Method and device for dynamically judging reservoir spatial form of fractured-vuggy carbonate reservoir

Abstract

The invention discloses a method and device for dynamically judging the spatial form of a fracture-cavity type carbonate reservoir, and the method comprises the steps: determining the height-width ratio of a fracture-cavity body in the carbonate reservoir drilled by an oil well according to the cumulative liquid production capacity and oil pressure change data of the oil well in a set development stage; determining the effective length and width of the fracture-cavity body according to the dynamic geological reserves in the oil well control range in the development stage, the length and width of the fracture-cavity body determined through the seismic reservoir inversion result and the effective porosity in the oil well control range; according to the effective length, the width and the height-width ratio of the fracture-cavity body, performing equivalence according to a circular stratum, and determining the effective height of the fracture-cavity body in the development stage; according to the effective length, the effective width and the effective height of the fracture-cavity body in the development stage, the three-dimensional space distribution form of the fracture-cavity body is judged. According to the method, the actual development dynamic data of the put-into-production oil well is fully utilized, the reservoir inversion result is combined, and the judged space structure form of the fracture-cavity body better conforms to mine field practice.

Description

Technical Field

[0001] The invention relates to a method and a device for dynamically distinguishing the spatial morphology of a fracture-cavity carbonate oil reservoir reservoir, and belongs to the technical field of fine description of carbonate oil reservoirs. Background Art

[0002] Fracture-cavity carbonate reservoirs often have extremely strong heterogeneity characteristics, and the study of the spatial structural morphology of their reservoir bodies has always been difficult. Over the past decade, due to the actual situation that single wells often empty or leak a large amount of oil when encountering the target layer, it is difficult to obtain logging data and core data. Therefore, the existing technology overly relies on geophysical methods to describe the reservoir spatial structure of this type of oil reservoir. However, since this type of reservoir is buried deep and seismic waves are subject to more interference factors, the multi-solution of seismic data is enhanced. The description of the fracture-cavity structure morphology based solely on seismic data cannot meet production needs well. Summary of the invention

[0003] The inventors have found that providing an effective method for dynamically distinguishing the spatial morphology of fracture-cavity carbonate reservoirs has become a technical problem that needs to be solved in this field. In order to enrich the process route and increase the selection space, the embodiment of the present invention provides a method and device for dynamically distinguishing the spatial morphology of fracture-cavity carbonate reservoirs, which combines the reservoir inversion results with the oil well production dynamic data, and the spatial structural morphology of the fracture-cavity body is more in line with the mine practice.

[0004] In a first aspect, an embodiment of the present invention provides a method for dynamically distinguishing the spatial morphology of a fracture-vuggy carbonate reservoir, comprising:

[0005] Determine the height-to-width ratio of the fracture-cavity body in the carbonate reservoir penetrated by the oil well based on the cumulative liquid production and oil pressure change data of the oil well in the set development stage;

[0006] Determine the effective length and effective width of the fracture-cavity body according to the dynamic geological reserves within the control range of the oil well in the development stage, the length and width of the fracture-cavity body determined by the seismic reservoir inversion results, and the effective porosity within the control range of the oil well;

[0007] According to the effective length and effective width of the fracture-cavity body and the aspect ratio, equivalent to a circular formation is performed to determine the effective height of the fracture-cavity body in the development stage;

[0008] According to the effective length, effective width and effective height of the fracture-cavity body in the development stage, the three-dimensional spatial distribution morphology of the fracture-cavity body is determined.

[0009] In a second aspect, an embodiment of the present invention provides a device for dynamically distinguishing the spatial morphology of a fracture-vuggy carbonate reservoir, comprising:

[0010] A module for determining the aspect ratio of fracture-cavity bodies, which is used to determine the aspect ratio of fracture-cavity bodies in carbonate reservoirs drilled by oil wells based on the cumulative liquid production and oil pressure change data of the oil wells in a set development stage;

[0011] The module for determining the effective length and effective width of the fracture-cavity body is used to determine the effective length and effective width of the fracture-cavity body according to the dynamic geological reserves within the control range of the oil well in the development stage, the length and width of the fracture-cavity body determined by the seismic reservoir inversion result, and the effective porosity within the control range of the oil well;

[0012] The effective height determination module of the fracture-cavity body is used to determine the effective height of the fracture-cavity body in the development stage according to the effective length and effective width of the fracture-cavity body and the aspect ratio, and to perform equivalent calculation according to the circular formation;

[0013] The three-dimensional spatial distribution morphology discrimination module of the fracture-cavity body is used to discriminate the three-dimensional spatial distribution morphology of the fracture-cavity body according to the effective length, effective width and effective height of the fracture-cavity body in the development stage.

[0014] In a third aspect, an embodiment of the present invention provides a computer storage medium, wherein the computer storage medium stores computer executable instructions, and when the computer executable instructions are executed by a processor, the above-mentioned method for dynamically distinguishing the spatial morphology of fracture-vuggy carbonate oil reservoir reservoirs is implemented.

[0015] In a fourth aspect, an embodiment of the present disclosure provides a server, comprising: a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein the processor implements the above-mentioned method for dynamically distinguishing the spatial morphology of fracture-vuggy carbonate oil reservoir reservoirs when executing the program.

[0016] The beneficial effects of the above technical solution provided by the embodiment of the present invention include at least:

[0017] The method for dynamically distinguishing the spatial morphology of fracture-cavity carbonate reservoirs provided in an embodiment of the present invention utilizes the actual development dynamic data of the oil wells that have been put into production, and combines the reservoir inversion results to calculate the effective length, width and height of the fracture-cavity body, and then distinguish the three-dimensional spatial distribution morphology of the fracture-cavity body, providing a basis for the characterization of the internal structure of the fracture-cavity reservoir and the representation of the reservoir scale. The research results can be applied to the research field of multi-scale characterization and geological modeling of fracture-cavity carbonate reservoirs, and can provide support for improving the utilization of reserves.

[0018] Other features and advantages of the present invention will be described in the following description, and partly become apparent from the description, or understood by practicing the present invention. The purpose and other advantages of the present invention can be realized and obtained by the structures particularly pointed out in the written description, claims, and drawings.

