Method and device for judging whether artificial CO2 gas cap of oil reservoir with dip angle is formed or not

Abstract

The invention relates to a method and device for judging whether an artificial CO2 gas cap is formed or not for an oil reservoir with a stratigraphic dip angle, and is applied to the oil reservoir with the stratigraphic dip angle. The method comprises the following steps that the CO2-crude oil capillary force gradient, the CO2 gas phase pore pressure gradient, the CO2 gas buoyancy force gradient and gravity gradient difference data of a target oil reservoir in the stratum direction of the CO2 injection well construction position are obtained; calculating a dimensionless numerical value formed by the artificial gas cap of the target oil reservoir based on a pre-constructed mechanical discrimination model for the dimensionless number of the artificial gas cap; and judging whether the dimensionless numerical value is greater than a first threshold value or not, if so, determining that the target oil reservoir artificial gas cap is formed, and if not, determining that the target oil reservoir artificial gas cap is not formed. The method can solve the problem that mechanical action mechanisms and conditions formed by the artificial gas cap of the oil reservoir with the dip angle are incomplete, imperfect and indefinite, and can conveniently judge whether the artificial gas cap can be formed by gas injection of the oil reservoir with the dip angle.

Description

Technical Field

[0001] This invention relates to the field of carbon capture, utilization and storage (CCUS) technology, and in particular to a method and apparatus for determining whether an artificial CO2 cap has formed in reservoirs with a dip angle. Background Technology

[0002] Oil reservoirs with a certain formation dip angle are widely distributed globally, especially in central and eastern China. They generally exhibit characteristics such as complex structures, small oil-bearing areas, large formation dip angles, thick oil layers, and low crude oil viscosity, making it difficult to form a complete injection-production well network. The remaining oil and water drive in the middle and high-performing sections is ineffective. Theoretical research and field practice indicate that top CO2 injection for stable gas drive is considered one of the effective methods for restoring formation pressure and achieving large-scale stable gas drive-enhanced oil production and geological preservation in such reservoirs. Furthermore, it boasts the highest recovery rate and preservation efficiency among all immiscible flooding methods.

[0003] However, existing top-injection elastic gas drive theories and technologies are not applicable to large-scale CO2 enhanced oil recovery and storage (CCUS-EOR). Therefore, providing a method to determine whether an artificial CO2 gas cap can form in reservoirs with formation dip, and addressing the incomplete, imperfect, and unclear mechanical mechanisms and conditions for the formation of artificial gas caps in reservoirs with formation dip, is an urgent problem to be solved. Summary of the Invention

[0004] The purpose of this invention is to at least address one of the shortcomings of the prior art by providing a method and apparatus for determining whether an artificial CO2 gas cap has formed in reservoirs with a formation dip angle.

[0005] To achieve the above objectives, the present invention adopts the following technical solution: Specifically, a method for determining whether an artificial CO2 cap has formed in reservoirs with a dip angle is proposed, and applied to reservoirs with a dip angle. The method includes the following: Acquire data on the CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, and the difference between the CO2 buoyancy gradient and gravity gradient in the formation direction at the structural location of the CO2 injection well in the target reservoir. The dimensionless number of artificial gas cap formation in the target reservoir is calculated based on a pre-constructed dimensionless mechanical discrimination model for artificial gas cap formation. Determine whether the dimensionless number value is greater than the first threshold. If it is, the artificial gas cap of the target reservoir is considered to have formed; otherwise, the artificial gas cap of the target reservoir is considered not to have formed.

