Method and system for quantitatively depicting distribution of different types of hydrocarbon source rocks in less-well area

Abstract

The invention belongs to the technical field of oil and gas exploration and development, and relates to a method and system for quantitatively depicting distribution of different types of hydrocarbon source rocks in a few-well area, and the method comprises the steps: obtaining a seismic body, a sedimentary facies diagram, interval transit time logging data and density logging data after target lamination; hydrocarbon source rock seismic reflection characteristics corresponding to different deposits are obtained through a seismic profile map obtained by intercepting a post-stack seismic body; analyzing the types of the hydrocarbon source rocks by utilizing a sedimentary facies diagram, and depicting plane distribution of different types of hydrocarbon source rocks in a target layer according to different types of hydrocarbon source rock development characteristics and sedimentary facies predicted by utilizing the seismic reflection characteristics of the hydrocarbon source rocks; the residual stratum thickness of the target layer is obtained according to the post-stack seismic body, the stratum sand-to-ground ratio of the target layer is predicted, and hydrocarbon source rock thickness distribution in the target layer is depicted according to the residual stratum thickness and the stratum sand-to-ground ratio; and carrying out coupling analysis on the hydrocarbon source rock plane distribution and the hydrocarbon source rock thickness distribution to obtain hydrocarbon source rock space distribution. According to the method, distribution of different types of hydrocarbon source rocks in the less-well area is quantitatively depicted.

Description

Technical Field

[0001] This application belongs to the technical field of oil and gas exploration and development, involves acoustic far-detection imaging logging technology, and specifically relates to a method and system for quantitatively depicting the distribution of different types of source rocks in areas with few wells. Background Art

[0002] In the field of oil and gas exploration, source rocks refer to rocks that have generated, may generate, or have the potential to generate oil and gas. Their distribution characteristics and contact relationships with migration channels play an important controlling role in the migration and accumulation of oil and gas. Currently, conventional source rock evaluation methods mainly rely on single-well stratigraphic development data to obtain the relative content of the thickness of dark mudstone and formation thickness revealed by different drill wells, and combine sedimentary facies analysis for planar digitization to form data such as the planar distribution of the dark mudstone ratio. Subsequently, the thickness of mudstone is calibrated through seismic inversion profiles to infer the distribution of source rocks.

[0003] However, in low-exploration areas, due to limited drilling and coring data, traditional source rock evaluation methods based on geochemistry and logging data are difficult to meet the requirements of high-precision resource quantity calculation. In these areas, the identification and prediction of source rocks rely more on seismic data, especially seismic inversion technology. Seismic inversion technology combines geophysical data and geological data, calibrates seismic reflection characteristics, and establishes a seismic identification model for source rocks to identify the seismic characteristics and development patterns of source rocks and predict the spatial distribution of source rocks. However, this method is mainly used for qualitatively depicting the distribution of source rocks and is difficult to meet the requirements of high-precision resource assessment. Summary of the Invention

[0004] In view of the problems existing in the prior art, this application provides a method and system for quantitatively depicting the distribution of different types of source rocks in areas with few wells. By combining seismic inversion and seismic multi-attribute analysis, it directly predicts source rocks. The required data is simple, applicable to the identification and prediction of source rocks in areas with few wells, and meets the requirements of high-precision resource assessment.

[0005] In the first aspect of this application, a method for quantitatively depicting the distribution of different types of source rocks in areas with few wells is provided. The steps are as follows: Data acquisition step: Obtain the stacked seismic volume of the target layer, sedimentary facies map, acoustic travel-time logging data, and density logging data; Data processing step: Intercept the stacked seismic volume to obtain a seismic profile, and obtain the seismic reflection characteristics of source rocks corresponding to different sedimentary facies through the seismic profile; Source rock planar distribution depiction step: Analyze the source rock types using the sedimentary facies map, predict the development characteristics of different types of source rocks using the seismic reflection characteristics of source rocks, and depict the planar distribution of different types of source rocks in the target layer based on the development characteristics of different types of source rocks and sedimentary facies; Steps for depicting the longitudinal thickness distribution of source rocks: Obtain the residual formation thickness of the target layer from the post-stack seismic volume. Predict the sand-to-shale ratio of the target layer using seismic inversion method based on the post-stack seismic volume, acoustic time difference logging data, and density logging data, or predict the sand-to-shale ratio of the target layer using seismic attribute analysis method based on the post-stack seismic volume. Depict the thickness distribution of source rocks in the target layer according to the residual formation thickness and the sand-to-shale ratio. Steps for the distribution of source rocks: Coupling and analyzing the planar distribution and thickness distribution of source rocks to obtain the spatial distribution of source rocks.

