Method and device for determining oil-gas interface migration distance of oil ring condensate gas reservoir

Abstract

The present application relates to a kind of oil ring condensate gas reservoir oil-gas interface migration distance determination method and device, the method comprises: establishing the material balance equation of oil ring condensate gas reservoir;Wherein, material balance equation is by the influence of gas cap anti-condensation factor, oil ring dissolved gas factor, reservoir rock expansion factor and water vapor content factor in the process of oil ring condensate gas reservoir gas cap and oil ring cooperative exploitation is established;Based on the obtained reservoir geologic feature parameter, development dynamic data and material balance equation, the oil-gas interface migration distance of different time under different oil-gas cooperative exploitation mode is determined.The present application can describe the oil-gas interface migration law of oil ring condensate gas reservoir, so as to determine the reasonable oil ring condensate gas reservoir development mode according to the oil-gas interface migration law of oil ring condensate gas reservoir, it is of great significance for preventing oil-gas crossflow, keeping oil-gas interface stable and maximum limit exploitation gas cap and oil ring resource.

Description

Technical Field

[0001] This invention relates to a method and apparatus for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir. Background Technology

[0002] When condensate gas reservoirs with oil rings are put into development, both oil and gas are in a saturated state. Once the formation pressure drops, reverse condensation will occur in the condensate gas cap, resulting in condensate oil loss; crude oil degassing will occur in the oil ring, increasing crude oil viscosity and making the development of the oilfield more difficult. Managing the interaction and mutual influence between the gas cap and the oil ring during the development of condensate gas reservoirs with oil rings, preventing cross-contamination of oil and gas, and maintaining a stable or slow-moving oil-gas interface are key factors for the rational development of this type of reservoir. Therefore, the development difficulty of condensate gas reservoirs with oil rings is much higher than that of simple gas or oil reservoirs. The development design of condensate gas reservoirs with oil rings must consider the rational exploitation of crude oil, condensate oil, and natural gas resources, maximizing their recovery rates. When the industrial value of crude oil reserves in the oil ring is not high, the focus should be on condensate gas extraction. Crude oil in the oil ring should be extracted as early as possible, and high-pressure condensate gas can be used for oil displacement to improve crude oil recovery. When the crude oil reserves in the oil ring are also quite large, the rational development of both crude oil and condensate gas should be emphasized. Controlling the stability of the oil-gas interface is very important during development. Summary of the Invention

[0003] To describe the migration patterns of the oil-gas interface in condensate gas reservoirs with oil rings, this invention proposes a method and apparatus for determining the migration distance of the oil-gas interface in such reservoirs. The technical solution proposed by this invention is as follows:

[0004] In a first aspect, the present invention provides a method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir, comprising:

[0005] A material balance equation is established for condensate gas reservoirs with oil rings. The material balance equation is established by comprehensively considering the influence of gas cap anti-condensation factors, oil ring dissolved gas factors, reservoir rock expansion factors, and water vapor content factors on the co-production process of gas cap and oil ring in condensate gas reservoirs with oil rings.

[0006] Based on the acquired reservoir geological characteristic parameters, development dynamic data, and the aforementioned material balance equation, the oil and gas interface migration distance at different times under different oil and gas co-production methods is determined.

[0007] In an optional embodiment, establishing the material balance equation for an oil-ring condensate gas reservoir includes:

[0008] Based on the water vapor content in the formation, the original pore volume of the gas cap is represented;

[0009] Based on the original pore volume of the gas cap, the original pore volume of the oil ring is represented;

[0010] Based on the gas cap anti-condensation parameters during the gas cap development process, the current gas cap pore volume is represented;

[0011] Based on the dissolved gas parameters of the oil ring, the current pore volume of the oil ring region is represented;

[0012] Based on reservoir rock expansion parameters, the expansion volume of formation rocks is represented;

[0013] The material balance equation is established based on the original pore volume of the gas cap, the original pore volume of the oil ring, the current pore volume of the gas cap, the current pore volume of the oil ring, and the expansion volume of the formation rocks.

[0014] In an optional embodiment, the original pore volume of the oil ring, based on the original pore volume of the gas crown, includes:

[0015] Based on the original pore volume of the gas crown, the original pore volume of the oil ring is determined by the following formula 1;

[0016] V Oi =mV Gi , Formula 1;

[0017] In the formula, V Oi V represents the original pore volume of the oil ring; m is the ratio of the pore volume of the oil ring to the pore volume of the gas cap under the original conditions; Gi This represents the original pore volume of the air cap.

[0018] In an optional embodiment, the step of representing the current pore volume of the oil annulus region based on the dissolved gas parameters of the oil annulus includes:

[0019] Based on the dissolved gas parameters of the oil ring, the current pore volume of the oil ring region is determined using the following formula 2:

[0020]

[0021] In the formula, V O S represents the current pore volume of the oil annulus region. wcO B represents the bound water saturation in the oil ring region. oi N is the volume factor of the oil ring oil under the original conditions; p Accumulated surface crude oil production in the oil ring region; B o S represents the volume coefficient of the oil-ring oil under current conditions. gO ΔS represents the current gas saturation level within the oil annulus region. w This represents the current increase in water saturation within the oil ring region, indicating the increase in water saturation caused by external water intrusion.

[0022] In an optional embodiment, the gas saturation S in the current oil ring region gO Determined by the following formula 3:

[0023]

[0024] In the formula, R si The original dissolved gas-oil ratio of the oil ring oil; R s R represents the dissolved gas-oil ratio of the oil ring oil under current conditions. p B represents the production gas-oil ratio in the oil annulus region. g The current volume coefficient of the gas at the top of the gas cap is given by... Find p sc Z is the pressure under standard conditions; Z is the condensate gas deviation factor under the current formation pressure; T is the temperature of the gas cap reservoir; T sc ρ is the temperature under standard conditions; p is the current formation pressure of the gas cap reservoir.

[0025] In an optional embodiment, the water saturation increment ΔS within the current oil ring region w Determined by the following formula 4:

[0026]

[0027] In the formula, ΔW e The amount of water intrusion is ΔW e =W e -W p B w Find; W e W represents the current cumulative water intrusion. p B represents the current cumulative water production. w This is the formation water volume factor under the current formation pressure.

[0028] In an optional embodiment, the statement representing the expansion volume of the formation rocks based on reservoir rock expansion parameters includes:

[0029] Based on the reservoir rock expansion parameters, the expansion volume of the formation rocks is determined using the following formula 5:

[0030]

[0031] In the formula, ΔV f The expansion volume of the formation rocks represents the total expansion volume of the rocks within the oil and gas reservoir. is the average rock compressibility coefficient of the reservoir.

