Shale oil sweet spot logging evaluation method and apparatus based on source-reservoir coupling characteristics

Abstract

The present description relates to the field of oil and gas field exploration and development, and in particular, to a shale oil sweet spot logging evaluation method and apparatus based on source-reservoir coupling characteristics. The method comprises: on the basis of the effective porosity and effective thickness of a shale oil reservoir in a research area, determining reservoir quality, wherein the effective porosity is greater than a preset porosity lower threshold; on the basis of effective points of kerogen total organic carbon content in the research area, the effective thickness of an interval corresponding to each effective point, and the kerogen total organic carbon content of each effective point, evaluating the quality of source rock intervals; on the basis of an estimated longitudinal distance range of the positions where the effective points of kerogen total organic carbon content are located, determining a coupling relationship between the reservoir quality and the quality of the source rock intervals; and on the basis of the coupling relationship, evaluating a shale oil sweet spot within the estimated longitudinal distance range.

Description

A method and apparatus for evaluating sweet spots in shale oil based on source-reservoir coupling characteristics.

[0001] Related applications

[0002] This application claims priority to Chinese Patent Application No. 202411548840.1, filed on October 31, 2024, and incorporates the entire contents of the aforementioned patent application as part of this application. Technical Field

[0003] This manual relates to the field of oil and gas field exploration and development, and in particular to a method and apparatus for evaluating sweet spot logging in shale oil based on source-reservoir coupling characteristics. Background Technology

[0004] In recent years, shale oil has increasingly become a key area of ​​exploration and development. Accurate characterization of sweet spots in shale oil is crucial for selecting optimal fracturing test zones, significantly increasing single-well production, accurately assessing the scale of shale oil resources, and implementing effective strategies. Continental shale oil reservoirs exhibit complex lithology and pore structures, strong heterogeneity in reservoir and source rock quality, significant differences in source rock characteristics, complex geostress distribution, and distinct hydrocarbon accumulation characteristics, making it difficult to grasp the patterns of hydrocarbon enrichment. This results in generally low single-well production in current continental shale oil exploration, extremely uneven distribution of high- and low-yield wells, unclear main controlling factors for shale oil enrichment, and inconsistent sweet spot evaluation standards. Further research is needed to continuously develop methods and standards for sweet spot evaluation.

[0005] The "source control theory" is one of the core tenets of continental petroleum geology, applicable to both conventional and unconventional oil and gas reservoirs. Shale oil is defined as "oil hosted in organic-rich shale formations." Hydrocarbons remain within the source rock formations without undergoing long-distance migration. Therefore, the enrichment level of shale oil, i.e., the distribution of geologically static sweet spots, is closely related to the quality of the source rocks, demonstrating a strong source control effect. Furthermore, shale oil sweet spots refer to areas with good oil content, superior reservoir conditions, and high potential for modification. Clearly, the reservoir is the carrier of the sweet spot; without a high-quality reservoir, there is no sweet spot. Therefore, the geologically static sweet spot of shale oil is simultaneously controlled by both the quality of the source rocks and the quality of the reservoir. Both are indispensable and are inseparable elements in the evaluation of shale oil sweet spots. High-quality source rocks are a sufficient condition for shale oil sweet spots, while a high-quality reservoir is a necessary condition. Only when these sufficient and necessary conditions are met can the reservoir be considered a sweet spot.

[0006] Existing evaluation methods typically do not consider the coupling relationship between source rock quality and reservoir quality. How to objectively and accurately evaluate the sweet spot development zone of shale oil using well logging data is a key technical issue that needs further research. Summary of the Invention

[0007] To address the problem that existing technologies do not consider the coupling relationship between source rock quality and reservoir quality when evaluating shale oil sweet spots, this specification provides a method and apparatus for evaluating shale oil sweet spots based on source-reservoir coupling characteristics. The method includes: determining the reservoir quality of the study area based on the effective porosity and effective thickness of the shale oil reservoir, wherein the effective porosity and effective thickness are determined based on well logging data; evaluating the quality of each source rock segment based on effective points of total organic carbon (TOC) content in the study area, the effective thickness of the corresponding segments at each effective point, and the TOC content at the effective points, wherein the effective points are points where the TOC content is higher than the lower limit of TOC content; determining the coupling relationship between the reservoir quality and the quality of the source rock segment within an estimated vertical distance range of the location of the effective TOC content points; and evaluating the shale oil sweet spots within the estimated vertical distance range based on the coupling relationship.

[0008] According to one aspect of the embodiments of this specification, determining the quality of the shale oil reservoir based on its effective porosity and effective thickness in the study area includes: determining the quality parameters of the shale oil reservoir based on a first effective porosity, a first effective thickness, and pore structure parameters, wherein the first effective porosity is determined based on conventional logging data; and determining the quality parameters of the shale oil reservoir in the study area based on a second effective porosity, the geometric mean of the nuclear magnetic resonance spectrum, and a second effective thickness, wherein the second effective porosity is determined based on nuclear magnetic resonance logging data.

[0009] According to one aspect of the embodiments of this specification, a first effective porosity is determined by: determining the content of inorganic framework mineral components and clay content based on well logging data; determining the density of a mixed inorganic mineral framework based on the content of different inorganic framework mineral components; and determining the effective porosity of a shale oil formation based on a density logging three-framework model, the formation density, the density of the mixed inorganic mineral framework, the clay content, and the total organic carbon content of kerogen obtained from well logging data, wherein the effective porosity of the shale oil formation is the first effective porosity.

[0010] According to one aspect of an embodiment of this specification, the pore structure parameters are determined in the following manner:

[0011] in, represents formation porosity; k represents formation permeability.

[0012] According to one aspect of the embodiments of this specification, determining the quality parameters of the shale oil reservoir in the study area based on the second effective porosity, the geometric mean of the nuclear magnetic resonance spectrum, and the second effective thickness includes: determining the quality parameters of the shale oil reservoir using the following formula: in, T2LM represents the second effective porosity, and H represents the geometric mean of the T2 NMR spectrum. Re This indicates the second effective thickness.

[0013] According to one aspect of the embodiments of this specification, based on the location of the effective point of total organic carbon content of each kerogen, a reservoir within an estimated vertical distance range is searched vertically; the reservoir quality and source rock quality within the estimated vertical distance range are divided to obtain the division results of reservoir and source rock respectively; based on the division results of reservoir and source rock, the reservoir and source rock are matched.

[0014] According to one aspect of the embodiments of this specification, the evaluation of the quality of each source rock formation includes: determining the total organic carbon content of kerogen at each point in the study area based on the total organic carbon content of the formation and the total organic carbon content of the crude oil contained in the formation, wherein the total organic carbon content of the formation is calculated based on different well logging data;

[0015] Based on the lower limit of the total organic carbon content of kerogen that contributes to hydrocarbon accumulation, effective points of total organic carbon content of kerogen are determined from various points in the study area; based on the depth of the effective points of total organic carbon content of kerogen, the hydrocarbon source rock development sections in the study area are determined layer by layer; the effective thickness of the section corresponding to each effective point in each section of the hydrocarbon source rock development section is determined; based on the effective thickness and the total organic carbon content of kerogen at the effective points, the quality of each hydrocarbon source rock section is evaluated.