[0019] The technical solution of the present invention is further described in detail below through the accompanying drawings and embodiments. BRIEF DESCRIPTION OF THE DRAWINGS

[0020] The accompanying drawings are used to provide a further understanding of the present invention and constitute a part of the specification. Together with the embodiments of the present invention, they are used to explain the present invention and do not constitute a limitation of the present invention. In the accompanying drawings:

[0021] Figure 1 This is a flow chart of a method for dynamically distinguishing the spatial morphology of a fracture-vuggy carbonate reservoir in an embodiment of the present invention;

[0022] Figure 2 for Figure 1 Specific implementation flow chart of step S11;

[0023] Figure 3 for Figure 1 Specific implementation flow chart of step S12;

[0024] Figure 4A This is a curve diagram showing the relationship between the segmented oil pressure and the cumulative production of a stage in a P1 well in a certain block in the second embodiment of the present invention;

[0025] Figure 4B This is a curve diagram showing the relationship between the segmented oil pressure and the cumulative production of a stage in a P2 well in a certain block in the second embodiment of the present invention;

[0026] Figure 4C This is a curve diagram showing the relationship between the segmented oil pressure and the cumulative production of a stage in a P3 well in a certain block in the second embodiment of the present invention;

[0027] Figure 4D This is a curve diagram showing the relationship between the segmented oil pressure and the cumulative production of a stage in a P4 well in a certain block in the second embodiment of the present invention;

[0028] Figure 4E This is a curve diagram showing the relationship between the segmented oil pressure and the cumulative production of a stage in a P5 well in a certain block in the second embodiment of the present invention;

[0029] Figure 5 Schematic diagram of the structure of the device for dynamically distinguishing the spatial morphology of fracture-vuggy carbonate reservoirs in an embodiment of the present invention. DETAILED DESCRIPTION

[0030] The exemplary embodiments of the present disclosure will be described in more detail below with reference to the accompanying drawings. Although the exemplary embodiments of the present disclosure are shown in the accompanying drawings, it should be understood that the present disclosure can be implemented in various forms and should not be limited by the embodiments set forth herein. On the contrary, these embodiments are provided to enable a more thorough understanding of the present disclosure and to fully convey the scope of the present disclosure to those skilled in the art.

[0031] It should be understood that the terms described in the present invention are only for describing special embodiments and are not intended to limit the present invention. In addition, for the numerical range in the present invention, it should be understood that each intermediate value between the upper and lower limits of the scope is also specifically disclosed. Each smaller range between the intermediate value in any stated value or stated range and any other stated value or intermediate value in the described range is also included in the present invention. The upper and lower limits of these smaller ranges can be independently included or excluded in the scope.

[0032] Unless otherwise indicated, all technical and scientific terms used herein have the same meanings as commonly understood by those skilled in the art to which the invention belongs. Although the present invention describes only preferred methods and materials, any methods and materials similar or equivalent to those described herein may also be used in the implementation or testing of the present invention. All documents mentioned in this specification are incorporated by reference to disclose and describe the methods and / or materials related to the documents. In the event of a conflict with any incorporated document, the content of this specification shall prevail.

[0033] In order to meet the production needs of the development of fracture-cavity carbonate oil reservoirs, an embodiment of the present invention provides a method and device for dynamically distinguishing the spatial morphology of fracture-cavity carbonate oil reservoirs. The dynamic data of oil well production is combined with the seismic reservoir inversion results to more accurately characterize the spatial distribution characteristics of the fracture-cavity body from the perspective of spatial structural morphology. The data used in the research method are easy to obtain and have a high degree of reliability. Therefore, the research results can better meet the mine practice, greatly improve the accuracy of fine reservoir characterization, and provide technical support for formulating technical countermeasures for improving the reserve utilization degree of the oil field in the later stage.

[0034] Embodiment 1

[0035] Embodiment 1 of the present invention provides a method for dynamically distinguishing the spatial morphology of a fracture-cavity carbonate reservoir reservoir, and the process thereof is as follows Figure 1 As shown, the following steps are included:

[0036] Step S11: Determine the aspect ratio of the fracture-cavity body in the carbonate reservoir stratum drilled by the oil well according to the cumulative liquid production and oil pressure change data of the oil well in the set development stage.

[0037] See also Figure 2 As shown, the following steps may be included:

[0038] Step S111: According to the cumulative liquid production and oil pressure change data of the oil well in the set development stage, the corresponding relationship between the cumulative liquid production and the oil pressure is obtained by fitting method, and the unit pressure drop liquid production and initial oil pressure of the development stage are determined according to the corresponding relationship.

[0039] The actual development dynamic data of the oil well in the set development stage, including the cumulative liquid production and oil pressure change data, is obtained. The relationship curve between the cumulative liquid production and the oil pressure is established by fitting method to obtain the corresponding relationship between the two. The unit pressure drop liquid production in the development stage is determined according to the corresponding relationship, and the initial oil pressure, that is, the oil pressure at the beginning of the development stage, is reversed.

[0040] Furthermore, the above-mentioned cumulative fluid production refers to the cumulative fluid production in the corresponding development stage, that is, the cumulative fluid production corresponding to the initial oil pressure is 0.

[0041] Step S112: determining the aspect ratio of the fracture-cavity body in the carbonate reservoir stratum drilled by the oil well according to the unit pressure drop liquid production and the initial oil pressure in the development stage.

[0042] According to the unit pressure drop, the liquid production can be approximately equivalent to the cross-sectional area of ​​the fracture-cavity body, and the reversed initial oil pressure can be approximately equivalent to the produced oil column height of the fracture-cavity body. Therefore, the height-to-width ratio of the fracture-cavity body in the carbonate reservoir penetrated by the oil well can be determined by the following formula (1):

[0043]

[0044] In formula (1):

[0045] m is the aspect ratio of the fracture body, dimensionless;

[0046] P t is the initial oil pressure, MPa;

[0047] Q l is the liquid production per unit pressure drop, m 3 / MPa.

[0048] Step S12: Determine the effective length and effective width of the fracture-cavity body according to the dynamic geological reserves within the control range of the oil well in the development stage, the length and width of the fracture-cavity body determined by the seismic reservoir inversion result, and the effective porosity within the control range of the oil well.

[0049] See also Figure 3 As shown, the following steps may be included:

[0050] Step S121: Determine the apparent porosity of the fracture-cavity body according to the dynamic geological reserves within the control range of the oil well in the development stage and the length and width of the fracture-cavity body determined by the seismic reservoir inversion result.

[0051] According to the seismic reservoir inversion results, the plane distribution shape of the fracture-cavity body is determined to be elliptical, and the plane distribution length and width of the fracture-cavity body are measured;

[0052] According to the dynamic geological reserves within the control range of the oil well in the development stage and the length and width of the fracture-cavity body determined by the seismic reservoir inversion results, the apparent porosity of the fracture-cavity body is determined by the following formula (2):

[0053]

[0054] In formula (2):

[0055] The apparent porosity of the fracture-cavity body is dimensionless;

[0056] Np: Dynamic geological reserves within the control range of the oil well, determined according to the dynamic development characteristics of the oil well, 10 4 t;

[0057] ρ o : Density of crude oil under formation conditions, which can be obtained based on fluid monitoring data, g / cm 3 ;

[0058] A: The length of the fracture-cavity body determined by the seismic reservoir inversion results, m;

[0059] B: Fracture-cavity width determined by seismic reservoir inversion results, m.