[0006] In some embodiments, in the steps for depicting the longitudinal thickness distribution of source rocks, the method for predicting the sand-to-shale ratio using seismic inversion method based on the post-stack seismic volume, acoustic time difference logging data, and density logging data is as follows: Steps for determining boundary values: Calculate the wave impedance values of sandstone and mudstone in the target layer based on the acoustic time difference logging data and density logging data. Analyze the wave impedance characteristics of sandstone and mudstone in the target layer, and determine the wave impedance boundary values of sandstone and mudstone. Inversion steps: Perform wave impedance inversion on the post-stack seismic volume through seismic inversion software to obtain a wave impedance inversion profile. Judgment steps: Based on the wave impedance boundary values of sandstone and mudstone, conduct lithology determination for each sampling point on the wave impedance inversion profile. When the wave impedance value is greater than the wave impedance boundary values of sandstone and mudstone, determine that the corresponding formation at this point is sandstone; when the wave impedance is less than the wave impedance boundary values of sandstone and mudstone, determine it as mudstone. Calculation steps: In the target layer, for each seismic trace, count the number of sampling points Ns identified as sandstone and the total number of sampling points Nt, and calculate the sand-to-shale ratio of this seismic trace according to the number of sampling points Ns and the total number of sampling points Nt. Sand-to-shale ratio = Ns / Nt Integration steps: Integrate the sand-to-shale ratios of each seismic trace with the corresponding position information to obtain the sand-to-shale ratio of the target layer.

[0007] In some embodiments, in the steps for depicting the longitudinal thickness distribution of source rocks, the method for predicting the sand-to-shale ratio using seismic attribute analysis method based on the post-stack seismic volume is as follows: Extraction steps: Convert the post-stack seismic volume into a seismic attribute volume, and extract the root mean square amplitude seismic attribute from the seismic attribute volume to obtain a root mean square amplitude profile of the seismic. Steps for determining the root mean square amplitude value: According to the sedimentary facies distribution range, set up virtual wells. On the root mean square amplitude profile of the seismic, find the corresponding positions of the virtual wells and read the root mean square amplitude values at these positions. Calculation steps: Substitute the read root mean square amplitude value into the fitting relationship formula between the sand-to-shale ratio and the root mean square amplitude to obtain the sand-to-shale ratio of the target layer.

[0008] In some embodiments, the fitting relationship formula between the sand-to-shale ratio and the root mean square amplitude is expressed as: Sand ratio = 0.2002·Root mean square amplitude – 0.0098.

[0009] In some embodiments, in the step of depicting the vertical thickness distribution of the source rock, the method for obtaining the residual formation thickness from the post-stack seismic volume is as follows: Identification step: On the seismic profile, identify the seismic times t1 and t2 corresponding to the top and bottom interfaces of the target layer; Depth calculation step: Substitute the seismic times t1 and t2 into the actual drilling time-depth conversion relationship to obtain the formation depth corresponding to the top interface of the target layer and the depth corresponding to the bottom interface of the target layer; Residual thickness calculation step: Subtract the formation depth corresponding to the top interface of the target layer from the depth corresponding to the bottom interface of the target layer to obtain the residual formation thickness of the target layer.

[0010] In the second aspect of the present application, a system for quantitatively depicting the distribution of different types of source rocks in a well-poor area is provided, which is used to implement the method for quantitatively depicting the distribution of different types of source rocks in a well-poor area described in the first aspect of the present application, and includes: A data acquisition module, configured to acquire the post-stack seismic volume of the target layer, sedimentary facies map, acoustic time difference logging data, and density logging data; A data processing module, which intercepts the post-stack seismic volume to obtain a seismic profile, and obtains the seismic reflection characteristics of the source rock corresponding to different sedimentary facies through the seismic profile; A source rock planar distribution depiction module, which analyzes the source rock type using the sedimentary facies map, predicts the development characteristics of different types of source rocks using the seismic reflection characteristics of the source rock, and depicts the planar distribution of different types of source rocks in the target layer according to the development characteristics of different types of source rocks and sedimentary facies; A source rock vertical thickness distribution depiction module, which obtains the residual formation thickness of the target layer from the post-stack seismic volume, predicts the formation sand ratio of the target layer using seismic inversion method based on the post-stack seismic volume, acoustic time difference logging data, and density logging data, or predicts the formation sand ratio of the target layer using seismic attribute analysis method based on the post-stack seismic volume, and depicts the source rock thickness distribution in the target layer according to the residual formation thickness and formation sand ratio; A source rock distribution module, which performs coupled analysis on the planar distribution and thickness distribution of the source rock to obtain the spatial distribution of the source rock.

[0011] In some embodiments, the source rock planar distribution depiction module includes: A sedimentary facies analysis module, which analyzes the source rock type using the sedimentary facies map; A characteristic prediction module, which predicts the development characteristics of different types of source rocks using the seismic reflection characteristics of the source rock; A planar distribution depiction module, which depicts the planar distribution of different types of source rocks in the target layer according to the development characteristics of different types of source rocks and sedimentary facies.