[0016] This specification provides an embodiment of a shale oil sweet spot logging evaluation device based on source-reservoir coupling characteristics. The device includes: a reservoir quality determination unit, used to determine the reservoir quality of the study area based on the effective porosity and effective thickness of the shale oil reservoir in the study area, wherein the effective porosity and effective thickness are determined based on logging data; a source rock quality determination unit, used to evaluate the quality of each source rock segment based on the effective points of total organic carbon content (TOC) in the study area, the effective thickness of the corresponding segments of each effective point, and the TOC content of the effective points, wherein the effective points are points where the TOC content is higher than the lower limit of TOC content; a coupling relationship determination unit, used to determine the coupling relationship between the reservoir quality and the quality of the source rock segment in the study area based on the estimated vertical distance range of the location of the effective points of TOC content; and an evaluation unit, used to evaluate the shale oil sweet spots within the estimated vertical distance range based on the coupling relationship.

[0017] This specification also provides a computer device, which includes a memory, a processor, and a computer program stored in the memory and executable on the processor. When the processor executes the computer program, it implements the shale oil sweet spot logging evaluation method based on source-reservoir coupling characteristics.

[0018] This specification also provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the shale oil sweet spot logging evaluation method based on source-reservoir coupling characteristics.

[0019] This application lays the foundation for the accurate classification and evaluation of sweet spot development zones in shale oil, based on the classification of source rock quality, reservoir quality, and source-reservoir coupling relationship. Attached Figure Description

[0020] To more clearly illustrate the technical solutions in the embodiments or prior art of this specification, the drawings used in the description of the embodiments or prior art will be briefly introduced below. Obviously, the drawings described below are only some embodiments of this specification. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0021] Figure 1 shows a flowchart of a shale oil sweet spot logging evaluation method based on source-reservoir coupling characteristics according to an embodiment of this specification;

[0022] Figure 2 is a flowchart of a method for determining reservoir quality in a study area according to an embodiment of this specification.

[0023] Figure 3 is a flowchart of a method for determining shale oil reservoir quality parameters according to an embodiment of this specification.

[0024] Figure 4 shows a flowchart of a method for determining the coupling relationship between reservoir quality and source rock quality according to an embodiment of this specification.

[0025] Figure 5 shows a flowchart of a method for evaluating the quality of each source rock stratum according to an embodiment of this specification.

[0026] Figure 6 is a schematic diagram of an example of shale oil sweet spot logging evaluation in a key well in the study area according to an embodiment of this specification;

[0027] Figure 7 shows a schematic diagram of a shale oil sweet spot logging evaluation device based on source-reservoir coupling characteristics according to an embodiment of this specification.

[0028] Figure 8 is a schematic diagram of a shale oil sweet spot discrimination rule according to an embodiment of this specification;

[0029] Figure 9 shows a schematic diagram of the structure of a computer device according to an embodiment of this specification. Detailed Implementation

[0030] To enable those skilled in the art to better understand the technical solutions in this specification, the technical solutions in the embodiments of this specification will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of this specification, and not all embodiments. Based on the embodiments in this specification, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this specification.

[0031] It should be noted that the terms "first," "second," etc., in the specification, claims, and accompanying drawings are used to distinguish similar objects and are not necessarily used to describe a specific order or sequence. It should be understood that such data can be interchanged where appropriate so that the embodiments described herein can be implemented in orders other than those illustrated or described herein. Furthermore, the terms "comprising" and "having," and any variations thereof, are intended to cover a non-exclusive inclusion; for example, a process, method, apparatus, product, or device that comprises a series of steps or units is not necessarily limited to those steps or units explicitly listed, but may include other steps or units not explicitly listed or inherent to such processes, methods, products, or devices.

[0032] This specification provides the operational steps of the methods described in the embodiments or flowcharts, but based on conventional or non-inventive labor, more or fewer operational steps may be included. The order of steps listed in the embodiments is merely one possible execution order among many and does not represent the only possible execution order. In actual system or device products, the methods shown in the embodiments or drawings can be executed sequentially or in parallel.

[0033] It should be noted that the shale oil sweet spot logging evaluation method and device based on source-reservoir coupling characteristics described in this specification can be used in the field of oil and gas field exploration and development. This specification does not limit the application field of the shale oil sweet spot logging evaluation method and device based on source-reservoir coupling characteristics.

[0034] Based on high-resolution logging data, this manual establishes quantitative characterization methods and evaluation standards for source rock quality and reservoir quality, and finely evaluates the depth profile distribution characteristics of source rock quality and reservoir quality. It studies the interaction and mutual influence of the three factors controlling the distribution of sweet spots, namely source rock quality, reservoir quality, and effective vertical distance controlling reservoirs, i.e., source-reservoir coupling relationship, and defines the shale oil types with vertical distribution at the logging level.

[0035] Figure 1 shows a flowchart of a well logging evaluation method for shale oil source rock quality according to an embodiment of this specification. The system includes:

[0036] Step 101: Determine the reservoir quality of the study area based on the effective porosity and effective thickness of the shale oil reservoir. The effective porosity and effective thickness are determined based on well logging data.

[0037] In the embodiments of this specification, different logging data can be used to determine the reservoir quality of the target well in the study area, including: determining the effective porosity and effective thickness of the reservoir in the target well in the study area based on density logging data, thereby determining the reservoir quality of the target well in the study area; or determining the porosity at each point in the reservoir of the target well, and the corresponding reservoir thickness at each point location based on nuclear magnetic resonance logging data, thereby determining the reservoir quality of the study area. It should be noted that the logging data can, for example, be determined based on data obtained from the study area by sensors.

[0038] In this specification, effective porosity refers to the porosity corresponding to a point whose porosity value is higher than a preset lower limit, and effective thickness refers to the reservoir thickness at the location of the point corresponding to effective porosity. A point with effective porosity is likely located in a reservoir with good oil content, and this point may be situated in a layer with favorable reservoir conditions. In this step, by combining the effective porosity and effective thickness of multiple points in the reservoir, the quality parameters of the reservoir can be determined. Furthermore, the reservoir quality parameters can be used to help determine sweet spots, thereby determining the reservoir quality of the study area.

[0039] In the embodiments described in this specification, the first effective porosity and the second effective porosity can be calculated based on conventional logging data or nuclear magnetic resonance logging data, respectively. The first effective thickness can be calculated based on the first effective porosity, and the second effective thickness can be calculated based on the second effective porosity. For a detailed description of the calculation of the first effective porosity, the second effective porosity, the first effective thickness, and the second effective thickness, please refer to Figure 2. This step will not be repeated here.