[0006] Furthermore, specifically, data on the CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, and the difference between the CO2 buoyancy gradient and gravity gradient are obtained along the formation direction at the structural location of the CO2 injection well in the target reservoir. A detailed reservoir description of the target reservoir is performed, and a three-dimensional detailed geological model of the reservoir is established using Schlumberger's Petrel data integration, geological modeling and simulation workflow platform. Based on the aforementioned three-dimensional fine geological model of the reservoir, a numerical simulation model of the target reservoir was further established using Schlumberger. The target reservoir numerical simulation model is corrected and improved by fitting historical data to obtain an updated target reservoir numerical simulation model; Finally, the updated numerical simulation model of the target reservoir was used to obtain data on the CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, and the difference between the CO2 buoyancy gradient and gravity gradient in the formation direction at the structural location of the CO2 injection well.

[0007] Furthermore, specifically, the updated numerical simulation model of the target reservoir is used to obtain data on the CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, and the difference between the CO2 buoyancy gradient and gravity gradient in the formation direction at the structural location of the CO2 injection well. The CO2-crude oil capillary force in the formation direction at the structural location of the CO2 injection well was obtained using the updated numerical simulation model of the target reservoir. CO2 gas phase pore pressure , Stratigraphic dip ; in Where g represents the capillary force of crude oil, o represents the CO2 gas phase, and g represents the oil phase. To bind water saturation; This refers to the capillary force at the CO2 gas-oil interface under water saturation.

[0008] Calculate the distance from the location of the CO2 injection well structure to the location of the top structure of the reservoir along the formation direction. ; Calculate the difference between the buoyancy gradient of injected CO2 gas and its gravity gradient along the formation direction. CO2-Crude Oil Capillary Force Gradient CO2 gas phase pore pressure gradient ; in, and The calculation formula is as follows: (1) (2) In the formula, Porosity at the location of the CO2 injection well structure. For the interfacial tension between gas and oil, The contact angle for wetting at the gas-oil interface. For the tortuosity of the duct, based on the Bruggeman relation of cemented sandstone. Perform calculations, Air permeability in the formation direction at the location of the CO2 injection well structure. This represents the oil phase pore pressure at the location of the CO2 injection well structure, and by default, it represents the formation pore pressure at that location.

[0009] Furthermore, specifically, the construction process of the dimensionless mechanical discrimination model for artificial air cap formation includes, Based on Darcy's quantification, the seepage velocity of a unit volume of injected gas in the formation direction in reservoirs with formation dip angles is as follows: (4) In the formula, The gas infiltration velocity in the formation direction. The air permeability of the reservoir rock in the formation direction. The relative permeability of the gas phase. For gas phase viscosity, This represents the gas-water capillary pressure gradient under bound water conditions in the target oil reservoir. It is equal to its maximum value, which is a constant, so its value is 0.

[0010] Considering that injected gas can only migrate towards the top of the reservoir when the injected gas seepage velocity is greater than zero, that is, only when... Only then can an artificial dome be formed, therefore: (5) Organizing, one can obtain (6) If let The conditions for the formation of an artificial roof can then be expressed as follows: (7) in, This is the calculated dimensionless value.

[0011] Furthermore, specifically, the first threshold is 1.

[0012] The present invention also proposes a device for determining whether an artificial CO2 cap has formed in an oil reservoir with a formation dip angle, comprising the following: The data acquisition module is used to acquire data on the CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, and the difference between the CO2 buoyancy gradient and gravity gradient in the formation direction at the structural location of the CO2 injection well in the target reservoir. The dimensionless number value calculation module is used to calculate the dimensionless number value of artificial gas cap formation in the target reservoir based on the pre-built dimensionless number mechanical discrimination model for artificial gas cap formation; The gas cap formation judgment module is used to determine whether the dimensionless number value is greater than the first threshold. If it is, the artificial gas cap of the target reservoir is considered to have formed; otherwise, the artificial gas cap of the target reservoir is considered not to have formed.