[0060] Step S122: Determine the effective length and effective width of the fracture-cavity body according to the length and width of the fracture-cavity body determined by the seismic reservoir inversion results, the apparent porosity and the effective porosity within the control range of the oil well.

[0061] According to the fracture-cavity length, apparent porosity and effective porosity within the well control range determined by seismic reservoir inversion results, the effective length of the fracture-cavity body is determined by the following formula (3):

[0062]

[0063] According to the width of the fracture-cavity body determined by the seismic reservoir inversion result, the apparent porosity and the effective porosity within the control range of the oil well, the effective width of the fracture-cavity body is determined by the following formula (4):

[0064]

[0065] In formula (3) and formula (4):

[0066] L: effective length of the fracture body, m;

[0067] W: effective width of the fracture body, m;

[0068] The effective porosity within the control range of the oil well can be obtained through seismic porosity inversion and is dimensionless.

[0069] Step S13: According to the effective length, effective width and aspect ratio of the fracture-cavity body, equivalent to a circular formation is performed to determine the effective height of the fracture-cavity body in the development stage.

[0070] The effective height of the fracture-cavity body cannot be understood as the height of the produced oil column in the fracture-cavity body during the corresponding development stage.

[0071] According to the effective length and effective width of the fracture-cave body, the equivalent is performed according to the circular formation, and the width of the fracture-cave body within the equivalent formation range is determined by the following formula (5); according to the width of the fracture-cave body within the equivalent formation range and the aspect ratio of the fracture-cave body determined in step S11, the effective height of the fracture-cave body in the development stage is determined by the following formula (6):

[0072]

[0073] h o =W o *m (6)

[0074] In formula (5) and formula (6):

[0075] W o : is the width of the fracture-cavity body within the circular equivalent formation range, m;

[0076] h o : is the effective height of the fracture cavity, m.

[0077] Step S14: according to the effective length, effective width and effective height of the fracture-cavity body in the development stage, the three-dimensional spatial distribution form of the fracture-cavity body is determined.

[0078] According to the effective length, effective width and effective height of the fracture-cavity body in the development stage, the length-width-height ratio of the fracture-cavity body is determined; according to the length-width-height ratio of the fracture-cavity body, the three-dimensional spatial distribution form of the fracture-cavity body is judged. The spatial structural distribution form of the fracture-cavity body can be divided into: layered body, tubular body, cylindrical body, ellipsoid body and plate body.

[0079] Specifically, if the length, width and height ratio of the fracture-cavity body is M:N:1, where 2≦M:N﹤3, and N≠1, the three-dimensional spatial distribution morphology of the fracture-cavity body is judged to be a layered body;

[0080] If the length, width and height ratio of the fracture-cavity body is M:N:1, where M:N≧3 and N≠1, the three-dimensional spatial distribution morphology of the fracture-cavity body is judged to be tubular;

[0081] If the length, width and height ratio of the fracture-cavity body is M:N:1, where M:N<2 and N≠1, the three-dimensional spatial distribution shape of the fracture-cavity body is determined to be a cylinder;

[0082] If the length-width-height ratio of the fracture-cavity body is M:1:1, where M≧2, the three-dimensional spatial distribution shape of the fracture-cavity body is judged to be an ellipsoid;

[0083] If the length, width and height ratio of the fracture-cavity body is 2:1:M, where M≧2, the three-dimensional spatial distribution morphology of the fracture-cavity body is judged to be a plate-like body.

[0084] Due to the complexity of the spatial structure of the actual fracture-cavity body, the length, width and height ratios of the fracture-cavity body calculated through actual production dynamic data may not completely conform to the above ratios. If the calculated values ​​do not conform to the above, the fracture-cavity body morphology similar to the above ratio relationship is determined based on the relative proportional relationship.

[0085] The method for dynamically distinguishing the spatial morphology of fracture-cavity carbonate reservoirs provided in Example 1 of the present invention utilizes the actual development dynamic data of the oil wells that have been put into production, and combines the reservoir inversion results to calculate the effective length, width and height of the fracture-cavity body, and then distinguish the three-dimensional spatial distribution morphology of the fracture-cavity body, providing a basis for the characterization of the internal structure of the fracture-cavity reservoir and the characterization of the reservoir scale. The research results can be applied to the research field of multi-scale characterization and geological modeling of fracture-cavity carbonate reservoirs, and can provide support for improving the utilization of reserves.

[0086] In some embodiments, the above-mentioned oil well may be a single oil well; since some of the fracture-cavity bodies developed in carbonate oil reservoirs are large in scale, several wells may drill through the same fracture-cavity body in the reservoir, so the above-mentioned oil well may also be a well group consisting of multiple oil wells.

[0087] Correspondingly, the cumulative liquid production of the well group in the set development stage and the cumulative liquid production in the oil pressure change data are the sum of the liquid production of each well in the well group in the corresponding development stage; since the fluids in the same fracture body are often connected, the oil pressure here refers to the average oil pressure of each well in the well group (the oil pressure of each well in the well group at the same production time is basically the same). At this time, the parameter Np is the dynamic geological reserves within the well group range control.

[0088] In some optional embodiments, the effective length, effective width and effective height of the fracture-cavity body in multiple development stages may also be determined, and the three-dimensional spatial distribution morphology of the fracture-cavity body may be determined by comprehensive analysis.

[0089] In some optional embodiments, the width of the fracture-cavity body within the equivalent formation range of multiple development stages can also be determined; and the vertical two-dimensional spatial distribution morphology of the fracture-cavity body can be determined based on the variation characteristics of the width of the fracture-cavity body within the equivalent formation range of multiple development stages.

[0090] The longitudinal direction here refers to the direction perpendicular to the horizontal plane. Specifically, in the order of time from the earliest to the latest, if the change amplitude of the fracture-cavity body width within the equivalent stratum range at different development stages is less than the set amplitude, the longitudinal two-dimensional spatial distribution shape of the fracture-cavity body is judged to be cylindrical;

[0091] According to the time sequence from earliest to later, if the width of the fracture-cavity body in the equivalent stratum range at different development stages changes from large to small, the vertical two-dimensional spatial distribution form of the fracture-cavity body is judged to be a pagoda shape;

[0092] According to the time sequence, if the width of the fracture-cavity body in the equivalent stratum range at different development stages increases from small to large, the vertical two-dimensional spatial distribution morphology of the fracture-cavity body is judged to be funnel-shaped.