[0012] In some embodiments, the hydrocarbon source rock vertical thickness distribution characterization module includes: A residual formation thickness calculation module that obtains the residual formation thickness of the target layer from the post-stack seismic volume, A sand-to-shale ratio prediction module that predicts the formation sand-to-shale ratio of the target layer using seismic inversion based on the post-stack seismic volume, acoustic time difference logging data, and density logging data, or predicts the formation sand-to-shale ratio of the target layer using seismic attribute analysis based on the post-stack seismic volume, A thickness distribution characterization module that characterizes the thickness distribution of the hydrocarbon source rock in the target layer based on the residual formation thickness and the formation sand-to-shale ratio.

[0013] Compared with the prior art, the advantages and positive effects of the present application are as follows: The method and system for quantitatively characterizing the distribution of different types of hydrocarbon source rocks in a low-well area provided by the present application are based on multi-source data. On the basis of data processing, the planar distribution and vertical thickness distribution of the hydrocarbon source rock are respectively characterized. The planar distribution is characterized using the sedimentary facies map and seismic reflection characteristics, which can clearly present the distribution range of different types of hydrocarbon source rocks on the plane; the thickness distribution is characterized by combining seismic inversion or seismic attribute analysis with the residual formation thickness, accurately describing the vertical variation of the hydrocarbon source rock. Finally, the planar and thickness distributions are coupled to obtain intuitive and comprehensive spatial distribution information of the hydrocarbon source rock. The required data is simple, providing a complete solution for the study of hydrocarbon source rocks in low-well areas. BRIEF DESCRIPTION OF THE DRAWINGS

[0014] Figure 1 is a flowchart of the method for quantitatively characterizing the distribution of different types of hydrocarbon source rocks in a low-well area according to an embodiment of the present application; Figure 2 is a flowchart of the method for characterizing the planar distribution of different types of hydrocarbon source rocks in the target layer according to an embodiment of the present application; Figure 3 is a flowchart of the method for characterizing the thickness distribution of the hydrocarbon source rock in the target layer according to an embodiment of the present application; Figure 4 is a flowchart of the method for obtaining the residual formation thickness from the post-stack seismic volume according to an embodiment of the present application; Figure 5 is a flowchart of the method for predicting the formation sand-to-shale ratio of the target layer using seismic inversion according to an embodiment of the present application; Figure 6 is a flowchart of the method for predicting the formation sand-to-shale ratio of the target layer using seismic attribute analysis according to an embodiment of the present application; Figure 7 is a structural block diagram of the system for quantitatively characterizing the distribution of different types of hydrocarbon source rocks in a low-well area according to an embodiment of the present application; Figure 8 is a structural block diagram of the hydrocarbon source rock planar distribution characterization module according to an embodiment of the present application; Figure 9 This is the structural block diagram of the hydrocarbon source rock vertical thickness distribution characterization module in the embodiment of the present application; Figure 10 This is the seismic reflection characteristic diagram of the target layer hydrocarbon source rock in Sag A of the embodiment of the present application; Figure 11 This is the wave impedance analysis diagram of the target sandstone and mudstone in Sag A of the embodiment of the present application; Figure 12 This is the post-stack wave impedance inversion profile across the actual well in Sag A of the embodiment of the present application; Figure 13 This is the post-stack wave impedance inversion sand-mud ratio plan view of the target layer in Sag A of the embodiment of the present application; Figure 14 This is the correlation diagram of the root mean square amplitude attribute value and the sand-to-ground ratio of the target layer in Sag A of the embodiment of the present application; Figure 15 This is the root mean square amplitude profile across the virtual well in Sag A of the embodiment of the present application; In the figure, 1. Data acquisition module, 2. Data processing module, 3. Hydrocarbon source rock planar distribution characterization module, 31. Sedimentary facies analysis module, 32. Feature prediction module, 33. Planar distribution characterization module, 4. Hydrocarbon source rock vertical thickness distribution characterization module, 41. Residual formation thickness calculation module, 42. Sand-to-ground ratio prediction module, 43. Thickness distribution characterization module, 5. Hydrocarbon source rock distribution module, W. Well trajectory of actual well A1, B. Bottom interface of the target layer, T. Top interface of the target layer, D. Virtual well trajectory. Detailed implementation manners

[0015] Next, the present application will be specifically described through exemplary embodiments in conjunction with the accompanying drawings. However, it should be understood that without further description, the elements, structures, and features in one embodiment can also be beneficially combined into other embodiments.

[0016] See Figure 1 , the first aspect embodiment of the present application provides a method for quantitatively characterizing the distribution of different types of hydrocarbon source rocks in a low-well area, and its steps are as follows: S1. Data acquisition step: Obtain the post-stack seismic volume, sedimentary facies map, acoustic travel time logging data, and density logging data of the target layer.

[0017] The post-stack seismic volume provides macroscopic information on the underground stratigraphic structure; the sedimentary facies map helps to understand the sedimentary environment and thus infer the type of hydrocarbon source rock; the acoustic travel time logging data and density logging data can be used for subsequent wave impedance calculation.

