Shale dominant reservoir facies identification method and system

Abstract

The invention discloses a shale dominant reservoir facies identification method and system, and relates to the technical field of well logging exploration, and the method comprises the steps: obtaining conventional well logging curve data, element well logging curve data, nuclear magnetic well logging curve data, physical property experiment data and geochemical parameter hydrogen indexes of target shale; performing rock type division on the target shale according to small layers to obtain a plurality of layers of the target shale; determining corrected pore permeability data of the target shale; shale aperture microscopic parameters are determined; on the basis of the geochemical parameter hydrogen-containing index, the corrected porosity and permeability data, the shale aperture microscopic parameter and a preset rock structure correction index, constructing a dominant reservoir facies identification index of the target shale; and respectively calculating a dominant reservoir facies identification index corresponding to each horizon of the target shale, obtaining a longitudinal reservoir facies distribution state of the target shale, and determining the dominant reservoir facies of the target shale. According to the method, the technical problem that the dominant reservoir facies evaluation result is unreliable due to incomplete consideration of parameters in the prior art is solved.

Description

Technical Field

[0001] The present invention relates to the field of well logging exploration technology, and in particular to a method and system for identifying shale dominant reservoir phases. Background Art

[0002] In recent years, as conventional oil and gas production has gradually declined in various regions, unconventional oil and gas resources have occupied an increasingly important position as an alternative energy source and have become one of the important resources for increasing oil and gas production and reserves. At the same time, with breakthrough progress made in many shale oil and gas wells at home and abroad, shale oil and gas have received more and more attention.

[0003] There are many solutions to the research on logging identification of terrestrial shale oil reservoir phases. Most methods qualitatively give the curve state of the dominant reservoir phase in most cases through the amplitude change of the logging curve, or through single factor analysis from the aspects of reservoir properties or physical properties. Different methods tend to have different parameters and different weights, but there are still certain problems:

[0004] 1. Before determining the dominant reservoir phase of shale, the rock mineral composition triangle plate and TOC content are often used to achieve preliminary identification and naming of rocks. The study did not show the impact of rock structure changes on rock types. In addition, rock structure, mineral composition, and gamma spectrum that demonstrates the rock formation environment were not used together as a means of rock classification.

[0005] 2. Most well logging-based reservoir dominant phase studies use different parameter relationships to represent reservoir changes, but these studies do not consider the combination of pore size micro-parameters and macro-porosity and permeability parameters in parameter construction, and use geochemical logging parameters as a supplement. At the same time, they do not consider the changes in dominant reservoir (sweet spot) identification parameters caused by changes in rock structure.

[0006] Therefore, the existing logging identification methods for terrestrial shale oil reservoir phases all have the technical problem of unreliable evaluation results of the dominant reservoir phases due to incomplete consideration of parameters. Summary of the invention

[0007] The purpose of the present invention is to provide a method and system for identifying shale dominant reservoir phases in order to solve at least one of the above technical problems.

[0008] In a first aspect, an embodiment of the present invention provides a method for identifying a shale dominant reservoir phase, comprising: obtaining conventional logging curve data, element logging curve data, nuclear magnetic logging curve data, physical property experimental data, and geochemical parameter hydrogen index of a target shale; based on the element logging curve data and the conventional logging curve data, respectively determining the mineral content and natural gamma ray spectrum of the target shale; based on the rock structure of the target shale, the mineral content, and the natural gamma ray spectrum, dividing the target shale into rock types according to small layers to obtain multiple strata of the target shale; based on the element logging curve data, determining the mineral content and natural gamma ray spectrum of the target shale; dividing the target shale into rock types according to small layers to obtain multiple strata of the target shale; based on the element logging curve data, determining the mineral content and natural gamma ray spectrum of the target shale; and determining the mineral content and natural gamma ray spectrum of the target shale. The method comprises the following steps: determining the corrected porosity and permeability data of the target shale based on the well logging data, the conventional logging curve data, the nuclear magnetic logging curve data and the physical property experimental data; determining the pore size micro parameters of the shale according to the nuclear magnetic logging curve data; constructing the dominant reservoir phase identification index of the target shale based on the geochemical parameter hydrogen content index, the corrected porosity and permeability data, the shale pore size micro parameters and the preset rock structure correction index; calculating the dominant reservoir phase identification index corresponding to each stratum of the target shale respectively, obtaining the vertical reservoir phase distribution state of the target shale, and identifying the dominant reservoir phase of the target shale.