[0013] The beneficial effects of this invention are as follows: This invention proposes a method and apparatus for determining whether an artificial CO2 cap has formed in reservoirs with formation dip. By acquiring data on the CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, and the difference between the CO2 buoyancy gradient and gravity gradient along the formation direction at the CO2 injection well location in the target reservoir, a dimensionless mechanical discrimination model for artificial cap formation is used to calculate the dimensionless value of artificial cap formation in the target reservoir. The determination of whether an artificial CO2 cap has formed is directly obtained based on the magnitude of the dimensionless value and a first threshold. This invention solves the problem of determining whether artificial CO2 can form in reservoirs with formation dip under CO2 injection or shutdown conditions, thus greatly facilitating related work. Attached Figure Description

[0014] The above and other features of this disclosure will become more apparent from the detailed description of the embodiments illustrated in conjunction with the accompanying drawings. In the accompanying drawings, the same reference numerals denote the same or similar elements. Obviously, the drawings described below are merely some embodiments of this disclosure. For those skilled in the art, other drawings can be obtained from these drawings without any creative effort. In the drawings: Figure 1 The diagram shows a preferred embodiment of the method for determining whether an artificial CO2 cap has formed in a reservoir with a formation dip angle according to the present invention. Figure 2 The diagram shows the forces acting on CO2 bubbles in the reservoir oil zone according to the present invention. Detailed Implementation

[0015] The following will provide a clear and complete description of the concept, specific structure, and technical effects of the present invention in conjunction with embodiments and accompanying drawings, so as to fully understand the purpose, solution, and effects of the present invention. It should be noted that, unless otherwise specified, the embodiments and features described in this application can be combined with each other. The same reference numerals used throughout the accompanying drawings indicate the same or similar parts.

[0016] Example 1: This invention proposes a method for determining whether an artificial CO2 cap has formed in reservoirs with a formation dip angle. The method is applied to reservoirs with a formation dip angle and includes the following: Acquire data on the CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, and the difference between the CO2 buoyancy gradient and gravity gradient in the formation direction at the structural location of the CO2 injection well in the target reservoir. The dimensionless number of artificial gas cap formation in the target reservoir is calculated based on a pre-constructed dimensionless mechanical discrimination model for artificial gas cap formation. Determine whether the dimensionless number value is greater than the first threshold. If it is, the artificial gas cap of the target reservoir is considered to have formed; otherwise, the artificial gas cap of the target reservoir is considered not to have formed.

[0017] In this embodiment 1, by acquiring data on the CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, and the difference between the CO2 buoyancy gradient and gravity gradient in the formation direction at the CO2 injection well location of the target reservoir, the dimensionless value of artificial gas cap formation in the target reservoir is calculated based on a pre-constructed dimensionless mechanical discrimination model. The determination of whether an artificial CO2 gas cap has formed is then directly obtained based on the magnitude of the dimensionless value and a first threshold. This invention solves the problem of determining whether artificial CO2 can form in reservoirs with formation dip angles under CO2 injection or shutdown conditions, thus greatly facilitating related work.

[0018] In a preferred embodiment of the present invention, specifically, data on the difference between the CO2-crude oil capillary force gradient, the CO2 gas phase pore pressure gradient, the CO2 buoyancy gradient, and the gravity gradient in the formation direction at the structural location of the CO2 injection well in the target reservoir are obtained, including: A detailed reservoir description of the target reservoir is performed, and a three-dimensional detailed geological model of the reservoir is established using Schlumberger's Petrel data integration, geological modeling and simulation workflow platform. Based on the aforementioned three-dimensional fine geological model of the reservoir, a numerical simulation model of the target reservoir was further established using Schlumberger. The target reservoir numerical simulation model is corrected and improved by fitting historical data to obtain an updated target reservoir numerical simulation model; Finally, the updated numerical simulation model of the target reservoir was used to obtain data on the CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, and the difference between the CO2 buoyancy gradient and gravity gradient in the formation direction at the structural location of the CO2 injection well.

