquisition parameters of the seismic observation system in the specific embodiments of the present invention;

[0069] Figure 13 Schematic diagram of the structure of the electronic device in the embodiments of the present invention. Specific embodiments

[0070] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings in the embodiments of the present invention. Obviously, the described embodiments are some, but not all, of the embodiments of the present invention. All other embodiments obtained by those of ordinary skill in the art without creative efforts based on the embodiments of the present invention fall within the scope of protection of the present invention.

[0071] Those skilled in the art should understand that the embodiments of the present invention can be provided as a method, a system, or a computer program product. Therefore, the present invention can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Moreover, the present invention can 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.) that contain computer-usable program code.

[0072] It should be noted that the terms "including" and "having" in the description and claims of this application and any variations thereof in the above-mentioned drawings are intended to cover non-exclusive inclusion. For example, a process, method, system, product, or device that includes a series of steps or units does not necessarily have to be limited to those steps or units clearly listed, but may include other steps or units that are not clearly listed or are inherent to these processes, methods, products, or devices. Without conflict, the embodiments in this application and the features in the embodiments can be combined with each other. The following will refer to the drawings and combine the embodiments to detail this application.

[0073] In the technical solution of this application, the acquisition, storage, use, processing, etc. of data all comply with the relevant regulations of laws and regulations.

[0074] Embodiment 1:

[0075] A seismic observation system is used to describe the arrangement mode of the relative spatial position relationship between the excitation point and the receiver point arrangement in seismic exploration. Different seismic exploration methods adopt different observation systems.

[0076] From the perspective of the type of received seismic waves, the observation system can be divided into a refraction wave observation system, a longitudinal wave observation system, a transverse wave observation system, and a converted wave observation system; from the perspective of the observation space, it can be divided into a two-dimensional seismic observation system and a three-dimensional seismic observation system; from the perspective of the observation method, it can be divided into a simple continuous observation system and a multiple coverage observation system. If it is desired to make the observation system optimal, then it is necessary to specify the optimal acquisition parameters. However, the existing method for determining the optimal acquisition parameters has a large amount of calculation and a long time consumption, and is suitable for the design of long-cycle observation systems. Most seismic acquisition observation systems have a short design cycle and high efficiency requirements, that is, the existing methods are difficult to meet the needs.

[0077] For the above reasons, the embodiments of the present invention provide a specific implementation manner of a method for determining the acquisition parameters of a seismic observation system. Refer to Figure 1 , which specifically includes the following content:

[0078] Step 100: Construct a three-dimensional model of the target work area according to the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data;

[0079] Step 200: Generate multiple imaging profiles corresponding to multiple acquisition schemes based on the 3D model; wherein, the acquisition schemes and the imaging profiles are in one-to-one correspondence.

[0080] Step 300: Determine the current acquisition parameters of the target work area according to the multiple imaging profiles.

[0081] As can be seen from the above description, the embodiment of the present invention provides a method for determining the acquisition parameters of a seismic observation system, including: First, construct a 3D model of the target work area according to the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data; then, generate multiple imaging profiles corresponding to multiple acquisition schemes based on the 3D model; wherein, the acquisition schemes and the imaging profiles are in one-to-one correspondence; finally, determine the current acquisition parameters of the target work area according to the multiple imaging profiles.

[0082] The method for determining the acquisition parameters of the seismic observation system provided by the embodiment of the present invention effectively avoids the deficiencies of the existing method for determining the acquisition parameters of the seismic observation system, such as large calculation amount, long time consumption, and high cost, realizes the rapid and accurate design of the acquisition parameters of the seismic observation system, shortens the design cycle of the seismic observation system, thereby reducing the acquisition cost, improving the efficiency of the effective implementation of seismic acquisition, and providing guarantee for subsequent seismic data processing, interpretation, and inversion.

[0083] Embodiment 2:

[0084] It can be understood that the digital elevation model (DEM) in step 100 is a digital map used to describe the elevation information of the earth's surface. By collecting a large amount of terrain data, including height, slope, aspect, etc., and then representing these data in a digital way, a model of the terrain surface is formed.

[0085] Preferably, the DEM can be represented using a raster data structure, that is, the surface of the target work area is divided into a series of grid cells, and the elevation value at each grid cell is stored. In this way, the elevation information at any position on the earth's surface can be obtained through the DEM.

[0086] Specifically, a digital elevation model can be generated through the following steps. Use remote sensing technology (such as satellite images, aerial images) to obtain elevation data of the surface of the target work area. At the same time, elevation data of some control points can be collected through ground surveys (such as total stations, GPS). Preprocess the collected remote sensing data, including image correction, geometric correction, etc. At the same time, register the ground survey data with the remote sensing data to make them spatially corresponding. According to the collected elevation data, interpolation is performed within the entire area to fill in the missing ground elevation data. Preferably, the interpolation methods include inverse distance weighted interpolation, triangulation interpolation, Kriging interpolation, etc. Smooth and filter the interpolated elevation data to remove noise and outliers, making the digital elevation model more realistic and accurate. Store the processed digital elevation model data in raster form and generate an elevation map or a 3D model.

[0087] Stratigraphic distribution data refers to the data that describes the distribution and characteristics of underground strata. These data are used to study the formation and reservoir conditions of oil and gas reservoirs and to determine exploration targets and development plans. Stratigraphic distribution data can be obtained through the following channels.

[0088] Stratigraphic distribution map: The stratigraphic distribution map shows the horizontal and vertical distribution of different strata underground. It can display information such as the thickness, dip angle, and variation trend of different strata, providing clues to the potential locations and formation conditions of oil and gas reservoirs for exploration personnel.

[0089] Drilling records: Drilling records are the records of underground stratigraphic information obtained during the drilling process. It includes drilling core samples, logging curves (such as resistivity, acoustic velocity, natural gamma radiation, etc.), drilling fluid data, etc. By analyzing the drilling records, important parameters such as the lithology, porosity, and permeability of the strata can be obtained.

