Method and device for identifying natural gas hydrate and conventional free gas and medium

Abstract

The invention discloses a method and a device for identifying natural gas hydrate and conventional free gas and a medium. A rock physical model is established through the natural gas hydrate and the conventional free gas with various parameter combinations so as to simulate and predict seismic response of the natural gas hydrate; in addition, the seismic data is analyzed by using a spectral decomposition technology, so that specific frequency characteristics related to the natural gas hydrate can be identified; meanwhile, by comparing the actually measured seismic data with the synthesized seismic data, the existence and characteristics of the natural gas hydrate and the related free gas can be identified. The invention aims to improve the success rate and efficiency of natural gas hydrate exploration through a more accurate identification and quantification method, develops a new exploration and characterization method for challenges in natural gas hydrate exploration so as to realize effective utilization of potential energy resources, and can be widely applied to the technical field of data processing.

Description

Technical Field

[0001] The present invention relates to the technical field of data processing, and in particular to a method, a device and a medium for identifying natural gas hydrate and conventional free gas. Background Art

[0002] As global energy demand grows, the exploration of new energy resources has become particularly important. As a potential energy resource, natural gas hydrates have received great attention. The exploration of natural gas hydrates faces many challenges, including their uneven distribution underground, low density, and difficulty in direct observation. Traditional exploration methods, such as logging and seismic exploration, can provide information about underground structures and rock physical properties, but have limitations in the direct detection and quantification of natural gas hydrates. Summary of the invention

[0003] The present invention aims to solve the problem of related technical limitations at least to a certain extent. To this end, the present invention proposes a method, device and medium for identifying natural gas hydrates and conventional free gas, which can conveniently identify natural gas hydrates and conventional free gas.

[0004] On the one hand, an embodiment of the present invention provides a method for identifying natural gas hydrates and conventional free gas, comprising the following steps: Obtain well logging data and measured seismic data in the target exploration area; Based on the logging data, a rock physics model is obtained by constructing a preset layered structure; wherein the layered structure includes a background clay layer and a target sand layer; the rock physics model includes a hydrate wedge model and a conventional gas wedge model; the target sand layer of the hydrate wedge model presets natural gas hydrates with multiple parameter combinations, and the target sand layer of the conventional gas wedge model presets conventional free gas with multiple parameter combinations; Generate synthetic seismic data based on the rock physics model; the synthetic seismic data includes first synthetic seismic data corresponding to the hydrate wedge model and second synthetic seismic data corresponding to the conventional gas wedge model; Performing frequency spectrum decomposition on measured seismic data and synthetic seismic data in turn, and obtaining measured low-frequency data and synthetic low-frequency data correspondingly; the synthetic low-frequency data includes first synthetic low-frequency data corresponding to the hydrate wedge model and second synthetic low-frequency data corresponding to the conventional gas wedge model; The amplitude of the positive and negative phases of the measured low-frequency data is extracted to obtain the positive amplitude and the reverse amplitude; the amplitude of the first synthetic low-frequency data and the second synthetic low-frequency data are extracted in sequence to obtain the hydrate amplitude and the conventional gas amplitude respectively; The forward amplitude and the hydrate amplitude, as well as the reverse amplitude and the conventional gas amplitude are compared and identified in turn, and the identification results of natural gas hydrate and conventional free gas in the target exploration area are obtained.

[0005] Optionally, obtaining well logging data and measured seismic data of the target exploration area includes the following steps: Deploy a logging system in the target exploration area and obtain logging data of the target exploration area through the logging system; the logging data includes resistivity data, acoustic wave velocity data, radioactivity data, electromagnetic data and nuclear magnetic resonance data; A seismic source is arranged in the target exploration area, and seismic waves are emitted through the seismic source. Then, the reflection and refraction information of the seismic waves in the target exploration area is recorded by the geophone to obtain the measured seismic data.

[0006] Optionally, the logging data includes resistivity data, acoustic wave velocity data, radioactivity data, electromagnetic data and nuclear magnetic resonance data; based on the logging data, a rock physics model is obtained by constructing a preset layered structure, comprising the following steps: Determine the properties and distribution information of underground rocks in the target exploration area based on well logging data; Among them, the property and distribution information includes: water content and mineral type determined based on resistivity data; porosity, lithology and pressure determined based on acoustic wave velocity data; mud content determined based on radioactive data; porosity and fluid type determined based on electromagnetic data; dynamic information of fluid in the voids determined based on nuclear magnetic resonance data; According to the properties and distribution information and preset multiple parameter combinations of natural gas hydrates and conventional free gas, a rock physics model is constructed based on the layered structure through a preset quantitative theoretical method.

[0007] Optionally, generating synthetic seismic data based on the rock physics model comprises the following steps: Based on the rock physics model, preliminary synthetic seismic data are generated using 3D geological modeling technology; According to the main frequency of the measured seismic data, the frequency content of the preliminary synthetic seismic data is matched and adjusted using spectrum analysis and frequency band extension technology to obtain synthetic seismic data.

[0008] Optionally, performing amplitude extraction of positive and negative phases on the measured low-frequency data to obtain a positive amplitude and a reverse amplitude includes the following steps: The phase scanning method is used to extract amplitude data from the measured low-frequency data, and then the positive and negative phase characteristics of the amplitude in the amplitude data and their corresponding dominant positions are identified to obtain the positive amplitude and reverse amplitude.

[0009] Optionally, the plurality of parameter combinations include a combination of thickness and saturation in a plurality of numerical ranges for natural gas hydrates and a combination of distribution and content in a plurality of numerical ranges for conventional free gas; the forward amplitude and the hydrate amplitude, and the reverse amplitude and the conventional gas amplitude are sequentially compared and identified to obtain identification results of natural gas hydrates and conventional free gas in the target exploration area, including the following steps: Performing a first comparison and identification on the hydrate amplitude of the hydrate wedge model corresponding to the thickness and saturation in each numerical range by the forward amplitude, and obtaining a first identification result of the thickness and saturation of the natural gas hydrate; A second comparison and identification is performed on the reverse amplitude and the conventional gas amplitude of the conventional gas wedge model corresponding to the distribution and content of each numerical range to obtain a second identification result of the distribution and content of the conventional free gas.

[0010] Optionally, the method further comprises the following steps: Obtain sampling data of the target exploration area; the sampling data is collected based on the wellbore coring technology; The identification results are verified based on the sampling data, and the parameters of the rock physics model are adjusted according to the verification results.

[0011] On the other hand, an embodiment of the present invention provides a device for identifying natural gas hydrates and conventional free gas, comprising: The first module is used to obtain well logging data and measured seismic data in the target exploration area; The second module is used to obtain a rock physics model based on the well logging data through a preset layered structure; wherein the layered structure includes a background clay layer and a target sand layer; the rock physics model includes a hydrate wedge model and a conventional gas wedge model; the target sand layer of the hydrate wedge model presets natural gas hydrates with multiple parameter combinations, and the target sand layer of the conventional gas wedge model presets conventional free gas with multiple parameter combinations; The third module is used to generate synthetic seismic data based on the rock physics model; the synthetic seismic data includes first synthetic seismic data corresponding to the hydrate wedge model and second synthetic seismic data corresponding to the conventional gas wedge model; The fourth module is used to perform spectral decomposition on the measured seismic data and the synthetic seismic data in sequence, and obtain measured low-frequency data and synthetic low-frequency data accordingly; the synthetic low-frequency data includes first synthetic low-frequency data corresponding to the hydrate wedge model and second synthetic low-frequency data corresponding to the conventional gas wedge model; The fifth module is used to extract the amplitude of the positive and negative phases of the measured low-frequency data to obtain the positive amplitude and the reverse amplitude; extract the amplitude of the first synthetic low-frequency data and the second synthetic low-frequency data in sequence to obtain the hydrate amplitude and the conventional gas amplitude respectively; The sixth module is used to compare and identify the forward amplitude with the hydrate amplitude, and the reverse amplitude with the conventional gas amplitude in turn, to obtain the identification results of the natural gas hydrate and conventional free gas in the target exploration area.

