Flowing prediction method suitable for carbon dioxide flooding producing well

Abstract

The invention relates to a blowing prediction method suitable for a carbon dioxide flooding producing well, and belongs to the technical field of carbon dioxide flooding. The method comprises the following specific steps: calculating the solubility of CO2 in crude oil, and determining a gas-liquid ratio; drawing an inflow dynamic curve of the carbon dioxide flooding producing well; drawing an outflow dynamic curve of the carbon dioxide flooding producing well; predicting a formation inflow dynamic curve of carbon dioxide flooding under different formation pressures in the future; and drawing a blowing prediction curve of the carbon dioxide flooding producing well. The prediction method has a certain theoretical basis, a node system analysis method is utilized, a formation inflow dynamic curve (IPR) and a shaft oil pipe dynamic curve (TPC) are drawn according to the current formation pressure and wellhead back pressure, inflow dynamics under different formation pressures are predicted and analyzed, and therefore accurate prediction of the flowing opportunity is achieved. Compared with a statistical method, the method has higher precision and definition, is wide in application range, and has better consistency with the actual situation on site.

Description

Technical Field

[0001] The present invention relates to a method for predicting the natural flow of an oil production well suitable for carbon dioxide flooding, belonging to the technical field of carbon dioxide flooding. Background Art

[0002] As one of the effective ways to achieve the "dual carbon" goal, carbon dioxide capture, utilization and storage technology (CCUS) is widely used at home and abroad. This technology can not only greatly improve the recovery rate of low-permeability oil reservoirs, but also sequester CO 2 to achieve carbon emission reduction. At present, the carbon dioxide flooding technology in Jilin Oilfield has entered the stage of industrial promotion. The oil production wells in each test area show different effectiveness characteristics. In some blocks, the formation energy is replenished sufficiently, and the injected CO 2 gas breaks into the wellbore of the oil production well, reducing the density of the wellbore fluid and enabling the oil production well to have the ability of natural flow production. When the fluid pressure at the wellhead of the flowing oil well is higher than the mixing and transportation pressure of the ground system, it will cause the ground system to malfunction, affect the production rate of the oil production well, and pose safety risks at the same time. It is necessary to support the pressure control process for flowing oil wells to ensure the stable operation of the ground system. Therefore, accurately predicting the natural flow timing of carbon dioxide flooding oil production wells is crucial for the design of the pressure control production process of oil production wells and the safe operation of the carbon dioxide flooding wellbore-ground system during production.

[0003] Predicting the natural flow timing of carbon dioxide flooding oil production wells involves the coupled flow problems of CO 2 , oil and water three-phase formation seepage and wellbore multiphase pipe flow. During the formation seepage process, under certain conditions, CO 2 and the crude oil in the formation will reach a miscible state. With the increase of the CO 2 injection volume and injection time, it is difficult to predict the change of the bottom-hole pressure of the oil production well; during the wellbore multiphase flow, due to the temperature and pressure changes, complex phase change processes will occur to CO 2 , resulting in the difficulty of determining the pressure change in the wellbore of the oil production well; therefore, both of the above situations increase the difficulty of accurately predicting the natural flow timing of carbon dioxide flooding oil production wells. Usually, the prediction of oil well natural flow only predicts the natural flow time. The time required to reach the natural flow critical condition can be predicted according to the calculated flowing pressure or the changing trend of the measured formation static pressure, or the time required for the oil pressure to rise to the maximum bearing capacity of the ground pipeline can be determined according to the rising trend of the oil pressure. However, these methods are all empirical methods, lacking theoretical support and having large prediction errors. Summary of the Invention

[0004] In order to accurately predict the self - flowing time of oil - production wells in carbon dioxide flooding, and clarify the flow parameters such as bottom - hole flowing pressure, formation pressure and production rate during self - flowing, the present invention proposes a self - flowing prediction method applicable to oil - production wells in carbon dioxide flooding, aiming to clarify the intervention time of the well - head pressure control process, maintain the normal operation of the wellbore - surface system in carbon dioxide flooding during production, and avoid problems such as the well - head pressure being greater than the surface mixing and transportation pressure, affecting the normal production of oil - production wells and bringing safety risks. This method uses the nodal system analysis method. According to the current formation pressure and well - head back - pressure, the formation inflow performance relationship curve (IPR) and the wellbore tubing performance relationship curve (TPC) are plotted, and the inflow performance under different formation pressures is predicted and analyzed, so as to accurately predict the self - flowing time.