[0093] Embodiment 2

[0094] Embodiment 2 of the present invention provides a specific application of a method for dynamically distinguishing the spatial morphology of a fracture-vuggy carbonate reservoir:

[0095] (1) According to the relevant indicators of oil well production dynamic data, the aspect ratio of the fracture-cavity body is calculated, which specifically includes the following three steps:

[0096] The first step is to draw the relationship curve between the cumulative liquid production and oil pressure in each development stage based on the production data of the oil wells at different development stages, and calculate the equivalent unit pressure drop liquid production of the oil wells at different development stages;

[0097] The second step is to reversely calculate the initial oil pressure of the oil well at the corresponding development stage based on the unit pressure drop liquid production relationship curve;

[0098] In the third step, the unit pressure drop liquid production can be approximately equivalent to the cross-sectional area of ​​the fracture-cavity body, and the reversed initial oil pressure can be approximately equivalent to the height of the produced oil column of the fracture-cavity body. Therefore, the aspect ratio of the fracture-cavity body can be approximately calculated, and its calculation formula is shown in the above formula (1).

[0099] The relationship curve between oil pressure and cumulative liquid production of a typical well in a block is shown in Figure 4A-4D As shown, Figure 4A The relationship curves between oil pressure and cumulative liquid production of Well P1 in four different production stages (including 4mm nozzle production stage, 5mm nozzle production stage, 4mm and 6mm nozzle production stage, and 4mm, 5mm and 6mm nozzle production stage); Figure 4B The relationship curves between oil pressure and cumulative liquid production of P2 well in four different production stages (including 8mm nozzle production stage, 9mm nozzle production stage, 12mm nozzle production stage, 8mm, 9mm and 12mm nozzle production stage); Figure 4C This is the relationship curve between oil pressure and cumulative liquid production of P3 well during the production stage of 4mm nozzle; Figure 4D This is the relationship curve between oil pressure and cumulative liquid production of P4 well during the 3mm nozzle production stage; Figure 4E This is a curve diagram showing the relationship between oil pressure and cumulative liquid production in the P5 well during the production stages with 4mm, 6mm and 8mm nozzles.

[0100] The calculation summary of the height-to-width ratio of typical well fractures and caves in a certain block is shown in Table 1:

[0101] Table 1 Summary of calculation of height-to-width ratio of typical well fracture-cavity bodies in a certain block

[0102] well name Segmented Plotting <![CDATA[Q l ,t / MPa]]> <![CDATA[P t ,MPa]]> m P1 1 3960.18 33.44 0.47 P1 2 1502.37 54.96 1.26 P1 3 960.90 84.14 2.41 P1 4 2725.29 36.41 0.62 P2 1 1209.63 10.48 0.27 P2 2 2472.82 9.43 0.17 P2 3 5457.86 6.68 0.08 P2 4 3222.33 8.91 0.14 P3 1 4204.59 43.99 0.60 P4 1 1854.75 42.23 0.87 P5 1 112.98 27.14 2.26

[0103] (2) Based on the single well controlled reserves and the reservoir planar distribution characteristics obtained through seismic inversion, the apparent porosity of the fracture-cavity body is calculated, which specifically includes the following four steps:

[0104] The first step is to measure the plane distribution length and width of the fracture-cavity body according to the seismic reservoir inversion results, which shows that the plane distribution shape of the fracture-cavity body is elliptical.

[0105] The second step is to obtain the dynamic geological reserves within the control range of a single well based on the dynamic development characteristics of the single well;

[0106] The third step is to obtain the fluid density of the formation crude oil based on the fluid monitoring data;

[0107] The fourth step is to calculate the apparent porosity of the fracture-cavity body based on the seismic reservoir inversion results and the single well controlled reserves. The calculation formula is shown in the above formula (2).

[0108] The calculation results of the apparent porosity of typical well fractures and caves in a certain block are shown in Table 2:

[0109] Table 2 Summary of calculation results of apparent porosity of typical well fractures and caves in a certain block

[0110] well name Segmented Plotting <![CDATA[ρ o ,g / cm 3 ]]> <![CDATA[N p ,10 4 t]]> A,m B,m <![CDATA[φ f ,%]]> P1 1 0.6224 254.70 1350 520 1.88 P1 2 0.6224 158.78 1350 520 0.44 P1 3 0.6224 155.48 1350 520 0.22 P1 4 0.6224 190.81 1350 520 1.07 P2 1 0.5733 24.37 1050 450 0.62 P2 2 0.5733 44.83 1050 450 1.82 P2 3 0.5733 70.14 1050 450 5.98 P2 4 0.5733 55.22 1050 450 2.71 P3 1 0.5187 355.70 710 420 8.92 P4 1 0.5051 150.61 480 280 8.87 P5 1 0.5789 5.90 1060 470 0.02

[0111] (3) Based on the apparent porosity and effective porosity, the effective length and width of the fracture-cavity body at different development stages are calculated, which specifically includes the following three steps:

[0112] In the first step, effective porosity refers to the effective porosity within the control range of a single well obtained by seismic porosity inversion;

[0113] The second step is to calculate the effective length of the fracture-vuggy body under the condition of effective porosity based on the apparent porosity, effective porosity and the plane length of the fracture-vuggy body obtained by seismic reservoir inversion. The calculation formula is shown in the above formula (3).

[0114] The third step is to calculate the effective width of the fracture-vuggy body under the condition of effective porosity based on the apparent porosity, effective porosity and the plane width of the fracture-vuggy body obtained by seismic reservoir inversion. The calculation formula is shown in the above formula (4).

[0115] The calculation results of the effective length and width of the fracture-cave body in the plane of a typical well in a certain block at different development stages are shown in Table 3:

[0116] Table 3 Summary of calculation results of effective length and width of fracture-cavity bodies in different development stages of typical wells in a certain block

[0117]

[0118]

[0119] (4) Equivalence is performed based on the plane distribution of seismic fracture-cavity bodies to calculate the oil column height at different development stages, which specifically includes the following two steps:

[0120] The first step is to calculate the width of the fracture-cavity body within the equivalent formation range according to the calculated effective length and width data of the fracture-cavity body within the range of the single well / well group unit, and perform equivalent to the circular formation. The calculation formula is shown in the above formula (5);

[0121] The second step is to reversely calculate the oil column height produced at different development stages based on the fracture-cavity width and the calculated fracture-cavity height-to-width ratio. The calculation formula is shown in the above formula (6).