[0012] Optionally, the device further comprises: The seventh module is used to obtain sampling data of the target exploration area; the sampling data is collected based on the well wall coring technology; The eighth module is used to verify the identification results based on the sampling data and adjust the parameters of the rock physics model according to the verification results.

[0013] On the other hand, an embodiment of the present invention provides an electronic device, including: a processor and a memory; the memory is used to store programs; the processor executes the program to implement the above-mentioned method for identifying natural gas hydrates and conventional free gas.

[0014] On the other hand, an embodiment of the present invention provides a computer storage medium storing a program executable by a processor, and the program executable by the processor is used to implement the above-mentioned method for identifying natural gas hydrates and conventional free gas when executed by the processor.

[0015] The embodiment of the present invention obtains logging data and measured seismic data of the target exploration area; based on the logging data, a rock physics model is obtained through a preset layered structure construction; wherein the layered structure includes a background clay layer and a target sand body layer; the rock physics model includes a hydrate wedge model and a conventional gas wedge model; the target sand body layer of the hydrate wedge model presets natural gas hydrates with multiple parameter combinations, and the target sand body layer of the conventional gas wedge model presets conventional free gas with multiple parameter combinations; synthetic seismic data is generated based on the rock physics model; the synthetic seismic data includes first synthetic seismic data corresponding to the hydrate wedge model and second synthetic seismic data corresponding to the conventional gas wedge model ; Spectral decomposition is performed on measured seismic data and synthetic seismic data in sequence, and measured low-frequency data and synthetic low-frequency data are obtained accordingly; the synthetic low-frequency data includes the first synthetic low-frequency data corresponding to the hydrate wedge model and the second synthetic low-frequency data corresponding to the conventional gas wedge model; amplitude extraction of positive and negative phases is performed on the measured low-frequency data to obtain the positive amplitude and the reverse amplitude; amplitude extraction is performed on the first synthetic low-frequency data and the second synthetic low-frequency data in sequence to obtain the hydrate amplitude and the conventional gas amplitude; the forward amplitude is compared with the hydrate amplitude, and the reverse amplitude is compared with the conventional gas amplitude in sequence to obtain the identification results of natural gas hydrate and conventional free gas in the target exploration area. The present invention establishes a rock physics model through natural gas hydrate and conventional free gas with multiple parameter combinations to simulate and predict the seismic response of natural gas hydrate; and the present invention uses spectral decomposition technology to analyze seismic data, which is helpful to identify specific frequency characteristics related to natural gas hydrate; at the same time, by comparing the measured seismic data with the synthetic seismic data, the existence and characteristics of natural gas hydrate and related free gas can be identified. The goal of the present invention is to improve the success rate and efficiency of natural gas hydrate exploration through more accurate identification and quantification methods. The present invention targets the challenges in natural gas hydrate exploration and develops new exploration and characterization methods to achieve effective utilization of this potential energy resource. BRIEF DESCRIPTION OF THE DRAWINGS

[0016] The accompanying drawings are used to provide a further understanding of the technical solution of the present invention and constitute a part of the specification. Together with the embodiments of the present invention, they are used to explain the technical solution of the present invention and do not constitute a limitation on the technical solution of the present invention.

[0017] Figure 1 This is a schematic diagram of an implementation environment for identifying natural gas hydrates and conventional free gas provided by an embodiment of the present invention; Figure 2 It is a schematic flow chart of a method for identifying natural gas hydrates and conventional free gas provided by an embodiment of the present invention; Figure 3 A schematic diagram of the expansion process of step S100 provided in an embodiment of the present invention; Figure 4 A schematic diagram of the expanded flow of step S200 provided in an embodiment of the present invention; Figure 5 A schematic diagram of an exemplary configuration of a rock physics model provided by an embodiment of the present invention; Figure 6 A schematic diagram of another exemplary configuration of a rock physics model provided by an embodiment of the present invention; Figure 7 A schematic diagram of the expanded flow of step S300 provided in an embodiment of the present invention; Figure 8 A schematic diagram of the overall process of a method for identifying natural gas hydrates and conventional free gas provided in an embodiment of the present invention; Fig. 9 A schematic diagram of the structure of a device for identifying natural gas hydrates and conventional free gas provided in an embodiment of the present invention; Fig.10 A schematic diagram of the structure of an electronic device provided by an embodiment of the present invention. DETAILED DESCRIPTION

[0018] In order to make the purpose, technical solution and advantages of the present invention more clearly understood, the present invention is further described in detail below in conjunction with the accompanying drawings and embodiments. It should be understood that the specific embodiments described herein are only used to explain the present invention and are not used to limit the present invention.

[0019] It should be noted that, although the functional modules are divided in the system schematic diagram and the logical order is shown in the flowchart, in some cases, the steps shown or described may be performed in a different order than the module division in the system or the order in the flowchart. The terms "first / S100", "second / S200", etc. in the specification, claims and the above-mentioned drawings are used to distinguish similar objects, and are not necessarily used to describe a specific order or sequence.

[0020] Reference to "embodiments" herein means that a particular feature, structure, or characteristic described in conjunction with the embodiments may be included in at least one embodiment of the present invention. The appearance of the phrase in various places in the specification does not necessarily refer to the same embodiment, nor is it an independent or alternative embodiment that is mutually exclusive with other embodiments. It is explicitly and implicitly understood by those skilled in the art that the embodiments described herein may be combined with other embodiments.

[0021] It is understandable that the identification method of natural gas hydrate and conventional free gas provided in the embodiment of the present invention can be applied to any computer device with data processing and computing capabilities, and this computer device can be various terminals or servers. When the computer device in the embodiment is a server, the server is an independent physical server, or a server cluster or distributed system composed of multiple physical servers, or a cloud server that provides basic cloud computing services such as cloud services, cloud databases, cloud computing, cloud functions, cloud storage, network services, cloud communications, middleware services, domain name services, security services, CDN (Content Delivery Network), and big data and artificial intelligence platforms. Optionally, the terminal is a smart phone, a tablet computer, a laptop computer, a desktop computer, etc., but is not limited to this.

[0022] To facilitate the understanding of the technical solution of the present invention, the technical feature terms that may appear in the embodiments of the present invention are first explained: like Figure 1 FIG. 1 is a schematic diagram of an implementation environment provided by an embodiment of the invention. Figure 1 The implementation environment includes at least one terminal 102 and a server 101. The terminal 102 and the server 101 can be connected to a network wirelessly or wired to complete data transmission and exchange.

[0023] Server 101 can be an independent physical server, or a server cluster or distributed system composed of multiple physical servers. It can also be a cloud server that provides basic cloud computing services such as cloud services, cloud databases, cloud computing, cloud functions, cloud storage, network services, cloud communications, middleware services, domain name services, security services, CDN (Content Delivery Network), as well as big data and artificial intelligence platforms.

[0024] In addition, the server 101 can also be a node server in the blockchain network. Blockchain is a new application model of computer technologies such as distributed data storage, peer-to-peer transmission, consensus mechanism, and encryption algorithm.