[0032] In an optional embodiment, the representation of the original pore volume of the gas cap based on the water vapor content in the formation includes:

[0033] Based on the water vapor content in the formation, the initial pore volume of the gas cap is determined using the following formula 6:

[0034]

[0035] In the formula, V Gi G represents the original pore volume of the gas cap; G represents the original natural gas reserves in the formation; B represents the original pore volume of the gas cap. gi The volume coefficient of the gas cap gas under the original conditions is given by... Find; y wi S represents the water vapor content in the gas cap under original conditions. wcG p represents the bound water saturation level within the air cap region. sc The pressure under standard conditions; T sc Temperature under standard conditions; T is the temperature of the gas cap reservoir; P i Z represents the original formation pressure; i This is the gas deviation factor of the condensate cap under the original conditions.

[0036] In an optional embodiment, the gas cap anti-condensation parameters based on the gas cap development process, representing the current gas cap pore volume, include:

[0037] Based on the gas cap reverse condensation parameters, the current gas cap pore volume is determined using the following formula 7:

[0038]

[0039] In the formula, V G G represents the current gas cap pore volume under the current formation pressure; p B represents the cumulative volume of hydrocarbon well fluid produced in the gas cap area. g y is the volume factor of the current cap gas; w S represents the current water vapor content in the air cap. oc denoted as saturation of condensate oil in the gas cap region; Z is the condensate gas deviation factor under the current formation pressure; and p is the current formation pressure of the gas cap reservoir.

[0040] In an optional embodiment, the cumulative volume G of hydrocarbon well fluid produced in the gas cap area p It is determined by the following formula 8:

[0041] G p =G gp +G Eoc , formula 8;

[0042] In the formula, G gp Accumulated pure natural gas production for the gas cap area; G Eoc The equivalent gas volume for the cumulative condensate production in the gas cap region is given by... V is obtained. oc Accumulated condensate production in the gas cap region; ρ oc M is the density of the condensate oil. oc The average molecular weight of the condensate oil is given.

[0043] In an optional embodiment, establishing the mass balance equation based on the original pore volume of the gas cap, the original pore volume of the oil ring, the current pore volume of the gas cap, the current pore volume of the oil ring, and the expansion volume of the formation rock includes:

[0044] Based on the original pore volume of the gas cap, the original pore volume of the oil ring, the current pore volume of the gas cap, the current pore volume of the oil ring, and the expansion volume of the formation rocks, the following material balance equation (Formula 9) is established:

[0045] V Gi +V Oi =V G +V O +ΔV f , Formula 9.

[0046] In an optional embodiment, the development dynamic data includes the cumulative surface crude oil production in the oil annulus and the cumulative volume of hydrocarbon well fluids produced in the gas cap at different times under different oil and gas co-production methods; determining the oil and gas interface migration distance at different times under different oil and gas co-production methods based on the acquired reservoir geological characteristic parameters, development dynamic data, and the material balance equation includes:

[0047] Based on the combination of the reservoir geological characteristic parameters, the cumulative surface crude oil production in the oil annulus at different times under different oil and gas co-production methods, and the cumulative volume of hydrocarbon well fluids produced in the gas cap area, the material balance equation is iteratively solved to obtain the corresponding current formation pressure.

[0048] Based on the cumulative volume of hydrocarbon well fluid produced in the gas cap area and the current formation pressure, the oil and gas interface migration distance is determined using Formula 10.

[0049]

[0050] In the formula, r 1i r is the radius of the outer edge of the gas cap region under the original conditions. 2i h is the radius of the inner edge of the gas cap region under the original conditions. 1i h represents the maximum vertical height of the outer edge profile of the air cap area under the original conditions. 2i Δh represents the maximum vertical height of the edge profile within the gas cap area under the original conditions; φ represents the migration distance of the oil and gas interface; φ represents the porosity of the gas cap area; and α represents the dip angle of the gas cap formation.

[0051] Secondly, the present invention provides a device for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir, comprising:

[0052] The material balance equation establishment module is used to establish the material balance equation for condensate gas reservoirs with oil rings. The material balance equation is established by comprehensively considering the influence of gas cap anti-condensation factors, oil ring dissolved gas factors, reservoir rock expansion factors, and water vapor content factors on the co-production process of gas cap and oil ring in condensate gas reservoirs with oil rings.

[0053] The oil and gas interface migration distance determination module is used to determine the oil and gas interface migration distance at different times under different oil and gas co-production methods based on the acquired reservoir geological characteristic parameters, development dynamic data and the material balance equation.

[0054] Thirdly, the present invention provides a computer-readable storage medium having a computer program stored thereon, which, when executed by a processor, implements the method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir as described in the first aspect.

[0055] Fourthly, the present invention provides an electronic device, including a processor, a communication interface, a memory, and a communication bus, wherein the processor, the communication interface, and the memory communicate with each other through the communication bus;

[0056] Memory, used to store computer programs;

[0057] The processor, when executing a program stored in memory, implements the method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir as described in the first aspect.

[0058] Based on the above technical solution, the beneficial effects of the present invention compared with the prior art are as follows:

[0059] The present invention provides a method for determining the migration distance of the oil-gas interface in condensate gas reservoirs with an oil ring. This method establishes a material balance equation for condensate gas reservoirs with an oil ring by comprehensively considering the influence of factors such as anti-condensation at the gas cap, dissolved gas in the oil ring, reservoir rock expansion, and water vapor content during the co-production of the gas cap and oil ring. Based on the acquired reservoir geological characteristic parameters, development dynamic data, and the established material balance equation, the method determines the migration distance of the oil-gas interface at different times under different co-production methods. This method can describe the migration law of the oil-gas interface in condensate gas reservoirs with an oil ring, thereby determining a reasonable development method for such reservoirs. This is of great significance for preventing oil and gas cross-contamination, maintaining the stability of the oil-gas interface, and maximizing the development of gas cap and oil ring resources.

[0060] Other features and advantages of the invention will be set forth in the description which follows, and will be apparent in part from the description, or may be learned by practicing the invention. The objects and other advantages of the invention are realized and obtained in accordance with the structures particularly pointed out in the description, claims and drawings.

[0061] To make the above-mentioned objects, features and advantages of the present invention more apparent and understandable, preferred embodiments are described below in detail with reference to the accompanying drawings. Attached Figure Description

[0062] To more clearly illustrate the specific embodiments of the present invention or the technical solutions in the prior art, the drawings used in the description of the specific embodiments or the prior art will be briefly introduced below. Obviously, the drawings described below are some embodiments of the present invention. For those skilled in the art, other drawings can be obtained from these drawings without creative effort.

[0063] Figure 1 This is a flowchart illustrating the method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir provided in an embodiment of the present invention.