[0090] Seismic data: Seismic data is the underground stratigraphic information collected through seismic exploration. Seismic exploration uses the propagation characteristics of seismic waves underground to obtain information such as the velocity, density, and interface position of underground strata. By interpreting and processing seismic data, the structure and properties of the strata can be revealed, providing important references for oil and gas exploration.

[0091] Porosity and permeability data: Porosity and permeability are important parameters that describe the ability of reservoir rocks (such as sandstone, carbonate rock) to store and flow oil and gas. These data can be obtained through methods such as core analysis and logging curve interpretation.

[0092] Geological model: A geological model is an underground geological simulation model established based on stratigraphic distribution data. It includes the geometric shape of the strata, property distribution, lithology model, etc. Geological models can be used to predict the distribution, shape, and reserves of oil and gas reservoirs and to guide exploration and development decisions.

[0093] The acquisition and analysis of formation distribution data require the combination of various technical means and data processing methods, including geological surveys, logging interpretation, seismic interpretation, geological modeling, etc. These data are crucial for the success of oil exploration and development.

[0094] The seismic imaging profile in step 200 is a commonly used method in seismic exploration to obtain information on the underground formation structure. By analyzing the propagation and reflection characteristics of seismic waves underground, as well as the reflection and refraction phenomena of seismic waves at different underground formation interfaces, information such as the distribution, velocity, and lithology of underground formations can be obtained.

[0095] Existing technologies generally rely on the three-dimensional model of the target work area, obtain seismic observation data through forward modeling of the wave equation, and then use depth migration for imaging. Specifically, based on the established three-dimensional geological model, the wave equation is used for forward modeling. The wave equation describes the propagation and reflection process of seismic waves underground. Through numerical methods (such as the finite difference method, finite element method, etc.), the propagation of seismic waves in the three-dimensional geological model is simulated to obtain the propagation process of seismic waves underground and the observation data. The seismic observation data obtained from the forward modeling are processed and preprocessed, including removing noise, correcting data, extracting the arrival time of seismic waves, etc. Finally, the depth migration method (depth migration is a seismic data processing method based on the wave equation, which reconstructs the position and structure of the reflection interface of underground formations by inverting the travel time and amplitude information in seismic data) is used to image the processed seismic observation data. It can be seen that the above process is relatively complex and time-consuming.

[0096] In some embodiments of the present invention, referring to Figure 2 , step 100 includes:

[0097] Step 101: Construct the surface structure model of the target work area according to the digital elevation model and the historical acquisition parameters;

[0098] Specifically, based on the geological structure characteristics of the target area, a complex undulating surface model is established using the digital elevation model (DEM) input in Step 1 and the data of the previous acquisition observation system (SPS).

[0099] Step 102: Construct the formation model of the target work area according to the formation distribution data;

[0100] The previous seismic interpretation horizon and fault data are used to establish horizon and fault models respectively, and the contact and cutting relationships between the surface, horizons, and faults are analyzed to construct the formation model.

[0101] Step 103: Construct the three-dimensional model according to the surface structure model and the formation model.

[0102] In some embodiments of the present invention, the formation distribution data includes: seismic interpretation horizon data, seismic facies, and fault data;

[0103] It can be understood that in the field of oil and gas exploration technology, seismic interpretation horizon data is very important, and it can provide information about the underground structure and properties of potential oil and gas reservoirs. Preferably, the seismic interpretation horizon data includes the following aspects: Oil and gas reservoir identification: By seismic horizon interpretation, the location, thickness, and morphology of potential oil and gas reservoirs can be determined. The reflection characteristics and amplitude changes of seismic waves can be used to identify potential reservoirs, such as sandstone, carbonate rock, or shale, etc. Reservoir property evaluation: Seismic horizon interpretation can provide information about reservoir properties, such as porosity, permeability, saturation, etc. By analyzing the changes in seismic wave velocity, frequency, and amplitude, the physical properties of the reservoir can be inferred, and its potential oil and gas reserves can be evaluated. Underground structure analysis: Seismic horizon interpretation can reveal the characteristics of underground structures, such as faults, folds, and basins, etc. By analyzing the reflection characteristics and fault displacements on seismic profiles, the geometric morphology and movement history of structural features can be determined, providing important references for oil and gas exploration. Directional drilling decision-making: The results of seismic horizon interpretation can be used to determine the drilling target and path. By analyzing the location, morphology, and thickness of the reservoir, the optimal drilling location and direction can be determined, improving the success rate of oil and gas exploration.

[0104] Seismic facies is the sum of the manifestations of sedimentary facies on seismic profiles. It is the seismic characteristics formed by the sedimentary environment (such as marine or continental facies). It refers to a seismic reflection unit within a certain area, and the seismic attribute parameters within this unit are different from those of adjacent units. It represents the lithologic combination, bedding, and sedimentary characteristics of the sediments that generate its reflections.

[0105] Geologically, sedimentary facies are divided according to sedimentary physical, biological, and chemical characteristics, etc. Seismically, sedimentary facies are mainly divided according to reflection wave characteristics, that is, seismic stratigraphic parameters. The latter mainly includes: the shape of seismic facies, internal structure, top and bottom contact relationships, amplitude, continuity, apparent period, interval velocity, and lateral changes in reflection characteristics, etc. Seismic facies analysis is carried out on the basis of the sedimentary sequences obtained from seismic reflection sequence analysis. Usually, a sedimentary sequence can be further divided into several seismic facies units, and a seismic facies unit can be defined as a sedimentary unit with significantly different seismic properties from adjacent units. Seismic facies data can be used for direct interpretation, that is, to find out the geological reasons for each seismic facies element in the seismic facies unit, and then obtain information such as lithology and lithofacies changes of the formation; it can also be used for indirect interpretation, that is, to infer sedimentary environments, sediment transport directions, and geological evolution, etc.