[0018] S2. Data processing step: Intercept the post-stack seismic volume to obtain a seismic profile, and obtain the seismic reflection characteristics of the hydrocarbon source rock corresponding to different sedimentary facies through the seismic profile.

[0019] S3. Steps for depicting the planar distribution of source rocks: Depict the planar distribution of different types of source rocks in the target formation.

[0020] Specifically, refer to Figure 2 , and the specific method for depicting the planar distribution of different types of source rocks in the target formation is as follows: S31. Analyze the types of source rocks using the sedimentary facies map.

[0021] S32. Predict the development characteristics of different types of source rocks using the seismic reflection characteristics of source rocks.

[0022] S33. Depict the planar distribution of different types of source rocks in the target formation according to the development characteristics of different types of source rocks and sedimentary facies.

[0023] Depicting the planar distribution using the sedimentary facies map and seismic reflection characteristics can clearly present the distribution range of different types of source rocks on the plane.

[0024] S4. Steps for depicting the vertical thickness distribution of source rocks: Depict the thickness distribution of source rocks in the target formation.

[0025] Specifically, refer to Figure 3 , and the specific method for depicting the thickness distribution of source rocks in the target formation is as follows: S41. Obtain the residual formation thickness of the target formation from the post-stack seismic volume.

[0026] Specifically, in some embodiments, refer to Figure 4 , and the method for obtaining the residual formation thickness from the post-stack seismic volume is as follows: S411. Identification step: On the seismic profile, identify the seismic times t1 and t2 corresponding to the top and bottom interfaces of the target formation; S412. Depth calculation step: Substitute the seismic times t1 and t2 into the actual drilling depth-time conversion relationship to obtain the formation depth corresponding to the top interface of the target formation and the depth corresponding to the bottom interface of the target formation; S413. Residual thickness calculation step: Subtract the formation depth corresponding to the top interface of the target formation from the depth corresponding to the bottom interface of the target formation to obtain the residual formation thickness of the target formation.

[0027] By identifying the seismic times of the top and bottom interfaces of the target formation on the seismic profile, substituting them into the actual drilling depth-time conversion relationship to calculate the corresponding depths, and finally subtracting to obtain the residual formation thickness. This method makes full use of the combination of seismic data and actual drilling data and can accurately obtain the residual formation thickness of the target formation. Accurate residual formation thickness data is crucial for subsequent calculation of the source rock thickness distribution in combination with the sand-to-shale ratio, ensuring the vertical accuracy of the final source rock distribution depiction result.

[0028] S42. Predict the formation sand-to-shale ratio of the target formation.

[0029] In some embodiments, referring to Figure 5 , the seismic inversion method is used to predict the sand-to-shale ratio of the target layer based on the post-stack seismic volume, acoustic travel-time log data, and density log data. The specific method is as follows: S421. Boundary value determination step: Calculate the wave impedance values of sandstone and mudstone in the target layer based on the acoustic travel-time log data and density log data, analyze the wave impedance characteristics of sandstone and mudstone in the target layer, and determine the wave impedance boundary values of sandstone and mudstone; S422. Inversion step: Perform wave impedance inversion on the post-stack seismic volume through seismic inversion software to obtain a wave impedance inversion profile; S423. Judgment step: Perform lithology determination on each sampling point on the wave impedance inversion profile according to the wave impedance boundary values of sandstone and mudstone. When the wave impedance value is greater than the wave impedance boundary values of sandstone and mudstone, it is determined that the corresponding formation of this point is sandstone; when the wave impedance is less than the wave impedance boundary values of sandstone and mudstone, it is determined as mudstone; S424. Calculation step: In the target layer, for each seismic trace, count the number of sampling points Ns identified as sandstone and the total number of sampling points Nt, and calculate the sand-to-shale ratio of this seismic trace based on the number of sampling points Ns and the total number of sampling points Nt; Sand-to-shale ratio = Ns / Nt S425. Integration step: Integrate the sand-to-shale ratios of each seismic trace with the corresponding position information to obtain the sand-to-shale ratio of the target layer.

[0030] In the embodiments of the present application, by calculating the wave impedance value based on the acoustic travel-time log data and density log data and determining the wave impedance boundary values of sandstone and mudstone, it is possible to accurately perform lithology determination on each sampling point on the wave impedance inversion profile. This determination method based on rock physical properties is more accurate and reliable than simply relying on seismic reflection characteristics to judge lithology, reducing the possibility of misjudgment. Based on accurate lithology determination, the number of sampling points identified as sandstone and the total number of sampling points are counted to calculate the sand-to-shale ratio, so that the calculation result of the sand-to-shale ratio can truly reflect the proportion of sandstone in the formation. Integrating the sand-to-shale ratios of each seismic trace with the corresponding position information, the obtained sand-to-shale ratio data of the target layer is continuous and accurate in space, providing high-precision data support for calculating the thickness distribution of source rocks in combination with the remaining formation thickness.