[0005] The technical solution adopted by the present invention is: a self - flowing prediction method applicable to oil - production wells in carbon dioxide flooding, and the specific steps are as follows:

[0006] Step 1: Calculate the solubility of CO 2 in crude oil and determine the gas - liquid ratio;

[0007] Step 2: Plot the formation inflow performance relationship curve of the oil - production well in carbon dioxide flooding;

[0008] Step 3: Plot the wellbore outflow performance relationship curve of the oil - production well in carbon dioxide flooding;

[0009] Step 4: Predict the formation inflow performance relationship curve under different future formation pressures in carbon dioxide flooding;

[0010] Step 5: Plot the self - flowing prediction curve of the oil - production well in carbon dioxide flooding.

[0011] Further, the specific content of Step 1 is that by measuring the solubility of CO 2 in liquid paraffin - based oil and its influencing factors, and through the correlation regression of pressure and temperature among the influencing factors, the calculation method of the solubility of CO 2 in crude oil is obtained, and it is calculated by formula 1:

[0012]

[0013] In formula 1, S is the solubility of CO 2 in crude oil, with the unit of kmol / m 3 ; P is the pressure under the corresponding conditions, with the unit of MPa; T is the temperature under the corresponding conditions, with the unit of °C; R is the ideal gas constant, with the unit of J / (mol·K);

[0014] Assume that the production gas - liquid ratio under standard surface conditions is GLR 0 , and the produced gas is CO 2 , then the gas - liquid ratio under different working conditions can be calculated by formula 2:

[0015]

[0016] In Equation 2, P 0 is the atmospheric pressure under standard conditions, with the unit of MPa; P is the pressure under corresponding conditions, with the unit of MPa; T 0 is the temperature under standard conditions, with the unit of °C; T is the temperature under corresponding conditions, with the unit of °C; Z is the CO 2 deviation factor.

[0017] Furthermore, the specific content of Step 2 is that in the middle and late production stages of the carbon dioxide flooding oil production well, the bottom-hole flowing pressure is less than the oil saturation pressure. Therefore, the flow in the formation is a three-phase flow of CO 2 , crude oil, and water;

[0018] When the oil production well is a vertical well, the liquid production rate is calculated by Equation 3;

[0019]

[0020] In Equation 3, q o is the oil well production rate, with the unit of m 3 / d; J o is the liquid production index, with the unit of m 3 / (d·MPa); p r is the average formation pressure, with the unit of MPa; p wf is the bottom-hole flowing pressure, with the unit of MPa; p b is the oil saturation pressure, with the unit of MPa;

[0021] When the oil production well is a horizontal well, the liquid production rate is calculated by Equation 4;

[0022]

[0023] In Equation 4, q o is the oil well production rate, with the unit of m 3 / d; J oh is the liquid production index of the horizontal well, m 3 / (d·MPa); p r is the average formation pressure, with the unit of MPa; p wf is the bottom-hole flowing pressure, with the unit of MPa; p b is the oil saturation pressure, with the unit of MPa;

[0024] According to the different bottom-hole flowing pressures and the calculated liquid production rates, the inflow performance curve can be plotted on the bottom-hole flowing pressure - liquid production rate coordinate axis;

[0025] When the bottom-hole flowing pressure is 0, the open flow rate q omax of the oil well corresponding to the formation pressure of the reference inflow performance curve can be calculated.