[0040] Step 102: Based on the effective points of total organic carbon content of kerogen in the study area, the effective thickness of the corresponding layer of the source rock development section of each effective point, and the total organic carbon content of kerogen at the effective points, evaluate the quality of each source rock layer. Among them, the effective points are the points where the total organic carbon content of kerogen is higher than the lower limit of the total organic carbon content of kerogen.

[0041] In this step, the total organic carbon (TOC) content of kerogen at each point in the study area is determined based on the TOC content of the formation and the TOC content of the crude oil contained in the formation. Based on the lower limit of TOC content in kerogen that contributes to hydrocarbon accumulation, effective TOC content points are determined from each point in the study area. Based on the depth of the effective TOC content points, the source rock development intervals in the study area are determined layer by layer. The effective thickness of the interval corresponding to each effective point within each interval is determined. Based on the effective thickness and the TOC content of the effective points, the quality of each source rock interval is evaluated.

[0042] Step 103: Based on the estimated longitudinal distance range of the effective point of total organic carbon content in kerogen, determine the coupling relationship between reservoir quality and source rock quality in the study area.

[0043] In this step, the estimated longitudinal distance is the vertical distance between the source rock and the reservoir formed by the source rock.

[0044] In this step, source rock quality, reservoir quality, and effective vertical distance controlling hydrocarbon accumulation are the three key factors influencing sweet spot distribution. The coupling relationship between reservoir quality and source rock quality in this step is the source-reservoir coupling relationship.

[0045] Step 104: Evaluate the shale oil sweet spot within the estimated longitudinal distance range based on the coupling relationship.

[0046] Based on the calculation and classification results of source rock quality and reservoir quality, and referring to the discrimination rules shown in Figure 8, this step further classifies and evaluates the sweet spot development section of shale oil.

[0047] This step studies the interaction and mutual influence of three factors: source rock quality, reservoir quality, and effective vertical distance controlling reservoir growth. It defines the types of shale oil distributed vertically at small logging levels, determining whether the shale oil is an integrated source-reservoir type or a source-reservoir differentiated type. Based on source rock quality classification, reservoir quality classification, and source-reservoir coupling relationships, this application lays the foundation for the accurate classification and evaluation of sweet spot development zones in shale oil.

[0048] Figure 2 shows a flowchart of a method for determining reservoir quality in a study area according to an embodiment of this specification. In this specification, different methods are used to determine reservoir quality parameters and evaluate reservoir quality based on different types of well logging data. Specifically, the methods include the following steps:

[0049] Step 201: Determine the quality parameters of the shale oil reservoir based on the first effective porosity, the first effective thickness, and the pore structure parameters, wherein the first effective porosity is determined based on conventional logging data.

[0050] In this step, density logging data can be used to determine the first effective porosity of the shale oil reservoir and the first effective thickness of the sweet spot in the shale oil. In the embodiments of this specification, the first effective porosity is an object with a porosity value greater than a preset first lower limit value. The first effective thickness is the shale oil reservoir thickness corresponding to the location of the first effective porosity point. Specifically, the reservoir thickness corresponding to the point is determined based on the bottom and top depths of the reservoir at the location of the first effective porosity point.

[0051] In this step, under the condition of only conventional logging data, the shale oil reservoir quality parameters are calculated using the following formula based on the first effective porosity, pore structure parameters, and first effective thickness:

[0052] Where RQ represents the quality parameters of shale oil reservoirs; β represents the scale coefficient, which is dimensionless; H represents the first effective porosity, and its value is a decimal; Re The first effective thickness of the sweet spot in shale oil is represented in meters; FZI represents the pore structure parameter. In the embodiments of this specification, the pore structure parameter can also be referred to as the flow unit index, and the value of the pore structure parameter can be calculated from the effective porosity and permeability of the formation.

[0053] In this specification, the calculation method for the pore structure parameter FZI is as follows:

[0054] Where, φ e This represents the porosity of the shale oil formation; this value is a decimal. k represents the formation permeability, in chaudacizi.

[0055] Among them, the porosity φ of shale oil formations e The porosity of the shale oil formation is calculated by substituting parameters such as formation density, density of the mixed inorganic mineral skeleton, clay content, and total organic carbon content of kerogen obtained from density logging data into the following formula:

[0056] Where, φ e Indicates the porosity of shale oil formations;

[0057] ρ b Density represents the bulk density of a formation, expressed in g / cm³; ρ f This represents the density of formation fluids, expressed in g / cm³. 3 ;ρ sh This indicates the density of wet clay, expressed in g / cm³. 3 ;ρ k This indicates the density of kerogen, expressed in g / cm³. 3 Vsh represents the clay content, expressed as a decimal.

[0058] In this specification, after calculating the porosity of the shale oil formation, the porosity that is greater than the first preset lower limit threshold porosity is selected from the porosity of the shale oil formation at each point in the study area and determined as the first effective porosity.

[0059] Step 202: Determine the quality parameters of the shale oil reservoir in the study area based on the second effective porosity, the geometric mean of the nuclear magnetic resonance spectrum, and the second effective thickness. The second effective porosity is determined based on nuclear magnetic resonance logging data.

[0060] In the embodiments of this specification, the quality of shale oil reservoirs in the study area can also be determined based on nuclear magnetic resonance (NMR) logging data. The results of determining the quality of shale oil reservoirs in the study area based on NMR logging data are more accurate to a certain extent. This specification acquires one-dimensional and two-dimensional NMR logging data from target wells in the shale oil study area. To accurately evaluate the effective porosity of the shale oil formation in the study area, one-dimensional and two-dimensional NMR logging data (i.e., NMR logging data) are collected from key wells.

[0061] The third effective porosity of the shale oil study area was calculated using the first nuclear magnetic resonance T2 spectrum from one-dimensional nuclear magnetic resonance logging data, and the fourth effective porosity of the shale oil study area was calculated using the second nuclear magnetic resonance T2 spectrum and nuclear magnetic resonance T1 spectrum from two-dimensional nuclear magnetic resonance logging data.

[0062] The differences between the third and fourth effective porosity and the reference porosity are calculated. The reference porosity is the effective porosity measurement value obtained from the core experiment of the target well.

[0063] The effective porosity of the shale oil study area is determined by the smaller difference between the third and fourth effective porosities and the benchmark porosity, which is the second effective porosity in this specification.

[0064] In the embodiments described in this specification, one-dimensional and two-dimensional nuclear magnetic resonance (NMR) logging can be performed on target wells in the shale oil research area to obtain one-dimensional and two-dimensional NMR logging data. Based on this, the effective porosity of the shale oil research area is calculated using the NMR T2 spectrum from the one-dimensional NMR logging data, and the effective porosity is calculated using the NMR T2 and NMR T1 spectra from the two-dimensional NMR logging data. Then, the two effective porosities are compared with the baseline porosity (the effective porosity measurement value obtained from core experiments of the target well), and the final effective porosity of the shale oil research area is determined based on the comparison. Since nuclear magnetic resonance (NMR) logging can directly measure the free fluid (oil, gas, water) seepage volume characteristics of reservoirs of any lithology, it can more accurately calculate the effective porosity of shale oil reservoirs. Furthermore, by comparing the effective porosity obtained from one-dimensional and two-dimensional NMR logging data with the effective porosity measurements obtained from core experiments of the target well, the accuracy of effective porosity assessment of shale oil reservoirs can be further improved.