[0025] The terminal 102 may be a smart phone, a tablet computer, a laptop computer, a desktop computer, a smart speaker, a smart watch, etc., but is not limited thereto. The terminal 102 and the server 101 may be directly or indirectly connected via wired or wireless communication, which is not limited in the embodiment of the present invention.

[0026] Based on the example Figure 1In the implementation environment shown, an embodiment of the present invention provides a method for identifying natural gas hydrates and conventional free gas. The following is explained using the example of applying the method for identifying natural gas hydrates and conventional free gas in the server 101. It can be understood that the method for identifying natural gas hydrates and conventional free gas can also be applied to the terminal 102.

[0027] Reference Figure 2 , Figure 2 The flowchart of the method for identifying natural gas hydrates and conventional free gas applied to a server provided in an embodiment of the present invention, the execution subject of the method for identifying natural gas hydrates and conventional free gas can be any of the aforementioned computer devices (including servers or terminals). Figure 2 , the method comprises the following steps: S100, acquiring well logging data and measured seismic data in the target exploration area; It should be noted that in some embodiments, Figure 3 As shown, step S100 may include the following steps: S101. deploy a logging system in the target exploration area, and obtain logging data of the target exploration area through the logging system; the logging data includes resistivity data, acoustic wave velocity data, radioactivity data, electromagnetic data, and nuclear magnetic resonance data; For example, in some specific embodiments, a logging system can be deployed on an offshore platform, which lowers logging instruments into an oil well via a cable and uses a variety of sensors to record the physical properties of the rock. These instruments can measure the resistivity, acoustic wave velocity, radioactivity, electromagnetic properties, and nuclear magnetic resonance properties of the rock, thereby obtaining detailed information about the rock and the rock-filled fluid.

[0028] S102, arranging a seismic source in the target exploration area, emitting seismic waves through the seismic source, and then using a geophone to record reflection and refraction information of the seismic waves in the target exploration area to obtain measured seismic data.

[0029] For example, in some specific implementations, 3D seismic data can be collected on site by arranging multiple geophones and seismic sources. These data help generate three-dimensional images of underground structures by recording the reflection and refraction information of seismic waves underground, which plays an important role in identifying geological structures, faults, and oil and gas reservoir boundaries.

[0030] Among them, during the logging process, the following key parameter data will be collected: resistivity data is used to determine the water content and mineral type of the rock formation; acoustic wave velocity data is used to infer the porosity, lithology and pressure of the formation; radioactivity data is used to determine the mud content of the formation; electromagnetic data is used to infer the porosity and fluid type of the rock; nuclear magnetic resonance data is used to obtain dynamic information of the fluid in the rock pores. These data are crucial to understanding the properties and distribution of underground rocks.

[0031] S200, based on the well logging data, a rock physics model is obtained by constructing a preset layered structure; The layered structure includes background clay layers and target sand layers; the rock physics model includes a hydrate wedge model and a conventional gas wedge model; the target sand layer of the hydrate wedge model presets natural gas hydrates with multiple parameter combinations, and the target sand layer of the conventional gas wedge model presets conventional free gas with multiple parameter combinations; It should be noted that the logging data includes resistivity data, acoustic wave velocity data, radioactivity data, electromagnetic data and nuclear magnetic resonance data; in some embodiments, such as Figure 4 As shown, step S200 may include the following steps: S201, determining the properties and distribution information of underground rocks in the target exploration area based on logging data; wherein the properties and distribution information include: water content and mineral type determined based on resistivity data; porosity, lithology and pressure determined based on acoustic wave velocity data; mud content determined based on radioactive data; porosity and fluid type determined based on electromagnetic data; dynamic information of fluid in the voids determined based on nuclear magnetic resonance data; S202, according to the properties and distribution information and natural gas hydrates and conventional free gas with preset multiple parameter combinations, a rock physical model is constructed based on layered structure through a preset quantitative theoretical method.

[0032] For example, in some specific embodiments, a velocity-density-thickness model may be established using well logging data to determine the physical parameters of the background clay layer and the target sand layer.

[0033] Assuming that the target sand layer is full of water, the physical parameters of water are used as the basis. When establishing the velocity-density-thickness model and determining the physical parameters of the background clay layer and the target sand layer, the following theoretical and empirical formulas are mainly used: Biot theory: This is a theory that describes the propagation of elastic waves in saturated porous media. In the interpretation of well logging data, Biot theory is used to explain the propagation characteristics of sound waves in fluid-containing rocks, especially in the three-phase medium (rock skeleton, hydrate, pore fluid) when considering the presence of gas hydrates.

[0034]

[0035]

[0036]

[0037]

[0038] in, are the speeds of the fast and slow longitudinal waves, is the attenuation coefficient of fast and slow longitudinal waves, is the velocity of the transverse wave, is the attenuation coefficient of shear waves, is the angular frequency, and represent the real and imaginary parts of a complex number respectively.

[0039] Gassmann equation: This is an empirical formula used to describe the change in wave velocity in fluid-saturated rocks. It can be used to calculate the elastic parameters of rocks after fluid replacement, such as longitudinal wave velocity and shear wave velocity. The Gassmann equation is used to describe the change in elastic parameters of rocks after fluid replacement, and its basic form is:

[0040] in, is the bulk modulus of dry rock, is the bulk modulus of the fluid-containing rock, is the bulk modulus of the fluid, Porosity.

[0041] Equivalent medium theory: This theory is used to describe the macroscopic physical properties of multiphase media, such as resistivity and elastic wave velocity, and simplifies calculations by treating the multiphase medium as a single equivalent medium.

[0042] Through these theories and methods, the effects of natural gas hydrates and conventional free gas on rock physical properties under different saturation conditions can be quantitatively analyzed and predicted, thus providing a scientific basis for geological exploration and resource assessment.

[0043] Furthermore, the two models in the rock physics model can be constructed as follows: Model A: Assume that there are natural gas hydrates with different contents (thickness and saturation) in the target sand layer. Figure 5 , which is a schematic diagram of a construction example of model A ( Figure 5 The percentage content of hydrate is used as an example for explanation. It can be adjusted according to needs in actual application).

[0044] Model B: Assume that there is conventional free gas of different contents (distribution and content) in the target sand layer. Figure 6 , which is a schematic diagram of a construction example of model B ( Figure 6The percentage content of conventional gas is used as an example for explanation. In actual application, it can be adjusted according to needs).

[0045] When constructing Model A and Model B, the effects of different saturations of natural gas hydrate and conventional free gas on rock physical properties are considered mainly in the following ways: Model A (gas hydrate saturation model, also known as hydrate wedge model): In this model, the effects of hydrate morphology, distribution, and saturation on rock physical properties are considered. The presence of hydrates affects the elastic properties of rocks and fluid flow characteristics, and these effects are quantified using Biot theory and equivalent medium theory.

[0046] Model B (conventional free gas saturation model, i.e., conventional gas wedge model): In this model, the influence of the presence and saturation of conventional free gas on the physical properties of rocks is considered. Free gas affects the porosity, permeability, and elastic wave velocity of rocks, and these effects are described by the Gassmann equation and equivalent medium theory.

[0047] S300, generating synthetic seismic data based on a rock physics model; The synthetic seismic data include first synthetic seismic data corresponding to the hydrate wedge model and second synthetic seismic data corresponding to the conventional gas wedge model; It should be noted that in some embodiments, Figure 7 As shown, step S300 may include the following steps: S301, based on the rock physics model, using three-dimensional geological modeling technology to generate preliminary synthetic seismic data; S302, according to the main frequency of the measured seismic data, using spectrum analysis and frequency band extension technology to match and adjust the frequency content of the preliminary synthetic seismic data to obtain synthetic seismic data.

