Reservoir fluid property identification method, device, equipment and medium

Abstract

The invention discloses a reservoir fluid property identification method and device, equipment and a medium, and relates to the technical field of petroleum geophysical logging, and the method comprises the steps: determining the main type of an oil and gas reservoir, analyzing the main type of the oil and gas reservoir, and obtaining oil and gas reservoir forming features; identifying the lithology of the reservoir, judging whether the lithology is the reservoir with the developed sand body, if so, judging whether a crack exists in the sand body by using the electric imaging image, and if so, determining the occurrence of stratigraphic stratification and natural crack based on the electric imaging image, and calculating the crack porosity and the crack density; drawing a fracture relational graph and a stratigraphic relational graph according to the stratigraphic stratification and the occurrence of the natural fractures, and performing analysis to obtain a fracture tendency distribution interval and a stratigraphic tendency distribution interval; and fluid properties are identified based on the fracture tendency distribution interval, the stratum tendency distribution interval, the fracture porosity and the fracture density. The reservoir fluid property identification accuracy and efficiency can be improved, the reservoir fluid property identification complexity is reduced, and the diversity of oil and gas reservoir exploration types is met.

Description

Technical Field

[0001] The present invention relates to the technical field of petroleum geophysical logging, and in particular to a reservoir fluid property identification method, device, equipment and medium. Background Art

[0002] In recent years, with the development of the oil and gas industry, the types of oil and gas reservoir exploration have become increasingly complex and diverse, and the objects of logging evaluation have gradually changed from conventional pore types to complex fracture-cavity reservoirs. The logging response characteristics of oil and gas layers no longer fully present the typical characteristics of "high resistivity, convex shape, low invasion, and large porosity", but present atypical response characteristics of "low resistivity value, non-convex resistivity shape, unclear resistivity low invasion characteristics, and small porosity". The oil and gas layer fluid property identification method derived from resistivity-porosity as the core is difficult to accurately identify the fluid properties in complex fracture-cavity oil and gas layers, and often shows inadaptability or even ineffectiveness, which leads to a decrease in the conformity rate of the comprehensive interpretation of oil and gas reservoirs, and reduces the accuracy and efficiency of reservoir fluid property identification.

[0003] It can be seen from the above that how to improve the accuracy and efficiency of reservoir fluid property identification, reduce the complexity of reservoir fluid property identification, and meet the diversity of oil and gas reservoir exploration types are problems to be solved in this field. Summary of the invention

[0004] In view of this, the purpose of the present invention is to provide a reservoir fluid property identification method, device, equipment and medium, which can improve the accuracy and efficiency of reservoir fluid property identification, reduce the complexity of reservoir fluid property identification, and meet the diversity of oil and gas reservoir exploration types. The specific scheme is as follows:

[0005] In a first aspect, the present application discloses a method for identifying reservoir fluid properties, comprising:

[0006] Determine the main types of oil and gas reservoirs in the reservoir, and analyze the main types of oil and gas reservoirs to obtain the oil and gas accumulation characteristics of the reservoir;

[0007] Identify the lithology of the reservoir and determine whether the lithology is a reservoir with developed sand bodies. If the lithology is a reservoir with developed sand bodies, use the electrical imaging image to determine whether there are cracks in the sand bodies. If there are cracks in the sand bodies, determine the stratigraphic bedding and the occurrence of natural cracks in the reservoir based on the electrical imaging image, and calculate the crack porosity and crack density.

[0008] Draw a fracture relationship diagram and a formation relationship diagram according to the formation bedding and the occurrence of the natural fractures, respectively, and analyze the fracture relationship diagram and the formation relationship diagram to obtain a fracture tendency distribution interval and a formation tendency distribution interval;

[0009] The fluid properties in the reservoir are identified based on the fracture tendency distribution interval, the formation tendency distribution interval, the fracture porosity and the fracture density to obtain a reservoir fluid property identification result.

[0010] Optionally, the analysis of the main types of the oil and gas reservoirs to obtain the oil and gas accumulation characteristics of the reservoirs includes:

[0011] The main types of oil and gas reservoirs are analyzed according to preset analysis factors to obtain the oil and gas accumulation characteristics of the reservoir; wherein the oil and gas accumulation characteristics include structural characteristics, oil and gas sources, transportation systems, oil and gas migration and reservoir characteristics.

[0012] Optionally, the identifying the lithology of the reservoir and determining whether the lithology is a reservoir with developed sand bodies, and if the lithology is a reservoir with developed sand bodies, determining whether there are cracks in the sand bodies by using electrical imaging images, includes:

[0013] Using a natural gamma curve to identify the lithology of the reservoir, and determine whether the lithology is a reservoir with developed sand bodies;

[0014] If the lithology is a reservoir with developed sand bodies, measured electrical imaging data is obtained, an electrical imaging image is drawn based on the electrical imaging data, and the electrical imaging image is used to determine whether there are cracks in the sand body.

[0015] Optionally, determining the formation bedding and the occurrence of natural fractures of the reservoir based on the electrical imaging image, and calculating fracture porosity and fracture density, comprises:

[0016] Determine the formation bedding and the occurrence of natural fractures of the reservoir based on the electrical imaging image, extract the fracture occurrence from the formation bedding and the occurrence of the natural fractures to obtain fracture inclination, fracture dip, formation inclination and formation dip;

[0017] The fracture porosity and fracture density of the reservoir are calculated.

[0018] Optionally, drawing a fracture relationship diagram and a stratum relationship diagram respectively according to the stratum bedding and the occurrence of the natural fractures, and analyzing the fracture relationship diagram and the stratum relationship diagram, comprises:

[0019] Draw a fracture relationship diagram based on the fracture inclination and the fracture dip angle, and draw a formation relationship diagram based on the formation inclination and the formation dip angle;

[0020] Mathematical statistics and analysis are performed on the fracture relationship diagram and the formation relationship diagram respectively.

[0021] Optionally, the identifying the fluid properties in the reservoir based on the fracture tendency distribution interval, the formation tendency distribution interval, the fracture porosity and the fracture density to obtain a reservoir fluid property identification result includes:

[0022] Comparing the fracture inclination direction in the fracture inclination distribution interval with the formation inclination direction in the formation inclination distribution interval to obtain a comparison result;

[0023] Based on the comparison results, and in combination with the fracture porosity and fracture density, a comprehensive fluid property identification standard is constructed, and the fluid properties in the reservoir are identified using the comprehensive fluid property identification standard to obtain a reservoir fluid property identification result.