[0064] Figure 2 This is a fluid distribution map of a gas cap reservoir with edge-bottom water condensate provided in an embodiment of the present invention;

[0065] Figure 3 This is a graph showing the changes in formation pressure calculated by the method provided in this embodiment of the invention and the changes in measured formation pressure with the cumulative production from the gas cap.

[0066] Figure 4 This is a graph showing the variation of formation pressure and oil-gas interface migration distance under different gas cap production rates provided in this embodiment of the invention.

[0067] Figure 5 This is a graph showing the variation of formation pressure and oil-gas interface migration distance under different oil ring production rates provided in this embodiment of the invention.

[0068] Figure 6 This is a schematic diagram of the device for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir provided in an embodiment of the present invention;

[0069] Figure 7 This is a schematic diagram of the structure of the electronic device provided in an embodiment of the present invention. Detailed Implementation

[0070] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

[0071] Exemplary embodiments will now be described in detail, examples of which are illustrated in the accompanying drawings. When the following description relates to the drawings, unless otherwise indicated, the same numerals in different drawings denote the same or similar elements. The embodiments described in the following exemplary embodiments do not represent all embodiments consistent with the present invention. Rather, they are merely examples of apparatuses and methods consistent with some aspects of the invention as detailed in the appended claims.

[0072] In the description of this invention, it should be noted that the terms "center," "upper," "lower," "left," "right," "vertical," "horizontal," "inner," and "outer," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are used only for the convenience of describing the invention and for simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on the invention. Furthermore, the terms "first," "second," and "third" are used for descriptive purposes only and should not be construed as indicating or implying relative importance.

[0073] In the description of this invention, it should be noted that, unless otherwise explicitly specified and limited, the terms "installation," "connection," and "linking" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; and they can refer to the internal connection of two components. Those skilled in the art can understand the specific meaning of the above terms in this invention based on the specific circumstances.

[0074] Example 1

[0075] The inventors discovered that during the co-production of the gas cap and oil ring in condensate gas reservoirs with an oil ring, a pressure difference exists between the gas cap and oil ring due to factors such as their respective production rates and injection-production ratios. This pressure difference leads to migration at the oil-gas interface. When the gas cap pressure is higher than the oil ring pressure, gas from the gas cap will surge towards the oil well under the influence of the pressure difference, causing gas channeling and reduced production. Conversely, when the oil ring pressure is higher than the gas cap pressure, oil from the oil ring will infiltrate the gas cap and disperse in a scattered manner, making crude oil recovery difficult and resulting in resource loss, failing to meet the inventors' expectations. Therefore, accurately describing the migration patterns of the oil-gas interface in condensate gas reservoirs with an oil ring is crucial for preventing oil-gas cross-contamination, maintaining oil-gas interface stability, and maximizing the development of both the gas cap and oil ring resources. The inventors, through further research and development, developed this invention. This invention establishes a material balance equation for condensate gas reservoirs with oil rings that comprehensively considers factors such as gas cap anti-condensation, dissolved gas in the oil ring, reservoir rock expansion, and water vapor content. Based on this equation, the migration distance of the oil and gas interface at different times under different oil and gas co-production methods is calculated using the volumetric method.

[0076] This invention provides a method for determining the migration distance of the oil-gas interface in condensate gas reservoirs with oil rings, referring to... Figure 1 As shown, it includes:

[0077] S101. Establish the material balance equation for a condensate gas reservoir with an oil ring; wherein, the material balance equation is established by comprehensively considering the influence of gas cap anti-condensation factors, oil ring dissolved gas factors, reservoir rock expansion factors, and water vapor content factors on the co-production process of the gas cap and oil ring in a condensate gas reservoir with an oil ring.

[0078] S102. Based on the acquired reservoir geological characteristic parameters, development dynamic data, and the aforementioned material balance equation, determine the oil and gas interface migration distance at different times under different oil and gas co-production methods.

[0079] Based on the derived material balance equation for condensate gas reservoirs with oil rings, analytical methods can be used to quickly calculate the oil and gas interface migration distance at different times under different oil and gas co-production methods in condensate gas reservoirs with oil rings.

[0080] The method for determining the oil-gas interface migration distance in condensate gas reservoirs with oil rings provided in this invention comprehensively considers the influence of factors such as gas cap anti-condensation, dissolved gas in the oil ring, reservoir rock expansion, and water vapor content on the co-production of the gas cap and oil ring in condensate gas reservoirs with oil rings. It establishes a material balance equation for condensate gas reservoirs with oil rings. Based on the acquired reservoir geological characteristic parameters, development dynamic data, and the established material balance equation, it determines the oil-gas interface migration distance at different times under different oil-gas co-production methods. This method can describe the oil-gas interface migration law in condensate gas reservoirs with oil rings. Therefore, based on the oil-gas interface migration law in condensate gas reservoirs with oil rings, it can determine a reasonable development method for condensate gas reservoirs with oil rings. This is of great significance for preventing oil and gas crosstalk, maintaining oil-gas interface stability, and maximizing the development of gas cap and oil ring resources.

[0081] Assuming that in a condensate gas cap reservoir, the gas cap and the bottom oil ring are within the same pressure system, and the oil-gas interface advances uniformly; neglecting the dissolution and adsorption of condensate gas in the oil ring; considering the anti-condensation phenomenon in the gas cap area and the escape of dissolved gas from the oil ring area; as the formation pressure decreases, the primary water in the formation begins to evaporate continuously. In a specific embodiment, the establishment of the material balance equation for a condensate gas reservoir with an oil ring, as described in step S101 above, specifically includes:

[0082] S1011, based on the water vapor content in the formation, represents the original pore volume of the gas cap;

[0083] S1012. Based on the original pore volume of the gas crown, represent the original pore volume of the oil ring;

[0084] S1013. Based on the gas cap anti-condensation parameters during the development process of the gas cap, the current gas cap pore volume is represented.

[0085] S1014. Based on the dissolved gas parameters of the oil ring, this represents the current pore volume of the oil ring region.

[0086] S1015. Based on reservoir rock expansion parameters, represent the expansion volume of formation rocks;

[0087] S1016. Based on the original pore volume of the gas cap, the original pore volume of the oil ring, the current pore volume of the gas cap, the current pore volume of the oil ring zone, and the expansion volume of the formation rock, establish the material balance equation.

[0088] In determining the initial pore volume of the gas cap in this embodiment of the invention, the influence of water vapor in the formation is considered. The initial pore volume of the gas cap, based on the water vapor content in the formation, as described in step S1011 above, specifically includes:

[0089] Based on the water vapor content, the initial pore volume of the air cap is determined using the following formula 6:

[0090]

[0091] In the formula, V Gi The original pore volume of the air cap is m. 3 G represents the original natural gas reserves in the formation, in m³. 3 B gi The volume coefficient of the gas cap gas under the original conditions is given by... Find; y wi S represents the water vapor content in the gas cap under original conditions. wcG p represents the bound water saturation level within the air cap region. sc Pressure under standard conditions, MPa; T sc The temperature is K under standard conditions; T is the temperature of the gas cap reservoir, K; p i Z represents the original formation pressure, in MPa; i This is the gas deviation factor of the condensate cap under the original conditions.