[0122] The results of oil column height at different development stages calculated for a typical well in a certain block are shown in Table 4:

[0123] Table 4 Summary of oil column height results calculated for typical wells in a certain block at different development stages

[0124] well name Segmented Plotting m L,m W,m Wo,m ho,m P1 1 0.47 888 342 551 260 P1 2 1.26 547 211 340 427 P1 3 2.41 438 169 272 653 P1 4 0.62 737 284 457 283 P2 1 0.27 478 205 313 84 P2 2 0.17 684 293 448 75 P2 3 0.08 1016 436 665 53 P2 4 0.14 781 335 511 71 P3 1 0.60 785 464 604 363 P4 1 0.87 530 309 405 352 P5 1 2.26 143 64 95 216

[0125] (5) Based on the predicted length, width and height data of the fracture-cavity body, the length, width and height ratios of different development stages are calculated, which specifically includes the following two steps:

[0126] In the first step, according to the calculated effective length and width of the fracture-cavity body and the height of the oil column produced at different development stages, the length, width and height are normalized respectively. The calculation formula is as follows:

[0127]

[0128]

[0129]

[0130] Where:

[0131] L f : effective dimensionless length of the fracture body;

[0132] W f : effective dimensionless width of the fracture body;

[0133] h f : effective dimensionless height of the fracture cavity;

[0134] The second step is to calculate the length: width: height ratio of a single well or well group unit at different development stages based on the normalized results of length, width and height.

[0135] The calculation results of the length-width-height ratios of typical wells in a certain block at different development stages are shown in Table 5:

[0136] Table 5 Summary of calculation results of length-width-height ratios of typical wells in fracture-cavity bodies in a certain block at different development stages

[0137] well name Segmented Plotting L,m W,m <![CDATA[h o ,m]]> <![CDATA[L f :W f :h f ]]> P1 1 888 342 260 6:2:2 P1 2 547 211 427 5:2:4 P1 3 438 169 653 3:1:5 P1 4 737 284 283 6:2:2 P2 1 478 205 84 6:3:1 P2 2 684 293 75 6:3:1 P2 3 1016 436 53 7:3:0 P2 4 781 335 71 7:3:1 P3 1 785 464 363 5:3:2 P4 1 530 309 352 4:3:3 P5 1 143 64 216 3:2:5

[0138] (6) According to the length-width-height ratio of the fracture-cavity body at different development stages and the variation characteristics of the width of the fracture-cavity body within the equivalent formation range, the spatial distribution morphology of the fracture-cavity body is determined, which specifically includes the following two steps:

[0139] The first step is to determine the longitudinal distribution of the fracture-cavity bodies according to the calculated change in the width of the fracture-cavity bodies within the equivalent formation range at different development stages of a single well, which can be mainly divided into cylindrical, funnel-shaped, and pagoda-shaped reservoirs;

[0140] In the second step, according to the calculated length: width: height ratio values ​​of single well or well group units in different development stages, the spatial structural distribution forms of the fracture-cavity body can be divided into: layered body, tubular body, cylindrical body, ellipsoid body and plate body.

[0141] (7) The longitudinal distribution of the fracture-cavity bodies in step (6) is mainly divided into cylindrical, funnel-shaped, and pagoda-shaped reservoirs, specifically including:

[0142] In the order of time from earliest to latest, if the variation range of the width of the fracture-cavity body within the equivalent formation range at different development stages is less than the set range, it is determined that the longitudinal two-dimensional spatial distribution shape of the fracture-cavity body is cylindrical;

[0143] In the order of time from earliest to latest, if the width of the fracture-cavity body in the equivalent stratum range at different development stages changes from large to small, it is determined that the vertical two-dimensional spatial distribution form of the fracture-cavity body is a pagoda shape;

[0144] In the order of time, if the width of the fracture-cavity body in the equivalent stratum range at different development stages increases from small to large, it is judged that the vertical two-dimensional spatial distribution shape of the fracture-cavity body is funnel-shaped.

[0145] (8) The spatial structural distribution forms of the fracture-cavity body in step (6) are divided into: layered body, tubular body, cylindrical body, ellipsoid body and plate-like body, specifically including:

[0146] If the length, width and height ratio of the fracture-cavity body is M:N:1, where 2≦M:N﹤3, and N≠1, the three-dimensional spatial distribution of the fracture-cavity body is judged to be a layered body;

[0147] If the length, width and height ratio of the fracture-cavity body is M:N:1, where M:N≧3 and N≠1, the three-dimensional spatial distribution morphology of the fracture-cavity body is judged to be tubular;

[0148] If the length, width and height ratio of the fracture-cavity body is M:N:1, where M:N<2 and N≠1, the three-dimensional spatial distribution shape of the fracture-cavity body is determined to be a cylinder;

[0149] If the length-width-height ratio of the fracture-cavity body is M:1:1, where M≧2, the three-dimensional spatial distribution shape of the fracture-cavity body is judged to be an ellipsoid;

[0150] If the length, width and height ratio of the fracture-cavity body is 2:1:M, where M≧2, the three-dimensional spatial distribution morphology of the fracture-cavity body is judged to be a plate-like body.

[0151] The results of the spatial structural morphology of the fracture-cavity body in a certain block are shown in Table 6:

[0152] Table 6 Summary of the results of the spatial structural morphology of fracture-cavity bodies in a certain area

[0153]

[0154] Based on the inventive concept of the present invention, the embodiment of the present invention also provides a device for dynamically distinguishing the spatial morphology of a fracture-cavity carbonate reservoir. The structure of the device is as follows: Figure 5 As shown, including:

[0155] The height-to-width ratio determination module 51 of the fracture-cavity body is used to determine the height-to-width ratio of the fracture-cavity body in the carbonate oil reservoir stratum drilled by the oil well according to the cumulative liquid production and oil pressure change data of the oil well in the set development stage;

[0156] The effective length and effective width determination module 52 of the fracture-cavity body is used to determine the effective length and effective width of the fracture-cavity body according to the dynamic geological reserves within the control range of the oil well in the development stage, the length and width of the fracture-cavity body determined by the seismic reservoir inversion result, and the effective porosity within the control range of the oil well;

[0157] The effective height determination module 53 of the fracture-cavity body is used to determine the effective height of the fracture-cavity body in the development stage according to the effective length and effective width of the fracture-cavity body and the aspect ratio, by performing equivalent calculation according to the circular formation;

[0158] The three-dimensional spatial distribution form discrimination module 54 of the fracture-cavity body is used to discriminate the three-dimensional spatial distribution form of the fracture-cavity body according to the effective length, effective width and effective height of the fracture-cavity body in the development stage.