[0024] Optionally, comparing the fracture inclination direction in the fracture inclination distribution interval with the formation inclination direction in the formation inclination distribution interval to obtain a comparison result includes:

[0025] Determining whether the fracture inclination direction in the fracture inclination distribution interval is consistent with the formation inclination direction in the formation inclination distribution interval;

[0026] If the fracture inclination direction in the fracture inclination distribution interval is consistent with the formation inclination direction in the formation inclination distribution interval, a comparison result for characterizing that the fluid property is an oil layer is generated;

[0027] If the fracture dip direction in the fracture dip distribution interval is inconsistent with the formation dip direction in the formation dip distribution interval, a comparison result for characterizing the fluid property as a non-oil layer is generated.

[0028] In a second aspect, the present application discloses a reservoir fluid property identification device, comprising:

[0029] A feature determination module is used to determine the main type of oil and gas reservoirs in the reservoir, and analyze the main type of oil and gas reservoirs to obtain the oil and gas accumulation characteristics of the reservoir;

[0030] A judgment module, used to identify the lithology of the reservoir and judge whether the lithology is a reservoir with developed sand bodies. If the lithology is a reservoir with developed sand bodies, the electrical imaging image is used to judge whether there are cracks in the sand bodies. If there are cracks in the sand bodies, the stratigraphic bedding and the occurrence of natural cracks in the reservoir are determined based on the electrical imaging image, and the crack porosity and crack density are calculated;

[0031] A relationship diagram analysis module, for drawing a fracture relationship diagram and a formation relationship diagram according to the formation bedding and the occurrence of the natural fractures, respectively, and analyzing the fracture relationship diagram and the formation relationship diagram to obtain a fracture tendency distribution interval and a formation tendency distribution interval;

[0032] The fluid property identification module is used to identify the fluid property in the reservoir based on the fracture tendency distribution interval, the formation tendency distribution interval, the fracture porosity and the fracture density to obtain a reservoir fluid property identification result.

[0033] In a third aspect, the present application discloses an electronic device, comprising:

[0034] Memory, used to store computer programs;

[0035] The processor is used to execute the computer program to implement the aforementioned reservoir fluid property identification method.

[0036] In a fourth aspect, the present application discloses a computer storage medium for storing a computer program; wherein, when the computer program is executed by a processor, the steps of the reservoir fluid property identification method disclosed above are implemented.

[0037] It can be seen that the present application provides a method for identifying reservoir fluid properties, including determining the main types of oil and gas reservoirs in the reservoir, analyzing the main types of oil and gas reservoirs to obtain the oil and gas accumulation characteristics of the reservoir; identifying the lithology of the reservoir, and judging whether the lithology is a reservoir with developed sand bodies, if the lithology is a reservoir with developed sand bodies, using electrical imaging images to judge whether there are cracks in the sand bodies, if there are cracks in the sand bodies, determining the stratigraphic bedding and the occurrence of natural cracks in the reservoir based on the electrical imaging images, and calculating the fracture porosity and fracture density; drawing a fracture relationship diagram and a formation relationship diagram according to the stratigraphic bedding and the occurrence of the natural cracks, respectively, analyzing the fracture relationship diagram and the formation relationship diagram to obtain a fracture inclination distribution interval and a formation inclination distribution interval; identifying the fluid properties in the reservoir based on the fracture inclination distribution interval, the formation inclination distribution interval, the fracture porosity and the fracture density to obtain a reservoir fluid property identification result. The present application obtains the characteristics of oil and gas accumulation by analyzing the main types of oil and gas reservoirs, which can reduce the multi-solution of conventional logging interpretation methods, and by analyzing the characteristics of oil and gas accumulation, it can meet the diversity of oil and gas reservoir exploration types, judge whether the sand body is developed, and use electrical imaging images to judge whether there are cracks in the sand body, so as to determine the occurrence of stratigraphic bedding and natural fractures. By using electrical imaging images to judge whether the sand body is developed and whether there are cracks, the shortcomings of traditional "resistivity-porosity" and its derivative methods are avoided, and the interpretation compliance rate of tight sandstone fracture-type oil and gas reservoirs is improved. Fracture relationship diagrams and formation relationship diagrams are drawn to obtain fracture tendency distribution intervals and formation tendency distribution intervals. On the basis of accurately evaluating reservoir fracture parameters, the relationship between fracture tendency and fluid properties is analyzed. Compared with previous methods, it has better operability, innovation, and applicability, and is conducive to promotion. The fluid properties are identified in combination with fracture porosity and fracture density to obtain reservoir fluid property identification results. The overall technical solution can improve the accuracy and efficiency of reservoir fluid property identification and reduce the complexity of reservoir fluid property identification. BRIEF DESCRIPTION OF THE DRAWINGS

[0038] In order to more clearly illustrate the embodiments of the present invention or the technical solutions in the prior art, the drawings required for use in the embodiments or the description of the prior art will be briefly introduced below. Obviously, the drawings described below are only embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on the provided drawings without paying creative work.

[0039] Figure 1 A flow chart of a reservoir fluid property identification method disclosed in this application;

[0040] Figure 2 A flow chart of a reservoir fluid property identification method disclosed in this application;

[0041] Figure 3 A comprehensive evaluation diagram of well logging of X1 well disclosed in this application;

[0042] Figure 4 A statistical diagram of the formation occurrence of Well X1 disclosed in this application;

[0043] Figure 5 A diagram showing the relationship between fluid properties and fracture occurrence of Well X1 disclosed in this application;

[0044] Figure 6 A comprehensive evaluation diagram of well logging of X2 disclosed in this application;

[0045] Figure 7 A statistical diagram of the formation occurrence of the X2 well disclosed in this application;

[0046] Figure 8 A diagram showing the relationship between fluid properties and fracture occurrence of a X2 well disclosed in this application;

[0047] Fig. 9 A comprehensive evaluation diagram of well logging of X3 well disclosed in this application;

[0048] Fig.10 A statistical diagram of the formation occurrence of the X3 well disclosed in this application;

[0049] Fig.11 A diagram showing the relationship between fluid properties and fracture occurrence of a X3 well disclosed in this application;

[0050] Fig.12 This is a schematic diagram of the structure of a reservoir fluid property identification device disclosed in this application;

[0051] Fig.13 A structural diagram of an electronic device provided for this application. DETAILED DESCRIPTION

[0052] 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.