[0065] In some embodiments of this specification, for low-porosity, low-permeability shale oil reservoirs with small pore sizes and complex pore structures, the full polarization of small pores should be fully considered during the acquisition of nuclear magnetic resonance logging data to improve the detection accuracy of small pores. Short echo intervals can be used to increase the number of repeated measurements and reduce the measurement speed.

[0066] In one embodiment of this specification, after determining the second effective porosity, the quality parameters of the shale oil reservoir in the study area are determined based on the second effective porosity, the geometric mean of the nuclear magnetic resonance spectrum, and the second effective thickness, including:

[0067] The following formula is used to determine the quality parameters of shale oil reservoirs:

[0068] RQ represents the quality parameters of shale oil reservoirs. T2LM represents the second effective porosity, and H represents the geometric mean of the T2 NMR spectrum. Re This indicates the second effective thickness. In this specification, the second effective thickness refers to the shale oil reservoir thickness corresponding to the location of the second effective porosity point.

[0069] In the embodiments of this specification, the lithology of the shale oil formation in the well is relatively complex. Nuclear magnetic resonance logging data is collected to obtain a relatively accurate effective porosity and T2 geometric mean. Based on the nuclear magnetic resonance logging data, the reservoir quality parameters are calculated using the method in this step. The reservoir quality parameters are calculated (wherein, the second preset effective porosity lower limit is 3%), as shown in the 6th channel of Figure 6.

[0070] Figure 3 shows a flowchart of a method for determining shale oil reservoir quality parameters according to an embodiment of this specification, which specifically includes the following steps:

[0071] Step 301: Based on the well logging data, determine the content of inorganic framework mineral components and clay content.

[0072] In this step, the logging data includes either full-spectrum elemental logging data or conventional logging data. When full-spectrum elemental logging data is available, the content of mineral components such as quartz, feldspar, calcite, and dolomite, as well as the clay content, is obtained by processing the full-spectrum elemental logging data based on an oxygen closure model. When only conventional logging data is available, the content of mineral components such as quartz, feldspar, calcite, and dolomite, as well as the clay content, is obtained by processing the conventional logging data based on an optimization model.

[0073] First, the yield Y of different elements was obtained through full-spectrum elemental logging. i The normalization factor was determined using the oxygen closure model:

[0074] Where F represents the normalization factor; Xi represents the oxide index of element i; Yi represents the relative yield of element i; and Si represents the detection sensitivity factor of element i.

[0075] Secondly, the element content is determined based on the element yield and normalization factor:

[0076] Where Wi represents the weight percentage of element i.

[0077] Furthermore, the elemental content is converted into mineral content:

[0078] [M] = [C] -1 [E]; where [M] represents the matrix of mineral weight percentage; [C] represents the transformation coefficient matrix; and [E] represents the matrix of element weight percentage.

[0079] Step 302: Determine the density of the mixed inorganic framework minerals based on the content of different inorganic framework mineral components.

[0080] In this step, the content of different inorganic framework mineral components is substituted into the following formula to calculate the density of the mixed inorganic framework: ρ ma =∑(V mai ·ρ mai ), i = 1, 2, ..., n.

[0081] Where, ρ ma Density of mixed inorganic framework minerals, expressed in g / cm³; ρ mai V represents the density of the i-th inorganic framework mineral, expressed in g / cm³. mai This represents the volume content of the i-th inorganic framework mineral, expressed as a decimal.

[0082] In the embodiments of this specification, multiple mineral components are obtained by jointly solving different types of logging response equations, forming an optimized model. In each type of logging response equation, the logging response value of the formation for that type is known, the logging response value of each mineral component for that type is known, but the mineral content is unknown. These logging response equations include equations for different types of logging responses such as acoustic, neutron, density, natural gamma, and resistivity. By jointly solving these equations, the unknown variables (the contents of different mineral components) in the equations are solved one by one, resulting in the optimized model.

[0083] Step 303: Based on the density logging three-framework model, determine the formation density, density of the mixed inorganic mineral framework, clay content, and total organic carbon content of kerogen based on the logging data, and determine the effective porosity of the shale oil formation. The effective porosity of the shale oil formation is the first effective porosity.

[0084] In this step, parameters such as formation density, density of the mixed inorganic mineral skeleton, clay content, and total organic carbon content of kerogen, obtained from density logging data, are substituted into the following formula to calculate the effective porosity of the shale oil formation. This effective porosity is also referred to as the first effective porosity in this specification. The formation density obtained from density logging data includes: formation volumetric density, formation fluid density, wet clay density, and kerogen density.

[0085] In the formula, φ e ρ represents the effective porosity of shale oil formations, and its value is expressed as a decimal; b Density represents the bulk density of a formation, expressed in g / cm³; ρ f This represents the density of formation fluids, expressed in g / cm³. 3 ;ρ sh This indicates the density of wet clay, expressed in g / cm³. 3 ;ρ k This indicates the density of kerogen, expressed in g / cm³. 3 Vsh represents the clay content, expressed as a decimal. In this specification, the clay content is the same as the mud content, which can be calculated by full-spectrum elemental logging based on the oxygen closure model, or by conventional logging based on the optimization model.

[0086] Shale oil reservoir quality parameters are determined based on the effective porosity of the shale oil formation and the following formula:

[0087] Where RQ represents the shale oil reservoir quality parameter; β represents the calibration coefficient; H represents the first effective porosity; Re It represents the first effective thickness of the sweet spot in shale oil; FZI represents the pore structure parameter, also known as the flow unit index.

[0088] The calculation process for the pore structure parameter FZI in this step has been described above and will not be repeated here.

[0089] Based on the first effective porosity of the shale oil formation calculated in step 303, the shale oil reservoir quality parameters are calculated by substituting it into the above formula.

[0090] Figure 4 shows a flowchart of a method for determining the coupling relationship between reservoir quality and source rock quality according to an embodiment of this specification, which specifically includes the following steps:

[0091] Step 401: Based on the location of the effective point of total organic carbon content of each kerogen, search the reservoir within the estimated vertical distance range.

[0092] In the embodiments of this specification, the segments constructed using effective points of kerogen organic carbon content are the development segments of source rocks. A specific source rock development segment may include multiple segments. To study the coupling relationship between reservoir quality and source rock quality, this specification requires matching source rocks and reservoirs within a certain depth range.