[0019] Reference Figure 1 In this preferred embodiment, the process includes the following five steps: Step 101: Perform a detailed reservoir description of the target reservoir and establish a three-dimensional detailed geological model of the reservoir using Schlumberger's Petrel data integration, geological modeling and simulation workflow platform. Step 102: Using the three-dimensional detailed geological model established in Step 101, a numerical simulation model of the target reservoir is established using Schlumberger's Petrel data integration, geological modeling and simulation workflow platform. Step 103: Perform history fitting on the reservoir numerical simulation model obtained in Step 102, and correct and improve the numerical simulation model of the target reservoir, thereby obtaining the CO2-crude oil capillary force gradient in the formation direction at the structural location of the CO2 injection well. CO2 gas phase pore pressure gradient in the formation direction at the location of the CO2 injection well structure ( The difference between the CO2 buoyancy gradient and the gravity gradient along the formation direction at the location of the CO2 injection well. Data such as ) Step 104, the CO2-crude oil capillary force gradient obtained in step 103 ( ,in Where g represents the capillary force of crude oil, o represents the CO2 gas phase, and g represents the oil phase. To bind water saturation; The capillary force at the CO2 gas-oil interface under water saturation and the CO2 gas phase pore pressure gradient are considered. The difference between the CO2 buoyancy gradient and the gravity gradient ( Substituting data such as these into the dimensionless mechanical discrimination model for artificial gas cap formation, the dimensionless number of artificial gas cap formation in the target reservoir can be obtained. The value of ); Step 105: Examine and compare the number of dimensionless cycles in the formation of the artificial air cap ( The value is considered to be greater than 1.0, and when it is greater than 1.0, the reservoir with the formation dip angle can be considered to form an artificial CO2 gas cap.

[0020] If the CO2-crude oil capillary force gradient in the formation direction at the structural location of the CO2 injection well can be obtained directly or indirectly through other calculation or testing methods, then... CO2 gas phase pore pressure gradient in the formation direction at the location of the CO2 injection well ( The difference between the CO2 buoyancy gradient and the gravity gradient along the formation direction at the location of the CO2 injection well. By obtaining data such as ), steps 101 and 102 can be omitted, and steps 103, 104, and 105 can be adjusted to steps 101, 102, and 103 respectively, which are the relevant steps of Embodiment 1 of the present invention.

[0021] In a preferred embodiment of the present invention, specifically, the updated numerical simulation model of the target reservoir obtains data on the CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, and the difference between the CO2 buoyancy gradient and gravity gradient in the formation direction at the structural location of the CO2 injection well. This includes... The CO2-crude oil capillary force in the formation direction at the structural location of the CO2 injection well was obtained using the updated numerical simulation model of the target reservoir. CO2 gas phase pore pressure , Stratigraphic dip ; Calculate the distance from the location of the CO2 injection well structure to the location of the top structure of the reservoir along the formation direction. ; Calculate the difference between the buoyancy gradient of injected CO2 gas and its gravity gradient along the formation direction. CO2-Crude Oil Capillary Force Gradient CO2 gas phase pore pressure gradient ; in, and The calculation formula is as follows: (1) (2) In the formula, Porosity at the CO2 injection well site, expressed in %. This refers to the interfacial tension between gas and oil, expressed in mN / m. The gas-oil interface wetting contact angle, in degrees. For the tortuosity of the duct, based on the Bruggeman relation of cemented sandstone. Perform calculations, Air permeability in the formation direction at the location of the CO2 injection well, expressed in dB. This represents the oil phase pore pressure at the location of the CO2 injection well structure, which is assumed to be approximately equal to the formation pore pressure at that location, and is expressed in MPa.

[0022] As a preferred embodiment of the present invention, specifically, the process of constructing a dimensionless mechanical discrimination model for artificial air cap formation includes, Reference Figure 2 Based on Darcy's quantification, the seepage velocity of a unit volume of injected gas in the formation direction in reservoirs with formation dip angles is as follows: (4) In the formula, The velocity of the injected gas in the formation direction is expressed in m / s. The air permeability of the reservoir rock in the formation direction, expressed in units of 10⁻⁶. -3 μm 2 , The relative permeability of the gas phase is dimensionless. This refers to the viscosity of the gas phase, expressed in mPa·s. This represents the capillary pressure gradient between the gas and water phases under bound water conditions in the oil reservoir area, expressed in MPa / m. (Note: The last sentence appears to be incomplete and possibly refers to a different context. It likely refers to a specific oil reservoir area under bound water conditions.) It is equal to its maximum value, which is a constant, so its value is 0.