[0106] Fault data refers to data that describes the characteristics and attributes of faults on the Earth's surface or underground formations. A fault is a fracture zone in the Earth's crust, usually caused by geomechanical actions, which causes the strata to move or slide along the fracture surface.

[0107] Preferably, the fault data can be obtained in the following ways:

[0108] Seismic data: The seismic data collected in seismic exploration can provide information on the structure and properties of subsurface strata, including the presence and attributes of faults. The reflected and refracted waves in seismic data can be used to infer the location, dip angle, slip direction, displacement, etc. of faults.

[0109] Seismic data: The seismic data collected in seismic exploration can provide information on the structure and properties of subsurface strata, including the presence and attributes of faults. The reflected and refracted waves in seismic data can be used to infer the location, dip angle, slip direction, displacement, etc. of faults. Additionally, the fault data can also be obtained through well logging data.

[0110] In some embodiments of the present invention, referring to Figure 3 , step 102 includes:

[0111] Step 1021: Determine the seismic facies based on the seismic data of the target work area;

[0112] Specifically, on the basis of dividing the seismic sequences, using the differences in seismic parameter characteristics, the seismic sequences are divided into different seismic facies zones, and then inferences about lithofacies and sedimentary environments are made. The basic parameters used to define seismic facies units are the parameters related to the reflection morphology within the series and the geometric shape of the series itself. Seismic facies include the following seismic reflection parameters:

[0113] (1) Reflection structure: The reflection structure reflects bedding types, sedimentation, erosion and paleogeomorphology, and fluid types.

[0114] (2) Seismic facies unit shape and planar combination: The lithofacies combinations formed under different sedimentary environments have specific bedding patterns and morphological patterns, resulting in specific combinations of reflection structures and shapes, thus reflecting sedimentary environments, sediment sources, and geological backgrounds.

[0115] (3) Reflection amplitude: The reflection amplitude is related to the wave impedance difference and reflects the interface velocity-density difference, formation interval, and changes in fluid composition and lithology. A large area of stable amplitude reveals good continuity of the overlying and underlying strata and reflects low-energy deposition; rapid changes in amplitude indicate rapid changes in the lithology of the overlying and / or underlying strata and are a reflection of a high-energy environment.

[0116] (4) Reflection frequency: The reflection frequency is affected by various factors, such as formation thickness, fluid composition, burial depth, lithology combination, data processing parameters, etc. Rapid changes in video frequency often indicate rapid changes in lithology and are thus the product of a high-energy environment.

[0117] (5) In-phase axis continuity: It directly reflects the continuity of the formation itself and is related to sedimentation. The better the continuity, the more the formation is related to a relatively lower energy level; the worse the continuity, the faster the lateral change of the formation is reflected, and the higher the sedimentation energy is.

[0118] (6) Interval velocity: Interval velocity reflects lithology, porosity, fluid composition, and formation pressure.

[0119] In addition, seismic facies markers are divided into: 1) basic attributes and structures of seismic reflections; 2) internal reflection structures; 3) external geometric shapes; 4) boundary relationships (including reflection termination types and lateral change types); 5) interval velocity, etc.

[0120] When implementing step 1021, specifically: First, preprocess the collected seismic data, including removing noise, correcting data, filtering, etc. This can improve the data quality and clarity and is beneficial to subsequent seismic facies analysis.

[0121] Then perform phase picking, that is, identify and calibrate the arrival times of different seismic facies in the seismic data. Phase picking can be performed manually or automatically. Manual picking requires manual judgment based on waveform characteristics, while automatic picking uses computer algorithms for identification. According to the results of phase picking, cut the seismic data according to the arrival time to obtain waveform segments of different seismic facies. According to information such as waveform characteristics, amplitude, and frequency, perform phase identification on the cut waveform segments. Common seismic phases include P-waves, S-waves, surface waves, etc. Phase identification can be performed using methods such as manual interpretation or machine learning.

[0122] Then perform phase feature extraction. For the identified different seismic facies, their characteristic parameters such as arrival time, amplitude, frequency, etc. can be extracted. These characteristic parameters can be used for the analysis and interpretation of seismic facies.

[0123] Finally, perform seismic phase analysis and interpretation. According to the characteristic parameters of the phase and the underground geological background, perform seismic phase analysis and interpretation. Information such as the velocity, density, and lithology of the underground formation can be inferred, and the geological structure can be evaluated.

[0124] Step 1022: Build the formation model according to the seismic interpretation horizon data, the seismic facies, and the fault data.

[0125] In some embodiments of the present invention, refer to Figure 4 , a method for determining acquisition parameters of a seismic observation system further includes:

[0126] Step 400: Generate the multiple acquisition schemes according to the geological target requirements of the target work area.

[0127] Different acquisition schemes correspond to different observation systems. The basic parameters of a seismic observation system include the trace interval, bin size, fold, offset, shot interval, receiver line interval, and shot line interval. Observation systems are generally represented by graphical methods, mainly the time-distance plane method and the comprehensive plane method.

[0128] The time-distance plane method represents the observed areas corresponding to different shot points in the form of time-distance curves on a plan. In simple cases, such as when the reflection interface is a single horizontal or inclined plane, the reflected waves from the same interface can be clearly represented. However, in complex observation systems, the positions of the observed areas cannot be correctly reflected.