[0093] During the evolution of source rocks, organic matter gradually matures and transforms into oil and gas with increasing burial depth and temperature. Immature source rocks (i.e., oil shale) contain a large amount of unconverted organic matter, which can be converted into shale oil through processes such as pyrolysis. Shale oil is usually retained in the pores and fractures of source rocks, or hosted in clastic or carbonate interlayers within the source rocks. Shale oil is characterized by in-situ generation and enrichment, and the reservoir is generally located within the control range of the nearby source rock. Mature source rocks have already completed this transformation process, and the oil and gas within them migrate and are stored in the reservoir.

[0094] In this specification, the vertical distance at which the hydrocarbon generation and expulsion processes of source rocks effectively control the formation of adjacent reservoirs is referred to as the reservoir-controlling vertical distance. The specific value of the reservoir-controlling vertical distance needs to be estimated based on experience. Therefore, the reservoir-controlling vertical distance can also be called the estimated vertical distance. The estimated vertical distance can be represented by D. SR It indicates that the unit is meters.

[0095] In this step, based on the comprehensive analysis of the source rock hydrocarbon generation and expulsion thermal evolution simulation and reservoir characteristics in the study area, and combined with oil testing and production data, the vertical distance D controlling shale oil in the study area of ​​this specification can be determined. SR The length is 3m to 7m, therefore, D SR The uniform value is 5m.

[0096] Furthermore, for each effective point in each layer of the classified source rock development segment, the reservoir within the estimated longitudinal distance range is searched up and down at that location.

[0097] Step 402 involves classifying the reservoir quality and source rock quality within the estimated vertical distance range to obtain the classification results for the reservoir and source rock. Specifically, based on the methods described in the preceding steps, the reservoir quality and source rock quality within the estimated vertical distance range are calculated. The reservoir quality and source rock quality within the estimated vertical distance range are then classified into different categories. As shown in Figure 8, the shale oil sweet spot discrimination rule is used to classify the reservoir and source rock within the estimated vertical distance range. The reservoir quality and source rock quality within the estimated vertical distance range are classified into Class I, Class II, or Class III. Class I has a higher quality than Class II, and Class II and Class I have higher quality than Class III.

[0098] Step 403: Match the reservoir and source rock according to the results of the reservoir and source rock division.

[0099] In the embodiments of this specification, the key factors affecting the vertical distance controlling shale oil reservoirs include: the abundance, type, and maturity of organic matter in the source rocks, which determine the intensity of hydrocarbon generation and pressurization; and the reservoir pore type, pore radius, and pore-throat coordination, which determine the displacement pressure. In this specification, based on the simulation of the thermal evolution of hydrocarbon generation and expulsion in the source rocks and reservoir characteristics, combined with oil testing and production data, the vertical distance controlling shale oil reservoirs in a specified study area can be determined.

[0100] Specifically, the simulation results of hydrocarbon generation and expulsion thermal evolution of source rocks are combined with reservoir characteristics to analyze the matching relationship between source rocks and reservoirs. The migration, accumulation, and preservation patterns of hydrocarbons generated by source rocks in the reservoir are identified.

[0101] In this step, the quality of the source rock and reservoir in the same layer are considered together to evaluate the sweet spot category of shale oil in that layer.

[0102] Figure 5 shows a flowchart of a method for evaluating the quality of each source rock stratum according to an embodiment of this specification, which specifically includes the following steps:

[0103] Step 501: Determine the total organic carbon content of kerogen at each point in the study area based on the total organic carbon content of the formation and the total organic carbon content of the crude oil contained in the formation. The total organic carbon content of the formation is calculated based on different well logging data.

[0104] In this step, the total organic carbon content of the formation in the study area can be determined using different methods depending on the type of well logging data available. The total organic carbon content of the crude oil contained in the formation of the study area is then calculated. This total organic carbon content is subtracted from the original total organic carbon content of the formation to obtain the total organic carbon content of kerogen at each point in the study area.

[0105] In some embodiments of this specification, the total organic carbon content of the crude oil contained in the formation can be determined according to the following formula: Among them, TOC oil φ represents the total organic carbon content of crude oil; K represents the conversion factor for converting the volumetric content of crude oil to its total organic carbon content; T S represents total porosity; o oil saturation; r oil Indicates the density of crude oil; r b This represents the formation bulk density. Since the conversion factor, total porosity, oil saturation, crude oil density, and formation bulk density are all known quantities, the total organic carbon content of the crude oil can be calculated using the formula described above.

[0106] Step 502: Based on the lower limit of the total organic carbon content of kerogen that contributes to hydrocarbon accumulation, determine the effective points of total organic carbon content of kerogen from each point in the study area.

[0107] In the embodiments described in this specification, not all formations with a total organic carbon content of kerogen greater than 0 effectively contribute to hydrocarbon accumulation. Based on comprehensive analysis of geochemical analysis and hydrocarbon accumulation studies, the lower limit or minimum value of total organic carbon content of kerogen that contributes to hydrocarbon accumulation can be taken as 0.4% to 0.6%.

[0108] This step selects effective points for total organic carbon content in kerogen from the study area in step 101, based on the lower limit of the total organic carbon content in kerogen. The total organic carbon content of kerogen at these effective points all exceeds the lower limit.

[0109] Step 503: Based on the depth of the effective points for total organic carbon content in kerogen, determine the source rock development sections in the study area layer by layer. In this step, each effective point has its own corresponding depth in the study area. For example, in the entire well section of a well in the study area, several effective points and their depth distribution data can be determined according to the aforementioned steps. Based on the depth distribution data of these effective points, effective points within the same depth range are considered as points in a layer of the source rock. In the embodiments of this specification, the layers constructed using the effective points for total organic carbon content in kerogen can constitute the source rock development sections. The source rock development sections may include multiple layers.

[0110] Step 504: Determine the effective thickness of the segment corresponding to each effective point in each layer of the source rock development section. In this step, the source rock development section refers to a rock segment rich in organic matter that can generate and expel oil and gas. Based on each layer of the source rock development section determined in Step 103, the thickness of the segment corresponding to each effective point in each layer is determined layer by layer. Since the total organic carbon content of the kerogen at the effective point is the effective content, it contributes to the oil and gas accumulation in the study area. Therefore, the thickness of the segment formed by the effective point can be called the effective thickness.

[0111] In the embodiments of this specification, there are multiple effective points within a certain depth range of the stratum where the total organic carbon content of kerogen is greater than the lower limit value. Multiple effective points form a stratum segment. If the horizontal trend of the stratum segment is gentle and uniform, then the difference between the bottom depth and the top depth of the stratum segment at each effective point is basically the same. The stratum segment can be regarded as a uniformly distributed elongated shape, and the effective thickness at each effective point is basically the same. Therefore, by selecting one effective point and calculating the difference between the bottom depth and the top depth of the stratum at that point, the effective thickness of the stratum segment can be determined.