[0053] In recent years, with the development of the oil and gas industry, the types of oil and gas reservoir exploration have become increasingly complex and diverse, and the objects of logging evaluation have gradually shifted from conventional pore types to complex fracture-cavity reservoirs. The logging response characteristics of oil and gas layers no longer fully present the typical characteristics of "high resistivity, convex shape, low invasion, and large porosity", but present atypical response characteristics of "low resistivity value, non-convex resistivity shape, unclear resistivity low invasion characteristics, and small porosity". The oil and gas layer fluid property identification method derived from resistivity-porosity as the core is difficult to accurately identify the fluid properties in complex fracture-cavity oil and gas layers, and often shows inadaptability or even ineffectiveness, which leads to a decrease in the conformity rate of the comprehensive interpretation of oil and gas reservoirs, and reduces the accuracy and efficiency of reservoir fluid property identification. As can be seen from the above, how to improve the accuracy and efficiency of reservoir fluid property identification, reduce the complexity of reservoir fluid property identification, and meet the diversity of oil and gas reservoir exploration types is a problem to be solved in this field.

[0054] See also Figure 1 As shown, the embodiment of the present invention discloses a reservoir fluid property identification method, which may specifically include:

[0055] Step S11: determining the main types of oil and gas reservoirs in the reservoir, and analyzing the main types of oil and gas reservoirs to obtain the oil and gas accumulation characteristics of the reservoir.

[0056] In this embodiment, the main types of oil and gas reservoirs in the reservoir are determined, and then the main types of oil and gas reservoirs are analyzed according to preset analysis factors to obtain the oil and gas accumulation characteristics of the reservoir; wherein the oil and gas accumulation characteristics include structural characteristics, oil and gas sources, transportation systems, oil and gas migration and reservoir characteristics.

[0057] Taking a tight sandstone fractured oil reservoir in a certain formation in the target work area as an example, this reservoir has the following five oil and gas accumulation characteristics: (1) Structural characteristics: The structure is located at the highest part of the central uplift belt rising to the north. The structure is cut by the Ming 5 main fault with a northeastern trend and southeastern dip and the Wei 7 main fault with a northeastern trend and northwesterly dip, forming a horst-type structural main body; (2) Oil and gas source: The Triassic crude oil originates from the third and fourth members of the Shahejie Formation, which are "newborn ancient reservoirs"; the Triassic natural gas comes from The coalbed methane in the Carboniferous-Permian system is a "paleogene new reservoir" gas reservoir; (3) Transportation system: The oil and gas migration pathways include faults, unconformities, cracks, bedding, etc.; (4) Oil and gas migration: Oil and gas migrate along faults and unconformities to the Triassic strata, and then migrate to the structural highs through the fracture system developed in the Triassic, and accumulate in the cracks and caves at the structural highs to form reservoirs; (5) Reservoir characteristics: Oil is endowed in fractures, and the matrix does not contain oil. Fractures are both storage spaces and seepage channels. Based on structural characteristics, oil and gas sources, transportation system, oil and gas migration, and reservoir characteristics, the oil and gas accumulation characteristics of tight sandstone fractures in this area are formed, that is, the double-fault bidirectional hydrocarbon supply accumulation model. When the fracture formation time and oil and gas migration time are ideally configured, only when the fracture inclination is spatially consistent with the formation inclination, can oil and gas migrate to the formation through the fractures to form oil and gas reservoirs.

[0058] Step S12: Identify the lithology of the reservoir and determine whether the lithology is a reservoir with developed sand bodies. If the lithology is a reservoir with developed sand bodies, use the electrical imaging image to determine whether there are cracks in the sand bodies. If there are cracks in the sand bodies, determine the stratigraphic bedding and the occurrence of natural cracks in the reservoir based on the electrical imaging image, and calculate the fracture porosity and fracture density.

[0059] In this embodiment, the natural gamma curve is used to identify the lithology of the reservoir, and to determine whether the lithology is a reservoir with developed sand bodies. If the lithology is a reservoir with developed sand bodies, measured electrical imaging data is obtained, and an electrical imaging image is drawn based on the electrical imaging data. The electrical imaging image is used to determine whether there are cracks in the sand body. If there are cracks in the sand body, the stratigraphic bedding and the occurrence of natural cracks in the reservoir are determined based on the electrical imaging image, and the fracture porosity and fracture density are calculated.

[0060] Step S13: drawing a fracture relationship diagram and a formation relationship diagram respectively according to the formation bedding and the occurrence of the natural fractures, and analyzing the fracture relationship diagram and the formation relationship diagram to obtain a fracture tendency distribution interval and a formation tendency distribution interval.

[0061] In this embodiment, a fracture relationship diagram and a stratigraphic relationship diagram are drawn according to the stratigraphic bedding and the occurrence of natural fractures. Taking the target work area as an example, it is found that the occurrence of the stratigraphic system is relatively stable, the stratigraphic dip is mostly between 10º-40º, and the azimuth is mostly between 10º-40º; the natural fractures are mostly high-angle fractures, and the fracture dip is mostly between 60º-90º; according to the different fracture inclinations, they can be divided into two groups: one group of fractures with a dip interval of 115º-210º, and the other group of fractures with a dip interval of 260º-360º.

[0062] Step S14: Identify the fluid properties in the reservoir based on the fracture tendency distribution interval, the formation tendency distribution interval, the fracture porosity and the fracture density to obtain a reservoir fluid property identification result.

[0063] In this embodiment, the fracture dip direction in the fracture dip distribution interval is compared with the formation dip direction in the formation dip distribution interval to obtain a comparison result; based on the comparison result, and in combination with the fracture porosity and fracture density, a comprehensive fluid property identification standard is constructed, and the fluid properties in the reservoir are identified using the comprehensive fluid property identification standard to obtain a reservoir fluid property identification result.

[0064] The specific comparison process is: determine whether the fracture inclination direction in the fracture inclination distribution interval is consistent with the formation inclination direction in the formation inclination distribution interval; if the fracture inclination direction in the fracture inclination distribution interval is consistent with the formation inclination direction in the formation inclination distribution interval, generate a comparison result for characterizing the fluid property as an oil layer; if the fracture inclination direction in the fracture inclination distribution interval is inconsistent with the formation inclination direction in the formation inclination distribution interval, generate a comparison result for characterizing the fluid property as a non-oil layer.

[0065] That is to say, by comparing the distribution intervals of the formation dip and the fracture dip in the fracture relationship diagram and the formation relationship diagram, the fluid properties of the reservoir can be qualitatively identified. As mentioned above, the formation dip in the target work area is relatively stable and the dips are basically consistent. When the fracture dip is consistent with or close to the formation dip, oil and gas can migrate to the formation through the fractures. Such a reservoir with enough fractures is prone to form oil and gas reservoirs, so the layer is qualitatively identified as an oil layer (i.e., generating a comparison result for characterizing the fluid properties as an oil layer); when the directions of the two are inconsistent, it is not conducive to the migration and storage of oil and gas. Such a reservoir with enough fractures is not easy to form oil and gas reservoirs, so the layer is qualitatively identified as a non-oil layer, i.e., a water layer or a dry layer (equivalent to generating a comparison result for characterizing the fluid properties as a non-oil layer).