[0009] Furthermore, based on the rock structure, the mineral content and the natural gamma ray spectrum of the target shale, the target shale is divided into rock types by small layers to obtain multiple strata of the target shale, including: dividing the target shale into multiple structural types based on the rock structure; dividing the target shale into multiple mineral types based on the mineral content; calculating the TH / U ratio based on the natural gamma ray spectrum; dividing the target shale into multiple thorium-uranium ratio types based on the TH / U ratio; and combining and classifying the multiple structural types, the multiple mineral types and the multiple thorium-uranium ratio types to divide the target shale into multiple strata.

[0010] Furthermore, the structural types include: matrix type, laminar type and interlayer type; the mineral types include: felsic type, ash type, clay type and mixed type; the thorium-uranium ratio types include: high thorium-uranium ratio, medium thorium-uranium ratio and low thorium-uranium ratio; the multiple strata include: matrix type medium thorium-uranium ratio felsic mixed shale, laminar type medium thorium-uranium ratio clay-containing mixed shale, laminar type medium thorium-uranium ratio felsic shale, laminar type low thorium-uranium ratio felsic shale, laminar type medium thorium-uranium ratio clay-containing mixed shale, laminar type low thorium-uranium ratio felsic shale, interlayer type low thorium-uranium ratio felsic shale.

[0011] Further, the corrected porosity and permeability data include effective porosity and corrected permeability; based on the element logging curve data, the conventional logging curve data and the nuclear magnetic logging curve data, the corrected porosity and permeability data of the target shale is determined, including: calculating the effective porosity based on the element logging curve data combined with the conventional logging curve data; wherein the effective porosity calculation formula includes:

[0012]

[0013] In the formula, a i Indicates the volume fraction of the i-th mineral in the element logging curve data, DMA i represents the skeleton density of the ith mineral, V TOC is the volume of organic matter, ρ b represents the volume density calculated by density logging in the conventional logging curve data, φ e is the effective porosity, ρ ma To calculate the corrected skeleton density, ρ TOC is the density of organic matter, ρ f is the fluid density; the initial permeability is estimated based on the geometric mean of the T2 distribution in the nuclear magnetic logging curve data, and is corrected using the physical property experimental data to obtain the corrected permeability.

[0014] Furthermore, the shale pore size microscopic parameters include displacement pressure and saturation median pressure; wherein the calculation formula of the displacement pressure includes:

[0015]

[0016] Where Pd is the displacement pressure, T 2GM is the geometric mean of the T2 distribution in the nuclear magnetic logging curve data; based on the pseudo capillary pressure curve converted from nuclear magnetic mercury injection in the nuclear magnetic logging curve data, the saturation median pressure is determined; the saturation median pressure is the capillary pressure corresponding to the non-wetting phase saturation of 50%; the displacement pressure and the saturation median pressure are normalized respectively to obtain the normalized displacement pressure and the normalized saturation median pressure.

[0017] Furthermore, the corrected porosity and permeability data include effective porosity and corrected permeability, the shale pore size microscopic parameters include displacement pressure and saturation median pressure; the calculation formula of the dominant reservoir phase identification index includes:

[0018]

[0019] Where, M represents the dominant reservoir phase identification index, K is the corrected permeability, φ e is the effective porosity, P′50 represents the normalized median saturation pressure, Pd′ represents the normalized displacement pressure, HI represents the hydrogen index of the geochemical parameter, and l represents the preset rock structure correction index.