[0112] If the horizontal slope of a stratigraphic segment is large and uneven, the difference between the bottom and top depths at each effective point may vary significantly. If the stratigraphic segment has an irregular shape, the effective thickness at each effective point will also differ. Therefore, multiple key points or all effective points can be selected, and the difference between the bottom and top depths at each point can be calculated separately. The summation and averaging of these differences will determine the effective thickness of the stratigraphic segment. Alternatively, based on the importance of each effective point in the stratigraphic sequence, the difference between the bottom and top depths at each point can be calculated separately, and different weights can be assigned to the calculated thickness values ​​before summing to determine the effective thickness of the stratigraphic segment.

[0113] Step 505: Evaluate the quality of each source rock segment based on the effective thickness and the total organic carbon content of the kerogen at the effective points.

[0114] In the embodiments of this specification, after determining the effective thickness of the segment corresponding to each effective point and the total organic carbon content of the kerogen at each effective point, the effective thickness and total organic carbon content of the kerogen at each point in a segment composed of multiple effective points can be determined. Therefore, the quality of the source rock segment can be evaluated by comprehensively using the effective thickness and total organic carbon content of the kerogen at each point in the segment. By combining the calculation results of source rock quality parameters from multiple wells and the results of oil testing and production, statistical analysis is used to determine whether each segment of the source rock belongs to high-quality, medium-quality, or general source rock. Specifically, the quality of the source rock corresponding to the effective point is determined by the product of the thickness and the total organic carbon content of the kerogen at the effective point.

[0115] This specification calculates the source rock quality layer by layer in the development section of the source rock, with multiple source rock quality parameter values ​​for each layer. Specifically, the source rock quality parameters are calculated using the following formula: Wherein, SQ represents the source rock quality parameter; The total organic carbon content of kerogen that is greater than the lower limit of the total organic carbon content of kerogen is expressed as a percentage; H se This indicates the thickness of the source rock development section, specifically the thickness of each layer where the total organic carbon content of kerogen is greater than the lower limit of the total organic carbon content of kerogen, expressed in meters.

[0116] In the embodiments of this specification, the total organic carbon content of kerogen can be determined based on the uranium content curve of the natural gamma ray spectroscopy logging data. In these embodiments, radioactive nuclides (e.g., uranium, thorium, potassium, etc.) in the formation continuously emit gamma rays, and the uranium content curve in the natural gamma ray spectroscopy logging reflects the changes in the content of radioactive mineral uranium in the formation. Therefore, by analyzing the gamma ray spectrum, the content of different radioactive nuclides in the formation and the content of radioactive mineral uranium in the formation of the study area can be determined. In the implementation of this specification, natural gamma ray spectroscopy logging data is collected to obtain the uranium content curve. The total organic carbon content of kerogen is calculated using a formula.

[0117] This manual explains how to calculate the total organic carbon content of kerogen using the following formula:

[0118] Among them, TOC k The total organic carbon content of kerogen is represented by ; U represents the uranium content obtained from natural gamma ray spectroscopy logging data; A, B, C, and D are empirical parameters and are dimensionless.

[0119] Specifically, the formula can also be in the following form:

[0120] Among them, TOC k The total organic carbon (TOC) content of kerogen is represented by denoted as ; U represents the uranium content obtained from natural gamma ray spectroscopy logging data. In the implementation of this specification, the more accurate TOC content of kerogen is calculated using the formula. k .

[0121] In this specification, the total organic carbon (TOC) content of the formation and the sulfur content of the TOC in kerogen can be determined based on different well logging data. In one embodiment of this specification, under the condition that only conventional well logging data is available, the TOC content of the formation is calculated using the DlgR method based on conventional three-porosity logging and resistivity logging data, and the TOC content of the crude oil contained in the formation is subtracted to obtain the TOC content of kerogen.

[0122] In this specification, the total organic carbon content of the formation and the total organic carbon content of kerogen can be determined based on different well logging data. In one embodiment of this specification, under the condition of only conventional well logging data, the total organic carbon content of the formation is calculated using the DlgR method based on conventional three-porosity logging and resistivity logging data, and the total organic carbon content of the crude oil contained in the formation is subtracted to obtain the total organic carbon content of kerogen.

[0123] In another embodiment of this specification, under the condition of collecting conventional logging data and nuclear magnetic resonance logging data, the total organic carbon content of the formation is calculated using density and total porosity from nuclear magnetic resonance logging, and the total organic carbon content of the crude oil contained in the formation is subtracted to obtain the total organic carbon content of kerogen.

[0124] In another embodiment of this specification, under the condition of acquiring full-spectrum elemental logging data, the total organic carbon content of the formation obtained by inversion from the full-spectrum elemental logging data is subtracted from the total organic carbon content of the crude oil contained in the formation to obtain the total organic carbon content of kerogen. In summary, the quality of each source rock interval can be determined. In one embodiment of this specification, full-spectrum elemental logging data was acquired, and the total organic carbon content of the formation obtained by inversion from the full-spectrum elemental logging data was subtracted from the total organic carbon content of the crude oil contained in the formation to obtain the total organic carbon content of kerogen. Further calculations yielded source rock quality parameters (assuming a lower limit of 0.4% for the total organic carbon content of kerogen in the study area), as shown in track 7 of Figure 6.

[0125] This specification further clarifies the source-reservoir coupling relationship in the study area and further determines the sweet spot category of shale oil based on this relationship. According to the calculation and classification results of source rock quality and reservoir quality, and referring to the discrimination rules shown in Figure 8, the sweet spot development sections of shale oil are classified and evaluated. Specifically, if the reservoir quality is Class I and the source rock quality is Class I or II, the shale oil sweet spot is evaluated as a Class I (high-quality) sweet spot; if the reservoir quality is Class II and the source rock quality is Class I or II, or if the reservoir quality is Class I and the source rock quality is Class III, the shale oil sweet spot is classified as a Class II (medium) sweet spot; if the reservoir quality is Class II and the source rock quality is Class III, or if the reservoir quality is Class III and the source rock quality is Class I or II, the shale oil sweet spot is classified as a Class III (poor) sweet spot; if both the reservoir quality and the source rock quality are Class III, it is a non-sweet spot.

[0126] Figure 6 is a schematic diagram of a shale oil sweet spot logging evaluation example from a key well in the study area according to an embodiment of this specification. In the figure, the first line represents depth, the second line represents lithological indicator curves, including wellbore caliber (CAL), natural gamma ray curve (GRTO), and uranium-removed gamma ray curve (GRTC), the third line represents dual lateral resistivity curves, the fourth line represents three porosity curves, the fifth line represents a lithological profile, the sixth line represents the calculated results of reservoir quality parameter (RQ), the seventh line represents the calculated results of source rock quality parameter (SQ), and the eighth line represents the shale oil sweet spot classification results. The depth segment of the first projection represents a type I sweet spot development segment, the depth segment of the second projection represents a type II sweet spot development segment, and the depth segment of the third projection represents a type III sweet spot development segment.