[0129] The comprehensive plane method represents the relative spatial position relationship between the shot points and receiver points, as well as the observed areas, on a plan based on the same principle as the time-distance plane method. The representation method of the comprehensive plan is to mark the shot points and receiver points distributed on the survey line on the survey line at a certain scale, and then draw oblique lines (common shot lines) at 45° to the survey line from each shot point in the direction of the receiver arrangement. Then, project from the receiver points to this oblique line. The projection line from the geophone point is called the common receiver line, and the intersection of the two is called the common reflection point. The observed area is the distance between the projection points of different common reflection points on the survey line. The distribution of the shot-receiver distance and the fold of each reflection point can be seen from the comprehensive plan. In 2D seismic exploration, the comprehensive plan is often used to design and analyze the seismic observation system. In 3D seismic exploration, the 3D observation system is usually displayed on a plane according to the shot-receiver point coordinates, and the comprehensive plan is still used to analyze the distribution of the shot-receiver distance, azimuth, and fold of each line in 3D observation.

[0130] In some embodiments of the present invention, referring to Figure 5 , step 200 includes:

[0131] Step 201: Initialize the acquisition parameters corresponding to the multiple acquisition schemes to determine the bin size, receiver line interval, fold, maximum offset, and aspect ratio of each acquisition scheme;

[0132] The bin size refers to the size of the ground area covered by each observation point (or receiver point) in seismic data acquisition. The bin size is usually represented by the side length of a square or rectangle, and the unit can be meters or kilometers. The selection of the bin size should be optimized according to the observation purpose and geological background to balance the accuracy requirements and observation costs.

[0133] The receiver line interval refers to the distance between adjacent receiver lines, that is, the spacing between receiver points in seismic data. The receiver line interval is usually represented by meters or kilometers. A smaller receiver line interval can obtain higher spatial resolution, but it will also increase the observation cost and the complexity of data processing. A larger receiver line interval can reduce the cost, but some detailed information may be lost.

[0134] The fold number refers to the number of times each subsurface target point (such as an oil and gas layer) is observed in seismic data acquisition. By covering the same target point multiple times, the data quality and stability can be improved, and the influence of random errors can be reduced. The selection of the fold number should be optimized according to the depth, complexity of the target, and the purpose of observation.

[0135] The maximum offset is the maximum distance between the seismic source and the receiver in seismic data acquisition. The maximum offset is usually expressed in meters or kilometers. A larger offset can provide a wider perspective and a longer propagation path, which helps to detect deep structures and improve the reliability of seismic interpretation. However, a larger offset may require a larger energy source and a longer observation time.

[0136] The aspect ratio is the ratio between the receiver line interval and the maximum offset in seismic data acquisition. The selection of the aspect ratio should be optimized according to the purpose of observation and the geological background. A larger aspect ratio can provide a wider coverage area and more comprehensive information, but it will also increase the observation cost and the complexity of data processing.

[0137] Step 202: Based on the three-dimensional model, generate the imaging profile corresponding to each acquisition scheme according to the bin size, receiver line interval, fold number, maximum offset, and aspect ratio of each acquisition scheme.

[0138] In some embodiments of the present invention, referring to Figure 6 , step 202 includes:

[0139] Step 2021: Generate the reflection coefficient model and the point spread function corresponding to each acquisition scheme according to the bin size, receiver line interval, fold number, maximum offset, and aspect ratio of each acquisition scheme.

[0140] The reflection coefficient model is a mathematical model that describes the reflection characteristics of different physical property interfaces in the subsurface medium. The reflection coefficient model usually uses elastic wave equations and boundary conditions to calculate the reflected and transmitted wave fields on different medium interfaces. The reflection coefficient model can be divided into two categories: discrete reflection coefficient model and continuous reflection coefficient model.

[0141] Discrete reflection coefficient model: Each interface in the subsurface medium is regarded as a discrete reflection interface, and each reflection interface has its own reflection coefficient. When calculating the wave field, according to the angle between the incident wave and the reflection interface and the physical property difference of the interface, the reflection coefficient is used to calculate the amplitude and phase of the reflected wave field.

[0142] Continuous reflection coefficient model: It is assumed that the interfaces in the subsurface medium have a continuously varying reflection coefficient distribution. This model is often used to describe complex formation structures, such as layered media or velocity models that vary with depth. In the continuous reflection coefficient model, the reflection coefficient can be estimated by adopting a certain interpolation or fitting method.

[0143] The point spread function refers to the response function corresponding to the propagation path between the seismic source and the receiver in seismic data. The point spread function describes the characteristics of seismic wave propagation in the subsurface medium, including amplitude attenuation, phase change, propagation time, etc. The point spread function can be used in processes such as seismic imaging, migration correction, and inversion in seismic data processing.

[0144] Generating a reflection coefficient model includes the following steps: performing an inversion process using an inversion algorithm based on the bin size, receiver line spacing, fold, maximum offset, acquired seismic data, and aspect ratio of each acquisition scheme. The inversion algorithm can be linear or non - linear, including prestack inversion, full - waveform inversion, migration inversion, etc. Based on the physical property parameters obtained from the inversion, the reflection coefficient can be calculated. The reflection coefficient is a numerical value describing the reflection characteristics of the medium interface, and the reflection and transmission wave fields of seismic waves at different medium interfaces can be calculated based on the reflection coefficient.

[0145] The calculation of the point spread function (which is used to describe the characteristics of seismic wave propagation in the subsurface medium, including amplitude attenuation, phase change, and propagation time, etc.) can be based on the reflection coefficient model. By simulating the propagation path of seismic waves in the subsurface medium, the amplitude and phase of seismic waves at different positions and times can be calculated. The calculation of the point spread function can use numerical simulation methods such as the finite - difference method, finite - element method, etc., or analytical methods such as the Born approximation. Generating the point spread function involves processes such as numerical simulation of seismic waves, calculation of propagation paths, estimation of amplitude attenuation, estimation of phase change, and calculation of propagation time. Specifically:

[0146] First, perform numerical simulation of seismic waves to simulate the propagation process of seismic waves in the subsurface medium. Numerical simulation methods such as the finite - difference method, finite - element method, etc. can be used to calculate the amplitude and phase of seismic waves at different positions and times according to the physical property parameters and boundary conditions of the subsurface medium. Then, based on the results of the seismic wave simulation, determine the propagation path between the seismic source and the receiver. The propagation path can be a straight - line path or a curved path, depending on the complexity of the subsurface medium and the propagation direction of the seismic waves.