[0048] For example, in some specific implementations, first, KL-3D GeoModeler three-dimensional geological modeling technology can be used to generate synthetic seismic data. This technology is centered on the construction of non-topologically consistent blocks, supports the fusion modeling of profile data, scattered point data, theoretical geometry and external level data, effectively improves the success rate of block construction and shortens the modeling cycle.

[0049] Furthermore, the frequency content of the synthetic seismic data can be adjusted according to the changes in sand thickness, hydrate saturation and conventional free gas volume in Model A and Model B to ensure that it matches the main frequency of the measured seismic data. Through the spectrum analysis and band extension technology of seismic data, the frequency response of the synthetic seismic data is ensured to match the measured data, thereby generating synthetic seismic data that conforms to the actual geological situation. This process involves a detailed analysis of the seismic data spectrum and the necessary band extension of the synthetic seismic data to achieve matching with the main frequency of the measured seismic data.

[0050] S400, performing frequency spectrum decomposition on the measured seismic data and the synthetic seismic data in sequence, and obtaining measured low-frequency data and synthetic low-frequency data accordingly; The synthetic low-frequency data includes first synthetic low-frequency data corresponding to the hydrate wedge model and second synthetic low-frequency data corresponding to the conventional gas wedge model; specifically, the spectrum decomposition is realized by discrete Fourier transform based on the preset main analysis frequency; For example, in some specific implementations, applying spectrum decomposition may be implemented as follows: 1) In this step, the measured seismic data set and the synthetic seismic data set are spectrally decomposed. For example, 15 Hz can be selected as the main analysis frequency. This selection is based on the spectrum parameters of the seismic data, where the main frequency is the frequency corresponding to the spectrum maximum, and 15 Hz can provide a good balance point to ensure appropriate anti-aliasing while avoiding information redundancy at the high frequency end.

[0051] 2) Extract low-frequency narrowband data using spectral decomposition technology. This technology is based on discrete Fourier transform (DFT) to convert seismic signals from the time domain to the frequency domain to generate high-resolution seismic images and identify the lateral distribution of medium properties.

[0052] S500, performing amplitude extraction of positive and negative phases on the measured low-frequency data to obtain a positive amplitude and a reverse amplitude; performing amplitude extraction on the first synthetic low-frequency data and the second synthetic low-frequency data in sequence to obtain a hydrate amplitude and a conventional gas amplitude accordingly; It should be noted that, in some embodiments, step S500 may include the following steps: extracting amplitude data from the measured low-frequency data using a phase scanning method, and then identifying the positive and negative phase characteristics of the amplitude in the amplitude data and their corresponding dominant positions to obtain positive amplitude and reverse amplitude.

[0053] For example, in some specific embodiments, the amplitude can be extracted from the measured low-frequency data to identify the positive and negative phase characteristics of the amplitude and their dominance. This process can be achieved by a phase scanning method, which determines the polarity of the seismic profile by comparing the correlation between the well impedance and the relative impedance of the well bypass inversion, as well as the phase of the seismic profile. In addition, the amplitude extraction of hydrate amplitude and conventional gas amplitude can be achieved by conventional amplitude extraction methods, which will not be described here.

[0054] S600: Compare and identify the forward amplitude with the hydrate amplitude, and the reverse amplitude with the conventional gas amplitude in sequence, to obtain identification results of natural gas hydrate and conventional free gas in the target exploration area.

[0055] It should be noted that the multiple parameter combinations include combinations of thickness and saturation in multiple numerical ranges for natural gas hydrates and combinations of distribution and content in multiple numerical ranges for conventional free gas; in some embodiments, step S600 may include the following steps: performing a first comparison and identification on the forward amplitude and the hydrate amplitude of the hydrate wedge model corresponding to the thickness and saturation in each numerical range to obtain a first identification result of the thickness and saturation of the natural gas hydrate; performing a second comparison and identification on the reverse amplitude and the conventional gas amplitude of the conventional gas wedge model corresponding to the distribution and content in each numerical range to obtain a second identification result of the distribution and content of the conventional free gas.

[0056] For example, in some specific implementations, the extracted amplitude is compared with the amplitude data corresponding to the synthetic seismic data. For areas where positive amplitude (i.e., positive amplitude) is dominant, the amplitude data corresponding to the synthetic seismic data of model A is compared; for areas where negative amplitude (i.e., negative amplitude) is dominant, the amplitude data corresponding to the synthetic seismic data of model B is compared. This comparison helps to verify the accuracy of the geological model and identify possible geological anomalies or features. Furthermore, based on the comparison results, the presence of natural gas hydrates and free gas and their data conditions are identified. Specifically, Figure 5 Taking the model A shown as an example, the amplitude data corresponding to the positive amplitude and the synthetic seismic data obtained with different hydrate contents in the model A are respectively judged for similarity, and then the identification result of the natural gas hydrate in the target exploration area is determined according to the hydrate content corresponding to the highest similarity.

[0057] It should also be noted that, in some embodiments, the method may also include the following steps: acquiring sampling data of the target exploration area; collecting the sampling data based on the wellbore coring technology; verifying the identification results based on the sampling data, and adjusting the parameters of the rock physics model according to the results of the verification processing.

[0058] For example, in some specific embodiments, assuming that the gap between the sampling data and the identification result is too large (for example, greater than a preset threshold), the distribution density of the data range of the various parameter combinations of the rock physics model settings can be adjusted accordingly according to the verified gap size (the larger the gap, the larger the distribution density setting).

[0059] In some specific application scenarios, verification and adjustment can be achieved as follows: 1) Verify exploration results. In the process of verifying exploration results, the sidewall coring technology is used to obtain core samples. In the coring operation, by using the sidewall coring device, it is possible to accurately determine whether the coring is successful and measure the length of the core. Spacers can be inserted between the cores to accurately distinguish the layers of the cores. This technology allows the key parameters of the instrument to be adjusted according to the characteristics of the formation, effectively improving the coring efficiency and success rate of coring. The sidewall coring device adopts a modular structure to facilitate the maintenance of the instrument.

[0060] 2) Adjust rock physics model and exploration parameters. Adjust rock physics model and exploration parameters based on core samples and verification results obtained from coring. This process involves a detailed analysis of core samples, including physical properties of the core such as porosity, permeability and elastic parameters of the rock. These parameters will be compared with seismic data to verify and adjust the rock physics model. The adjustment strategy includes re-evaluating the physical properties of the rock and their correlation with seismic data based on the core analysis results. In this way, it can be ensured that the adjusted model is more accurate and reliable, providing a scientific basis for the adjustment of exploration parameters. Such adjustments help optimize exploration strategies and improve the success rate and efficiency of exploration.

[0061] In order to explain the principle of the technical solution of the present invention in detail, the overall process of the present invention is described below in combination with some specific embodiments. It is easy to understand that the following is an explanation of the technical principle of the present invention and cannot be regarded as a limitation of the present invention.

[0062] First of all, it should be noted that the present invention can achieve the exploration of natural gas hydrates through the following steps: 1) Establish rock physics model: Well logging data (such as gamma ray, resistivity, acoustic velocity and density) are used to build velocity-density-thickness models of background clays and target sand bodies to accurately simulate geological structures.