[0092] The gas deviation factor Z of the condensate cap under the above original conditions i The solution can be obtained using the relevant empirical formulas of the DPR method (Formula 6.1):

[0093]

[0094] in, p pr =p i / p pc T pr =T / T pc ,

[0095] ppc =[46.7-32.1(γ)] g -0.5)]×0.09869, T pc =171(γ) g -0.5)+182;

[0096] In the formula, ρ R p represents the relative density of the gas. pr T pr These are the relative pressure and relative temperature, respectively; p pc The quasi-critical pressure is measured in MPa; T pc The quasi-critical temperature is K; γ g ρ represents the relative density of the gas.

[0097] The gas deviation factor is obtained by solving Equation 6.1 using an iterative calculation method.

[0098] Assuming the ratio of oil ring pore volume to gas cap pore volume under the original conditions is m, the original pore volume of the oil ring can be represented based on the original pore volume of the gas cap in this embodiment of the invention. The representation of the original pore volume of the oil ring based on the original pore volume of the gas cap in step S1012 above includes:

[0099] Based on the original pore volume of the gas crown, the original pore volume of the oil ring is determined by the following formula 1;

[0100]

[0101] In the formula, V Oi The original pore volume of the oil ring is m. 3 ; m is the ratio of the oil ring pore volume to the gas cap pore volume under the original conditions.

[0102] Dissolved gas in the oil annulus continuously escapes as formation pressure decreases. Some of this gas remains in the formation in a free form, while some is extracted to the surface along with the crude oil in the oil annulus. In this embodiment of the invention, the effect of dissolved gas escape is considered when determining the pore volume of the oil annulus when the formation pressure drops to p. The dissolved gas parameters in step S1014 above, representing the current pore volume of the oil annulus region, specifically include:

[0103] Based on the dissolved gas parameters of the oil ring, the current pore volume of the oil ring region is determined using the following formula 2:

[0104]

[0105] In the formula, V O Let m be the current pore volume of the oil ring region. 3 S wcO B represents the bound water saturation in the oil ring region. oi N is the volume factor of the oil ring oil under the original conditions;p To accumulate surface crude oil production in the oil ring region, m 3 B o S represents the volume coefficient of the oil-ring oil under current conditions. gO ΔS represents the current gas saturation level within the oil annulus region. w This represents the current increase in water saturation within the oil ring region, indicating the increase in water saturation caused by external water intrusion.

[0106] In one specific embodiment, the gas saturation S in the current oil annular region gO The calculation does not consider the condensate gas intrusion from the gas cap, but only the influence of free dissolved gas. The gas saturation S in the current oil annulus region is... gO Determined by the following formula 3:

[0107]

[0108] In the formula, R si For the original dissolved gas-oil ratio of the oil ring oil, m 3 / m 3 ;R s Let m be the dissolved gas-oil ratio of the oil ring oil under the current conditions. 3 / m 3 ;R p For the production gas-oil ratio in the oil annulus region, m 3 / m 3 .

[0109] In one specific embodiment, the water saturation increment ΔS within the current oil ring region w Determined by the following formula 4:

[0110]

[0111] In the formula, ΔW e For the amount of purified water, m 3 W e The current cumulative flooding volume, m 3 , by ΔW e =W e -W p B w Find; W p The current cumulative water production, m 3 B w This represents the formation water volume factor under the current formation pressure. Current cumulative water intrusion W e It can be obtained from the unsteady water intrusion calculation model. The specific process can be referred to the description in the existing technology, and will not be repeated here.

[0112] The above step S1015, which uses reservoir rock expansion parameters to represent the expansion volume of formation rocks, specifically includes:

[0113] Based on the reservoir rock expansion parameters, the expansion volume of the formation rocks is determined using the following formula 5:

[0114]

[0115] In the formula, ΔV f Let be the expansion volume of the formation rocks, representing the total expansion volume of the rocks within the oil and gas reservoir, in meters. 3 ; The average rock compressibility coefficient of the reservoir is given in MPa. -1 ΔV f Specifically, it represents the total expansion volume of rocks in the gas cap and oil ring regions when the formation pressure drops to p.

[0116] During the development of the condensate gas cap, when the formation pressure falls below the dew point pressure of the condensate gas, condensate oil will continuously precipitate out, and simultaneously, formation native water will begin to evaporate. This embodiment of the invention considers the influence of the above factors when determining the gas cap pore volume when the formation pressure drops to p. The gas cap anti-condensation parameters described in step S1013 above, representing the current gas cap pore volume, specifically include:

[0117] Based on the gas cap reverse condensation parameters, the current gas cap pore volume is determined using the following formula 7:

[0118]

[0119] In the formula, V G The current gas cap pore volume is given in m. 3 G represents the gas cap pore volume under the current formation pressure; p The volume of hydrocarbon well fluids accumulated in the gas cap area, in m 3 The volume of hydrocarbon well fluid is the volume converted to the gas phase; B g y is the volume factor of the current cap gas; w S represents the current water vapor content in the air cap. oc Z represents the saturation of condensate oil in the gas cap region; Z represents the condensate gas deviation factor under the current formation pressure; and p represents the current formation pressure of the gas cap reservoir, in MPa.

[0120] The cumulative volume G of hydrocarbon well fluid produced in the aforementioned gas cap area p It is determined by the following formula 8:

[0121]

[0122] In the formula, G gp For the cumulative pure natural gas production in the gas cap area, m 3 G Eoc The equivalent gas volume of the cumulative condensate production in the gas cap region, in m3 V oc For the cumulative condensate production in the gas cap area, m 3 ;ρ oc The density of the condensate oil is expressed in g / cm³. 3 M oc denoted as the average molecular weight of the condensate oil, in kg / mol.

[0123] The above condensate oil saturation S oc It can be obtained through indoor isochoric decay experiments or phase equilibrium calculations; water vapor content y w It can be measured through formation condensate gas saturation water content experiments, or by referring to water vapor content data from adjacent condensate gas reservoirs.

[0124] The condensate gas deviation factor Z under the current formation pressure can be solved using the relevant empirical formula (Formula 8.1) of the DPR method:

[0125]

[0126] in, p pr =p / p pc T pr =T / T pc ;

[0127] p pc =[46.7-32.1(γ)] g -0.5)]×0.09869, T pc =171(γ) g -0.5)+182;

[0128] In the formula, ρ R p represents the relative density of the gas. pr T pr These are the relative pressure and relative temperature, respectively; p pc The quasi-critical pressure is measured in MPa; T pc The quasi-critical temperature is K; γ g ρ represents the relative density of the gas.