[0147] Along the propagation path, the seismic waves will undergo amplitude attenuation. The amplitude attenuation can be estimated by calculating the energy loss along the propagation path. Preferably, the amplitude attenuation model includes geometric attenuation and attenuation coefficient model.

[0148] Along the propagation path, the phase of the seismic wave also changes. The phase change can be estimated by calculating the propagation time and frequency along the propagation path. Seismic waves with different frequencies will have different phase changes during propagation. The propagation time of the seismic wave along the propagation path can be calculated from the length of the propagation path and the wave velocity in the subsurface medium. The propagation time is an important parameter in the point spread function, which describes the propagation time of the seismic wave from the seismic source to the receiver. Finally, based on parameters such as amplitude attenuation, phase change, and propagation time, the point spread function can be calculated.

[0149] Step 2022: Generate the imaging profile corresponding to each acquisition scheme according to the reflection coefficient model and the point spread function corresponding to each acquisition scheme.

[0150] In some embodiments of the present invention, referring to Figure 7 , step 300 includes:

[0151] Step 301: Compare the multiple imaging profiles to select the optimal imaging profile;

[0152] Specifically, the effects of multiple imaging profiles can be evaluated from the following aspects:

[0153] Resolution: Resolution is the ability to evaluate the clarity of the imaging profile and the smallest feature size that can be resolved. A high-resolution imaging profile can clearly display the subsurface interface and structural features. Resolution can be evaluated by calculating the frequency response of the system or the width of specific features in the imaging profile.

[0154] Interference noise: Noise has a great impact on the quality of the imaging profile. Interference noise will distort or blur the subsurface structure in the profile. Preferably, interference noise includes seismic instrument noise, environmental noise, random perturbations of the subsurface medium, etc. The evaluation of interference noise can be measured using indicators such as signal-to-noise ratio (SNR) or noise level.

[0155] Reflection body reconstruction accuracy: The seismic imaging profile should be able to accurately reconstruct the position and shape of the subsurface reflector. The evaluation of reconstruction accuracy can be verified by comparing with geological observation data or using simulation data. Preferably, the evaluation indicators include position error, shape matching degree, etc.

[0156] Artifacts and multipaths: Artifacts and multipath phenomena in the seismic imaging profile will lead to distortion and confusion of the subsurface structure. Artifacts refer to non-real subsurface reflection interfaces, and multipaths refer to the interference caused by seismic waves propagating along different paths. The evaluation of artifacts and multipaths can be verified by comparing the results of different imaging algorithms or using simulation data.

[0157] Dynamic range: The dynamic range refers to the range of amplitude variations in the imaging profile. A larger dynamic range means that the imaging profile can display the differences in strength of the subsurface structures, which is beneficial for geological interpretation. The dynamic range can be evaluated using indicators such as the amplitude range or contrast.

[0158] Coherence: Coherence refers to the consistency of the same subsurface interface or feature at different positions in the imaging profile. Higher coherence means that the imaging profile can accurately display the subsurface continuity. Coherence can be evaluated by calculating the correlation coefficients at different positions in the profile or using frequency analysis methods.

[0159] Step 302: Determine the current acquisition parameters according to the acquisition scheme corresponding to the optimal imaging profile.

[0160] The acquisition parameters of the acquisition scheme corresponding to the optimal imaging profile are the current acquisition parameters.

[0161] As can be seen from the above description, the embodiments of the present invention provide a method for determining the acquisition parameters of a seismic observation system, including: first, constructing a three-dimensional model of the target work area based on the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data; then, generating multiple imaging profiles corresponding to multiple acquisition schemes based on the three-dimensional model; where the acquisition scheme corresponds to the imaging profile one by one; finally, determining the current acquisition parameters of the target work area according to the multiple imaging profiles.

[0162] Aiming at the technical pain points of the traditional method for determining the acquisition parameters of an observation system based on conventional migration imaging, such as large computational amount and long time consumption for obtaining the acquisition parameters of the seismic observation system, which cannot meet the requirements of the observation system design for efficiency and low-cost acquisition. The method for determining the acquisition parameters of the seismic observation system provided by the embodiments of the present invention is based on a high-precision three-dimensional model, and uses a fast migration imaging algorithm to conduct argument analysis on the parameters of the seismic acquisition observation system, so as to quickly and accurately obtain the optimal observation system parameters, providing a strong guarantee for the efficient implementation of subsequent seismic acquisition.

[0163] Embodiment Three:

[0164] In a specific implementation manner, the present invention also takes the design of the acquisition parameters of the seismic observation system in a certain target area in the southern mountainous region as an example to provide a specific implementation manner of the method for determining the acquisition parameters of the seismic observation system. See Figure 8 , which specifically includes the following steps.

[0165] S1: Input data;

[0166] Integrate the digital elevation model (DEM) of the target area, the historical acquisition observation system (SPS) data, the historical seismic interpretation horizons and fault data as the input.

[0167] S2: Construct a high-precision 3D model.

[0168] According to the geological structure characteristics of the target work area, first establish a complex undulating surface model using the digital elevation model (DEM) input in Step S1 and the previously collected survey system (SPS) data. Establish a horizon model and a fault model respectively based on the previous seismic interpretation horizons and fault data, analyze the contact and cutting relationships between the surface, horizons and faults, conduct spatial structure modeling, and establish a true surface structure model. Then, based on the spatial distribution pattern and range of the geological reservoirs in the target area, establish a reservoir model based on seismic facies. Finally, fuse the true surface structure model and the reservoir model to construct a high-precision 3D model. See Figure 9 。

[0169] S3: Determine the acquisition parameters of the survey system.