[0020] Further, identifying the dominant reservoir phase of the target shale includes: based on the size of the dominant reservoir phase identification index corresponding to each layer and in combination with the rock type to which each layer belongs, identifying the dominant reservoir phase of the target shale.

[0021] In a second aspect, an embodiment of the present invention further provides a shale dominant reservoir phase identification system, comprising: an acquisition module, a first determination module, a classification module, a second determination module, a third determination module, a construction module and an identification module; wherein the acquisition module is used to acquire conventional logging curve data, element logging curve data, nuclear magnetic logging curve data, physical property experimental data and geochemical parameter hydrogen index of the target shale; the first determination module is used to determine the mineral content and natural gamma ray spectrum of the target shale based on the element logging curve data and the conventional logging curve data; the classification module is used to classify the target shale into rock types by sublayer based on the rock structure of the target shale, the mineral content and the natural gamma ray spectrum, and obtain the target shale. The invention relates to a plurality of shale layers; the second determination module is used to determine the corrected porosity and permeability data of the target shale based on the element logging curve data, the conventional logging curve data, the nuclear magnetic logging curve data and the physical property experimental data; the third determination module is used to determine the shale pore size micro parameters according to the nuclear magnetic logging curve data; the construction module is used to construct the dominant reservoir phase identification index of the target shale based on the geochemical parameter hydrogen content index, the corrected porosity and permeability data, the shale pore size micro parameters and the preset rock structure correction index; the identification module is used to respectively calculate the dominant reservoir phase identification index corresponding to each layer of the target shale, obtain the vertical reservoir phase distribution state of the target shale, and identify the dominant reservoir phase of the target shale.

[0022] In a third aspect, an embodiment of the present invention further provides an electronic device, comprising: a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor implements the method provided in the embodiment of the present invention when executing the computer program.

[0023] In a fourth aspect, an embodiment of the present invention further provides a computer-readable storage medium, wherein the computer-readable storage medium stores computer instructions, and when the computer instructions are executed by a processor, the method provided in the embodiment of the present invention is implemented.

[0024] The present invention provides a shale dominant reservoir phase identification method and system, which comprehensively reflects the reservoir quality by forming dominant reservoir phase identification parameters by integrating various reservoir influencing factors, combining macroscopic and microscopic parameters, and considering the multi-parameter influence of the dominant reservoir. The parameters have clear physical and geological meanings, are simple and easy to operate and cover a wide range, and realize the comprehensive use of logging data to analyze the reservoir quality classification related indexes of the reservoir phase, which can be used to comprehensively identify the shale dominant reservoir phase. The dominant reservoir phase identification result is reasonable and clear, which alleviates the technical problem of unreliable dominant reservoir phase evaluation results due to incomplete consideration of parameters in the prior art. BRIEF DESCRIPTION OF THE DRAWINGS

[0025] In order to more clearly illustrate the implementation methods of the present application or the technical solutions in the prior art, the drawings required for use in the specific implementation methods or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are some implementation methods of the present application. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying any creative work.

[0026] Figure 1 A flowchart of a shale dominant reservoir phase identification method provided by an embodiment of the present invention;

[0027] Figure 2 A schematic diagram of shale classification provided by an embodiment of the present invention;

[0028] Figure 3 A shale dominant reservoir phase identification result diagram provided by an embodiment of the present invention;

[0029] Figure 4 A schematic diagram of a shale dominant reservoir phase identification system provided in an embodiment of the present invention. DETAILED DESCRIPTION

[0030] The following will be combined with the drawings in the embodiments of the present invention to clearly and completely describe the technical solutions in the embodiments of the present invention. Obviously, the described embodiments are only part of the embodiments of the present invention, not all of the embodiments. Based on the embodiments of the present invention, all other embodiments obtained by ordinary technicians in this field without creative work are within the scope of protection of the present invention.

[0031] Embodiment 1

[0032] Figure 1 FIG. 1 is a flow chart of a method for identifying shale dominant reservoir phases according to an embodiment of the present invention. Figure 1 As shown, the method specifically comprises the following steps:

[0033] Step S102, obtaining conventional logging curve data, element logging curve data, nuclear magnetic logging curve data, physical property experimental data and geochemical parameter hydrogen index of the target shale.