[0127] The rightmost line in Figure 6 shows the logging evaluation results of the shale oil sweet spot in this key well in the study area. The evaluation results indicate that the distribution of the shale oil sweet spot in this key well is highly heterogeneous. In Figure 6, the 3448m–3462m section has source rock quality of Class II–III and reservoir quality of Class I–II. Based on the sweet spot classification of shale oil, this section is evaluated as a Class I–II sweet spot. The initial fracturing test at the 3442m–3450m depth yielded 17 cubic meters of oil per day, confirming the accuracy of the sweet spot evaluation. In Figure 6, the 3390m–3418m section has source rock quality of Class I–II and reservoir quality of Class I–II, representing the best source-reservoir coupling section in the depth range shown. This section is evaluated as a Class I sweet spot. In Figure 6, the two independent fracturing sections at 3538m–3544m and 3590m–3598m have relatively good reservoir quality, but the coupled source rock quality is poor (Class III) or far exceeds Class D. SR These two layers were evaluated as Category III sweet or non-sweet, which is consistent with the oil test results (after the backflow rate reached 100%, the two layers produced only oil droplets and no oil gas was observed).

[0128] Figure 7 shows a schematic diagram of a shale oil source rock quality logging evaluation device according to an embodiment of this specification. The figure illustrates the basic structure of the shale oil source rock quality logging evaluation device. The functional units and modules can be implemented using software, or they can be implemented using general-purpose chips or specific chips to evaluate the shale oil source rock quality. The device specifically includes:

[0129] The reservoir quality determination unit 701 is used to determine the reservoir quality of the study area based on the effective porosity and effective thickness of the shale oil reservoir in the study area. The effective porosity and effective thickness are determined based on well logging data.

[0130] The source rock quality determination unit 702 is used to evaluate the quality of each source rock segment based on the effective points of total organic carbon content of kerogen in the study area, the effective thickness of the segment corresponding to each effective point, and the total organic carbon content of kerogen at the effective points. The effective points are those with total organic carbon content of kerogen higher than the lower limit of total organic carbon content of kerogen.

[0131] The coupling relationship determination unit 703 is used to determine the coupling relationship between reservoir quality and source rock quality in the study area based on the estimated longitudinal distance range of the effective point of total organic carbon content in kerogen.

[0132] Evaluation unit 704 is used to evaluate shale oil sweet spots within the estimated longitudinal distance range based on coupling relationships.

[0133] Figure 8 shows a schematic diagram of a shale oil sweet spot identification rule according to an embodiment of this specification. In the figure, reservoir quality is used as the horizontal axis, and source rock quality is used as the vertical axis. The intersection of the horizontal and vertical axes is called the origin. The horizontal and vertical axes extend outwards from the origin, with quality levels ranging from poor to good. Reservoir quality and source rock quality are respectively divided into Class I, Class II, and Class III. Class I corresponds to a quality superior to Class II, and Class II and Class I correspond to a quality superior to Class III. This embodiment of the specification comprehensively considers both source rock quality and reservoir quality to determine the static geological sweet spot of shale oil, identifying areas with good oil-bearing potential and superior reservoir conditions.

[0134] Taking the reservoir quality parameters calculated from nuclear magnetic resonance logging data in Figure 2 as an example, the calculation results show that the overall reservoir quality (third to last channel) is relatively good, with a large number of layers in categories I and II, and small individual layer thicknesses but large cumulative thicknesses. Taking the source rock quality calculated from elemental full-spectrum logging data in Figure 2 as an example, the calculation results show that the overall source rock quality is poor, with only one layer in category I and three layers in category II, and small individual layer thicknesses.

[0135] Figure 9 shows a schematic diagram of a computer device provided in an embodiment of this specification. The shale oil sweet spot logging evaluation method based on source-reservoir coupling characteristics of this application can be applied to a computer device. The computer device 902 may include one or more processors 904, such as one or more central processing units (CPUs), each of which can implement one or more hardware threads. The computer device 902 may also include any memory 906 for storing any kind of information, such as code, settings, data, etc. Non-limitingly, for example, the memory 906 may include any type of RAM, any type of ROM, flash memory, hard disk, optical disk, etc. More generally, any memory can use any technology to store information. Furthermore, any memory can provide volatile or non-volatile retention of information. Furthermore, any memory can represent a fixed or removable component of the computer device 902. In one case, when the processor 904 executes associated instructions stored in any memory or combination of memories, the computer device 902 can perform any operation of the associated instructions. The computer device 902 also includes one or more drive mechanisms 908 for interacting with any memory, such as a hard disk drive mechanism, an optical disk drive mechanism, etc.

[0136] Computer device 902 may also include an input / output module 910 (I / O) for receiving various inputs (via input device 912) and providing various outputs (via output device 914). A specific output mechanism may include a presentation device 916 and an associated graphical user interface (GUI) 918. In other embodiments, the input / output module 910 (I / O), input device 912, and output device 914 may be omitted, and the device may function solely as a computer device within a network. Computer device 902 may also include one or more network interfaces 920 for exchanging data with other devices via one or more communication links 922. One or more communication buses 924 couple the components described above together.

[0137] Communication link 922 can be implemented in any way, such as via a local area network (LAN), a wide area network (WAN) (e.g., the Internet), a point-to-point connection, or any combination thereof. Communication link 922 may include any combination of hardwired links, wireless links, routers, gateway functions, name servers, etc., governed by any protocol or combination of protocols.

[0138] Corresponding to the methods in Figures 1 to 5, embodiments of this specification also provide a computer-readable storage medium storing a computer program that, when executed by a processor, performs the steps of the above-described methods.

[0139] This specification also provides computer-readable instructions, wherein when a processor executes the instructions, the program therein causes the processor to perform the methods shown in Figures 1 to 5.

[0140] It should be understood that in the various embodiments of this specification, the sequence number of each process does not imply the order of execution. The execution order of each process should be determined by its function and internal logic, and should not constitute any limitation on the implementation process of the embodiments of this specification.

[0141] It should also be understood that, in the embodiments of this specification, the term "and / or" is merely a description of the relationship between related objects, indicating that three relationships can exist. For example, A and / or B can represent: A existing alone, A and B existing simultaneously, and B existing alone. Additionally, the character " / " in this specification generally indicates that the preceding and following related objects have an "or" relationship.

[0142] Those skilled in the art will recognize that the units and algorithm steps of the various examples described in conjunction with the embodiments disclosed in this specification can be implemented in electronic hardware, computer software, or a combination of both. To clearly illustrate the interchangeability of hardware and software, the components and steps of each example have been generally described in terms of functionality in the foregoing description. Whether these functions are implemented in hardware or software depends on the specific application and design constraints of the technical solution. Those skilled in the art can use different methods to implement the described functions for each specific application, but such implementation should not be considered beyond the scope of this specification.

[0143] Those skilled in the art will clearly understand that, for the sake of convenience and brevity, the specific working processes of the systems, devices, and units described above can be referred to the corresponding processes in the foregoing method embodiments, and will not be repeated here.