[0170] Based on the geological target requirements of seismic exploration, initialize the parameters of the seismic acquisition survey system, including bin size, receiver line spacing, coverage times, maximum offset and aspect ratio, etc. See Figure 10 。

[0171] S4: Optimize the acquisition parameters according to the fast migration imaging effect.

[0172] Based on the design of each survey system plan in Step 3 and deploy them respectively on the high-precision 3D model established in Step 2, and use the fast migration imaging algorithm respectively:

[0173] I mg =F ps *M r

[0174] where I mg is the fast migration imaging result, M r is the reflection coefficient model, and F ps is the point spread function:

[0175] F ps =[G(x 0 ;x s )G(x 0 ;x r )] T G(x n ;x s )G(x n ;x r )

[0176] where x n is the coordinate within the neighborhood, x 0 is the scattering point coordinate of the reflection coefficient model, x s is the shot point coordinate, x r is the geophone coordinate, and G is the Green's function:

[0177] G(x i ; x j ) = Ae 2πf(t-τ)

[0178] where G(x i ; x j ) is the Green's function from x i to x j , A is the amplitude, and τ is the travel-time delay.

[0179] Perform imaging processing to obtain the imaging profiles of each observation system scheme, and analyze and compare the imaging effects of the profiles corresponding to different sizes of each observation system parameter. See Figure 11 .

[0180] S5: Determine the acquisition parameters of the optimal observation system.

[0181] According to the results of the comparative analysis of the imaging profiles in step S4, output the optimal observation system parameters, as shown in Table 1.

[0182] Table 1 Acquisition Parameters of the Optimal Seismic Observation System

[0183] Observation system 38L6S512T304F Element (m) 25x12.5 Number of receiver channels (channels) 19456 Receiver interval (m) 25 Receiver line interval (m) 300 Shot interval (m) 50 Shot line interval (m) 400 Maximum longitudinal offset (m) 6387.5 Maximum non-longitudinal offset (m) 5687.5 Maximum offset (m) 8551.9 Coverage times (times) 304(16x19) Aspect ratio / Target layer 0.89 / 0.81 <![CDATA[Gun track density (ten thousand / km 2 )]]> 97.3

[0184] As can be seen from the above description, a method for determining the acquisition parameters of a seismic observation system provided by a specific application example of the present invention includes: first, constructing a three-dimensional model of the target work area according to the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data; then, generating multiple imaging profiles corresponding to multiple acquisition schemes based on the three-dimensional model; where the acquisition scheme corresponds to the imaging profile one by one; finally, determining the current acquisition parameters of the target work area according to the multiple imaging profiles.

[0185] The present invention realizes the rapid and accurate acquisition of the acquisition parameters of the optimal observation system in the design stage of the acquisition parameters of the seismic observation system in seismic exploration, provides guarantee for the rapid and effective implementation of subsequent seismic acquisition, thus provides a high-quality data basis for seismic processing, seismic interpretation, and seismic inversion, and at the same time reduces the acquisition cost and realizes cost reduction and efficiency increase in oil and gas exploration.

[0186] Example 4:

[0187] Based on the same inventive concept, an embodiment of the present application further provides an acquisition parameter determination device for a seismic observation system, which can be used to implement the method described in the above embodiment, as in the following embodiment. Since the principle of the acquisition parameter determination device for the seismic observation system to solve the problem is similar to that of the acquisition parameter determination method for the seismic observation system, the implementation of the acquisition parameter determination device for the seismic observation system can refer to the implementation of the acquisition parameter determination method for the seismic observation system, and the repeated parts will not be described again. As used hereinafter, the term "unit" or "module" can be a combination of software and / or hardware that can achieve a predetermined function. Although the systems described in the following embodiments are preferably implemented in software, implementation in hardware, or a combination of software and hardware is also possible and contemplated.

[0188] An embodiment of the present invention provides a specific implementation manner of an acquisition parameter determination device for a seismic observation system that can implement the acquisition parameter determination method for the seismic observation system. Refer to Figure 12 , an acquisition parameter determination device for a seismic observation system includes:

[0189] A three-dimensional model construction module 10, configured to construct a three-dimensional model of the target work area according to the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data;

[0190] An imaging profile generation module 20, configured to generate a plurality of imaging profiles corresponding to a plurality of acquisition schemes based on the three-dimensional model; wherein, the acquisition scheme and the imaging profile are in one-to-one correspondence;

[0191] A current acquisition parameter determination module 30, configured to determine the current acquisition parameters of the target work area according to the plurality of imaging profiles.

[0192] In an embodiment of the present invention, the three-dimensional model construction module includes:

[0193] A surface structure model construction unit, configured to construct a surface structure model of the target work area according to the digital elevation model and the historical acquisition parameters;

[0194] A formation model construction unit, configured to construct a formation model of the target work area according to the formation distribution data;

[0195] A three-dimensional model construction unit, configured to construct the three-dimensional model according to the surface structure model and the formation model.

[0196] In an embodiment of the present invention, the formation distribution data includes: seismic interpretation horizon data, seismic facies, and fault data; the formation model construction unit includes:

[0197] A seismic facies determination unit, configured to determine the seismic facies according to the seismic data of the target work area;

[0198] A formation model construction subunit, configured to construct the formation model according to the seismic interpretation horizon data, the seismic facies, and the fault data.

[0199] In an embodiment of the present invention, an acquisition parameter determination device of a seismic observation system further includes:

[0200] A plurality of acquisition scheme generation modules, configured to generate the plurality of acquisition schemes according to the geological target requirements of the target work area.