[0023] Considering that injected gas can only migrate towards the top of the reservoir when the injected gas seepage velocity is greater than zero, that is, only when... Only then can an artificial dome be formed, therefore: (5) Organizing, one can obtain (6) If let The conditions for the formation of an artificial roof can then be expressed as follows: (7) in, This is the calculated dimensionless value.

[0024] In a preferred embodiment of the present invention, specifically, the first threshold is 1.

[0025] In this preferred embodiment, the final determination is made through theoretical reasoning and experimental verification. A value greater than 1.0 indicates that the reservoir with the formation dip angle can be considered capable of forming an artificial CO2 cap. This should include the dimensionless number of times the artificial cap forms in the target reservoir. Artificial air can only be formed when the time is right, so the first threshold value is preferably set to 1.

[0026] To illustrate the application of this invention, taking the Sand Reservoir B (S RB) CO2 miscible gravity stabilization pilot test area reservoir in Weeks Island, New Iberia Parish, Louisiana, USA as an example, the CO2-crude oil capillary force gradient in the formation direction at the N2 injection well location was obtained using direct and indirect methods. CO2 gas phase pore pressure gradient in the formation direction at the N2 injection well location ( The difference between the CO2 buoyancy gradient and the gravity gradient along the formation direction at the N2 injection well location. Data such as these are used to calculate the dimensionless number of the reservoir in the pilot test area of ​​CO2 injection at the top of the Yanling oilfield using the dimensionless mechanical model formula (7) formed by the artificial gas cap. The value of ) is used to determine whether an artificial CO2 cap has formed in the oil reservoir of the test area.

[0027] Based on the data in Table 1 (Parameter Table of the Pilot Test Area for S sand Reservoir B (S RB) CO2 Gravity Stabilized Drive in Weeks Island, New Iberia Parish, Louisiana, USA), the following parameters can be obtained directly or indirectly using Equations (1), (2) and the formula for the difference between buoyancy gradient and gravity gradient. It is 0.00 MPa / m. It is 0.1357 MPa / m. The value is 2.6549 MPa / m. The dimensionless number of the reservoir in the S sand Reservoir B (S RB) CO2 gravity stabilization pilot test area of ​​New Iberia Parish, Louisiana, is calculated by equation (7). The value of 9.5745 indicates the formation of an artificial CO2 cap in the reservoir, which aligns with the actual situation at the mine (an artificial CO2 cap formed at the top of the technically abandoned SRB reservoir, with the gas-oil interface decreasing from -3889.248 m to 3953.256 m, meaning the average thickness of the artificial cap was 64.008 m; the cap drove the crude oil to sink, causing the oil-water interface to drop by 10.3632 m, and the oil column height to increase from 7.0104 m to 17.3736 m before the production wells A-18 and A-17). Furthermore, during the pilot test of CO2 injection at the top of the SRB reservoir, well A-16 began injection in October 1978 and stopped in January 1980, with a cumulative CO2 injection of approximately 0.6889 × 10⁻⁶ m. 8 m 3 Cumulative crude oil production: 0.3582 × 10 8 t, CO2 sealing 2 0.1039×10 8 m 3 The experimental results are significant. At the same time, it also reveals the theoretical basis of the invention and its good application effects; its widespread application has yielded good social and economic benefits.