[0063] 2) Generate synthetic seismic data: Two sets of synthetic seismic data are generated based on the geological model, one set represents pure gas hydrates and the other represents free gas under the gas hydrates. The synthetic seismic data are generated by simulating different geological conditions, such as changes in sand layer thickness, hydrate saturation, and free gas content.

[0064] 3) Apply spectral decomposition: Spectral decomposition of measured and synthetic seismic data is performed to extract low-frequency narrow-band data to highlight specific seismic features associated with gas hydrates and free gas.

[0065] 4) Amplitude extraction and comparison: Extract amplitudes from measured seismic data and compare them with synthetic seismic data. This includes identifying the positive and negative phase characteristics of the amplitude and their dominance to distinguish different types of geological structures.

[0066] like Figure 8 As shown, the method of the present invention may specifically include the following steps: Step 1: Data Collection: 1) Offshore platform logging system: The logging system is deployed on the offshore platform. The logging instrument is lowered into the oil well via a cable and uses a variety of sensors to record the physical properties of the rock. These instruments can measure the resistivity, acoustic velocity, radioactivity, electromagnetic properties and nuclear magnetic resonance properties of the rock, thereby obtaining detailed information about the rock and the fluid filling the rock.

[0067] 2) Collect logging data: During the logging process, the following key parameter data will be collected: resistivity data is used to determine the water content and mineral type of the rock formation; acoustic velocity data is used to infer the porosity, lithology and pressure of the formation; radioactivity data is used to determine the mud content of the formation; electromagnetic data is used to infer the porosity and fluid type of the rock; nuclear magnetic resonance data is used to obtain dynamic information of the fluid in the rock pores. These data are crucial to understanding the properties and distribution of underground rocks.

[0068] 3) Collect measured earthquake data sets: In the field, multiple geophones and seismic sources are deployed to collect 3D seismic data. These data help generate a three-dimensional image of the underground structure by recording the reflection and refraction information of seismic waves underground, which is important for identifying geological structures, faults, and boundaries of oil and gas reservoirs.

[0069] Among them, the technical requirements and operating specifications are as follows: During the data collection process, strict technical requirements and operating specifications will be followed, including the selection of appropriate instruments and equipment and regular calibration to ensure the accuracy and reliability of data collection. At the same time, the data of various indicators will be accurately collected, and attention will be paid to the consistency of time and space to ensure the continuity and integrity of the data. In addition, the geological structure, landform, soil quality and other conditions of the target area will be recorded and observed in detail, and information such as sample number, sampling depth, sampling layer and so on will be properly preserved. Data processing will include data collation, data analysis and data interpretation to ensure the reliability and effectiveness of exploration results. All personnel engaged in geological exploration must undergo safety awareness education and training, understand relevant safety regulations and systems, be familiar with operating procedures, and master necessary safety skills.

[0070] Step 2: Build a rock physics model 1) Use logging data to establish a velocity-density-thickness model to determine the physical parameters of the background clay layer and the target sand layer.

[0071] Assuming that the target sand layer is full of water, the physical parameters of water are used as the basis. When establishing the velocity-density-thickness model and determining the physical parameters of the background clay layer and the target sand layer, it is mainly based on the Biot theory, Gassmann equation and equivalent medium theory (the specific principle logic refers to the above-mentioned specific implementation method content, which will not be repeated here).

[0072] Through these theories and methods, the effects of natural gas hydrates and conventional free gas on rock physical properties under different saturation conditions can be quantitatively analyzed and predicted, thus providing a scientific basis for geological exploration and resource assessment.

[0073] 2) Build two models: Model A: It is assumed that there are gas hydrates of different thicknesses and saturations in the target sand layer.

[0074] Model B: It is assumed that there is conventional free gas with different distribution and content in the target sand layer.

[0075] When constructing Model A and Model B, the effects of different saturations of natural gas hydrate and conventional free gas on rock physical properties are considered mainly in the following ways: Model A (gas hydrate saturation model): In this model, the effects of hydrate morphology, distribution and saturation on rock physical properties are considered. The presence of hydrates affects the elastic properties of rocks and fluid flow characteristics, and these effects are quantified using Biot theory and equivalent medium theory.

[0076] Model B (conventional free gas saturation model): In this model, the effects of the presence and saturation of conventional free gas on rock physical properties are considered. Free gas affects the porosity, permeability, and elastic wave velocity of rocks, and these effects are described by the Gassmann equation and equivalent medium theory.

[0077] Step 3: Generate synthetic seismic data: Two sets of synthetic seismic data are generated based on Model A and Model B.

[0078] 1) In this step, KL-3D GeoModeler 3D geological modeling technology is used to generate synthetic seismic data. This technology is centered on the construction of non-topologically consistent blocks and supports the fusion modeling of profile data, scattered point data, theoretical geometry, and external layer data, effectively improving the success rate of block construction and shortening the modeling cycle.

[0079] 2) According to the changes in sand thickness, hydrate saturation and conventional free gas volume in Model A and Model B, the frequency content of the synthetic seismic data is adjusted to ensure that it matches the main frequency of the measured seismic data. Through the spectrum analysis and band extension technology of seismic data, the frequency response of the synthetic seismic data is ensured to match the measured data, thereby generating synthetic seismic data that conforms to the actual geological situation. This process involves a detailed analysis of the seismic data spectrum and the necessary band extension of the synthetic seismic data to achieve matching with the main frequency of the measured seismic data.

[0080] Step 4: Apply spectral decomposition: 1) In this step, the measured seismic data set and the synthetic seismic data set are spectrally decomposed. 15 Hz is selected as the main analysis frequency. This selection is based on the spectral parameters of the seismic data, where the main frequency is the frequency corresponding to the spectral maximum, and 15 Hz can provide a good balance point to ensure appropriate anti-aliasing while avoiding information redundancy at the high frequency end.

[0081] 2) Extract low-frequency narrowband data using spectral decomposition technology. This technology is based on discrete Fourier transform (DFT) to convert seismic signals from the time domain to the frequency domain to generate high-resolution seismic images and identify the lateral distribution of medium properties.

[0082] Step 5: Amplitude extraction and comparison: 1) Extract the amplitude from the measured low-frequency data and identify the positive and negative phase characteristics of the amplitude and their dominance. This process can be achieved through the phase scanning method, which determines the polarity of the seismic section by comparing the correlation between the well impedance and the relative impedance inverted by the well bypass channel and the phase of the seismic section.

[0083] 2) Compare the extracted amplitudes with the low-frequency data corresponding to the synthetic seismic data. For areas where positive amplitudes are dominant, compare with the synthetic seismic data of model A; for areas where negative amplitudes are dominant, compare with the synthetic seismic data of model B. This comparison helps to verify the accuracy of the geological model and identify possible geological anomalies or features.

[0084] Step 6: Identify and explain: 1) Based on the comparison results, identify the presence of natural gas hydrate and free gas.

[0085] 2) Determine the saturation and thickness of gas hydrates.

[0086] 3) Determine the distribution and content of conventional free gas.

[0087] Step 7: Verify and adjust: 1) Verify exploration results. In the process of verifying exploration results, the sidewall coring technology is used to obtain core samples. In the coring operation, by using the sidewall coring device, it is possible to accurately determine whether the coring is successful and measure the length of the core. Spacers can be inserted between the cores to accurately distinguish the layers of the cores. This technology allows the key parameters of the instrument to be adjusted according to the characteristics of the formation, effectively improving the coring efficiency and success rate of coring. The sidewall coring device adopts a modular structure to facilitate the maintenance of the instrument.