[0031] In some other embodiments of the present application, referring to Figure 6 , the seismic attribute analysis method is used to predict the sand-to-shale ratio of the target layer based on the post-stack seismic volume. The specific method is as follows: S421. Extraction step: Convert the post-stack seismic volume into a seismic attribute volume, and extract the root-mean-square amplitude seismic attribute from the seismic attribute volume to obtain a seismic root-mean-square amplitude profile; S422. Root-mean-square amplitude determination step: According to the distribution range of sedimentary facies, virtual wells are set up. On the seismic root-mean-square amplitude profile map, find the positions corresponding to the virtual wells and read the root-mean-square amplitude values at these positions. S423. Calculation step: Substitute the read root-mean-square amplitude values into the fitting relationship formula between sand-to-shale ratio and root-mean-square amplitude to obtain the sand-to-shale ratio of the target formation.

[0032] In the embodiments of the present application, the post-stack seismic volume is converted into a seismic attribute volume and the root-mean-square amplitude seismic attribute is extracted, taking advantage of the internal relationship between seismic attributes and formation lithology and physical properties. The root-mean-square amplitude seismic attribute can reflect the characteristics of the formation to a certain extent. By setting up virtual wells to read the root-mean-square amplitude values and then calculating the sand-to-shale ratio, it provides an effective method for predicting the sand-to-shale ratio in areas with few wells and lacking sufficient logging data. Compared with the above seismic inversion method, the operation is more convenient and the calculation amount is smaller. Only by obtaining the post-stack seismic volume and performing attribute extraction, combined with the setting of virtual wells and the reading of root-mean-square amplitude values, can the sand-to-shale ratio of the target formation be quickly obtained, improving the work efficiency and having strong practicability in areas with few wells.

[0033] Specifically, in some embodiments of the present application, the fitting relationship formula between sand-to-shale ratio and root-mean-square amplitude is expressed as: Sand-to-shale ratio = 0.2002 · Root-mean-square amplitude – 0.0098.

[0034] In the embodiments of the present application, the fitting relationship between sand-to-shale ratio and root-mean-square amplitude is given, providing a clear quantitative basis for calculating the sand-to-shale ratio using the root-mean-square amplitude. This quantitative relationship enables quick and accurate calculation of the sand-to-shale ratio as long as the root-mean-square amplitude value is obtained in actual operation, reducing human errors and improving the consistency and reliability of the calculated results of the sand-to-shale ratio.

[0035] S43. Characterize the thickness distribution of source rocks in the target formation according to the residual formation thickness and the sand-to-shale ratio of the formation.

[0036] Specifically, the calculation formula for the thickness of source rocks in the target formation based on the residual formation thickness and the sand-to-shale ratio of the formation is expressed as: Source rock thickness = Residual formation thickness × (1 – Sand-to-shale ratio) Substitute the residual formation thickness obtained in step S41 and the sand-to-shale ratio obtained in step S42 into the above source rock thickness calculation formula to obtain the source rock thickness distribution.

[0037] S5. Source rock distribution step: Coupling analysis of the planar distribution and thickness distribution of source rocks to obtain the spatial distribution of source rocks.

[0038] In the method for quantitatively characterizing the distribution of different types of source rocks in the few - well area of the present application, by obtaining the stacked seismic volume of the target layer, sedimentary facies map, acoustic time - difference logging data, and density logging data, the integration of multi - source data is achieved. On the basis of data processing, the planar distribution and vertical thickness distribution of the source rocks are respectively characterized. Using the sedimentary facies map and seismic reflection characteristics to characterize the planar distribution can clearly present the distribution range of different types of source rocks on the plane; by using seismic inversion method or seismic attribute analysis method combined with the remaining formation thickness to characterize the thickness distribution, the vertical variation of the source rocks is accurately described. Finally, coupling the planar and thickness distributions, intuitive and comprehensive spatial distribution information of the source rocks is obtained, solving the problem of quantitatively characterizing the distribution of source rocks in the few - well area and providing a complete solution for the study of source rocks in the few - well area.

[0039] In the second - aspect embodiment of the present application, a system for quantitatively characterizing the distribution of different types of source rocks in the few - well area is provided, which is used to implement the method for quantitatively characterizing the distribution of different types of source rocks in the few - well area described in the first aspect of the present application. Refer to Figure 7 , the system includes: A data acquisition module 1, which is used to acquire the stacked seismic volume of the target layer, sedimentary facies map, acoustic time - difference logging data, and density logging data; A data processing module 2, which intercepts the stacked seismic volume to obtain a seismic profile, and obtains the seismic reflection characteristics of the source rocks corresponding to different sedimentary facies through the seismic profile; A source - rock planar - distribution characterization module 3, which analyzes the source - rock types using the sedimentary facies map, predicts the development characteristics of different types of source rocks using the seismic reflection characteristics of the source rocks, and characterizes the planar distribution of different types of source rocks in the target layer according to the development characteristics of different types of source rocks and sedimentary facies; A source - rock vertical - thickness - distribution characterization module 4, which obtains the remaining formation thickness of the target layer according to the stacked seismic volume, predicts the formation sand - to - shale ratio of the target layer using the seismic inversion method based on the stacked seismic volume, acoustic time - difference logging data, and density logging data, or predicts the formation sand - to - shale ratio of the target layer using the seismic attribute analysis method based on the stacked seismic volume, and characterizes the thickness distribution of the source rocks in the target layer according to the remaining formation thickness and the formation sand - to - shale ratio; A source - rock distribution module 5, which couples and analyzes the planar distribution and thickness distribution of the source rocks to obtain the spatial distribution of the source rocks.