[0066] Based on the comparison results (i.e. the relationship between the above-mentioned fracture inclination and formation inclination), combined with the quantitatively evaluated fracture porosity, fracture density and other parameters, a comprehensive identification standard for the fluid properties of the tight sandstone fracture reservoir in this area was established, and the reservoir fluid property identification results of the reservoir were finally determined, as shown in Table 1:

[0067] Table 1

[0068]

[0069] When the fracture inclination is basically consistent with the formation inclination, such as the fracture porosity is large (greater than 2.0% in the target work area) or the fracture density is large (≥3 fractures / m in the target work area), the reservoir fluid property identification result is an oil layer; if the fracture porosity is average (between 1.0% and 2.0% in the target work area) or the fracture density is average (1-3 fractures / m in the target work area), the reservoir fluid property identification result is a low-yield oil layer; when the fracture inclination is inconsistent with the formation inclination, such as the fracture porosity is large (greater than 1.0% in the target work area) or the fracture density is large (≥1 fracture / m in the target work area), the reservoir fluid property identification result is a water layer; if the fracture porosity is relatively small (less than 1.0% in the target work area) or the fracture density is small (<1 fracture / m), the reservoir fluid property identification result is a dry layer.

[0070] In this embodiment, the main types of oil and gas reservoirs in the reservoir are determined, and the main types of oil and gas reservoirs are analyzed to obtain the oil and gas accumulation characteristics of the reservoir; the lithology of the reservoir is identified, and it is judged whether the lithology is a reservoir with developed sand bodies. If the lithology is a reservoir with developed sand bodies, the electrical imaging image is used to judge whether there are cracks in the sand bodies. If there are cracks in the sand bodies, the stratigraphic bedding and the occurrence of natural cracks in the reservoir are determined based on the electrical imaging image, and the fracture porosity and fracture density are calculated; a fracture relationship diagram and a formation relationship diagram are drawn according to the stratigraphic bedding and the occurrence of the natural cracks, respectively, and the fracture relationship diagram and the formation relationship diagram are analyzed to obtain a fracture tendency distribution interval and a formation tendency distribution interval; based on the fracture tendency distribution interval, the formation tendency distribution interval, the fracture porosity and the fracture density, the fluid properties in the reservoir are identified to obtain a reservoir fluid property identification result. The present application obtains the characteristics of oil and gas accumulation by analyzing the main types of oil and gas reservoirs, which can reduce the multi-solution of conventional logging interpretation methods, and by analyzing the characteristics of oil and gas accumulation, it can meet the diversity of oil and gas reservoir exploration types, judge whether the sand body is developed, and use electrical imaging images to judge whether there are cracks in the sand body, so as to determine the occurrence of stratigraphic bedding and natural fractures. By using electrical imaging images to judge whether the sand body is developed and whether there are cracks, the shortcomings of traditional "resistivity-porosity" and its derivative methods are avoided, and the interpretation compliance rate of tight sandstone fracture-type oil and gas reservoirs is improved. Fracture relationship diagrams and formation relationship diagrams are drawn to obtain fracture tendency distribution intervals and formation tendency distribution intervals. On the basis of accurately evaluating reservoir fracture parameters, the relationship between fracture tendency and fluid properties is analyzed. Compared with previous methods, it has better operability, innovation, and applicability, and is conducive to promotion. The fluid properties are identified in combination with fracture porosity and fracture density to obtain reservoir fluid property identification results. The overall technical solution can improve the accuracy and efficiency of reservoir fluid property identification and reduce the complexity of reservoir fluid property identification.

[0071] See also Figure 2 As shown, the embodiment of the present invention discloses a reservoir fluid property identification method, which may specifically include:

[0072] Step S21: determining the main types of oil and gas reservoirs in the reservoir, and analyzing the main types of oil and gas reservoirs to obtain the oil and gas accumulation characteristics of the reservoir.

[0073] Step S22: Identify the lithology of the reservoir and determine whether the lithology is a reservoir with developed sand bodies. If the lithology is a reservoir with developed sand bodies, use the electrical imaging image to determine whether there are cracks in the sand bodies. If there are cracks in the sand bodies, determine the stratigraphic bedding and the occurrence of natural cracks in the reservoir based on the electrical imaging image, extract the crack occurrence in the stratigraphic bedding and the occurrence of the natural cracks to obtain the crack tendency, crack dip, formation dip and formation dip, and calculate the fracture porosity and fracture density of the reservoir.

[0074] This application uses the natural gamma curve to identify lithology and determine whether the sand body is developed. If the sand body is developed, the characteristics of the drawn electrical imaging image are used to qualitatively determine whether there are cracks in the sand body. For tight sandstone fracture reservoirs, the natural gamma is relatively low, and the electrical imaging logging data indicates that natural fractures are developed, and most of them are high-angle fractures.

[0075] Natural fractures are always accompanied by tectonic movements and dissolution, so the conductivity anomalies are generally neither parallel nor regular; fractures can cut any medium (including layer interfaces), and fractures can be parallel or intersecting with each other, and the electrical phases between adjacent fractures can be different. The fracture strike is the extension direction of the fracture, and the fracture strike is perpendicular to the fracture dip. Based on this, the fracture strike can be determined, and then the favorable exploration direction can be determined. For the target work area, the well site is deployed along the strike of the fracture. Bedding is often a group of parallel or nearly parallel conductivity anomalies, and the anomaly width is narrow and uniform. It is generally continuous and complete on the image, and is not interrupted at will. If the stratum is inclined, the bedding on the image will be a sinusoidal wave curve. The amplitude of the sine wave reflects the value of the dip angle, and the position of the trough indicates the stratum dip.

[0076] The process of calculating fracture porosity is as follows: the degree of fracture development is completed by comprehensive evaluation of fracture parameters such as fracture density and fracture apparent porosity. FVPA (fracture porosity) is the opening area of ​​visible fractures on the 1m well wall divided by the coverage area of ​​FMI (Formation MicroScanner Image) in the 1m well section, that is:

[0077] ;

[0078] in, is the fracture porosity, is the average width of the i-th crack, is the length of the ith fracture in the unit well section, which is generally selected as 1m, and D is the well diameter. In fact, the fracture porosity is the porosity over an area.

[0079] Calculate the fracture density as follows: The fracture density is the number of fractures per unit length of the wellbore wall, in units of fractures / m, and the calculation formula is:

[0080] .

[0081] Step S23: Draw a fracture relationship diagram based on the fracture tendency and the fracture dip angle, draw a formation relationship diagram based on the formation tendency and the formation dip angle, and perform mathematical statistics and analysis on the fracture relationship diagram and the formation relationship diagram, respectively, to obtain a fracture tendency distribution interval and a formation tendency distribution interval.