[0159] In some embodiments, the module 51 for determining the aspect ratio of the fracture body is used to:

[0160] According to the cumulative liquid production and oil pressure change data of the oil well in the set development stage, the corresponding relationship between the cumulative liquid production and the oil pressure is obtained by a fitting method, and the unit pressure drop liquid production and the initial oil pressure in the development stage are determined according to the corresponding relationship;

[0161] According to the unit pressure drop liquid production and the initial oil pressure in the development stage, the aspect ratio of the fracture-cavity body in the carbonate reservoir stratum drilled by the oil well is determined by the following formula (1):

[0162]

[0163] In formula (1), m is the aspect ratio of the fracture body, P t is the initial oil pressure, Q l It is the liquid production per unit pressure drop.

[0164] In some embodiments, the effective length and effective width determination module 52 of the fracture body is used to:

[0165] The apparent porosity of the fracture-cavity body is determined based on the dynamic geological reserves of the oil well in the development stage and the length and width of the fracture-cavity body determined by the seismic reservoir inversion results; the effective length and effective width of the fracture-cavity body are determined based on the length and width of the fracture-cavity body determined by the seismic reservoir inversion results, the apparent porosity and the effective porosity within the control range of the oil well.

[0166] In some embodiments, the effective length and effective width determination module 52 of the fracture body is used to:

[0167] According to the seismic reservoir inversion results, the plane distribution shape of the fracture-cavity body is determined to be elliptical, and the plane distribution length and width of the fracture-cavity body are measured;

[0168] According to the dynamic geological reserves within the control range of the oil well in the development stage and the length and width of the fracture-cavity body determined by the seismic reservoir inversion results, the apparent porosity of the fracture-cavity body is determined by the following formula (2):

[0169]

[0170] In formula (1), is the apparent porosity of the fracture-cavity body, Np is the dynamic geological reserves within the control range of the oil well, ρ o is the crude oil density under formation conditions, A is the length of the fracture-vuggy body determined by the seismic reservoir inversion results, and B is the width of the fracture-vuggy body determined by the seismic reservoir inversion results.

[0171] In some embodiments, the effective length and effective width determination module 52 of the fracture body is used to:

[0172] According to the length of the fracture-cavity body determined by the seismic reservoir inversion result, the apparent porosity and the effective porosity within the control range of the oil well, the effective length of the fracture-cavity body is determined by the following formula (3):

[0173]

[0174] According to the width of the fracture-cavity body determined by the seismic reservoir inversion result, the apparent porosity and the effective porosity within the control range of the oil well, the effective width of the fracture-cavity body is determined by the following formula (4):

[0175]

[0176] In formula (3) and formula (4), L is the effective length of the fracture-cavity body, W is the effective width of the fracture-cavity body, is the effective porosity within the well control range, is the apparent porosity of the fracture-cave body, A is the length of the fracture-cave body determined by the seismic reservoir inversion results, and B is the width of the fracture-cave body determined by the seismic reservoir inversion results.

[0177] In some embodiments, the effective height determination module 53 of the fracture body is used to:

[0178] According to the effective length and effective width of the fracture-cavity body, the equivalent circular formation is used to determine the width of the fracture-cavity body within the equivalent formation range by the following formula (5):

[0179]

[0180] According to the width of the fracture-cavity body within the equivalent formation range and the aspect ratio, the effective height of the fracture-cavity body in the development stage is determined by the following formula (6):

[0181] h o =W o *m (6);

[0182] In formula (5) and formula (6), W o is the width of the fracture-cavity body within the equivalent formation range, h o is the effective height of the fracture-cavity body, m is the aspect ratio of the fracture-cavity body, L is the effective length of the fracture-cavity body, and W is the effective width of the fracture-cavity body.

[0183] In some embodiments, the three-dimensional spatial distribution morphology discrimination module 54 of the fracture-cavity body is used to:

[0184] According to the effective length, effective width and effective height of the fracture-cavity body in the development stage, the length-width-height ratio of the fracture-cavity body is determined; and according to the length-width-height ratio of the fracture-cavity body, the three-dimensional spatial distribution morphology of the fracture-cavity body is determined.

[0185] In some embodiments, the three-dimensional spatial distribution morphology discrimination module 54 of the fracture-cavity body is further used to:

[0186] According to the effective length, effective width and effective height of the fracture-cavity body in multiple development stages, the three-dimensional spatial distribution morphology of the fracture-cavity body is determined by comprehensive analysis.

[0187] In some embodiments, the above device further includes a longitudinal two-dimensional spatial distribution morphology determination module 55 of the fracture-hole body, which is used to:

[0188] Determine the width of the fracture-cavity body within the equivalent formation range of multiple development stages; and discern the vertical two-dimensional spatial distribution morphology of the fracture-cavity body according to the variation characteristics of the width of the fracture-cavity body within the equivalent formation range of multiple development stages.

[0189] In some embodiments, the longitudinal two-dimensional spatial distribution morphology determination module 55 of the fracture-hole body is used to:

[0190] In the order of time from earliest to latest, if the variation range of the width of the fracture-cavity body within the equivalent formation range at different development stages is less than the set range, it is determined that the longitudinal two-dimensional spatial distribution shape of the fracture-cavity body is cylindrical;

[0191] In the order of time from earliest to latest, if the width of the fracture-cavity body in the equivalent stratum range at different development stages changes from large to small, it is determined that the vertical two-dimensional spatial distribution form of the fracture-cavity body is a pagoda shape;

[0192] In the order of time, if the width of the fracture-cavity body in the equivalent stratum range at different development stages increases from small to large, it is judged that the vertical two-dimensional spatial distribution shape of the fracture-cavity body is funnel-shaped.

[0193] Regarding the device in the above embodiment, the specific manner in which each module performs operations has been described in detail in the embodiment of the method, and will not be elaborated here.

[0194] Based on the inventive concept of the present invention, an embodiment of the present invention further provides a computer storage medium, in which computer executable instructions are stored. When the computer executable instructions are executed by a processor, the above-mentioned method for dynamically distinguishing the spatial morphology of fracture-vuggy carbonate oil reservoir reservoirs is implemented.

[0195] Based on the inventive concept of the present invention, an embodiment of the present invention also provides a server, including: a memory, a processor, and a computer program stored in the memory and executable on the processor, wherein when the processor executes the program, the above-mentioned method for dynamically distinguishing the spatial morphology of fracture-vuggy carbonate oil reservoir reservoirs is implemented.