[0040] In this embodiment, through the division of the data acquisition module 1, data processing module 2, source - rock planar - distribution characterization module 3, source - rock vertical - thickness - distribution characterization module 4, and source - rock distribution module 5, the modular integration of functions is achieved. Each module performs its own duties and cooperates with each other, enabling the entire process of quantitatively characterizing the distribution of different types of source rocks in the few - well area to operate efficiently and orderly. This modular design facilitates the maintenance, upgrade, and expansion of the system, improving the stability and flexibility of the system.

[0041] In some embodiments of the present application, referring to Figure 8 , the planar distribution characterization module 3 of the source rock includes: A sedimentary facies analysis module 31 that analyzes the type of source rock using a sedimentary facies map; A feature prediction module 32 that predicts the development characteristics of different types of source rocks using the seismic reflection characteristics of the source rock; A planar distribution characterization module 33 that characterizes the planar distribution of different types of source rocks in the target layer according to the development characteristics of different types of source rocks and the sedimentary facies.

[0042] In the embodiments of the present application, the planar distribution characterization module of the source rock is further subdivided into a sedimentary facies analysis module 31, a feature prediction module 32, and a planar distribution characterization module 33. The sedimentary facies analysis module 31 analyzes the type of source rock using a sedimentary facies map, providing a basis for subsequent analysis; the feature prediction module 32 predicts the development characteristics of the source rock using seismic reflection characteristics, increasing the scientific nature of the prediction; the planar distribution characterization module 33 combines the results of the previous two to be able to finely characterize the planar distribution of different types of source rocks in the target layer, making the planar distribution characterization result more accurate and detailed, and helping to deeply understand the distribution law of the source rock in the plane.

[0043] In some embodiments, referring to Figure 9 , the vertical thickness distribution characterization module 4 of the source rock includes: A residual formation thickness calculation module 41 that obtains the residual formation thickness of the target layer from the post-stack seismic volume, A sand-to-shale ratio prediction module 42 that predicts the formation sand-to-shale ratio of the target layer using seismic inversion method based on the post-stack seismic volume, acoustic time difference logging data, and density logging data, or predicts the formation sand-to-shale ratio of the target layer using seismic attribute analysis method based on the post-stack seismic volume, A thickness distribution characterization module 43 that characterizes the thickness distribution of the source rock in the target layer according to the residual formation thickness and the formation sand-to-shale ratio.

[0044] In the embodiments of the present application, the vertical thickness distribution characterization module of the source rock is subdivided into a residual formation thickness calculation module, a sand-to-shale ratio prediction module, and a thickness distribution characterization module. The residual formation thickness calculation module accurately obtains the residual formation thickness; the sand-to-shale ratio prediction module predicts the sand-to-shale ratio through different methods; the thickness distribution characterization module combines the results of the two to be able to accurately characterize the thickness distribution of the source rock in the target layer. This subdivided module design makes the thickness distribution characterization process more rigorous and scientific, improving the accuracy of the thickness distribution characterization result of the source rock, and providing a strong guarantee for comprehensively and accurately presenting the spatial distribution of the source rock.

[0045] To verify the effectiveness of the method and system for quantitatively characterizing the distribution of different types of hydrocarbon source rocks in a sparse well area described in the above embodiments of the present application, the following specific embodiments are described for illustration.

[0046] Embodiment: Taking Sag A as an example. Obtain the post-stack seismic volume, sedimentary facies map, acoustic travel-time log data, and density log data of this area.

[0047] First, analyze the types of hydrocarbon source rocks using the sedimentary facies of the target layer in Sag A. Generally, source rocks are mainly divided into mid-deep lacustrine facies hydrocarbon source rocks and shallow lacustrine facies hydrocarbon source rocks according to sedimentary facies.

[0048] According to Figure 10 Shown is the seismic reflection characteristic map of the hydrocarbon source rocks in the target layer of Sag A. Select seismic profiles at equal intervals to predict the development characteristics of different types of hydrocarbon source rocks.

[0049] Conduct petrophysical analysis on the log wave impedance curves of the wells drilled in the target layer of Sag A. As Figure 11 Shown is the post-stack wave impedance inversion sand-shale ratio plane map of the target layer in Sag A. The longitudinal wave impedance has a strong resolution ability for sandstone and mudstone. The wave impedance boundary value between sandstone and mudstone is 8500 (unit: g / cm 3 ·m / s). High wave impedance represents sandstone, and low wave impedance represents mudstone.