[0026] Further, Step 3 specifically involves collecting the pipeline transportation pressure, surface temperature, surface gas-liquid ratio, water cut, tubing size, and well depth parameters of the oil well, and combining with the solubility of CO in crude oil in Step 1, and adopting an iterative method to calculate the wellbore pressure drop; including the following steps: 2

[0027] S3.1: Divide the liquid production volume into N parts, and respectively make them equal to q omax ; Segment the wellbore according to the well depth, and divide the number of iterative segments into N I ;

[0028] S3.2: Give a liquid production volume in ascending order according to the liquid production volume in Step S3.1;

[0029] S3.3: Give boundary conditions: wellhead condition p i0 = p t , wherein, p i0 is the initial wellhead pressure, with the unit of MPa; p t is the wellhead oil pressure, with the unit of MPa; g is the gravitational acceleration, with the unit of m / s 2 ; ρ g is the gas density, with the unit of kg / m 3 ;

[0030] S3.4: Calculate p i (j = 1): j is the well section number, and i is the number of iterations;

[0031] S3.5: Let p = 0.5[p i-1 + p i (j)];

[0032] The apparent gas flow velocity v sg is calculated by Formula 5;

[0033]

[0034] In Formula 5, B g is the gas volume coefficient; A is the tubing area, with the unit of m 2 ; Q g is the gas production;

[0035] Calculate the true liquid flow velocity v sl of the wellbore using the p value, and calculate it by Formula 6;

[0036]

[0037] In Formula 6, Q g is the gas production volume, with the unit of m 3 ​ / d; v sl is the liquid-phase flow rate, in m / s; f w is the water cut, in %; GLR is the gas-liquid ratio; B oc is the oil-phase volume coefficient; C Bo is the oil-phase compressibility;

[0038] Calculate d using the p value p / d z (j + 1), d p / d z (j + 1) value is calculated by Equation 7;

[0039]

[0040] In Equation 7, p is the pressure, in Pa; θ is the well deviation angle (the angle between the well axis and the horizontal direction); v m is the two-phase mixture flow rate, in m / s; D is the inner diameter of the tubing, in m; f m is the two-phase friction factor; ρ m is the average density of the gas-liquid mixture at any cross-section Z; among them, the two-phase friction factor f m is calculated by the Mukherjee-Brill model method;

[0041] The average density ρ of the gas-liquid mixture m is calculated by Equation 8;

[0042] ρ m = ρ l H L + ρ g (1 - H L ) (8)

[0043] In Equation 8, ρ g is the gas density, in kg / m 3 ; ρ l is the liquid density, in kg / m 3 ; H L is the liquid holdup, calculated by Equation 9 established by fitting experimental data;

[0044]

[0045] In Equation 9, c 1 = -1.089, c 2 = 1.319, c 3 = -0.961, c 4 = 0.362, c 5 = 0.061; σ is the gas-water interfacial tension, N / m;

[0046] S3.6: Calculate p i (j + 1):

[0047] S3.7: Judge convergence: If |p i (j + 1) - p i (j)| / p i (j + 1) > ε, then let p i (j) = p i (j + 1), and repeat steps S3.5 - S3.7; otherwise let p i+1 = p i (j + 1), i = i + 1, and repeat steps S3.4 - S3.7 until i = N I , and obtain the bottom - hole pressure p wf ;

[0048] S3.8: Change the liquid production rate according to the requirements of step S3.2, and repeat steps S3.2 - S3.8.

[0049] Furthermore, the ε = 0.001.

[0050] Furthermore, the specific content of step four is as follows:

[0051] (1) The future liquid - production index is calculated by formula 10;

[0052] J f = J p (μ o B o ) f / (μ o B o ) p (10)

[0053] In formula 10, J f is the liquid - production index under the future formation pressure, with the unit of m 3 / (d·MPa); J p is the liquid - production index under the current formation pressure, with the unit of m 3 / (d·MPa); μ o is the crude - oil viscosity, with the unit of mPa·s; B o is the crude - oil volume factor.

[0054] (2) When the formation pressure is lower than the bubble - point pressure, the relationship of the open - flow potential is calculated by formula 11;

[0055] q omaxF = q omaxb (p rF / p rb ) 3 (11)

[0056] In Formula 11, q omaxF is the absolute open flow corresponding to the formation pressure p rF with the unit of m 3 / d; q omaxb is the absolute open flow corresponding to the formation pressure p rb with the unit of m 3 / d; p rb is the bubble point pressure with the unit of MPa; p rF is the future formation pressure with the unit of MPa;

[0057] (3) According to the above-mentioned J f and q omaxF results obtained, the inflow performance relationship curve under the predicted future formation pressure conditions can be obtained.