[0034] Specifically, the element logging curve data includes the measured abundance of oxygen, silicon, aluminum, iron, calcium, potassium, magnesium, sodium, and trace elements such as manganese and titanium in the formation. The physical property experimental data include the measurement data of the whole rock porosity and permeability. The geochemical parameter hydrogen index refers to HI=S2 / TOC×100.

[0035] Step S104, based on the element logging curve data and the conventional logging curve data, respectively determine the mineral content and the natural gamma spectrum of the target shale.

[0036] Specifically, the abundance of element logging curve data can be converted into formation mineral content. The approximate relative molecular mass of the oxides of the main elements in the rock can be used to reflect the mineral composition content in the rock. Different lithofacies are determined by determining the mineral content of different boundaries. The linear equation is solved by using the correlation between the element content and the mineral content, through the following formula:

[0037]

[0038] Use the element percentage to solve the required mineral content.

[0039] In the formula, E i Represents the content of the i-th element, %; C ij It represents the content of the i-th element in the j-th mineral and is the conversion coefficient between the element content and the mineral content; M j is the content of the jth mineral, %. The present invention uses multiple parameters to analyze from three main angles: rock classification, macroscopic and microscopic combination, and consideration of rock structure changes.

[0040] Step S106, based on the rock structure, mineral content and natural gamma ray spectrum of the target shale, the target shale is divided into rock types according to small layers to obtain multiple layers of the target shale.

[0041] Step S108, determining the corrected porosity and permeability data of the target shale based on the element logging curve data, conventional logging curve data, nuclear magnetic logging curve data and physical property experimental data.

[0042] Step S110, determining the shale pore size microscopic parameters according to the nuclear magnetic resonance logging curve data.

[0043] Step S112, constructing a dominant reservoir phase identification index of the target shale based on the geochemical parameter hydrogen index, the corrected porosity and permeability data, the shale pore size microscopic parameters and the preset rock structure correction index.

[0044] Step S114, respectively calculating the dominant reservoir phase identification index corresponding to each layer of the target shale, obtaining the vertical reservoir phase distribution state of the target shale, and identifying the dominant reservoir phase of the target shale.

[0045] Specifically, step S106 also includes the following steps:

[0046] Step S1061, dividing the target shale into multiple structural types based on the rock structure.

[0047] Specifically, the structural types include: matrix type, lamination type and interlayer type.

[0048] Step S1062: classify the target shale into multiple mineral types based on the mineral content.

[0049] Specifically, the mineral types include: felsic type, limy type, clay type and mixed type; among them, they are divided according to the mineral content:

[0050] Felsic type: felsic shale (felsic 75-100%, gray <25%, clay <25%), clay-bearing felsic shale (felsic 50-75%, gray <25%, clay 12.5%-50%), gray-bearing felsic shale (felsic 50-75%, gray 12.5-50%, clay <25%);

[0051] Mixed material type: mixed shale containing felsic (felsic <50%, ash <50%, clay <50%), mixed shale containing clay (felsic <50%, ash <50%, clay <50%), mixed shale containing ash (felsic <50%, ash <50%, clay <50%), the specific mixed material type is determined according to the content of felsic, ash and clay;

[0052] Clay types (felsic <25%, ash <25%, clay 75-100%), felsic clay shale (felsic 12.5-50%, ash <25%, clay 50-75%), ash clay shale (felsic <25%, ash 12.5-50%, clay 50-75%);

[0053] Gray material types: gray shale (felsic <25%, gray 75-100%, clay <25%), gray shale containing felsic (12.5-50%, gray 50-75%, clay <25%), and gray shale containing clay (felsic <25%, gray 50-75%, clay 12.5-50%).

[0054] Step S1063, based on the natural gamma ray spectrum, the TH / U ratio is calculated; based on the TH / U ratio, the target shale is divided into multiple thorium-uranium ratio types, where TH is the thorium content and U is the uranium content, so as to highlight its sedimentary environment.