[0201] In an embodiment of the present invention, the imaging profile generation module includes:

[0202] An acquisition parameter initialization unit, configured to initialize the acquisition parameters corresponding to the plurality of acquisition schemes to determine the bin size, receiver line spacing, fold number, maximum offset, and aspect ratio of each acquisition scheme;

[0203] An imaging profile generation unit, configured to generate the imaging profile corresponding to each acquisition scheme based on the three-dimensional model according to the bin size, receiver line spacing, fold number, maximum offset, and aspect ratio of each acquisition scheme.

[0204] In an embodiment of the present invention, the imaging profile generation unit includes:

[0205] A function model generation unit, configured to generate the reflection coefficient model and the point spread function corresponding to each acquisition scheme according to the bin size, receiver line spacing, fold number, maximum offset, and aspect ratio of each acquisition scheme;

[0206] An imaging profile generation subunit, configured to generate the imaging profile corresponding to each acquisition scheme according to the reflection coefficient model and the point spread function corresponding to each acquisition scheme.

[0207] In an embodiment of the present invention, the current acquisition parameter determination module includes:

[0208] An optimal imaging profile selection unit, configured to compare the plurality of imaging profiles to select the optimal imaging profile;

[0209] A current acquisition parameter determination unit, configured to determine the current acquisition parameters according to the acquisition scheme corresponding to the optimal imaging profile.

[0210] As can be seen from the above description, the embodiment of the present invention provides an acquisition parameter determination device for a seismic observation system, including: a three-dimensional model construction module, configured to construct a three-dimensional model of a target work area according to the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data; an imaging profile generation module, configured to generate multiple imaging profiles corresponding to multiple acquisition schemes based on the three-dimensional model; wherein, the acquisition scheme and the imaging profile are in one-to-one correspondence; a current acquisition parameter determination module, configured to determine the current acquisition parameters of the target work area according to the multiple imaging profiles.

[0211] The acquisition parameter determination device for the seismic observation system provided by the embodiment of the present invention effectively avoids the deficiencies of the existing acquisition parameter determination method for the seismic observation system, such as large computational amount, long time consumption, and high cost, realizes the rapid and accurate design of the acquisition parameters of the seismic observation system, shortens the design cycle of the seismic observation system, thereby reducing the acquisition cost, improving the efficiency of the effective implementation of seismic acquisition, and providing guarantee for subsequent seismic data processing, interpretation, and inversion.

[0212] Embodiment Five:

[0213] The embodiment of the present application further provides a specific implementation manner of an electronic device capable of implementing all the steps in the acquisition parameter determination method of the seismic observation system in the above embodiment. Refer to Figure 13 , and the electronic device specifically includes the following content:

[0214] A processor 1201, a memory 1202, a communication interface 1203, and a bus 1204;

[0215] Among them, the processor 1201, the memory 1202, and the communication interface 1203 complete mutual communication through the bus 1204; the communication interface 1203 is used to realize information transmission between related devices such as server-side devices and client-side devices;

[0216] The processor 1201 is used to call the computer program in the memory 1202. When the processor executes the computer program, all the steps in the acquisition parameter determination method of the seismic observation system in the above embodiment are realized. For example, when the processor executes the computer program, the following steps are realized:

[0217] Construct a three-dimensional model of the target work area according to the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data;

[0218] Generate multiple imaging profiles corresponding to multiple acquisition schemes based on the three-dimensional model; wherein, the acquisition scheme and the imaging profile are in one-to-one correspondence;

[0219] Determine the current acquisition parameters of the target work area according to the multiple imaging profiles.

[0220] Embodiment Six:

[0221] An embodiment of the present application further provides a computer-readable storage medium capable of implementing all steps in the acquisition parameter determination method of the seismic observation system in the above embodiments. A computer program is stored on the computer-readable storage medium. When the computer program is executed by a processor, all steps of the acquisition parameter determination method of the seismic observation system in the above embodiments are implemented. For example, when the processor executes the computer program, the following steps are implemented:

[0222] Construct a three-dimensional model of the target work area according to the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data;

[0223] Generate multiple imaging profiles corresponding to multiple acquisition schemes based on the three-dimensional model; wherein, the acquisition scheme corresponds to the imaging profile one by one;

[0224] Determine the current acquisition parameters of the target work area according to the multiple imaging profiles.

[0225] Each embodiment in this specification is described in a progressive manner. The same or similar parts between each embodiment can be referred to each other. The key point of each embodiment is to illustrate the differences from other embodiments. In particular, for the hardware + program type embodiments, since they are basically similar to the method embodiments, the description is relatively simple, and the relevant parts can be referred to the partial description of the method embodiments.

[0226] The above describes specific embodiments of this specification. Other embodiments are within the scope of the appended claims. In some cases, the actions or steps recited in the claims can be performed in a different order than in the embodiments and still achieve the desired results. Additionally, the processes depicted in the figures do not necessarily require the particular order or sequential order shown to achieve the desired result. In certain implementations, multitasking and parallel processing are also possible or may be advantageous.

[0227] Although the present application provides method operation steps such as in the embodiments or flowcharts, based on routine or non-creative labor, there may be more or fewer operation steps. The step order listed in the embodiments is only one way among the execution orders of numerous steps and does not represent the only execution order. When the actual device or client product is executed, it can be executed in the order shown in the embodiments or the figures or in parallel (such as in an environment of parallel processors or multithreaded processing).

[0228] For the convenience of description, when describing the above device, various modules are described separately according to their functions. Of course, when implementing the embodiments of this specification, the functions of each module can be implemented in the same or multiple 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, etc. The device embodiments described above are only illustrative. For example, the division of the units is only a logical function division. In actual implementation, there may be other division methods. For example, 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 displayed or discussed coupling or direct coupling or communication connection between each other can be through some interfaces. The indirect coupling or communication connection of the device or unit can be in electrical, mechanical or other forms.