[0129] The gas deviation factor Z is obtained by solving Equation 8.1 using an iterative calculation method.

[0130] According to the principle of volume conservation during oil and gas reservoir development, the gas cap pore volume and oil ring pore volume of the original oil and gas reservoir are equal to the sum of the total pore volume of the gas cap and oil ring of the current oil and gas reservoir and the expansion volume of the formation rocks. The step S1016 above, which establishes the material balance equation based on the original pore volume of the gas cap, the original pore volume of the oil ring, the current pore volume of the gas cap, the current pore volume of the oil ring, and the expansion volume of the formation rocks, specifically includes:

[0131] Based on the original pore volume of the gas cap, the original pore volume of the oil ring, the current pore volume of the gas cap, the current pore volume of the oil ring, and the expansion volume of the formation rocks, the following material balance equation (Formula 9) is established:

[0132] V Gi +V Oi =V G +V O +ΔV f , Formula 9.

[0133] The original pore volume V of the gas crown obtained in steps S1011-S1015 above is... Gi The original pore volume V of the oil ring Oi The current gas crown pore volume V G The current oil ring region pore volume V O and the expansion volume ΔV of the strata rocks f Substituting into formula 9 above, we get:

[0134]

[0135] Formula 11 above is the material balance equation for condensate gas cap reservoirs that takes into account factors such as gas cap reverse condensation, oil ring dissolved gas escape, primary water evaporation, external dynamic water intrusion, and formation rock expansion.

[0136] Considering the elastic expansion of the rock in the gas cap region, the change in pore volume in the gas cap region when the formation pressure drops to p, i.e., the change in pore volume of the gas cap, can be expressed as:

[0137]

[0138] In the formula, ΔV G V represents the change in pore volume at the gas cap when the formation pressure drops to p. G V represents the current gas cap pore volume; Gi The original pore volume of the gas crown; ΔV f This represents the expansion volume of the rock strata.

[0139] Assuming the fluid distribution in the condensate gas cap reservoir is referenced Figure 2 As shown, the inner and outer edges of the gas cap region are distributed in a conical shape, and the total volume of the gas cap can be regarded as the difference in volume between the two cones inside and outside the gas cap region; the dip angle of the strata in the gas cap region is constant.

[0140] The change in pore volume at the gas crown can also be expressed as:

[0141]

[0142] Wherein, r1 is determined by the following formula 14:

[0143]

[0144] r2 is determined by the following formula 15:

[0145]

[0146] In the formula, r 1i r1 and r2 are the outer edge radii of the gas cap region under the original conditions and the current formation pressure, respectively, in meters; r 2i r1 and r2 represent the inner edge radius of the gas cap region under the original conditions and the current formation pressure, respectively, in meters; h represents the inner edge radius of the gas cap region. 1i h1 and h2 represent the maximum vertical heights (in meters) of the outer edge contour of the gas cap region under the original conditions and the current formation pressure, respectively; h3 and h4 represent the maximum vertical heights (in meters). 2i h1 and h2 represent the maximum vertical height of the edge profile within the gas cap area under the original conditions and the current formation pressure, respectively, in meters; Δh represents the migration distance of the oil and gas interface, in meters; φ represents the porosity of the gas cap area, in decimals; and α represents the dip angle of the gas cap formation, in degrees.

[0147] Combining formulas 12 and 13 above, we can obtain:

[0148]

[0149] Simplifying Equation 16, we get:

[0150]

[0151] In one specific embodiment, the development dynamic data includes the cumulative surface crude oil production N of the oil annulus at different times under different oil and gas co-extraction methods. p The cumulative volume of hydrocarbon well fluids produced in the gas top area, G p The step S102 above, which involves determining the oil and gas interface migration distance at different times under different oil and gas co-production methods based on the acquired reservoir geological characteristic parameters, development dynamic data, and the aforementioned material balance equation, specifically includes:

[0152] S1021. Based on the reservoir geological characteristic parameters, the cumulative surface crude oil production N of the oil ring area at different times under different oil and gas co-production methods. p The cumulative volume of hydrocarbon well fluids produced in the gas top area, G p By combining the above factors, the mass balance equation is solved iteratively to obtain the corresponding current formation pressure.

[0153] S1022. Based on the cumulative volume of hydrocarbon well fluids produced in the gas cap area and the current formation pressure, determine the oil and gas interface migration distance using Formula 10.

[0154]

[0155] Formula 10 shows that the migration distance Δh at the oil-gas interface is the cumulative volume of hydrocarbon well fluids G produced in the gas cap area. p The function of the current formation pressure p is Δh = f(G) p ,p), while parameter G p The mass balance equation (Equation 9) is satisfied with p. Therefore, in this embodiment of the invention, a series of production data G are first given. p N p Then, the material balance equation (Equation 9) is solved by iterative calculation to obtain the corresponding current formation pressure p. Finally, the calculated (G) p Substituting p into formula 10 yields the oil-gas interface migration distance Δh.

[0156] The mass balance equation (Equation 11) is rearranged to obtain:

[0157]

[0158] The specific iterative calculation process for the current formation pressure at different times is as follows:

[0159] (1) Let p A =0, p B =p i ;

[0160] (2) Let Calculate the condensate oil saturation S at the current formation pressure p. oc (p), Condensate gas deviation factor Z(p) under current formation pressure, and water vapor content y in the current gas cap. w (p) Current cumulative flood volume W e (p) Production gas-oil ratio R in the oil ring region p (p) Under current conditions, the oil-to-oil dissolved gas-oil ratio R s (p) and other parameters, the calculation process can be referred to the specific description in the above steps.

[0161] (3) Substitute the above parameters into Formula 17 to obtain F under the current formation pressure. n (p);

[0162] (4) Determine |F n (p)|≤ε p Is it true (ε) p (This is the accuracy requirement for the current formation pressure calculation). If the inequality holds, stop the calculation; otherwise, perform the following judgment:

[0163] ①If F n (p A )F nIf (p) < 0, then let p A =p A p B =p, and go to (2) to recalculate;

[0164] ②If F n (p B )F n If (p) < 0, then let p A =p, p B =p B And then proceed to (2) to recalculate.