[0082] Step S24: identifying the fluid properties in the reservoir based on the fracture tendency distribution interval, the formation tendency distribution interval, the fracture porosity and the fracture density to obtain a reservoir fluid property identification result.

[0083] Taking the test and production results of the specific X1 well as an example, the accuracy of the present invention is verified. Figure 3 This is the X1 well logging comprehensive evaluation map, the left side is the conventional logging comprehensive evaluation map, and the right side is the EMI (Electrical Microscanner Imager) electrical imaging logging evaluation map. It can be seen that the natural gamma curve of the 2945.0-2987.0 meter well section indicates that the sand body is relatively developed, and the electrical imaging logging data indicates that the natural fractures in the 66th layer are well developed, and most of them are high-angle fractures. Combined with the characteristics of the three-porosity and three-resistivity curves, a comprehensive analysis shows that it is a tight sandstone fracture reservoir. Using the technical solution of the present application, the process is: (1) Draw the fracture relationship diagram of the fracture tendency and fracture dip angle of the tight sandstone fracture reservoir, and the formation relationship diagram of the formation dip angle and formation dip angle, respectively. Among them, the X1 well formation occurrence statistical diagram is shown in the figure. Figure 4 As shown in Figure 2, the relationship between the fluid properties and fracture occurrence in Well X1 is as follows: Figure 5 As shown in Figure 1, the occurrence of this section of the strata is relatively consistent, with a formation dip angle of 22º-45º, a formation inclination of 90º-140º, and fracture inclinations of 55º-90º. According to the different fracture inclinations, they can be divided into two groups: one group of fractures with a dip range of 130º-200º, and another group of fractures with a dip range of 310º-360º. (2) Further analysis of the distribution range of formation dips and fracture inclinations shows that this section of the strata has a series of fractures with a dip range of 130º-200º, which is consistent with the formation dip angle. The configuration relationship is good (the formation dip is 90º-140º), which is convenient for oil and gas migration and storage, and easy to form oil layers; (3) According to the comprehensive identification standard of fluid properties of tight sandstone fracture reservoirs, the formation fracture dip is consistent with the formation dip, and the reservoir fluid properties of layers 66, 70, and 71 with large fracture porosity are identified as oil layers, and the reservoir fluid properties of layer 72 with medium fracture porosity are identified as poor oil layers, and the reservoir fluid properties of the remaining layers are identified as dry layers. The test results show that the daily production of crude oil is 63.9 tons and water is 0.6 tons, and the test conclusion is that it is an oil layer.

[0084] Taking the test and production results of the specific X2 well as an example, the accuracy of the present invention is verified. Figure 6 This is the X2 well logging comprehensive evaluation map, the left side is the conventional logging comprehensive evaluation map, and the right side is the EMI electrical imaging logging evaluation map. It can be seen that the natural gamma curve of the 2687.0-2737.0 meter well section indicates that the sand body is relatively developed, and the electrical imaging logging data indicate that the natural fractures in the 42, 43, and 48 layers are well developed, and most of them are high-angle fractures. The logging interpretation of the fracture porosity of the 42, 43, and 48 layers is 3.20%, 3.37%, and 3.01%, respectively. Combined with the characteristics of the three porosity and three resistivity curves, the comprehensive analysis shows that it is a tight sandstone fracture reservoir. Using the technical solution of the present application, the process is: (1) Draw the relationship diagrams between the fracture tendency and fracture dip angle, and the formation dip angle and formation dip angle of the tight sandstone fracture reservoir, respectively, where the X2 well formation occurrence statistical diagram is shown in the figure. Figure 7 As shown in Figure 2, the relationship between the fluid properties and fracture occurrence in Well X2 is as follows: Figure 8 As shown in the figure, the occurrence of this section of the strata is relatively consistent, with a formation dip angle of 22º-45º and a formation dip of 90º-140º; the fracture dip angles are mostly between 40º-90º, and they can be divided into two groups according to the fracture dips: one group of fractures with a dip interval of 70º-200º and the other group of fractures with a dip interval of 240º-310º. (2) Further analysis of the distribution range of formation dips and fracture dips shows that the fracture series with a dip interval of 70º-200º developed in this section of the strata have a good relationship with the formation configuration (formation dip is 90º-140º), which is convenient for oil and gas migration and storage, and is easy to form oil layers. (3) According to the established comprehensive identification standard for fluid properties of tight sandstone fracture reservoirs, the fracture dip of this section of the strata is consistent with the formation dip, and the reservoir fluid property identification results of layers 42, 43, and 48 with larger fracture porosity are oil layers. The remaining layers have no fractures and the fracture porosity is very small according to quantitative evaluation, so the reservoir fluid property identification results are dry layers. The test produced 23.2 tons of crude oil and 0.5 tons of water per day, and the logging interpretation conclusions were consistent with the test results.

[0085] Taking the test and production results of the specific X3 well as an example, the accuracy of the present invention is verified. Fig. 9 This is the comprehensive evaluation diagram of well logging of X3 well. It can be seen that the natural gamma curve of the well section of 2088.0-2095.0 meters is relatively low, the sand body is relatively developed, and the electrical imaging logging data indicates the development of natural fractures, and most of them are high-angle fractures. The calculated fracture apparent porosity is 1% on average. Combined with the characteristics of the three porosity and three resistivity curves, the comprehensive analysis shows that it is a tight sandstone fracture reservoir. Using the technical solution of this application, the process is as follows: (1) Draw the relationship diagrams between the fracture tendency and fracture dip angle, and the formation tendency and formation dip angle of the tight sandstone fracture reservoir, respectively. Among them, the statistical diagram of the formation occurrence of X3 well is as follows Fig.10 As shown in Figure 2, the relationship between the fluid properties and fracture occurrence in Well X3 is as follows: Fig.11As shown in the figure, the occurrence of the strata in this section is relatively consistent, with a formation dip angle of 20º-45º and a formation dip of 100º-150º; the fracture dip angle is between 40º-90º, and they can be divided into two groups according to the fracture dip: one group of fractures with a dip interval of 140º-220º and the other group of fractures with a dip interval of 290º-360º. (2) Further analysis of the distribution range of formation dip and fracture dip shows that the formation dip is 100º-150º, and the formation has a series of fractures with a dip interval of 140º-220º, which has a good relationship with the formation configuration, is convenient for oil and gas migration and storage, and is easy to form oil layers. (3) According to the established comprehensive identification standard for fluid properties of tight sandstone fracture reservoirs, the average porosity of the upper fractures in this section is close to 1%, and the average porosity of the lower fractures is greater than 2%. The fracture dip is consistent with the formation dip. The reservoir fluid property identification result shows that the upper part is a poor oil layer and the lower part is an oil layer. The fracturing produces 21.8 tons of crude oil and 3.5 cubic meters of water per day, and the conclusion of production is oil layer.