[0055] Specifically, the types of thorium-uranium ratios include: high thorium-uranium ratio, medium thorium-uranium ratio and low thorium-uranium ratio. In shale formations, the boundaries can be adjusted according to the actual geological background conditions. For example, a TH / U ratio greater than 1.8 is considered a high thorium-uranium ratio, between 1.2 and 1.8 is considered a medium thorium-uranium ratio, and less than or equal to 1.2 is considered a low thorium-uranium ratio.

[0056] Step S1064, combining and classifying multiple structural types, multiple mineral types, and multiple thorium-to-uranium ratio types, and dividing the target shale into multiple strata.

[0057] Figure 2 FIG. 1 is a schematic diagram of shale classification provided according to an embodiment of the present invention. Figure 2 As shown, in an optional implementation provided by an embodiment of the present invention, the target shale is divided into seven layers, including: matrix-type medium thorium-uranium ratio mixed shale containing clay, laminated type medium thorium-uranium ratio mixed shale containing clay, laminated type medium thorium-uranium ratio felsic shale, laminated type low thorium-uranium ratio felsic shale, laminated type medium thorium-uranium ratio clay-containing mixed shale, laminated type low thorium-uranium ratio felsic shale, and interlayer type low thorium-uranium ratio felsic shale.

[0058] Optionally, the seven layers are numbered respectively, from layer 1 to layer 7.

[0059] Specifically, the corrected porosity and permeability data include effective porosity and corrected permeability; step S108 also includes:

[0060] Step S1081, calculating effective porosity based on element logging curve data combined with conventional logging curve data; wherein the effective porosity calculation formula includes:

[0061]

[0062] In the formula, a i Represents the volume fraction of the i-th mineral in the element logging curve data, DMA i represents the skeleton density of the ith mineral, V TOC is the volume of organic matter, ρ b represents the volume density calculated by density logging in conventional logging curve data, φ e is the effective porosity, ρ ma To calculate the corrected skeleton density (g / cm 3 ), ρ TOC is the density of organic matter (g / cm 3 ), ρf is the fluid density (g / cm 3 ).

[0063] Step S1082, estimating the initial permeability based on the geometric mean of the T2 distribution in the nuclear magnetic logging curve data, and correcting it using the physical property experimental data to obtain the corrected permeability.

[0064] Specifically, the shale pore size microscopic parameters include displacement pressure and saturation median pressure; wherein, the calculation formula of displacement pressure includes:

[0065]

[0066] Where Pd is the displacement pressure, T 2GM is the geometric mean of the T2 distribution in the nuclear magnetic logging curve data.

[0067] Specifically, the median saturation pressure is determined based on a pseudo capillary pressure curve converted from nuclear magnetic mercury injection in nuclear magnetic logging curve data; the median saturation pressure is the capillary pressure corresponding to 50% saturation of the non-wetting phase.

[0068] Finally, the displacement pressure and the median saturation pressure are normalized to obtain the normalized displacement pressure and the normalized median saturation pressure.

[0069] Among them, the normalization formula includes:

[0070]

[0071] Where X represents the normalized parameter, including displacement pressure or saturation median pressure.

[0072] Specifically, the calculation formula for the dominant reservoir phase identification index includes:

[0073]

[0074] Where M represents the dominant reservoir phase identification index, K is the corrected permeability, unit: md, P′ 50 represents the normalized median saturation pressure, Pd′ represents the normalized displacement pressure, HI represents the geochemical parameter hydrogen index, the unit is mg / g, and l represents the preset rock structure correction index.