[0165] Example 2

[0166] To more clearly illustrate the method for determining the oil-gas interface migration distance in condensate gas reservoirs with an oil ring provided in this embodiment of the invention, and to verify the accuracy of the method, this method was applied to an abnormally high-pressure, constant-volume sealed condensate gas cap reservoir. The oil-gas interface migration distances at different times under different oil and gas co-production operating modes were obtained, thereby adjusting the oil and gas co-production operating mode based on the oil-gas interface migration distance pattern. For ease of explanation, the cumulative surface crude oil production N in the oil ring area is used. p Hereinafter referred to as cumulative oil ring production, and cumulative hydrocarbon well fluid volume G produced in the gas cap area. p Hereinafter referred to as cumulative gas cap production. The specific process is as follows:

[0167] A certain abnormally high-pressure, constant-volume sealed condensate gas cap reservoir has a gas cap natural gas reserve of 357.92 × 10⁻⁶. 8 m 3 The geological reserves of crude oil in the oil ring are 6804.11 × 10⁻⁶. 4 m 3 The gas cap and oil cap were developed using a depletion-based approach. The gas reservoir has a central burial depth of 2720m, an initial formation pressure of 32.82MPa, and a temperature of 101.8℃. Under these initial conditions, the ratio of oil cap pore volume to gas cap pore volume (m) is 0.33, and the initial gas deviation factor Z... i The value is 1.18, representing the water vapor content (y) per unit volume of the gas phase at the original pressure. wi The bound water saturation S within the gas cap volume is 0.0112%. wcG The bound water saturation S within the oil ring volume is 0.13. wcO The average rock compressibility coefficient of the reservoir is 0.19. 1.58×10 -4 MPa -1 Under original conditions, the outer edge of the gas cap region r 1i With inner edge radius r 2i The inner edge profile h of the air cap is 1700m and 860m respectively, under the original conditions. 2iWith outer edge contour h 1i The maximum vertical heights are 300m and 150m respectively, and the dip angle α of the gas cap stratum is 10°.

[0168] Table 1 shows the production dynamics data and residual fluid properties of the oil and gas reservoir. Among them, the saturation of condensate oil, S... oc Water vapor content y w Dissolved gas-oil ratio R s It is obtained by interpolating indoor experimental data. The gas deviation factor Z is solved using the relevant empirical formula of the DPR method. For details, please refer to the specific description in the above steps.

[0169] First, the formation pressure data calculated iteratively using the material balance equation is compared with the actual shut-in well pressure measurement data, with reference to... Figure 3 As shown in the figure, the current formation pressure obtained by iterative calculation using the method provided in this embodiment of the invention matches the measured value well, and can predict the formation pressure of condensate gas cap reservoir at any time with relatively accurate and reliable results.

[0170] Secondly, by setting different oil and gas co-production operating regimes (gas cap production rate and oil ring production rate), and using the method for determining the migration distance of the oil and gas interface in condensate gas reservoirs with oil rings provided in this embodiment of the invention, the changing trend of the oil and gas interface migration distance under different oil and gas co-production operating regimes is predicted, with reference to... Figure 4 and Figure 5 As shown. Among them, Figure 4 The oil recovery rate of the oil ring in the central oilfield is fixed at 2%; Figure 5 The gas extraction rate from the central gas cap is fixed at 2%.

[0171] from Figure 4 and Figure 5 It can be seen that:

[0172]

[0173] Table 1

[0174] (1) As the gas production rate or oil production rate increases, the rate of decrease in formation pressure will continue to accelerate. Since the gas cap volume of the oil and gas reservoir is significantly larger than the oil ring volume, that is, the elastic energy of the gas cap is greater than that of the oil ring, the increase in gas production rate will more easily accelerate the decrease in formation pressure.

[0175] (2) From Figure 4It can be seen that, under a constant oil production rate in the oil ring, when the gas production rate at the gas cap is low (1%), the migration distance of the oil-gas interface towards the oil ring increases continuously with the increase of the oil ring production level (i.e., the cumulative oil ring production); however, when the gas production rate is high (3%), the migration distance of the oil-gas interface decreases continuously with the increase of the oil ring production level (i.e., the cumulative oil ring production). This is mainly because a higher gas production rate accelerates the depletion rate of the gas cap energy and weakens the gas cap expansion effect, thereby slowing down the migration speed of the oil-gas interface. Therefore, it can be seen that in the oil-gas co-production model, appropriately increasing the gas production rate is beneficial to slowing down the migration of the oil-gas interface towards the oil ring, thereby preventing premature gas channeling in the well.

[0176] (3) From Figure 5 It can be seen that, under a constant gas cap production rate, when the oil ring production rate is low (1%), the oil-gas interface migration distance decreases continuously with the increase of gas cap production level (i.e., cumulative gas cap production); while when the production rate is high (3%), the oil-gas interface migration distance increases continuously with the increase of gas cap production level (i.e., cumulative gas cap production). This is mainly because under lower production rate conditions, the oil ring pressure remains at a higher level, which can resist the expansion of the gas cap into the oil ring, thereby slowing down the migration of the oil-gas interface. This also indicates that under the condition of gas cap and oil ring co-development, it is necessary to control the oil ring production rate to slow down the migration of the oil-gas interface.

[0177] This invention establishes a material balance equation for a gas reservoir with condensate in an oil ring by comprehensively considering the effects of factors such as gas cap anti-condensation, dissolved gas in the oil ring, reservoir rock expansion, and water vapor content. Based on this equation, the migration distance of the oil-gas interface at different times under different oil-gas co-production methods is calculated using the volumetric method. Then, based on the predicted trend of the migration distance of the oil-gas interface under different oil-gas co-production operating systems, the oil-gas co-production operating system is adjusted, that is, the gas production rate of the gas cap and the oil production rate of the oil ring are adjusted. This is of great significance for preventing oil and gas cross-contamination, maintaining the stability of the oil-gas interface, and maximizing the development of gas cap and oil ring resources.

[0178] Example 3

[0179] Based on the same inventive concept, this invention also provides a device for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir, referring to... Figure 6 As shown, it includes:

[0180] The material balance equation establishment module 201 is used to establish the material balance equation for condensate gas reservoirs with oil rings; wherein, the material balance equation is established by comprehensively considering the influence of gas cap anti-condensation factors, oil ring dissolved gas factors, reservoir rock expansion factors, and water vapor content factors on the co-production process of gas cap and oil ring in condensate gas reservoirs with oil rings.

[0181] The oil and gas interface migration distance determination module 202 is used to determine the oil and gas interface migration distance at different times under different oil and gas co-production methods based on the acquired reservoir geological characteristic parameters, development dynamic data and the material balance equation.

[0182] The device for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir provided in this embodiment of the invention has a similar implementation principle and technical effect to any of the aforementioned method embodiments, and will not be repeated here.

[0183] Example 4

[0184] Based on the same inventive concept, embodiments of the present invention also provide a computer-readable storage medium storing a computer program thereon, which, when executed by a processor, implements the method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir as described in any of the foregoing method embodiments.