[0086] In summary, combined with the above analysis and conclusions of X1, X2, and X3, a comparison table of reservoir fluid property identification results and formation production (testing) results is generated, as shown in Table 2:

[0087] Table 2

[0088]

[0089] The innovations of this application are as follows: (1) It is proposed to use electrical imaging images to determine whether there are cracks in the sand body, thereby calculating the fracture porosity and fracture density, and then identifying the fluid properties, avoiding the shortcomings of the traditional "resistivity-porosity" and its derivative methods, and improving the interpretation compliance rate of tight sandstone fractured oil and gas reservoirs; (2) The technical solution of this application involves a method for distinguishing the fluid properties of tight sandstone fractured reservoirs. The technical ideas are clear and the application is fast. It reduces the multi-solution of conventional well logging interpretation methods, and considers factors such as fracture porosity and fracture density to establish a comprehensive well logging interpretation standard; (3) Through the geological application research of electrical imaging images, on the basis of accurately evaluating the reservoir fracture parameters, the relationship between fracture tendency and fluid properties is analyzed. Compared with previous methods, it has better operability, innovation, and applicability, and is conducive to promotion. This method has been successfully applied to more than 100 wells in a block of Zhongyuan Oilfield; (4) From the analysis of the embodiments X1, X2, and X3, it can be seen that compared with the test results, the well logging interpretation compliance rate is 87.5%, which is higher than the industry standard requirements.

[0090] In this embodiment, the main types of oil and gas reservoirs in the reservoir are determined, and the main types of oil and gas reservoirs are analyzed to obtain the oil and gas accumulation characteristics of the reservoir; the lithology of the reservoir is identified, and it is judged whether the lithology is a reservoir with developed sand bodies. If the lithology is a reservoir with developed sand bodies, the electrical imaging image is used to judge whether there are cracks in the sand bodies. If there are cracks in the sand bodies, the stratigraphic bedding and the occurrence of natural cracks in the reservoir are determined based on the electrical imaging image, and the fracture porosity and fracture density are calculated; a fracture relationship diagram and a formation relationship diagram are drawn according to the stratigraphic bedding and the occurrence of the natural cracks, respectively, and the fracture relationship diagram and the formation relationship diagram are analyzed to obtain a fracture tendency distribution interval and a formation tendency distribution interval; based on the fracture tendency distribution interval, the formation tendency distribution interval, the fracture porosity and the fracture density, the fluid properties in the reservoir are identified to obtain a reservoir fluid property identification result. The present application obtains the characteristics of oil and gas accumulation by analyzing the main types of oil and gas reservoirs, which can reduce the multi-solution of conventional logging interpretation methods, and by analyzing the characteristics of oil and gas accumulation, it can meet the diversity of oil and gas reservoir exploration types, judge whether the sand body is developed, and use electrical imaging images to judge whether there are cracks in the sand body, so as to determine the occurrence of stratigraphic bedding and natural fractures. By using electrical imaging images to judge whether the sand body is developed and whether there are cracks, the shortcomings of traditional "resistivity-porosity" and its derivative methods are avoided, and the interpretation compliance rate of tight sandstone fracture-type oil and gas reservoirs is improved. Fracture relationship diagrams and formation relationship diagrams are drawn to obtain fracture tendency distribution intervals and formation tendency distribution intervals. On the basis of accurately evaluating reservoir fracture parameters, the relationship between fracture tendency and fluid properties is analyzed. Compared with previous methods, it has better operability, innovation, and applicability, and is conducive to promotion. The fluid properties are identified in combination with fracture porosity and fracture density to obtain reservoir fluid property identification results. The overall technical solution can improve the accuracy and efficiency of reservoir fluid property identification and reduce the complexity of reservoir fluid property identification.

[0091] See also Fig.12 As shown, the embodiment of the present invention discloses a reservoir fluid property identification device, which may specifically include:

[0092] The characteristic determination module 11 is used to determine the main type of oil and gas reservoirs in the reservoir, and analyze the main type of oil and gas reservoirs to obtain the oil and gas accumulation characteristics of the reservoir;

[0093] A judgment module 12 is used to identify the lithology of the reservoir and judge whether the lithology is a reservoir with developed sand bodies. If the lithology is a reservoir with developed sand bodies, the electrical imaging image is used to judge whether there are cracks in the sand bodies. If there are cracks in the sand bodies, the stratigraphic bedding and the occurrence of natural cracks in the reservoir are determined based on the electrical imaging image, and the crack porosity and crack density are calculated;

[0094] A relationship diagram analysis module 13 is used to draw a fracture relationship diagram and a formation relationship diagram according to the formation bedding and the occurrence of the natural fractures, respectively, and analyze the fracture relationship diagram and the formation relationship diagram to obtain a fracture tendency distribution interval and a formation tendency distribution interval;

[0095] The fluid property identification module 14 is used to identify the fluid property in the reservoir based on the fracture tendency distribution interval, the formation tendency distribution interval, the fracture porosity and the fracture density to obtain a reservoir fluid property identification result.

[0096] In this embodiment, the main types of oil and gas reservoirs in the reservoir are determined, and the main types of oil and gas reservoirs are analyzed to obtain the oil and gas accumulation characteristics of the reservoir; the lithology of the reservoir is identified, and it is judged whether the lithology is a reservoir with developed sand bodies. If the lithology is a reservoir with developed sand bodies, the electrical imaging image is used to judge whether there are cracks in the sand bodies. If there are cracks in the sand bodies, the stratigraphic bedding and the occurrence of natural cracks in the reservoir are determined based on the electrical imaging image, and the fracture porosity and fracture density are calculated; a fracture relationship diagram and a formation relationship diagram are drawn according to the stratigraphic bedding and the occurrence of the natural cracks, respectively, and the fracture relationship diagram and the formation relationship diagram are analyzed to obtain a fracture tendency distribution interval and a formation tendency distribution interval; based on the fracture tendency distribution interval, the formation tendency distribution interval, the fracture porosity and the fracture density, the fluid properties in the reservoir are identified to obtain a reservoir fluid property identification result. The present application obtains the characteristics of oil and gas accumulation by analyzing the main types of oil and gas reservoirs, which can reduce the multi-solution of conventional logging interpretation methods, and by analyzing the characteristics of oil and gas accumulation, it can meet the diversity of oil and gas reservoir exploration types, judge whether the sand body is developed, and use electrical imaging images to judge whether there are cracks in the sand body, so as to determine the occurrence of stratigraphic bedding and natural fractures. By using electrical imaging images to judge whether the sand body is developed and whether there are cracks, the shortcomings of traditional "resistivity-porosity" and its derivative methods are avoided, and the interpretation compliance rate of tight sandstone fracture-type oil and gas reservoirs is improved. Fracture relationship diagrams and formation relationship diagrams are drawn to obtain fracture tendency distribution intervals and formation tendency distribution intervals. On the basis of accurately evaluating reservoir fracture parameters, the relationship between fracture tendency and fluid properties is analyzed. Compared with previous methods, it has better operability, innovation, and applicability, and is conducive to promotion. The fluid properties are identified in combination with fracture porosity and fracture density to obtain reservoir fluid property identification results. The overall technical solution can improve the accuracy and efficiency of reservoir fluid property identification and reduce the complexity of reservoir fluid property identification.