[0075] Specifically, after a large amount of analysis on the preset rock structure correction index l, it can be known that after a large amount of statistics on the reservoir performance of matrix type, laminar type and interlayer type reservoirs, it is known that the interlayer type is better than the laminar type in terms of reservoir oil content, and the laminar type is better than the matrix type. After statistics on the three types of structural reservoirs, it is found that the increase in the content of felsic minerals in the matrix type reservoir corresponds to a better quality reservoir, the increase in the content of felsic, illite and pyrite in the laminar shale corresponds to a better quality reservoir, and the increase in the sandy component in the interlayer type reservoir corresponds to a better quality reservoir. Therefore, for the matrix type, laminar type and interlayer type reservoirs, the l value range is 0 to 0.1, 0.1 to 0.15, and 0.15 to 0.2. For the l value range, its value is determined by the content of felsic minerals, the content of felsic, illite and pyrite, and the content of sand.

[0076] Specifically, step S114 further includes: based on the magnitude of the dominant reservoir phase identification index corresponding to each layer and in combination with the rock type to which each layer belongs, identifying the dominant reservoir phase of the target shale.

[0077] Figure 3 is a shale dominant reservoir phase identification result diagram provided according to an embodiment of the present invention. Figure 3 As shown in Figure 2, the 2nd and 3rd layers are the dominant reservoir phase reservoirs, and the 5th layer is the secondary dominant reservoir phase reservoir. Figure 3 The shale dominant reservoir identification result diagram clearly shows and identifies the shale dominant reservoir phase.

[0078] The method for identifying the dominant reservoir phase of shale in the present invention is based on the standardized method system of reservoir evaluation, combines the macroscopic porosity and permeability of shale reservoir quality with the microscopic parameters of pore size, combines geochemical logging parameters, and considers the influence of rock structure on the dominant reservoir phase, thus providing a reasonable method for distinguishing the dominant reservoir in shale reservoirs.

[0079] The present invention forms the dominant reservoir phase discrimination parameters by integrating various reservoir influencing factors to comprehensively reflect the reservoir quality, combines macroscopic and microscopic parameters, and considers the multi-parameter influence of the dominant reservoir. The parameters have clear physical and geological meanings, are simple and easy to operate, and cover a wide range. The present invention realizes the comprehensive use of logging data to analyze the reservoir quality classification related indexes of the reservoir phase, which can be used to comprehensively identify the dominant reservoir phase of shale. The dominant reservoir phase discrimination results are reasonable and clear, and have high promotion and application value in the actual shale mining research.

[0080] Embodiment 2

[0081] Figure 4 FIG. 1 is a schematic diagram of a shale dominant reservoir phase identification system provided according to an embodiment of the present invention. Figure 4As shown, the system includes: an acquisition module 10 , a first determination module 20 , a classification module 30 , a second determination module 40 , a third determination module 50 , a construction module 60 and a recognition module 70 .

[0082] Specifically, the acquisition module 10 is used to acquire conventional logging curve data, element logging curve data, nuclear magnetic logging curve data, physical property experimental data and geochemical parameter hydrogen index of the target shale;

[0083] A first determination module 20 is used to determine the mineral content and natural gamma spectrum of the target shale based on the element logging curve data and the conventional logging curve data;

[0084] A classification module 30 is used to classify the target shale into rock types according to small layers based on the rock structure, mineral content and natural gamma ray spectrum of the target shale, so as to obtain multiple layers of the target shale;

[0085] The second determination module 40 is used to determine the corrected porosity and permeability data of the target shale based on the element logging curve data, the conventional logging curve data and the nuclear magnetic logging curve data;

[0086] The third determination module 50 is used to determine the shale pore size microscopic parameters according to the nuclear magnetic logging curve data and the physical property experimental data;

[0087] A construction module 60 is used to construct a dominant reservoir phase identification index of the target shale based on the geochemical parameter hydrogen content index, the corrected porosity and permeability data, the shale pore size microscopic parameters and the preset rock structure correction index;

[0088] The identification module 70 is used to calculate the dominant reservoir phase identification index corresponding to each layer of the target shale, obtain the vertical reservoir phase distribution state of the target shale, and identify the dominant reservoir phase of the target shale.