[0050] Use Jason seismic inversion software to perform wave impedance inversion on the post-stack seismic volume of the target layer in Sag A to obtain the post-stack wave impedance inversion profile passing through the actual wells in Sag A as Figure 12 shown. Figure 12 In it, W represents the well trajectory of actual well A1, B represents the bottom interface of the target layer, and T represents the top interface of the target layer. It can be Figure 12 known that the seismic wave impedance profile is generally consistent with the wave impedance of the actual well. Combining the wave impedance boundary value of 8500 (unit: g / cm 3 ·m / s) between sandstone and mudstone in the target layer of Sag A, the sandstone and mudstone in the target layer of Sag A can be effectively distinguished, and then the sand-to-ground ratio distribution of the entire target layer in Sag A can be obtained (as Figure 13 shown). Figure 13 In it, A1 and A2 represent actual wells.

[0051] As Figure 14 shown is the correlation diagram between the root mean square amplitude attribute value and the sand-to-ground ratio of the target layer in Sag A. The sand-to-ground ratio of the actual wells in the target layer of Sag A has a good correlation with the root mean square amplitude seismic attribute. According to the distribution range of sedimentary facies, virtual wells are set up. Read the root mean square amplitude values of the virtual wells on the seismic root mean square amplitude profile (see Figure 15 . Calculate the sand-to-ground ratio of the virtual wells through the following formula according to the read root mean square amplitude values. Sand-to-ground ratio = 0.2002 · root mean square amplitude – 0.0098. Figure 15 In it, B represents the bottom interface of the target layer, T represents the bottom interface of the target layer, and D represents the virtual well trajectory.

[0052] Characterize the thickness distribution of source rocks according to the remaining formation thickness and sand-to-shale ratio.

[0053] Couple the planar distribution of source rocks with the thickness distribution of source rocks to obtain the spatial distribution of source rocks.

[0054] The above embodiments are used to explain the present application, rather than limit the present application. Any modifications and changes made to the present application within the spirit and scope of the claims of the present application fall within the protection scope of the present application.

Claims

1. A method for quantitatively characterizing the distribution of different types of source rocks in a well-polluted area, characterized in that: The steps are: Data acquisition steps: obtaining target post-stack seismic volume, sedimentary phase map, acoustic time difference logging data and density logging data; Data processing steps: intercepting the post-stack seismic volume to obtain a seismic profile, and obtaining the seismic reflection characteristics of the source rocks corresponding to different deposits through the seismic profile; Steps for characterizing the plane distribution of source rocks: using sedimentary facies diagrams to analyze the types of source rocks, using the seismic reflection characteristics of source rocks to predict the development characteristics of different types of source rocks, and characterizing the plane distribution of different types of source rocks in the target layer based on the development characteristics of different types of source rocks and sedimentary facies; The steps of characterizing the vertical thickness distribution of the source rock are as follows: obtaining the residual formation thickness of the target layer according to the post-stack seismic body, predicting the formation sand-to-stratigraphy ratio of the target layer by using the seismic inversion method according to the post-stack seismic body, acoustic time difference logging data and density logging data, or predicting the formation sand-to-stratigraphy ratio of the target layer by using the seismic attribute analysis method according to the post-stack seismic body, and characterizing the thickness distribution of the source rock in the target layer according to the residual formation thickness and the formation sand-to-stratigraphy ratio; Source rock distribution steps: Couple the plane distribution of source rocks with the thickness distribution of source rocks to obtain the spatial distribution of source rocks.

2. The method for quantitatively characterizing the distribution of different types of source rocks in a well-polluted area according to claim 1, characterized in that: In the step of characterizing the vertical thickness distribution of source rocks, the method of predicting the formation sand-to-ground ratio by using the seismic inversion method based on the post-stack seismic volume, acoustic time-difference logging data and density logging data is as follows: Boundary value determination steps: Calculate the wave impedance values ​​of the sandstone and mudstone of the target layer based on the acoustic time difference logging data and the density logging data, analyze the wave impedance characteristics of the sandstone and mudstone of the target layer, and determine the wave impedance boundary values ​​of the sandstone and mudstone; Inversion steps: Use seismic inversion software to perform wave impedance inversion on the post-stack seismic body to obtain a wave impedance inversion profile; Judgment steps: According to the wave impedance limit value of sandstone and mudstone, the lithology of each sampling point on the wave impedance inversion profile is judged. When the wave impedance value is greater than the wave impedance limit value of sandstone and mudstone, the corresponding stratum of the point is judged to be sandstone; when the wave impedance is less than the wave impedance limit value of sandstone and mudstone, it is judged to be mudstone; Calculation steps: In the target layer, for each seismic trace, count the number of sampling points Ns identified as sandstone and the total number of sampling points Nt, and use the following formula to calculate the sand-to-ground ratio of the seismic trace; Sand ratio=Ns / Nt Integration step: Integrate the sand-to-ground ratio of each seismic channel with the corresponding position information to obtain the sand-to-ground ratio of the target layer.