[0196] Unless otherwise specifically stated, terms such as processing, computing, calculating, determining, displaying, etc. may refer to the actions and / or processes of one or more processing or computing systems, or similar devices, which operate and convert data represented as physical (e.g., electronic) quantities within registers or memories of a processing system into other data similarly represented as physical quantities within memories, registers, or other such information storage, transmission, or display devices of the processing system. Information and signals may be represented using any of a variety of different techniques and methods. For example, data, instructions, commands, information, signals, bits, symbols, and chips mentioned throughout the above description may be represented by voltages, currents, electromagnetic waves, magnetic fields or particles, light fields or particles, or any combination thereof.

[0197] It should be understood that the specific order or hierarchy of steps in the disclosed process is an example of an exemplary method. Based on design preferences, it should be understood that the specific order or hierarchy of steps in the process can be rearranged without departing from the scope of protection of the present disclosure. The attached method claims present the elements of the various steps in an exemplary order and are not intended to be limited to the specific order or hierarchy described.

[0198] In the above detailed description, various features are grouped together in a single embodiment to simplify the disclosure. This method of disclosure should not be interpreted as reflecting an intention that an embodiment of the claimed subject matter requires more features than those set forth in each claim. On the contrary, as reflected in the appended claims, the invention is in a state of having less than all the features of the disclosed individual embodiments. Therefore, the appended claims are hereby expressly incorporated into the detailed description, with each claim standing on its own as a separate preferred embodiment of the invention.

[0199] Those skilled in the art will also appreciate that the various illustrative logic blocks, modules, circuits, and algorithmic steps described in conjunction with the embodiments herein can all be implemented as electronic hardware, computer software, or a combination thereof. In order to clearly illustrate the interchangeability between hardware and software, various illustrative components, blocks, modules, circuits, and steps are generally described above around their functions. Whether such functions are implemented as hardware or software depends on specific applications and the design constraints imposed on the entire system. A skilled person can implement the described functions in an alternative manner for each specific application, but such implementation decisions should not be interpreted as departing from the scope of protection of the present disclosure.

[0200] The steps of the method or algorithm described in conjunction with the embodiments herein may be directly embodied as hardware, a software module executed by a processor, or a combination thereof. The software module may be located in a RAM memory, a flash memory, a ROM memory, an EPROM memory, an EEPROM memory, a register, a hard disk, a mobile disk, a CD-ROM, or any other form of storage medium well known in the art. An exemplary storage medium is connected to the processor so that the processor can read information from the storage medium and can write information to the storage medium. Of course, the storage medium may also be an integral part of the processor. The processor and the storage medium may be located in an ASIC. The ASIC may be located in a user terminal. Of course, the processor and the storage medium may also be present in a user terminal as discrete components.

[0201] For software implementation, the techniques described in this application can be implemented with modules (e.g., procedures, functions, etc.) that perform the functions described in this application. These software codes can be stored in a memory unit and executed by a processor. The memory unit can be implemented within the processor or outside the processor. In the latter case, it is coupled to the processor in a communication manner via various means, which are well known in the art.

[0202] The above description includes examples of one or more embodiments. Of course, it is impossible to describe all possible combinations of components or methods for the purpose of describing the above embodiments, but it should be recognized by those skilled in the art that the various embodiments may be further combined and arranged. Therefore, the embodiments described herein are intended to cover all such changes, modifications and variations that fall within the scope of protection of the appended claims. In addition, with respect to the term "comprising" used in the specification or claims, the word is covered in a manner similar to the term "including", just as "including," is explained as a transitional word in the claims. In addition, any term "or" used in the specification of the claims is intended to mean "non-exclusive or".

Claims

1. A method for dynamically distinguishing the spatial morphology of a fracture-cavity carbonate reservoir, characterized in that: include: Determine the height-to-width ratio of the fracture-cavity body in the carbonate reservoir penetrated by the oil well based on the cumulative liquid production and oil pressure change data of the oil well in the set development stage; Determine the effective length and effective width of the fracture-cavity body according to the dynamic geological reserves within the control range of the oil well in the development stage, the length and width of the fracture-cavity body determined by the seismic reservoir inversion results, and the effective porosity within the control range of the oil well; According to the effective length and effective width of the fracture-cavity body and the aspect ratio, equivalent to a circular formation is performed to determine the effective height of the fracture-cavity body in the development stage; According to the effective length, effective width and effective height of the fracture-cavity body in the development stage, the three-dimensional spatial distribution morphology of the fracture-cavity body is determined.

2. The method according to claim 1, characterized in that: The method of determining the aspect ratio of the fracture-cavity body in the carbonate reservoir stratum drilled by the oil well according to the cumulative liquid production and oil pressure change data of the oil well in the set development stage includes: According to the cumulative liquid production and oil pressure change data of the oil well in the set development stage, the corresponding relationship between the cumulative liquid production and the oil pressure is obtained by a fitting method, and the unit pressure drop liquid production and the initial oil pressure in the development stage are determined according to the corresponding relationship; According to the unit pressure drop liquid production and the initial oil pressure in the development stage, the aspect ratio of the fracture-cavity body in the carbonate reservoir stratum drilled by the oil well is determined by the following formula (1): In formula (1), m is the aspect ratio of the fracture body, P t is the initial oil pressure, Q l It is the liquid production per unit pressure drop.

3. The method according to claim 1, characterized in that The effective length and effective width of the fracture-cavity body are determined according to the dynamic geological reserves within the control range of the oil well in the development stage, the length and width of the fracture-cavity body determined by the seismic reservoir inversion result, and the effective porosity within the control range of the oil well, including: Determine the apparent porosity of the fracture-cavity body according to the dynamic geological reserves within the control range of the oil well in the development stage and the length and width of the fracture-cavity body determined by the seismic reservoir inversion result; The effective length and effective width of the fracture-cavity body are determined according to the length and width of the fracture-cavity body determined by the seismic reservoir inversion result, the apparent porosity and the effective porosity within the control range of the oil well.

4. The method according to claim 3, characterized in that Determining the apparent porosity of the fracture-cavity body according to the dynamic geological reserves within the control range of the oil well in the development stage and the length and width of the fracture-cavity body determined by the seismic reservoir inversion result includes: According to the seismic reservoir inversion results, the plane distribution shape of the fracture-cavity body is determined to be elliptical, and the plane distribution length and width of the fracture-cavity body are measured; According to the dynamic geological reserves within the control range of the oil well in the development stage and the length and width of the fracture-cavity body determined by the seismic reservoir inversion results, the apparent porosity of the fracture-cavity body is determined by the following formula (2): In formula (1), is the apparent porosity of the fracture-cavity body, Np is the dynamic geological reserves within the control range of the oil well, ρ o is the crude oil density under formation conditions, A is the length of the fracture-vuggy body determined by the seismic reservoir inversion results, and B is the width of the fracture-vuggy body determined by the seismic reservoir inversion results.