[0088] 2) Adjust rock physics model and exploration parameters. Adjust rock physics model and exploration parameters based on core samples and verification results obtained from coring. This process involves a detailed analysis of core samples, including physical properties of the core such as porosity, permeability and elastic parameters of the rock. These parameters will be compared with seismic data to verify and adjust the rock physics model. The adjustment strategy includes re-evaluating the physical properties of the rock and their correlation with seismic data based on the core analysis results. In this way, it can be ensured that the adjusted model is more accurate and reliable, providing a scientific basis for the adjustment of exploration parameters. Such adjustments help optimize exploration strategies and improve the success rate and efficiency of exploration.

[0089] In summary, the present invention proposes the use of rock physics models to simulate and predict the seismic response of gas hydrates. This method can help to more accurately identify and quantify the distribution of gas hydrates. By establishing a geological model and a physical parameter model, synthetic seismic data can be generated, which are used to simulate the response of gas hydrates that may appear in actual seismic data. The invention mentions the use of spectral decomposition technology to analyze seismic data, which helps to identify specific frequency features associated with gas hydrates. By comparing measured seismic data with synthetic seismic data, the presence and characteristics of gas hydrates and related free gas can be identified. The goal of this technology is to improve the success rate and efficiency of gas hydrate exploration through more accurate identification and quantification methods. In general, the background of this technology is to develop new exploration and characterization methods to address the challenges in gas hydrate exploration in the context of global energy demand, so as to achieve effective utilization of this potential energy resource.

[0090] Compared with the prior art, the present invention has at least the following beneficial effects: 1) Improve the accuracy of resource assessment: More accurately identify the presence of natural gas hydrates and conventional free gas, improving the accuracy of resource assessment.

[0091] 2) Reducing exploration risks: By improving exploration accuracy, the present invention helps to reduce drilling risks and costs.

[0092] 3) Reduction of environmental impact: Through more precise exploration methods, disturbance and damage to the environment are reduced.

[0093] 4) Improve exploration efficiency: The efficiency of the exploration process is improved by using computer simulation and automated analysis.

[0094] 5) Support sustainable development: Help discover new energy resources and support sustainable development of energy.

[0095] 6) Flexibility of technology application: The method of the present invention can adapt to different geological conditions and exploration environments and has high flexibility.

[0096] The present invention, through its innovative methods and technologies, not only improves the accuracy and efficiency of natural gas hydrate exploration, but also helps to reduce exploration risks and environmental impacts, bringing significant beneficial effects to the field of energy exploration.

[0097] On the other hand, Fig. 9 As shown, an embodiment of the present invention provides a natural gas hydrate and conventional free gas identification device 900, which may include: The first module 901 is used to obtain well logging data and measured seismic data in the target exploration area; The second module 902 is used to obtain a rock physical model based on the well logging data through a preset layered structure; wherein the layered structure includes a background clay layer and a target sand layer; the rock physical model includes a hydrate wedge model and a conventional gas wedge model; the target sand layer of the hydrate wedge model presets a natural gas hydrate with multiple parameter combinations, and the target sand layer of the conventional gas wedge model presets a conventional free gas with multiple parameter combinations; The third module 903 is used to generate synthetic seismic data based on the rock physics model; the synthetic seismic data includes first synthetic seismic data corresponding to the hydrate wedge model and second synthetic seismic data corresponding to the conventional gas wedge model; The fourth module 904 is used to perform spectrum decomposition on the measured seismic data and the synthetic seismic data in sequence, and obtain measured low-frequency data and synthetic low-frequency data accordingly; the synthetic low-frequency data includes first synthetic low-frequency data corresponding to the hydrate wedge model and second synthetic low-frequency data corresponding to the conventional gas wedge model; The fifth module 905 is used to extract the amplitude of the positive and negative phases of the measured low-frequency data to obtain the positive amplitude and the reverse amplitude; extract the amplitude of the first synthetic low-frequency data and the second synthetic low-frequency data in sequence to obtain the hydrate amplitude and the conventional gas amplitude respectively; The sixth module 906 is used to compare and identify the forward amplitude with the hydrate amplitude, and the reverse amplitude with the conventional gas amplitude in sequence, to obtain the identification results of the natural gas hydrate and conventional free gas in the target exploration area.

[0098] In some embodiments, the apparatus may further include: The seventh module is used to obtain sampling data of the target exploration area; the sampling data is collected based on the well wall coring technology; The eighth module is used to verify the identification results based on the sampling data and adjust the parameters of the rock physics model according to the verification results.

[0099] The contents of the method embodiments of the present invention are all applicable to the device embodiments. The functions specifically implemented by the device embodiments are the same as those of the above method embodiments, and the beneficial effects achieved are also the same as those achieved by the above method embodiments.

[0100] On the other hand, an embodiment of the present invention further provides an electronic device, the electronic device comprising a memory and a processor, the memory storing a computer program, and the processor implementing the above-mentioned method for identifying natural gas hydrates and conventional free gas when executing the computer program. The electronic device can be any intelligent terminal including a tablet computer, a car computer, etc.

[0101] It can be understood that the contents of the above method embodiments are all applicable to the present device embodiments, the functions specifically implemented by the present device embodiments are the same as those of the above method embodiments, and the beneficial effects achieved are also the same as those achieved by the above method embodiments.

[0102] like Fig.10 As shown, Fig.10 The hardware structure of an electronic device 1000 of another embodiment is illustrated. The electronic device 1000 includes: The processor 1001 may be implemented by a general-purpose CPU (Central Processing Unit), a microprocessor, an application-specific integrated circuit (application-specific integrated circuit, aSIC), or one or more integrated circuits, and is used to execute relevant programs to implement the technical solutions provided in the embodiments of the present invention; The memory 1002 can be implemented in the form of a read-only memory (ROM), a static storage device, a dynamic storage device, or a random access memory (RAM). The memory 1002 can store an operating system and other application programs. When the technical solution provided in the embodiment of this specification is implemented by software or firmware, the relevant program code is stored in the memory 1002, and the processor 1001 calls and executes the network node population optimization method of the embodiment of the present invention; Input / output interface 1003, used to implement information input and output; Communication interface 1004, used to realize communication interaction between the device and other devices, which can be realized through wired mode (such as USB, network cable, etc.) or wireless mode (such as mobile network, WIFI, Bluetooth, etc.); A bus 1005 , which transmits information between various components of the device (e.g., the processor 1001 , the memory 1002 , the input / output interface 1003 , and the communication interface 1004 ); The processor 1001 , the memory 1002 , the input / output interface 1003 and the communication interface 1004 are connected to each other in communication within the device via the bus 1005 .

[0103] The electronic device embodiments described above are merely illustrative, and the units described as separate components may or may not be physically separated, that is, they may be located in one place, or they may be distributed on multiple network units. Some or all of the modules may be selected according to actual needs to achieve the purpose of the solution of this embodiment.

[0104] The contents of the method embodiments of the present invention are all applicable to the electronic device embodiments. The functions specifically implemented by the electronic device embodiments are the same as those of the above method embodiments, and the beneficial effects achieved are also the same as those achieved by the above method embodiments.

[0105] Another aspect of an embodiment of the present invention further provides a computer-readable storage medium, wherein the storage medium stores a program, and the program is executed by a processor to implement the above method.