3. The method for quantitatively characterizing the distribution of different types of source rocks in a well-polluted area according to claim 1, characterized in that: In the step of characterizing the vertical thickness distribution of source rocks, the method of predicting the formation sand-to-ground ratio by using the seismic attribute analysis method based on the post-stack seismic volume is as follows: Extraction step: converting the post-stack seismic volume into a seismic attribute volume, extracting the root mean square amplitude seismic attribute from the seismic attribute volume to obtain a seismic root mean square amplitude profile; The steps for determining the root mean square amplitude are as follows: a virtual well is set up according to the distribution range of the sedimentary phase, the position corresponding to the virtual well is found on the seismic root mean square amplitude profile, and the root mean square amplitude value at the position is read; Calculation steps: Substitute the read RMS amplitude value into the fitting relationship formula between sand-to-formation ratio and RMS amplitude to obtain the formation sand-to-formation ratio of the target layer.

4. The method for quantitatively characterizing the distribution of different types of source rocks in a well-polluted area as claimed in claim 3, characterized in that: The fitting relationship formula between sand-to-ground ratio and root mean square amplitude is expressed as: Sand ratio = 0.2002 · Root mean square amplitude – 0.0098.

5. The method for quantitatively characterizing the distribution of different types of source rocks in a well-polluted area according to any one of claims 1 to 4, characterized in that: In the step of characterizing the vertical thickness distribution of source rocks, the method for obtaining the residual stratum thickness based on the post-stack seismic volume is as follows: Identification steps: on the seismic profile, identify the seismic times t1 and t2 corresponding to the top and bottom interfaces of the target layer; Depth calculation steps: Substitute the seismic time t1 and t2 into the actual drilling time-depth conversion relationship to obtain the formation depth corresponding to the top interface of the target layer and the depth corresponding to the bottom interface of the target layer; Residual thickness calculation steps: The residual formation thickness of the target layer is obtained by subtracting the formation depth corresponding to the top interface of the target layer from the depth corresponding to the bottom interface of the target layer.

6. A system for quantitatively characterizing the distribution of different types of source rocks in a well-poor area, used to implement the method for quantitatively characterizing the distribution of different types of source rocks in a well-poor area as claimed in any one of claims 1 to 5, characterized in that: include: Data acquisition module, used to acquire target post-stack seismic volume, sedimentary phase map, acoustic time difference logging data and density logging data; The data processing module intercepts the post-stack seismic volume to obtain the seismic profile, and obtains the seismic reflection characteristics of the source rocks corresponding to different deposits through the seismic profile; The module for describing the plane distribution of source rocks uses sedimentary phase diagrams to analyze the types of source rocks, uses the seismic reflection characteristics of source rocks to predict the development characteristics of different types of source rocks, and describes the plane distribution of different types of source rocks in the target layer based on the development characteristics and sedimentary phases of different types of source rocks; The vertical thickness distribution characterization module of the source rock obtains the residual formation thickness of the target layer according to the post-stack seismic body, predicts the formation sand-to-stratigraphy ratio of the target layer by using the seismic inversion method according to the post-stack seismic body, acoustic time difference logging data and density logging data, or predicts the formation sand-to-stratigraphy ratio of the target layer by using the seismic attribute analysis method according to the post-stack seismic body, and characterizes the thickness distribution of the source rock in the target layer according to the residual formation thickness and the formation sand-to-stratigraphy ratio; The source rock distribution module couples the plane distribution of source rocks with the thickness distribution of source rocks to obtain the spatial distribution of source rocks.

7. The system for quantitatively characterizing the distribution of different types of source rocks in a well-polluted area as claimed in claim 6, characterized in that: The source rock plane distribution characterization module includes: Sedimentary phase analysis module, using sedimentary phase diagram to analyze source rock types; The feature prediction module uses the seismic reflection characteristics of source rocks to predict the development characteristics of different types of source rocks; The plane distribution characterization module characterizes the plane distribution of different types of source rocks in the target layer according to the development characteristics and sedimentary phases of different types of source rocks.

8. The system for quantitatively characterizing the distribution of different types of source rocks in a well-polluted area according to claim 6, characterized in that: The hydrocarbon source rock vertical thickness distribution characterization module includes: The residual formation thickness calculation module obtains the residual formation thickness of the target layer based on the post-stack seismic volume. The sand-to-stratigraphy ratio prediction module predicts the formation sand-to-stratigraphy ratio of the target layer by using the seismic inversion method based on the post-stack seismic volume, acoustic time-difference logging data and density logging data, or predicts the formation sand-to-stratigraphy ratio of the target layer by using the seismic attribute analysis method based on the post-stack seismic volume. The thickness distribution characterization module characterizes the thickness distribution of source rocks in the target layer according to the residual formation thickness and the formation sand-to-formation ratio.

Images