5. The method according to claim 3, characterized in that: The determining of the effective length and effective width of the fracture-cavity body according to the length and width of the fracture-cavity body determined by the seismic reservoir inversion result, the apparent porosity and the effective porosity within the control range of the oil well comprises: According to the length of the fracture-cavity body determined by the seismic reservoir inversion result, the apparent porosity and the effective porosity within the control range of the oil well, the effective length of the fracture-cavity body is determined by the following formula (3): According to the width of the fracture-cavity body determined by the seismic reservoir inversion result, the apparent porosity and the effective porosity within the control range of the oil well, the effective width of the fracture-cavity body is determined by the following formula (4): In formula (3) and formula (4), L is the effective length of the fracture-cavity body, W is the effective width of the fracture-cavity body, is the effective porosity within the control range of the oil well, is the apparent porosity of the fracture-vuggy body, A is the length of the fracture-vuggy body determined by the seismic reservoir inversion results, and B is the width of the fracture-vuggy body determined by the seismic reservoir inversion results.

6. The method according to claim 1, characterized in that The effective length and effective width of the fracture-cavity body and the aspect ratio are equivalent to a circular formation to determine the effective height of the fracture-cavity body in the development stage, including: According to the effective length and effective width of the fracture-cavity body, the equivalent circular formation is used to determine the width of the fracture-cavity body within the equivalent formation range by the following formula (5): According to the width of the fracture-cavity body within the equivalent formation range and the aspect ratio, the effective height of the fracture-cavity body in the development stage is determined by the following formula (6): h o =W o *m (6); In formula (5) and formula (6), W o is the width of the fracture-cavity body within the equivalent formation range, h o is the effective height of the fracture-cavity body, m is the aspect ratio of the fracture-cavity body, L is the effective length of the fracture-cavity body, and W is the effective width of the fracture-cavity body.

7. The method according to claim 6, characterized in that Also includes: Determine the width of the fracture-cavity body within the equivalent stratigraphic range at multiple development stages; According to the variation characteristics of the width of the fracture-cavity body within the equivalent formation range in multiple development stages, the vertical two-dimensional spatial distribution morphology of the fracture-cavity body is determined.

8. The method according to claim 7, characterized in that The method of determining the vertical two-dimensional spatial distribution of the fracture-cavity body according to the variation characteristics of the fracture-cavity body width within the equivalent formation range at multiple development stages includes: In the order of time from earliest to latest, if the variation range of the width of the fracture-cavity body within the equivalent formation range at different development stages is less than the set range, it is determined that the longitudinal two-dimensional spatial distribution shape of the fracture-cavity body is cylindrical; In the order of time from earliest to latest, if the width of the fracture-cavity body in the equivalent stratum range at different development stages changes from large to small, it is determined that the vertical two-dimensional spatial distribution form of the fracture-cavity body is a pagoda shape; In the order of time, if the width of the fracture-cavity body in the equivalent stratum range at different development stages increases from small to large, it is judged that the vertical two-dimensional spatial distribution shape of the fracture-cavity body is funnel-shaped.

9. The method according to claim 1, characterized in that: The three-dimensional spatial distribution form of the fracture-cavity body is determined according to the effective length, effective width and effective height of the fracture-cavity body at the development stage, including: Determine the length, width and height ratio of the fracture-cavity body according to the effective length, effective width and effective height of the fracture-cavity body at the development stage; The three-dimensional spatial distribution form of the fracture-hole body is determined according to the length-width-height ratio of the fracture-hole body.

10. The method according to claim 9, characterized in that The determining of the three-dimensional spatial distribution of the fracture-hole body according to the length-width-height ratio of the fracture-hole body comprises: If the length-width-height ratio of the fracture-cavity body is M:N:1, where 2≦M:N﹤3, and N≠1, the three-dimensional spatial distribution form of the fracture-cavity body is determined to be a layered body; If the length-width-height ratio of the fracture-cavity body is M:N:1, where M:N≧3, and N≠1, the three-dimensional spatial distribution form of the fracture-cavity body is determined to be a tubular body; If the length-width-height ratio of the fracture-cavity body is M:N:1, where M:N<2, and N≠1, the three-dimensional spatial distribution shape of the fracture-cavity body is determined to be a cylinder; If the length-width-height ratio of the fracture-cavity body is M:1:1, where M≧2, the three-dimensional spatial distribution shape of the fracture-cavity body is determined to be an ellipsoid; If the length-width-height ratio of the fracture-hole body is 2:1:M, where M≧2, it is determined that the three-dimensional spatial distribution form of the fracture-hole body is a plate-like body.

11. The method according to claim 9, characterized in that Also includes: The effective length, effective width and effective height of the fracture-cavity body in multiple development stages are determined, and the three-dimensional spatial distribution morphology of the fracture-cavity body is determined through comprehensive analysis.

12. A device for dynamically distinguishing the spatial morphology of a fracture-cavity carbonate reservoir, characterized in that: include: A module for determining the aspect ratio of fracture-cavity bodies, which is used to determine the aspect ratio of fracture-cavity bodies in carbonate reservoirs drilled by oil wells based on the cumulative liquid production and oil pressure change data of the oil wells in a set development stage; The module for determining the effective length and effective width of the fracture-cavity body is used to determine the effective length and effective width of the fracture-cavity body according to the dynamic geological reserves within the control range of the oil well in the development stage, the length and width of the fracture-cavity body determined by the seismic reservoir inversion result, and the effective porosity within the control range of the oil well; The effective height determination module of the fracture-cavity body is used to determine the effective height of the fracture-cavity body in the development stage according to the effective length and effective width of the fracture-cavity body and the aspect ratio, and to perform equivalent calculation according to the circular formation; The three-dimensional spatial distribution morphology discrimination module of the fracture-cavity body is used to discriminate the three-dimensional spatial distribution morphology of the fracture-cavity body according to the effective length, effective width and effective height of the fracture-cavity body in the development stage.

13. A computer storage medium, characterized in that: The computer storage medium stores computer executable instructions, and when the computer executable instructions are executed by a processor, the method for dynamically distinguishing the spatial morphology of a fracture-vuggy carbonate reservoir reservoir according to any one of claims 1 to 11 is implemented.

14. A server, characterized in that: include: A memory, a processor, and a computer program stored in the memory and executable on the processor, wherein when the processor executes the program, the method for dynamically distinguishing the spatial morphology of a fracture-cavity carbonate reservoir as claimed in any one of claims 11 to 12 is implemented.

Images