[0097] In some specific embodiments, the feature determination module 11 may specifically include:

[0098] The oil and gas accumulation characteristics determination module is used to analyze the main types of the oil and gas reservoirs according to preset analysis factors to obtain the oil and gas accumulation characteristics of the reservoir; wherein the oil and gas accumulation characteristics include structural characteristics, oil and gas sources, transportation systems, oil and gas migration and reservoir characteristics.

[0099] In some specific embodiments, the determination module 12 may specifically include:

[0100] A sand body development judgment module is used to identify the lithology of the reservoir using a natural gamma curve and judge whether the lithology is a reservoir with sand body development;

[0101] The electrical imaging image drawing module is used to obtain measured electrical imaging data if the lithology is a reservoir with developed sand bodies, draw electrical imaging images based on the electrical imaging data, and use the electrical imaging images to determine whether there are cracks in the sand bodies.

[0102] In some specific embodiments, the determination module 12 may specifically include:

[0103] A fracture occurrence extraction module, used for determining the formation bedding and the occurrence of natural fractures of the reservoir based on the electrical imaging image, extracting the fracture occurrence from the formation bedding and the occurrence of the natural fractures, so as to obtain fracture inclination, fracture dip, formation inclination and formation dip;

[0104] The calculation module is used to calculate the fracture porosity and fracture density of the reservoir.

[0105] In some specific embodiments, the relationship diagram analysis module 13 may specifically include:

[0106] A relationship diagram drawing module, used for drawing a fracture relationship diagram based on the fracture inclination and the fracture dip angle, and drawing a formation relationship diagram based on the formation inclination and the formation dip angle;

[0107] The mathematical statistics and analysis module is used to perform mathematical statistics and analysis on the fracture relationship diagram and the formation relationship diagram respectively.

[0108] In some specific embodiments, the fluid property identification module 14 may specifically include:

[0109] A comparison module, used for comparing the fracture inclination direction in the fracture inclination distribution interval with the formation inclination direction in the formation inclination distribution interval to obtain a comparison result;

[0110] The reservoir fluid property identification module is used to construct a comprehensive fluid property identification standard based on the comparison result and in combination with the fracture porosity and fracture density, and use the comprehensive fluid property identification standard to identify the fluid properties in the reservoir to obtain a reservoir fluid property identification result.

[0111] In some specific embodiments, the fluid property identification module 14 may specifically include:

[0112] A direction judgment module, used for judging whether the fracture inclination direction in the fracture inclination distribution interval is consistent with the formation inclination direction in the formation inclination distribution interval;

[0113] A first comparison result generating module, for generating a comparison result for characterizing that the fluid property is an oil layer if the fracture dip direction in the fracture dip distribution interval is consistent with the formation dip direction in the formation dip distribution interval;

[0114] The second comparison result generating module is used to generate a comparison result for characterizing the fluid property as a non-oil layer if the fracture dip direction in the fracture dip distribution interval is inconsistent with the formation dip direction in the formation dip distribution interval.

[0115] Fig.13 A schematic diagram of the structure of an electronic device provided in an embodiment of the present application. The electronic device 20 may specifically include: at least one processor 21, at least one memory 22, a power supply 23, a communication interface 24, an input / output interface 25, and a communication bus 26. The memory 22 is used to store a computer program, which is loaded and executed by the processor 21 to implement the relevant steps in the reservoir fluid property identification method performed by the electronic device disclosed in any of the aforementioned embodiments.

[0116] In this embodiment, the power supply 23 is used to provide working voltage for each hardware device on the electronic device 20; the communication interface 24 can create a data transmission channel between the electronic device 20 and the external device, and the communication protocol it follows is any communication protocol that can be applied to the technical solution of the present application, and is not specifically limited here; the input and output interface 25 is used to obtain external input data or output data to the outside world, and its specific interface type can be selected according to specific application needs and is not specifically limited here.

[0117] In addition, the memory 22, as a carrier for storing resources, can be a read-only memory, a random access memory, a disk or an optical disk, etc. The resources stored thereon include an operating system 221, a computer program 222 and data 223, etc. The storage method can be temporary storage or permanent storage.

[0118] Among them, the operating system 221 is used to manage and control the hardware devices and computer programs 222 on the electronic device 20, so as to realize the operation and processing of the data 223 in the memory 22 by the processor 21, which can be Windows, Unix, Linux, etc. In addition to including a computer program that can be used to complete the reservoir fluid property identification method performed by the electronic device 20 disclosed in any of the aforementioned embodiments, the computer program 222 can further include a computer program that can be used to complete other specific tasks. In addition to data transmitted from an external device received by the reservoir fluid property identification device, the data 223 can also include data collected by its own input and output interface 25, etc.

[0119] The steps of the method or algorithm described in conjunction with the embodiments disclosed herein may be implemented directly using hardware, a software module executed by a processor, or a combination of the two. The software module may be placed in a random access memory (RAM), a memory, a read-only memory (ROM), an electrically programmable ROM, an electrically erasable programmable ROM, a register, a hard disk, a removable disk, a CD-ROM, or any other form of storage medium known in the art.

[0120] Furthermore, an embodiment of the present application also discloses a computer-readable storage medium, in which a computer program is stored. When the computer program is loaded and executed by a processor, the steps of the reservoir fluid property identification method disclosed in any of the aforementioned embodiments are implemented.

[0121] Finally, it should be noted that, in this article, relational terms such as first and second, etc. are only used to distinguish one entity or operation from another entity or operation, and do not necessarily require or imply any such actual relationship or order between these entities or operations. Moreover, the terms "include", "comprise" or any other variants thereof are intended to cover non-exclusive inclusion, so that a process, method, article or device including a series of elements includes not only those elements, but also other elements not explicitly listed, or also includes elements inherent to such process, method, article or device. In the absence of further restrictions, the elements defined by the sentence "comprise a ..." do not exclude the presence of other identical elements in the process, method, article or device including the elements.