[0185] The computer-readable storage medium may be included in the device / apparatus described in the above embodiments; or it may exist independently and not assembled into the device / apparatus. The computer-readable storage medium carries one or more programs that, when executed, implement the method according to the embodiments of the present invention.

[0186] According to embodiments of the present invention, the computer-readable storage medium may be a non-volatile computer-readable storage medium, such as including, but not limited to: portable computer disks, hard disks, random access memory (RAM), read-only memory (ROM), erasable programmable read-only memory (EPROM or flash memory), portable compact disk read-only memory (CD-ROM), optical storage devices, magnetic storage devices, or any suitable combination thereof. In the present invention, the computer-readable storage medium may be any tangible medium containing or storing a program that can be used by or in conjunction with an instruction execution system, apparatus, or device.

[0187] Example 5

[0188] Based on the same inventive concept, embodiments of the present invention also provide an electronic device, referring to... Figure 7 The aforementioned system includes a processor 111, a communication interface 112, a memory 113, and a communication bus 114, wherein the processor 111, the communication interface 112, and the memory 113 communicate with each other via the communication bus 114.

[0189] Memory 113 is used to store computer programs;

[0190] When the processor 111 executes the program stored in the memory 113, it implements the method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir as described in any of the aforementioned method embodiments.

[0191] The electronic device provided in this embodiment of the invention has a similar implementation principle and technical effect to any of the aforementioned method embodiments, and will not be repeated here.

[0192] The aforementioned memory 113 may be an electronic memory such as flash memory, EEPROM (Electrically Erasable Programmable Read-Only Memory), EPROM, hard disk, or ROM. Memory 113 has storage space for program code used to perform any of the method steps described above. For example, the storage space for program code may include individual program codes for implementing the various steps in the methods described above. This program code can be read from or written to one or more computer program products. These computer program products include program code carriers such as hard disks, optical discs (CDs), memory cards, or floppy disks. Such computer program products are typically portable or fixed storage units. The storage unit may have storage segments or storage spaces arranged similarly to the memory 113 in the aforementioned electronic device. The program code may be compressed, for example, in a suitable form. Typically, the storage unit includes programs for performing the method steps according to embodiments of the invention, i.e., code that can be read by, for example, processor 111, which, when run by the electronic device, causes the electronic device to perform the various steps in the methods described above.

[0193] In this document, relational terms such as "first" and "second" are used merely to distinguish one entity or operation from another, without necessarily requiring or implying any such actual relationship or order between these entities or operations. Furthermore, the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such a process, method, article, or apparatus. The terms "upper," "lower," etc., indicating orientation or positional relationships based on the orientation or positional relationships shown in the accompanying drawings, are used only for the convenience of describing the invention and for simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, be constructed and operated in a specific orientation, and therefore should not be construed as limiting the invention.

[0194] The various embodiments in this specification are described in a progressive manner. Similar or identical parts between embodiments can be referred to interchangeably. Each embodiment focuses on its differences from other embodiments. It should be noted that, unless otherwise specified, the embodiments and features described in these embodiments can be combined with each other. This invention is not limited to any single aspect, nor to any single embodiment, nor to any combination and / or substitution of these aspects and / or embodiments. Each aspect and / or embodiment of this invention can be used alone, or in combination with one or more other aspects and / or other embodiments.

[0195] Finally, it should be noted that the above-described embodiments are merely specific implementations of the present invention, used to illustrate the technical solutions of the present invention, and not to limit it. The scope of protection of the present invention is not limited thereto. Although the present invention has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that any person skilled in the art can still modify or easily conceive of changes to the technical solutions described in the foregoing embodiments within the technical scope disclosed in the present invention, or make equivalent substitutions for some of the technical features; and these modifications, changes, or substitutions do not cause the essence of the corresponding technical solutions to deviate from the spirit and scope of the technical solutions of the embodiments of the present invention, and should all be covered within the scope of protection of the present invention. Therefore, the scope of protection of the present invention should be determined by the scope of the claims.

Claims

1. A method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir, characterized in that, include: The original pore volume of the gas cap is represented based on the water vapor content in the formation; the original pore volume of the oil ring is represented based on the original pore volume of the gas cap. Based on the gas cap anti-condensation parameters during the development of the condensate gas cap, the current gas cap pore volume is represented; based on the oil ring dissolved gas parameters, the current oil ring pore volume is represented; based on the reservoir rock expansion parameters, the formation rock expansion volume is represented; based on the original gas cap pore volume, the original oil ring pore volume, the current gas cap pore volume, the current oil ring pore volume, and the formation rock expansion volume, a mass balance equation is established; Based on the reservoir geological characteristics parameters, the cumulative surface crude oil production in the oil annulus and the cumulative volume of hydrocarbon well fluids produced in the gas cap at different times under different oil and gas co-production methods, the material balance equation is iteratively solved to obtain the corresponding current formation pressure. When the inner and outer edges of a condensate gas cap reservoir are distributed in a conical shape, the oil and gas interface migration distance is determined by the following formula based on the volume of hydrocarbon well fluids accumulated in the gas cap area and the current formation pressure. ； In the formula, The radius of the outer edge of the air cap region under the original conditions; The radius of the inner edge of the air cap region under the original conditions; The maximum vertical height of the outer edge profile of the air cap area under the original conditions; The maximum vertical height of the edge profile within the air cap area under the original conditions; This refers to the migration distance at the oil-gas interface. Porosity of the air cap region; The dip angle of the gas cap formation; Pressure under standard conditions; This represents the current formation pressure of the gas cap reservoir; This is the condensate gas deviation factor under the current formation pressure; The gas deviation factor of the condensate cap under the original conditions; The temperature of the gas cap reservoir; Temperature under standard conditions; The average rock compressibility coefficient of the reservoir; This represents the original natural gas reserves in the formation. This refers to the cumulative volume of hydrocarbon well fluid produced in the gas cap area. This represents the current water vapor content in the air cap. This represents the water vapor content in the air cap under the original conditions. This represents the saturation level of the condensate oil within the gas cap region. This represents the saturation of bound water within the air cap region.

2. The method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir according to claim 1, characterized in that, Establish the material balance equations for the condensate gas reservoir with an oil ring, including: ； in, This represents the original pore volume of the air cap. This represents the original pore volume of the oil ring; The current gas cap pore volume represents the gas cap pore volume under the current formation pressure. This represents the current pore volume of the oil ring region; This represents the expansion volume of the rocks within the formation, indicating the total expansion volume of the rocks within the oil and gas reservoir.