[0028]

[0029] Table 1 Example 2: The present invention also proposes a device for determining whether an artificial CO2 gas cap has formed in an oil reservoir with a formation dip angle, comprising the following: The data acquisition module is used to acquire data on the CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, and the difference between the CO2 buoyancy gradient and gravity gradient in the formation direction at the structural location of the CO2 injection well in the target reservoir. The dimensionless number value calculation module is used to calculate the dimensionless number value of artificial gas cap formation in the target reservoir based on the pre-built dimensionless number mechanical discrimination model for artificial gas cap formation; The gas cap formation judgment module is used to determine whether the dimensionless number value is greater than the first threshold. If it is, the artificial gas cap of the target reservoir is considered to have formed; otherwise, the artificial gas cap of the target reservoir is considered not to have formed.

[0030] In this second embodiment, there is an embodiment of the hardware corresponding to the method proposed in this invention. Therefore, this second embodiment also has the relevant technical effects of the first embodiment proposed in this invention.

[0031] Furthermore, the functional modules in the various embodiments of the present invention can be integrated into one processing module, or each module can exist physically separately, or two or more modules can be integrated into one module. The integrated modules described above can be implemented in hardware or as software functional modules.

[0032] If the integrated module is implemented as a software functional module and sold or used as an independent product, it can be stored in a computer-readable storage medium. Based on this understanding, all or part of the processes in the methods of the above embodiments of the present invention can also be implemented by a computer program instructing related hardware. The computer program can be stored in a computer-readable storage medium, and when executed by a processor, it can implement the steps of the various method embodiments described above. The computer program includes computer program code, which can be in the form of source code, object code, executable files, or certain intermediate forms. The computer-readable medium can include: any entity or system capable of carrying the computer program code, recording media, USB flash drives, portable hard drives, magnetic disks, optical disks, computer memory, read-only memory (ROM), random access memory (RAM), electrical carrier signals, telecommunication signals, and software distribution media, etc.

[0033] Although the description of the invention has been quite detailed and particularly of several described embodiments, it is not intended to limit it to any of these details or embodiments or any particular embodiment, but should be considered as providing a broad possible interpretation of the claims by referring to the appended claims and taking into account the prior art, thereby effectively covering the intended scope of the invention. Furthermore, the invention has been described above with respect to embodiments foreseeable by the inventors in order to provide a useful description, and non-substantial modifications to the invention that have not yet been foreseen may still represent equivalent modifications.

[0034] The above description is merely a preferred embodiment of the present invention. The present invention is not limited to the above-described embodiments. Any embodiment that achieves the technical effects of the present invention using the same means should fall within the protection scope of the present invention. Within the protection scope of the present invention, various modifications and variations can be made to the technical solutions and / or implementation methods.

Claims

1. A method for judging whether or not an artificial CO2 gas cap is formed in a reservoir having a stratigraphic dip, characterized by, The method is applied to a stratified dip reservoir, and the method comprises The following: CO2 injection well structure location in the direction of the formation 2- data of the difference between the crude oil capillary force gradient, the CO2 gas phase pore pressure gradient, the CO2 gas buoyancy force gradient and the gravity gradient; An artificial gas cap formation non-dimensional mechanical discrimination model is constructed based on a pre-constructed artificial gas cap to calculate a non-dimensional value of the artificial gas cap formation of the target reservoir. It is determined whether the non-dimensional value is greater than a first threshold value. If yes, it is considered that the artificial gas cap of the target reservoir is formed. If no, it is considered that the artificial gas cap of the target reservoir is not formed.

2. The method for judging whether or not an artificial CO2 gas cap is formed in a reservoir having a stratigraphic dip according to claim 1, characterized by, Specifically, the CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, CO2 gas buoyancy gradient and gravity gradient difference data of the target reservoir in the stratigraphic direction at the structure position of the CO2 injection well are obtained, including The target reservoir is subjected to fine reservoir description, and a reservoir three-dimensional fine geological model is established by using a Schlumberger Petrel data integration, geological modeling and simulation workflow platform. Based on the reservoir three-dimensional fine geological model, a target reservoir numerical simulation model is further established by using Schlumberger. The target reservoir numerical simulation model is corrected and improved by means of history data fitting to obtain an updated target reservoir numerical simulation model. Finally, the CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, CO2 gas buoyancy gradient and gravity gradient difference data of the target reservoir in the stratigraphic direction at the structure position of the CO2 injection well are obtained by using the updated target reservoir numerical simulation model.