[0106] It should be noted that the computer-readable medium shown in the embodiment of the present invention may be a computer-readable signal medium or a computer-readable storage medium or any combination of the above two. The computer-readable storage medium may be, for example, but not limited to, an electrical, magnetic, optical, electromagnetic, infrared, or semiconductor system, device or device, or any combination of the above. More specific examples of computer-readable storage media may include, but are not limited to: an electrical connection with one or more wires, a portable computer disk, a hard disk, a random access memory (RAM), a read-only memory (ROM), an erasable programmable read-only memory (EPROM), a flash memory, an optical fiber, a portable compact disk read-only memory (Compact Disc Read to Only Memory, CD to ROM), an optical storage device, a magnetic storage device, or any suitable combination of the above. In the present invention, a computer-readable storage medium may be any tangible medium containing or storing a program, which may be used by or in combination with an instruction execution system, device or device. In the present invention, a computer-readable signal medium may include a data signal propagated in a baseband or as part of a carrier wave, which carries a computer-readable program code. Such propagated data signals may take a variety of forms, including but not limited to electromagnetic signals, optical signals, or any suitable combination of the above. Computer readable signal media may also be any computer readable medium other than computer readable storage media, which may send, propagate, or transmit programs for use by or in conjunction with an instruction execution system, apparatus, or device. The program code contained on the computer readable medium may be transmitted using any suitable medium, including but not limited to: wireless, wired, etc., or any suitable combination of the above.

[0107] The contents of the method embodiments of the present invention are all applicable to the computer-readable storage medium embodiments. The functions specifically implemented by the computer-readable storage medium embodiments are the same as those of the above method embodiments, and the beneficial effects achieved are also the same as those achieved by the above method embodiments.

[0108] The embodiment of the present invention also discloses a computer program product or a computer program, which includes a computer instruction stored in a computer-readable storage medium. A processor of a computer device can read the computer instruction from the computer-readable storage medium, and the processor executes the computer instruction, so that the computer device executes the above method.

[0109] The flow chart and block diagram in the accompanying drawings illustrate the possible architecture, function and operation of the system, method and computer program product according to various embodiments of the present invention. In this regard, each box in the flow chart or block diagram can represent a module, a program segment, or a part of a code, and the above-mentioned module, program segment, or a part of a code contains one or more executable instructions for realizing the specified logical function. It should also be noted that in some alternative implementations, the functions marked in the box can also occur in a different order from the order marked in the accompanying drawings. For example, two boxes represented in succession can actually be executed substantially in parallel, and they can sometimes be executed in the opposite order, depending on the functions involved. It should also be noted that each box in the block diagram or flow chart, and the combination of the boxes in the block diagram or flow chart can be implemented with a dedicated hardware-based system that performs a specified function or operation, or can be implemented with a combination of dedicated hardware and computer instructions.

[0110] It should be noted that, although several modules of the device for action execution are mentioned in the above detailed description, this division is not mandatory. In fact, according to an embodiment of the present invention, the features and functions of two or more modules or units described above can be embodied in one module or unit. On the contrary, the features and functions of one module or unit described above can be further divided into being embodied by multiple modules or units.

[0111] Through the description of the above implementation, it is easy for those skilled in the art to understand that the example implementation described here can be implemented by software, or by software combined with necessary hardware. Therefore, the technical solution according to the implementation of the present invention can be embodied in the form of a software product, which can be stored in a non-volatile storage medium (which can be a CD to ROM, a USB flash drive, a mobile hard disk, etc.) or on a network, and includes several instructions to enable a computing device (which can be a personal computer, a server, a touch terminal, or a network device, etc.) to execute the method according to the implementation of the present invention.

[0112] In some selectable embodiments, the function / operation mentioned in the block diagram may not occur in the order mentioned in the operation diagram. For example, depending on the function / operation involved, the two boxes shown in succession can actually be executed substantially simultaneously or the boxes can sometimes be executed in reverse order. In addition, the embodiment presented and described in the flow chart of the present invention is provided by way of example, for the purpose of providing a more comprehensive understanding of technology. The disclosed method is not limited to the operation and logic flow presented herein. Selectable embodiments are expected, wherein the order of various operations is changed and the sub-operation of a part for which is described as a larger operation is performed independently.

[0113] In addition, although the present invention is described in the context of functional modules, it should be understood that, unless otherwise specified, one or more of the functions and / or features can be integrated into a single physical device and / or software module, or one or more functions and / or features can be implemented in a separate physical device or software module. It is also understood that a detailed discussion of the actual implementation of each module is unnecessary for understanding the present invention. More specifically, in view of the properties, functions and internal relationships of the various functional modules in the device disclosed herein, the actual implementation of the module will be understood within the conventional skills of the engineer. Therefore, those skilled in the art can implement the present invention set forth in the claims without excessive experimentation using ordinary techniques. It is also understood that the specific concepts disclosed are merely illustrative and are not intended to limit the scope of the present invention, which is determined by the full scope of the appended claims and their equivalents.

[0114] If the function is implemented in the form of a software functional unit and sold or used as an independent product, it can be stored in a computer-readable storage medium. Based on this understanding, the technical solution of the present invention, or the part that contributes to the prior art, or the part of the technical solution, can be embodied in the form of a software product. The computer software product is stored in a storage medium, including several instructions for a computer device (which can be a personal computer, server, or network device, etc.) to perform all or part of the steps of the methods of various embodiments of the present invention. The aforementioned storage medium includes: U disk, mobile hard disk, read-only memory (ROM, Read Only Memory), random access memory (RAM, Random Access Memory), disk or optical disk, etc. Various media that can store program codes.

[0115] The logic and / or steps represented in the flowchart or otherwise described herein, for example, may be considered as an ordered list of executable instructions for implementing logical functions, and may be embodied in any computer-readable medium for use by an instruction execution device, apparatus or device (such as a computer-based device, a device including a processor, or other device that can fetch instructions from an instruction execution device, apparatus or device and execute the instructions), or in conjunction with such instruction execution device, apparatus or device. For purposes of this specification, "computer-readable medium" may be any device that can contain, store, communicate, propagate or transmit a program for use by an instruction execution device, apparatus or device, or in conjunction with such instruction execution device, apparatus or device.

[0116] More specific examples of computer-readable media (a non-exhaustive list) include the following: an electrical connection with one or more wires (electronic device), a portable computer disk case (magnetic device), a random access memory (RAM), a read-only memory (ROM), an erasable and programmable read-only memory (EPROM or flash memory), an optical fiber device, and a portable compact disk read-only memory (CDROM). In addition, the computer-readable medium may even be a paper or other suitable medium on which the program is printed, since the program may be obtained electronically, for example, by optically scanning the paper or other medium, followed by editing, deciphering or processing in another suitable manner as necessary, and then stored in a computer memory.

[0117] It should be understood that the various parts of the present invention can be implemented by hardware, software, firmware or a combination thereof. In the above-mentioned embodiments, multiple steps or methods can be implemented by software or firmware stored in a memory and executed by a suitable instruction execution device. For example, if implemented by hardware, as in another embodiment, it can be implemented by any one of the following technologies known in the art or their combination: a discrete logic circuit having a logic gate circuit for implementing a logic function for a data signal, a dedicated integrated circuit having a suitable combination of logic gate circuits, a programmable gate array (PGA), a field programmable gate array (FPGA), etc.

[0118] In the description of this specification, the description with reference to the terms "one embodiment", "some embodiments", "example", "specific example", or "some examples" means that the specific features, structures, materials or characteristics described in conjunction with the embodiment or example are included in at least one embodiment or example of the present invention. 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 any one or more embodiments or examples in a suitable manner.

[0119] Although the embodiments of the present invention have been shown and described, it will be appreciated by those skilled in the art that various changes, modifications, substitutions and variations may be made to the embodiments without departing from the principles and spirit of the present invention, and that the scope of the present invention is defined by the claims and their equivalents.