[0089] Specifically, the classification module 30 is also used to: divide the target shale into multiple structural types based on the rock structure; divide the target shale into multiple mineral types based on the mineral content; calculate the TH / U ratio based on the natural gamma ray spectrum; divide the target shale into multiple thorium-uranium ratio types based on the TH / U ratio; combine and classify multiple structural types, multiple mineral types and multiple thorium-uranium ratio types to divide the target shale into multiple strata.

[0090] The present invention further provides an electronic device, comprising: a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor implements the method provided in the embodiment of the present invention when executing the computer program.

[0091] The present invention also provides a computer-readable storage medium, which stores computer instructions. When the computer instructions are executed by a processor, the method provided in the embodiment of the present invention is implemented.

[0092] It will be apparent to those skilled in the art that the invention is not limited to the details of the exemplary embodiments described above and that the invention can be implemented in other specific forms without departing from the spirit or essential features of the invention. Therefore, the embodiments should be considered exemplary and non-limiting in all respects, and the scope of the invention is defined by the appended claims rather than the foregoing description, and it is intended that all variations falling within the meaning and scope of the equivalent elements of the claims be included in the invention. Any reference numeral in a claim should not be considered as limiting the claim to which it relates.

[0093] In addition, it should be understood that although the present specification is described according to implementation modes, not every implementation mode contains only one independent technical solution. This description of the specification is only for the sake of clarity. Those skilled in the art should regard the specification as a whole. The technical solutions in each embodiment may also be appropriately combined to form other implementation modes that can be understood by those skilled in the art.

Claims

1. A method for identifying shale dominant reservoir phases, characterized in that: include: Obtain conventional logging curve data, element logging curve data, nuclear magnetic logging curve data, physical property experimental data and geochemical parameter hydrogen index of the target shale; Based on the element logging curve data and the conventional logging curve data, respectively determining the mineral content and natural gamma spectrum of the target shale; Based on the rock structure of the target shale, the mineral content and the natural gamma ray spectrum, the target shale is divided into rock types according to small layers to obtain multiple layers of the target shale; Determining the corrected porosity and permeability data of the target shale based on the element logging curve data, the conventional logging curve data, the nuclear magnetic logging curve data and the physical property experimental data; Determining shale pore size microscopic parameters according to the nuclear magnetic logging curve data; Based on the geochemical parameter hydrogen content index, the corrected porosity and permeability data, the shale pore size microscopic parameters and the preset rock structure correction index, constructing the dominant reservoir phase identification index of the target shale; The dominant reservoir phase identification index corresponding to each layer of the target shale is calculated respectively to obtain the vertical reservoir phase distribution state of the target shale, and the dominant reservoir phase of the target shale is identified.

2. The method according to claim 1, characterized in that: Based on the rock structure of the target shale, the mineral content and the natural gamma ray spectrum, the target shale is divided into rock types according to small layers to obtain multiple layers of the target shale, including: Classifying the target shale into a plurality of structural types based on the rock structure; classifying the target shale into a plurality of mineral types based on the mineral content; Calculating a TH / U ratio based on the natural gamma ray spectrum; Based on the TH / U ratio, the target shale is divided into a plurality of thorium-to-uranium ratio types; The multiple structural types, the multiple mineral types and the multiple thorium-to-uranium ratio types are combined and classified to divide the target shale into multiple horizons.

3. The method according to claim 2, characterized in that: The structural types include: matrix type, laminar type and interlayer type; The mineral types include: felsic type, limy type, clay type and mixed type; The thorium-uranium ratio types include: high thorium-uranium ratio, medium thorium-uranium ratio and low thorium-uranium ratio; The multiple strata include: matrix-type medium thorium-uranium ratio felsic mixed shale, laminated medium thorium-uranium ratio clay-containing shale, laminated medium thorium-uranium ratio felsic shale, laminated low thorium-uranium ratio felsic shale, laminated medium thorium-uranium ratio clay-containing mixed shale, laminated low thorium-uranium ratio felsic shale, and interlayer low thorium-uranium ratio felsic shale.