3. The method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir according to claim 2, characterized in that, The original pore volume based on the gas cap represents the original pore volume of the oil ring, including: Based on the original pore volume of the gas crown, the original pore volume of the oil ring is determined by the following formula 1; , Formula 1; In the formula, This represents the original pore volume of the oil ring; This represents the ratio of the oil ring pore volume to the gas cap pore volume under the original conditions. This represents the original pore volume of the air cap.

4. The method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir according to claim 3, characterized in that, The dissolved gas parameters based on the oil ring represent the current pore volume of the oil ring region, including: Based on the dissolved gas parameters of the oil ring, the current pore volume of the oil ring region is determined using the following formula 2: , Formula 2; In the formula, This represents the current pore volume of the oil ring region; The bound water saturation in the oil ring region; The volume factor of the oil ring oil under the original conditions; Accumulated surface crude oil production in the oil ring area; This represents the volume factor of the oil-ring oil under current conditions; This represents the current gas saturation level within the oil ring region. This represents the current increase in water saturation within the oil ring region, indicating the increase in water saturation caused by external water intrusion.

5. The method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir according to claim 4, characterized in that, The gas saturation in the current oil ring region Determined by the following formula 3: , Formula 3; In the formula, The original dissolved gas-oil ratio for oil ring oil; This represents the oil-to-oil dissolved gas-oil ratio under current conditions. The production gas-oil ratio in the oil ring region; The current volume coefficient of the gas at the top of the gas cap is given by... Seek; Pressure under standard conditions; This is the condensate gas deviation factor under the current formation pressure; The temperature of the gas cap reservoir; Temperature under standard conditions; This represents the current formation pressure of the gas cap reservoir.

6. The method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir according to claim 5, characterized in that, The current water saturation increment in the oil ring region Determined by the following formula 4: , Official 4; In the formula, For the amount of purified water, by Seek; This represents the current cumulative water intrusion volume; This represents the current cumulative water production. This is the formation water volume factor under the current formation pressure.

7. The method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir according to claim 6, characterized in that, The expansion volume of the formation rocks, based on reservoir rock expansion parameters, includes: Based on the reservoir rock expansion parameters, the expansion volume of the formation rocks is determined using the following formula 5: , Official 5; In the formula, The expansion volume of the formation rocks represents the total expansion volume of the rocks within the oil and gas reservoir. is the average rock compressibility coefficient of the reservoir.

8. The method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir according to claim 7, characterized in that, The water vapor content in the formation, representing the original pore volume of the gas cap, includes: Based on the water vapor content in the formation, the initial pore volume of the gas cap is determined using the following formula 6: , Official 6; In the formula, This represents the original pore volume of the air cap; This represents the original natural gas reserves in the formation. The volume coefficient of the gas cap gas under the original conditions is given by... Seek; This represents the water vapor content in the air cap under the original conditions. The bound water saturation level within the air cap region; Pressure under standard conditions; Temperature under standard conditions; The temperature of the gas cap reservoir; This represents the original formation pressure; This is the gas deviation factor of the condensate cap under the original conditions.

9. The method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir according to claim 8, characterized in that, The gas cap anti-condensation parameters based on the gas cap development process represent the current gas cap pore volume, including: Based on the gas cap reverse condensation parameters, the current gas cap pore volume is determined using the following formula 7: , Official 7; In the formula, The current gas cap pore volume represents the gas cap pore volume under the current formation pressure. This refers to the cumulative volume of hydrocarbon well fluid produced in the gas cap area. This represents the volume factor of the current gas at the top of the gas structure. This represents the current water vapor content in the air cap. The saturation level of the condensate oil in the gas cap region; This is the condensate gas deviation factor under the current formation pressure; This represents the current formation pressure of the gas cap reservoir.

10. The method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir according to claim 9, characterized in that, The cumulative volume of hydrocarbon well fluid produced in the gas cap area It is determined by the following formula 8: , Official 8; In the formula, Accumulated pure natural gas production for the gas cap area; The equivalent gas volume for the cumulative condensate production in the gas cap region is given by... Seek; Accumulated condensate production in the gas cap area; The density of the condensate oil; The average molecular weight of the condensate oil is given.

11. A device for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir, characterized in that, include: The material balance equation establishment module is used to represent the original pore volume of the gas cap based on the water vapor content in the formation; the original pore volume of the oil annulus based on the original pore volume of the gas cap; the current pore volume of the gas cap based on the gas cap anti-condensation parameters during the development of the condensate gas cap; the current pore volume of the oil annulus based on the dissolved gas parameters of the oil annulus; and the expansion volume of the formation rocks based on the reservoir rock expansion parameters. Based on the original pore volume of the gas cap, the original pore volume of the oil annulus, the current pore volume of the gas cap, the current pore volume of the oil annulus, and the expansion volume of the formation rocks, a material balance equation is established. The oil and gas interface migration distance determination module is used to iteratively solve the material balance equation based on reservoir geological characteristic parameters, the cumulative surface crude oil production in the oil ring area at different times under different oil and gas co-production methods, and the cumulative volume of hydrocarbon well fluids produced in the gas cap area, to obtain the corresponding current formation pressure. When the inner and outer edges of a condensate gas cap reservoir are distributed in a conical shape, the oil and gas interface migration distance is determined by the following formula based on the volume of hydrocarbon well fluids accumulated in the gas cap area and the current formation pressure. ； In the formula, The radius of the outer edge of the air cap region under the original conditions; The radius of the inner edge of the air cap region under the original conditions; The maximum vertical height of the outer edge profile of the air cap area under the original conditions; The maximum vertical height of the edge profile within the air cap area under the original conditions; This refers to the migration distance at the oil-gas interface. Porosity of the air cap region; The dip angle of the gas cap formation; Pressure under standard conditions; This represents the current formation pressure of the gas cap reservoir; This is the condensate gas deviation factor under the current formation pressure; The gas deviation factor of the condensate cap under the original conditions; The temperature of the gas cap reservoir; Temperature under standard conditions; The average rock compressibility coefficient of the reservoir; This represents the original natural gas reserves in the formation. This refers to the cumulative volume of hydrocarbon well fluid produced in the gas cap area. This represents the current water vapor content in the air cap. This represents the water vapor content in the air cap under the original conditions. This represents the saturation level of the condensate oil within the gas cap region. This represents the saturation of bound water within the air cap region.

12. A computer-readable storage medium having a computer program stored thereon, characterized in that, When executed by the processor, the program implements the method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir as described in any one of claims 1-10.

13. An electronic device, characterized in that, It includes a processor, a communication interface, a memory, and a communication bus, wherein the processor, the communication interface, and the memory communicate with each other through the communication bus; Memory, used to store computer programs; The processor, when executing a program stored in memory, implements the method for determining the migration distance of the oil-gas interface in an oil-ring condensate gas reservoir as described in any one of claims 1-10.

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