3. The method for judging whether or not an artificial CO2 gas cap is formed in a reservoir having a stratigraphic dip according to claim 2, characterized by Specifically, the CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, CO2 gas buoyancy gradient and gravity gradient difference data of the target reservoir in the stratigraphic direction at the structure position of the CO2 injection well are obtained by using the updated target reservoir numerical simulation model, including CO2-oil capillary forces in the direction of the formation at the location of the CO2 injection well obtained by the updated target reservoir numerical simulation model , CO2 gas phase pore pressure , formation dip ; wherein is the capillary force for crude oil, g is the CO2 gas phase, o is the oil phase, is the irreducible water saturation; is the capillary force at the CO2 gas-oil interface at the irreducible water saturation; calculating a distance in the formation direction from the injection well structure location to the reservoir top structure location ; Computing the difference between the CO2 gas buoyancy gradient and its gravity gradient in the direction of the formation , CO2 - crude oil capillary force gradient , CO2 gas phase pore pressure gradient ; wherein with the calculation formula is as follows, （1） （2） wherein is the porosity at the location of the CO2 injection well, is the gas-oil interfacial tension, is the gas-oil interfacial wetting contact angle, is the tortuosity of the pore path, based on the Bruggeman relation for cemented sandstone is calculated, is the air permeability in the direction of the formation at the location of the CO2 injection well, is the oil phase pore pressure at the location of the CO2 injection well, by default the formation pore pressure at that location.

4. The method for judging whether or not an artificial CO2 gas cap is formed in a reservoir having a stratigraphic dip according to claim 1, characterized by, Specifically, the construction process of the artificial gas cap formation non-dimensional mechanical discrimination model comprises Based on Darcy's law, the seepage velocity of a unit volume of injected gas in the stratigraphic direction in a stratified dip reservoir is as follows: （4） wherein is the gas injection seepage velocity in the formation direction, is the air permeability of the reservoir rock in the formation direction, is the gas phase relative permeability, is the gas phase viscosity, is the gas phase-water phase capillary pressure gradient under the irreducible water conditions in the reservoir oil region, since under the irreducible water conditions in the target reservoir oil region, is equal to its maximum value, which is a constant, and therefore its value is 0.

5. Considering that the injected gas can only migrate to the top of the reservoir when the injected gas seepage velocity is greater than zero, i.e. when the artificial gas cap can only be formed, we have: （5） After sorting, the following is obtained （6） If The formation condition of the artificial gas cap can be expressed as （7） wherein, is the calculated causation value.

6. The method of judging whether or not an artificial CO2 gas cap is formed in a reservoir having a stratigraphic dip according to claim 1, characterized by, Specifically, the first threshold value is 1.

7. An apparatus for judging whether an artificial CO2 gas cap is formed or not with respect to a reservoir having a stratigraphic dip, characterized by, The following is included: A data acquisition module is configured to obtain CO2-crude oil capillary force gradient, CO2 gas phase pore pressure gradient, CO2 gas buoyancy gradient and gravity gradient difference data of the target reservoir in the stratigraphic direction at the structure position of the CO2 injection well. A non-dimensional value calculation module is configured to calculate a non-dimensional value of the artificial gas cap formation of the target reservoir based on a pre-constructed artificial gas cap formation non-dimensional mechanical discrimination model. A gas cap formation judgment module is configured to determine whether the non-dimensional value is greater than a first threshold value. If yes, it is considered that the artificial gas cap of the target reservoir is formed. If no, it is considered that the artificial gas cap of the target reservoir is not formed.

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