[0144] In the several embodiments provided in this specification, it should be understood that the disclosed systems, apparatuses, and methods can be implemented in other ways. For example, the apparatus embodiments described above are merely illustrative; for instance, the division of units is only a logical functional division, and in actual implementation, there may be other division methods. For example, multiple units or components may be combined or integrated into another system, or some features may be ignored or not executed. Furthermore, the couplings or direct couplings or communication connections shown or discussed may be indirect couplings or communication connections through some interfaces, devices, or units, or they may be electrical, mechanical, or other forms of connection.

[0145] The units described as separate components may or may not be physically separate. The components shown as units may or may not be physical units; that is, they may be located in one place or distributed across multiple network units. Some or all of the units can be selected to achieve the purpose of the embodiments described in this specification, depending on actual needs.

[0146] Furthermore, the functional units in the various embodiments of this specification can be integrated into one processing unit, or each unit can exist physically separately, or two or more units can be integrated into one unit. The integrated unit can be implemented in hardware or as a software functional unit.

[0147] If the integrated unit is implemented as 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 this specification, in essence, or the part that contributes to the prior art, or all or part of the technical solution, can be embodied in the form of a software product. This computer software product is stored in a storage medium and includes several instructions to cause a computer device (which may be a personal computer, server, or network device, etc.) to execute all or part of the steps of the methods described in the various embodiments of this specification. The aforementioned storage medium includes various media capable of storing program code, such as USB flash drives, portable hard drives, read-only memory (ROM), random access memory (RAM), magnetic disks, or optical disks.

[0148] This specification uses specific embodiments to illustrate the principles and implementation methods of this specification. The descriptions of the above embodiments are only for the purpose of helping to understand the methods and core ideas of this specification. At the same time, for those skilled in the art, there will be changes in the specific implementation methods and application scope based on the ideas of this specification. Therefore, the content of this specification should not be construed as a limitation of this specification.

Claims

1. A method for evaluating sweet spot logging in shale oil based on source-reservoir coupling characteristics, characterized in that, The method includes: The reservoir quality in the study area is determined based on the effective porosity and effective thickness of the shale oil reservoirs in the study area, wherein the effective porosity and effective thickness are determined based on well logging data. The quality of each source rock segment is evaluated based on the effective points of total organic carbon content of kerogen in the study area, the effective thickness of the corresponding layer segment of each effective point, and the total organic carbon content of kerogen at the effective points. The effective points are those points where the total organic carbon content of kerogen is higher than the lower limit of the total organic carbon content of kerogen. Based on the estimated vertical distance range of the effective point of total organic carbon content in the kerogen, the coupling relationship between the reservoir quality and the quality of the source rock interval in the study area is determined; and Based on the aforementioned coupling relationship, the sweet spot of shale oil within the estimated longitudinal distance range is evaluated.

2. The method according to claim 1, characterized in that, The determination of reservoir quality in the study area based on the effective porosity and effective thickness of the shale oil reservoirs includes: The quality parameters of the shale oil reservoir are determined based on the first effective porosity, the first effective thickness, and pore structure parameters, wherein the first effective porosity is determined based on conventional well logging data; and The quality parameters of the shale oil reservoir in the study area were determined based on the second effective porosity, the geometric mean of the nuclear magnetic resonance spectrum, and the second effective thickness. The second effective porosity was determined based on nuclear magnetic resonance logging data.

3. The method according to claim 2, characterized in that, The first effective porosity is determined as follows: Based on well logging data, the content of inorganic framework mineral components and clay content were determined; The density of the mixed inorganic mineral framework is determined based on the content of different inorganic framework mineral components; and Based on the density logging three-framework model, the formation density, density of the mixed inorganic mineral framework, clay content, and total organic carbon content of kerogen are determined according to the logging data. The effective porosity of the shale oil formation is then determined, and the effective porosity of the shale oil formation is the first effective porosity.

4. The method according to claim 2, characterized in that, The pore structure parameters are determined as follows: in, represents formation porosity; k represents formation permeability.

5. The method according to claim 2, characterized in that, Based on the second effective porosity, the geometric mean of the nuclear magnetic resonance spectrum, and the second effective thickness, the quality parameters of the shale oil reservoir in the study area are determined as follows: The quality parameters of shale oil reservoirs are determined using the following formula: in, T2LM represents the second effective porosity, and H represents the geometric mean of the T2 NMR spectrum. Re This indicates the second effective thickness.

6. The method according to claim 1, characterized in that, Based on the estimated vertical distance range of the effective point of total organic carbon content in the kerogen, the coupling relationship between the reservoir quality and the quality of the source rock interval in the study area is determined, including: Based on the location of the effective point of total organic carbon content of each kerogen, the reservoir within the estimated vertical distance range is searched up and down; The reservoir quality and source rock quality within the estimated vertical distance range are divided to obtain the reservoir and source rock classification results respectively; and Based on the results of the division between reservoir and source rock, the reservoir and source rock are matched.

7. The method according to claim 1, characterized in that, The evaluation of the quality of each source rock stratum includes: Based on the total organic carbon content of the formation and the total organic carbon content of the crude oil contained in the formation, the total organic carbon content of kerogen at each point in the study area was determined. The total organic carbon content of the formation was calculated based on different well logging data. Based on the lower limit of the total organic carbon content of kerogen that contributes to hydrocarbon accumulation, effective points for the total organic carbon content of kerogen were determined from various points in the study area. Based on the depth of the effective point of total organic carbon content in kerogen, the hydrocarbon source rock development section in the study area was determined layer by layer; Determine the effective thickness of each effective point in each segment of the source rock development section; and The quality of each source rock segment is evaluated based on the effective thickness and the total organic carbon content of the kerogen at the effective points.

8. A shale oil sweet spot logging evaluation device based on source-reservoir coupling characteristics, characterized in that, The device includes: The reservoir quality determination unit is used to determine the reservoir quality of the study area based on the effective porosity and effective thickness of the shale oil reservoir in the study area, wherein the effective porosity and effective thickness are determined based on well logging data. The source rock quality determination unit is used to evaluate the quality of each source rock segment based on the effective points of total organic carbon content of kerogen in the study area, the effective thickness of the segment corresponding to each effective point, and the total organic carbon content of kerogen at the effective points. The effective points are those points where the total organic carbon content of kerogen is higher than the lower limit of the total organic carbon content of kerogen. The coupling relationship determination unit is used to determine the coupling relationship between the reservoir quality and the source rock quality in the study area based on the estimated vertical distance range of the effective point of the total organic carbon content of the kerogen; and An evaluation unit is used to evaluate the shale oil sweet spot within the estimated longitudinal distance range based on the coupling relationship.

9. A computer device, comprising a memory, a processor, and a computer program stored in the memory and executable on the processor, characterized in that, When the processor executes the computer program, it implements the method according to any one of claims 1 to 7.

10. A computer-readable storage medium, characterized in that, The computer-readable storage medium stores a computer program that, when executed by a processor, implements the method according to any one of claims 1 to 7.

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