[0229] Those skilled in the art also know that in addition to implementing the controller in the form of pure computer-readable program code, the method steps can be logically programmed to enable the controller to be implemented in the form of logic gates, switches, application-specific integrated circuits, programmable logic controllers, embedded microcontrollers, etc. to achieve the same function. Therefore, such a controller can be regarded as a hardware component, and the devices included therein for implementing various functions can also be regarded as the structure within the hardware component. Or even, the devices for implementing various functions can be regarded as either software modules for implementing the method or the structure within the hardware component.

[0230] In a typical configuration, a computing device includes one or more processors (CPUs), an input / output interface, a network interface, and memory.

[0231] The memory may include non-permanent memory in the form of computer-readable media, random access memory (RAM), and / or non-volatile memory such as read-only memory (ROM) or flash memory (flash RAM). The memory is an example of computer-readable media.

[0232] Each embodiment in this specification is described in a progressive manner. For the same or similar parts among the embodiments, reference can be made to each other, and the key point of each embodiment is to illustrate the differences from other embodiments. In particular, for the system embodiment, since it is basically similar to the method embodiment, the description is relatively simple, and for the relevant parts, reference can be made to the description of the method embodiment. In the description of this specification, the description with reference to terms such as "one embodiment", "some embodiments", "example", "specific example", or "some examples" means that the specific features, structures, materials, or characteristics described in connection with the embodiment or example are included in at least one embodiment or example of the embodiments of this specification. In this specification, the schematic representation of the above terms does not necessarily refer to the same embodiment or example. Moreover, the specific features, structures, materials, or characteristics described can be combined in a suitable manner in any one or more embodiments or examples. In addition, without contradiction, those skilled in the art can combine and combine the different embodiments or examples described in this specification and the features of different embodiments or examples.

[0233] The above is only the embodiment of the embodiments of this specification and is not used to limit the embodiments of this specification. For those skilled in the art, various changes and modifications can be made to the embodiments of this specification. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the embodiments of this specification shall be included within the scope of the claims of the embodiments of this specification.

Claims

1. A method for determining acquisition parameters of a seismic observation system, characterized in that, it includes: Construct a three-dimensional model of the target work area based on the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data; Generate multiple imaging profiles corresponding to multiple acquisition schemes based on the three-dimensional model; wherein, the acquisition scheme and the imaging profile are in one-to-one correspondence; Determine the current acquisition parameters of the target work area according to the multiple imaging profiles.

2. The acquisition parameter determination method according to claim 1, characterized in that, The step of constructing a three-dimensional model of the target work area based on the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data includes: Construct a surface structure model of the target work area according to the digital elevation model and the historical acquisition parameters; Construct a formation model of the target work area according to the formation distribution data; Construct the three-dimensional model according to the surface structure model and the formation model.

3. The acquisition parameter determination method according to claim 2, characterized in that, The formation distribution data includes: seismic interpretation horizon data, seismic facies, and fault data; the step of constructing a formation model of the target work area according to the formation distribution data includes: Determine the seismic facies according to the seismic data of the target work area; Construct the formation model according to the seismic interpretation horizon data, the seismic facies, and the fault data.

4. The acquisition parameter determination method according to claim 1, characterized in that, It further includes: Generate the multiple acquisition schemes according to the geological target requirements of the target work area.

5. The acquisition parameter determination method according to any one of claims 1 to 4, characterized in that, The step of generating multiple imaging profiles corresponding to multiple acquisition schemes based on the three-dimensional model includes: Initialize the acquisition parameters corresponding to the multiple acquisition schemes to determine the bin size, receiver line spacing, coverage, maximum offset, and aspect ratio of each acquisition scheme; Generate the imaging profile corresponding to each acquisition scheme based on the three-dimensional model according to the bin size, receiver line spacing, coverage, maximum offset, and aspect ratio of each acquisition scheme.

6. The acquisition parameter determination method according to claim 5, characterized in that, The step of generating the imaging profile corresponding to each acquisition scheme based on the three-dimensional model according to the bin size, receiver line spacing, coverage, maximum offset, and aspect ratio of each acquisition scheme includes: Generate the reflection coefficient model and the point spread function corresponding to each acquisition scheme according to the bin size, receiver line spacing, coverage, maximum offset, and aspect ratio of each acquisition scheme; Generate the imaging profile corresponding to each acquisition scheme according to the reflection coefficient model and the point spread function corresponding to each acquisition scheme.

7. The acquisition parameter determination method according to claim 1, characterized in that, The step of determining the current acquisition parameters of the target work area according to the multiple imaging profiles includes: Compare the multiple imaging profiles to select the optimal imaging profile; Determine the current acquisition parameters according to the acquisition scheme corresponding to the optimal imaging profile.

8. An acquisition parameter determination device for a seismic observation system, characterized in that, comprising: A three-dimensional model construction module, configured to construct a three-dimensional model of the target work area according to the digital elevation model of the target work area, the historical acquisition parameters of the seismic observation system, and the formation distribution data; An imaging profile generation module, configured to generate a plurality of imaging profiles corresponding to a plurality of acquisition schemes based on the three-dimensional model; wherein, the acquisition scheme and the imaging profile are in one-to-one correspondence; A current acquisition parameter determination module, configured to determine the current acquisition parameters of the target work area according to the plurality of imaging profiles.

9. An electronic device, comprising a memory, a processor, and a computer program stored on the memory and executable on the processor, characterized in that, When the processor executes the program, the steps of the acquisition parameter determination method for the seismic observation system according to any one of claims 1 to 7 are implemented.

10. A computer-readable storage medium, on which a computer program is stored, characterized in that, When the computer program is executed by a processor, the steps of the acquisition parameter determination method for the seismic observation system according to any one of claims 1 to 7 are implemented.

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