[0120] The above is a specific description of the preferred implementation of the present invention, but the present invention is not limited to the embodiments. Those skilled in the art can make various equivalent modifications or substitutions without violating the spirit of the present invention. These equivalent modifications or substitutions are all included in the scope defined by the claims of the present invention.

Claims

1. A method for identifying natural gas hydrates and conventional free gas, characterized in that: The following steps are involved: Acquire well logging data and measured seismic data in the target exploration area; the well logging data includes resistivity data, acoustic wave velocity data, radioactivity data, electromagnetic data and nuclear magnetic resonance data; Based on the logging data, a rock physics model is obtained by constructing a preset layered structure; wherein the layered structure includes a background clay layer and a target sand body layer; the rock physics model includes a hydrate wedge model and a conventional gas wedge model; the target sand body layer of the hydrate wedge model presets natural gas hydrates with multiple parameter combinations, and the target sand body layer of the conventional gas wedge model presets conventional free gas with multiple parameter combinations; Generate synthetic seismic data based on the rock physics model; the synthetic seismic data includes first synthetic seismic data corresponding to the hydrate wedge model and second synthetic seismic data corresponding to the conventional gas wedge model; Performing spectral decomposition on the measured seismic data and the synthetic seismic data in sequence to obtain measured low-frequency data and synthetic low-frequency data correspondingly; the synthetic low-frequency data includes first synthetic low-frequency data corresponding to the hydrate wedge model and second synthetic low-frequency data corresponding to the conventional gas wedge model; Perform amplitude extraction of positive and negative phases on the measured low-frequency data to obtain a positive amplitude and a reverse amplitude; perform amplitude extraction on the first synthetic low-frequency data and the second synthetic low-frequency data in sequence to obtain a hydrate amplitude and a conventional gas amplitude respectively; The forward amplitude and the hydrate amplitude, as well as the reverse amplitude and the conventional gas amplitude are compared and identified in turn to obtain identification results of the natural gas hydrate and conventional free gas in the target exploration area.

2. The method for identifying natural gas hydrate and conventional free gas according to claim 1, characterized in that: The step of obtaining the well logging data and measured seismic data of the target exploration area comprises the following steps: Deploy a well logging system in the target exploration area, and obtain the well logging data of the target exploration area through the well logging system; A seismic source is arranged in the target exploration area, seismic waves are emitted by the seismic source, and then reflection and refraction information of the seismic waves in the target exploration area are recorded by a geophone to obtain the measured seismic data.

3. The method for identifying natural gas hydrate and conventional free gas according to claim 1, characterized in that: The logging data includes resistivity data, acoustic wave velocity data, radioactivity data, electromagnetic data and nuclear magnetic resonance data; the rock physics model is obtained based on the logging data through a preset layered structure, including the following steps: Determine the properties and distribution information of underground rocks in the target exploration area based on the well logging data; The property and distribution information includes: water content and mineral type determined based on the resistivity data; porosity, lithology and pressure determined based on the acoustic wave velocity data; mud content determined based on the radioactivity data; porosity and fluid type determined based on the electromagnetic data; dynamic information of fluid in the void determined based on the nuclear magnetic resonance data; According to the properties and distribution information and the preset multiple parameter combinations of the natural gas hydrate and the conventional free gas, the rock physics model is constructed based on the layered structure through a preset quantitative theoretical method.

4. The method for identifying natural gas hydrate and conventional free gas according to claim 1, characterized in that: The generating of synthetic seismic data based on the rock physics model comprises the following steps: Based on the rock physics model, generating preliminary synthetic seismic data using three-dimensional geological modeling technology; According to the main frequency of the measured seismic data, the frequency content of the preliminary synthetic seismic data is matched and adjusted by using spectrum analysis and frequency band extension technology to obtain the synthetic seismic data.

5. The method for identifying natural gas hydrate and conventional free gas according to claim 1, characterized in that: The step of extracting the amplitude of the positive and negative phases of the measured low-frequency data to obtain the positive amplitude and the reverse amplitude comprises the following steps: Amplitude data is extracted from the measured low-frequency data using a phase scanning method, and then the positive and negative phase characteristics of the amplitude in the amplitude data and their corresponding dominant positions are identified to obtain the positive amplitude and the reverse amplitude.

6. The method for identifying natural gas hydrate and conventional free gas according to claim 1, characterized in that: The plurality of parameter combinations include a combination of thickness and saturation in a plurality of numerical ranges for the natural gas hydrate and a combination of distribution and content in a plurality of numerical ranges for the conventional free gas; the forward amplitude and the hydrate amplitude, and the reverse amplitude and the conventional gas amplitude are sequentially compared and identified to obtain the identification results of the natural gas hydrate and the conventional free gas in the target exploration area, including the following steps: Performing a first comparison and identification on the forward amplitude and the hydrate amplitude of the hydrate wedge model corresponding to the thickness and saturation in each numerical range, to obtain a first identification result of the thickness and saturation of the natural gas hydrate; A second comparison and identification is performed on the reverse amplitude and the conventional gas amplitude of the conventional gas wedge model corresponding to the distribution and content of each numerical range to obtain a second identification result of the distribution and content of the conventional free gas.

7. The method for identifying natural gas hydrate and conventional free gas according to claim 1, characterized in that: The method further comprises the following steps: Acquiring sampling data of the target exploration area; the sampling data is collected based on the well wall coring technology; The identification result is verified based on the sampling data, and parameters of the rock physics model are adjusted according to the result of the verification.

8. A device for identifying natural gas hydrates and conventional free gas, characterized in that: include: The first module is used to obtain well logging data and measured seismic data in the target exploration area; The logging data includes resistivity data, acoustic wave velocity data, radioactivity data, electromagnetic data and nuclear magnetic resonance data; The second module is used to obtain a rock physical model based on the logging data through a preset layered structure; wherein the layered structure includes a background clay layer and a target sand body layer; the rock physical model includes a hydrate wedge model and a conventional gas wedge model; the target sand body layer of the hydrate wedge model presets a natural gas hydrate with a plurality of parameter combinations, and the target sand body layer of the conventional gas wedge model presets a conventional free gas with a plurality of parameter combinations; A third module is used to generate synthetic seismic data based on the rock physics model; the synthetic seismic data includes first synthetic seismic data corresponding to the hydrate wedge model and second synthetic seismic data corresponding to the conventional gas wedge model; A fourth module is used to perform spectral decomposition on the measured seismic data and the synthetic seismic data in sequence, and obtain measured low-frequency data and synthetic low-frequency data correspondingly; the synthetic low-frequency data includes first synthetic low-frequency data corresponding to the hydrate wedge model and second synthetic low-frequency data corresponding to the conventional gas wedge model; The fifth module is used to extract the amplitude of the positive and negative phases of the measured low-frequency data to obtain the positive amplitude and the reverse amplitude; perform amplitude extraction on the first synthetic low-frequency data and the second synthetic low-frequency data in sequence to obtain the hydrate amplitude and the conventional gas amplitude respectively; The sixth module is used to compare and identify the forward amplitude and the hydrate amplitude, and the reverse amplitude and the conventional gas amplitude in turn, to obtain the identification results of the natural gas hydrate and conventional free gas in the target exploration area.

9. An electronic device, characterized in that: including a processor and a memory; The memory is used to store programs; The processor executes the program to implement the method according to any one of claims 1 to 7.

10. A computer storage medium storing a program executable by a processor, characterized in that: The program executable by the processor is used to implement the method according to any one of claims 1 to 7 when executed by the processor.

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