[0122] The above is a detailed introduction to a reservoir fluid property identification method, device, equipment and storage medium provided by the present invention. Specific examples are used in this article to illustrate the principles and implementation methods of the present invention. The description of the above embodiments is only used to help understand the method of the present invention and its core idea; at the same time, for general technical personnel in this field, according to the idea of ​​the present invention, there will be changes in the specific implementation method and application scope. In summary, the content of this specification should not be understood as a limitation on the present invention.

Claims

1. A method for identifying reservoir fluid properties, characterized in that: include: Determine the main types of oil and gas reservoirs in the reservoir, and analyze the main types of oil and gas reservoirs to obtain the oil and gas accumulation characteristics of the reservoir; Identify the lithology of the reservoir and determine whether the lithology is a reservoir with developed sand bodies. If the lithology is a reservoir with developed sand bodies, use the electrical imaging image to determine whether there are cracks in the sand bodies. If there are cracks in the sand bodies, determine the stratigraphic bedding and the occurrence of natural cracks in the reservoir based on the electrical imaging image, and calculate the crack porosity and crack density. Draw a fracture relationship diagram and a formation relationship diagram according to the formation bedding and the occurrence of the natural fractures, respectively, and analyze the fracture relationship diagram and the formation relationship diagram to obtain a fracture tendency distribution interval and a formation tendency distribution interval; The fluid properties in the reservoir are identified based on the fracture tendency distribution interval, the formation tendency distribution interval, the fracture porosity and the fracture density to obtain a reservoir fluid property identification result.

2. The reservoir fluid property identification method according to claim 1, characterized in that: The analysis of the main types of the oil and gas reservoirs to obtain the oil and gas accumulation characteristics of the reservoirs includes: The main types of oil and gas reservoirs are analyzed according to preset analysis factors to obtain the oil and gas accumulation characteristics of the reservoir; wherein the oil and gas accumulation characteristics include structural characteristics, oil and gas sources, transportation systems, oil and gas migration and reservoir characteristics.

3. The reservoir fluid property identification method according to claim 1, characterized in that: The identifying the lithology of the reservoir and judging whether the lithology is a reservoir with developed sand bodies, and if the lithology is a reservoir with developed sand bodies, judging whether there are cracks in the sand bodies by using electrical imaging images, includes: Using a natural gamma curve to identify the lithology of the reservoir, and determine whether the lithology is a reservoir with developed sand bodies; If the lithology is a reservoir with developed sand bodies, measured electrical imaging data is obtained, an electrical imaging image is drawn based on the electrical imaging data, and the electrical imaging image is used to determine whether there are cracks in the sand body.

4. The reservoir fluid property identification method according to claim 1, characterized in that: Determining the formation bedding and the occurrence of natural fractures of the reservoir based on the electrical imaging image, and calculating fracture porosity and fracture density, comprises: Determine the formation bedding and the occurrence of natural fractures of the reservoir based on the electrical imaging image, extract the fracture occurrence from the formation bedding and the occurrence of the natural fractures to obtain fracture inclination, fracture dip, formation inclination and formation dip; The fracture porosity and fracture density of the reservoir are calculated.

5. The reservoir fluid property identification method according to claim 4, characterized in that: The method of drawing a fracture relationship diagram and a stratum relationship diagram respectively according to the stratum bedding and the occurrence of the natural fractures, and analyzing the fracture relationship diagram and the stratum relationship diagram comprises: Draw a fracture relationship diagram based on the fracture inclination and the fracture dip angle, and draw a formation relationship diagram based on the formation inclination and the formation dip angle; Mathematical statistics and analysis are performed on the fracture relationship diagram and the formation relationship diagram respectively.

6. The reservoir fluid property identification method according to any one of claims 1 to 5, characterized in that: The identifying of the fluid properties in the reservoir based on the fracture tendency distribution interval, the formation tendency distribution interval, the fracture porosity and the fracture density to obtain a reservoir fluid property identification result includes: Comparing the fracture inclination direction in the fracture inclination distribution interval with the formation inclination direction in the formation inclination distribution interval to obtain a comparison result; Based on the comparison results, and in combination with the fracture porosity and fracture density, a comprehensive fluid property identification standard is constructed, and the fluid properties in the reservoir are identified using the comprehensive fluid property identification standard to obtain a reservoir fluid property identification result.

7. The reservoir fluid property identification method according to claim 6, characterized in that: The step of comparing the fracture inclination direction in the fracture inclination distribution interval with the formation inclination direction in the formation inclination distribution interval to obtain a comparison result includes: Determining whether the fracture inclination direction in the fracture inclination distribution interval is consistent with the formation inclination direction in the formation inclination distribution interval; If the fracture inclination direction in the fracture inclination distribution interval is consistent with the formation inclination direction in the formation inclination distribution interval, a comparison result for characterizing that the fluid property is an oil layer is generated; If the fracture dip direction in the fracture dip distribution interval is inconsistent with the formation dip direction in the formation dip distribution interval, a comparison result for characterizing the fluid property as a non-oil layer is generated.

8. A reservoir fluid property identification device, characterized in that: include: A feature determination module is used to determine the main type of oil and gas reservoirs in the reservoir, and analyze the main type of oil and gas reservoirs to obtain the oil and gas accumulation characteristics of the reservoir; A judgment module, used to identify the lithology of the reservoir and judge whether the lithology is a reservoir with developed sand bodies. If the lithology is a reservoir with developed sand bodies, the electrical imaging image is used to judge whether there are cracks in the sand bodies. If there are cracks in the sand bodies, the stratigraphic bedding and the occurrence of natural cracks in the reservoir are determined based on the electrical imaging image, and the crack porosity and crack density are calculated; A relationship diagram analysis module, for drawing a fracture relationship diagram and a formation relationship diagram according to the formation bedding and the occurrence of the natural fractures, respectively, and analyzing the fracture relationship diagram and the formation relationship diagram to obtain a fracture tendency distribution interval and a formation tendency distribution interval; The fluid property identification module is used to identify the fluid property in the reservoir based on the fracture tendency distribution interval, the formation tendency distribution interval, the fracture porosity and the fracture density to obtain a reservoir fluid property identification result.

9. An electronic device, characterized in that: include: Memory, used to store computer programs; A processor, configured to execute the computer program to implement the reservoir fluid property identification method according to any one of claims 1 to 7.

10. A computer-readable storage medium, characterized in that: Used to store a computer program; wherein, when the computer program is executed by a processor, the reservoir fluid property identification method according to any one of claims 1 to 7 is implemented.

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