4. The method according to claim 1, characterized in that: The corrected porosity and permeability data include effective porosity and corrected permeability; based on the element logging curve data, the conventional logging curve data, the nuclear magnetic logging curve data and the physical property experimental data, the corrected porosity and permeability data of the target shale are determined, including: The effective porosity is calculated based on the element logging curve data combined with the conventional logging curve data; wherein the effective porosity calculation formula includes: In the formula, a i Indicates the volume fraction of the i-th mineral in the element logging curve data, DMA i represents the skeleton density of the ith mineral, V TOC is the volume of organic matter, ρ b represents the volume density calculated by density logging in the conventional logging curve data, φ e is the effective porosity, ρ ma To calculate the corrected skeleton density, ρ TOC is the density of organic matter, ρ f is the fluid density; The initial permeability is estimated based on the geometric mean of the T2 distribution in the nuclear magnetic logging curve data, and is corrected using the physical property experimental data to obtain the corrected permeability.

5. The method according to claim 1, characterized in that: The shale pore size microscopic parameters include displacement pressure and saturation median pressure; wherein the calculation formula of the displacement pressure includes: Where Pd is the displacement pressure, T 2GM is the geometric mean of the T2 distribution in the nuclear magnetic logging curve data; Determine the median saturation pressure based on the pseudo capillary pressure curve converted from nuclear magnetic mercury injection in the nuclear magnetic logging curve data; the median saturation pressure is the capillary pressure corresponding to the non-wetting phase saturation of 50%; The displacement pressure and the saturation median pressure are normalized respectively to obtain a normalized displacement pressure and a normalized saturation median pressure.

6. The method according to claim 1, characterized in that: The corrected porosity and permeability data include effective porosity and corrected permeability, and the shale pore size microscopic parameters include displacement pressure and saturation median pressure; the calculation formula of the dominant reservoir phase identification index includes: Where, M represents the dominant reservoir phase identification index, K is the corrected permeability, φ e is the effective porosity, P′ 50 represents the normalized median saturation pressure, Pd′ represents the normalized displacement pressure, HI represents the hydrogen index of the geochemical parameter, and l represents the preset rock structure correction index.

7. The method according to claim 1, characterized in that: Identifying the dominant reservoir phase of the target shale includes: based on the magnitude of the dominant reservoir phase identification index corresponding to each layer and in combination with the rock type to which each layer belongs, identifying the dominant reservoir phase of the target shale.

8. A shale dominant reservoir phase identification system, characterized in that: include: an acquisition module, a first determination module, a classification module, a second determination module, a third determination module, a construction module and an identification module; wherein, The acquisition module is used to acquire conventional logging curve data, element logging curve data, nuclear magnetic logging curve data, physical property experimental data and geochemical parameter hydrogen index of the target shale; The first determination module is used to determine the mineral content and natural gamma spectrum of the target shale based on the element logging curve data and the conventional logging curve data; The classification module is used to classify the target shale into rock types according to small layers based on the rock structure of the target shale, the mineral content and the natural gamma ray spectrum, so as to obtain multiple layers of the target shale; The second determination module is used to determine the corrected porosity and permeability data of the target shale based on the element logging curve data, the conventional logging curve data, the nuclear magnetic logging curve data and the physical property experimental data; The third determination module is used to determine the shale pore size microscopic parameters according to the nuclear magnetic logging curve data; The construction module is used to construct a dominant reservoir phase identification index of the target shale based on the geochemical parameter hydrogen content index, the corrected porosity and permeability data, the shale pore size microscopic parameters and a preset rock structure correction index; The identification module is used to respectively calculate the dominant reservoir phase identification index corresponding to each layer of the target shale, obtain the vertical reservoir phase distribution state of the target shale, and identify the dominant reservoir phase of the target shale.

9. An electronic device, characterized in that: include: A memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor implements the method according to any one of claims 1 to 7 when executing the computer program.

10. A computer-readable storage medium, characterized in that: The computer-readable storage medium stores computer instructions, and when the computer instructions are executed by a processor, the method according to any one of claims 1 to 7 is implemented.

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