[0058] Further, the specific content of Step Five is to read the liquid production rate and bottom-hole flowing pressure at the intersection of the inflow performance and the outflow performance under different formation pressure conditions. If there is no intersection, it indicates that the liquid production rate is 0, and at this time, the oil well has not reached the condition of flowing by itself; if there is an intersection, the formation pressure, bottom-hole flowing pressure, and liquid production rate data corresponding to the last intersection point are the corresponding parameters for flowing by itself, and the condition of flowing by itself for the carbon dioxide flooding oil well is achieved.

[0059] The present invention discloses a method for predicting the flowing by itself of a carbon dioxide flooding oil well. The beneficial effect is that compared with the prior art, this prediction method has a certain theoretical basis. By using the nodal system analysis method, according to the current formation pressure and wellhead back pressure, the formation inflow performance relationship curve (IPR) and the wellbore tubing performance relationship curve (TPC) are drawn, and the inflow performance under different formation pressures is predicted and analyzed, so as to accurately predict the timing of flowing by itself. It has higher accuracy and clarity compared with the statistical method, has a wide range of applications, and has good consistency with the actual field situation. BRIEF DESCRIPTION OF THE DRAWINGS

[0060] In order to more clearly illustrate the technical solutions in the embodiments of the present invention or the prior art, the following will briefly introduce the drawings required for the description of the embodiments or the prior art. Obviously, the following-described drawings are some embodiments of the present invention. For those of ordinary skill in the art, other drawings can be obtained based on these drawings without creative efforts.

[0061] Figure 1 The following shows the schematic diagram of the wellbore flow comparison before and after the effectiveness of CO 2 flooding;

[0062] Figure 2 The following shows the schematic diagram of the current IPR curve change after the effectiveness of CO 2 flooding.

[0063] SPECIFIC IMPLEMENTATION METHOD

[0064] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings in the embodiments of the present invention. Obviously, the described embodiments are only a part rather than all of the embodiments of the present invention.

[0065] The following description of at least one exemplary embodiment is merely illustrative in nature and in no way serves as a limitation to the present invention, its application, or its use. All other embodiments obtained by those of ordinary skill in the art based on the embodiments of the present invention without creative efforts shall fall within the scope of protection of the present invention. Embodiment 1

[0066] This embodiment provides a method for predicting the natural flow of oil wells suitable for carbon dioxide flooding, and the specific steps are as follows:

[0067] Step 1: Calculate the solubility of CO 2 in crude oil and determine the gas-liquid ratio;

[0068] The specific operation of Step 1 is to measure the solubility of CO 2 in liquid paraffin-based oil and its influencing factors, and through the correlation regression of pressure and temperature among the influencing factors, obtain the calculation method of the solubility of CO 2 in crude oil, which is calculated by Formula 1:

[0069]

[0070] In Formula 1, S is the solubility of CO 2 in crude oil, with the unit of kmol / m 3 ; P is the pressure under the corresponding conditions, with the unit of MPa; T is the temperature under the corresponding conditions, with the unit of °C; R is the ideal gas constant, with the unit of J / (mol·K);

[0071] Let the production gas-liquid ratio under standard surface conditions be GLR 0 , and the produced gas is CO 2 , then the gas-liquid ratio under different working conditions can be calculated by Formula 2:

[0072]

[0073] In Formula 2, P 0 is the atmospheric pressure under standard conditions, with the unit of MPa; P is the pressure under the corresponding conditions, with the unit of MPa; T 0 is the temperature under standard conditions, with the unit of °C; T is the temperature under the corresponding conditions, with the unit of °C; Z is the CO 2 deviation factor.

[0074] Step 2: Plot the inflow performance relationship (IPR) curve of the oil well in CO2 flooding

[0075] As Figure 1 shown, in Step 2, the bottom-hole flowing pressure of the oil well in the middle and late stages of CO2 flooding is less than the saturation pressure of the crude oil. Therefore, the flow in the formation is three-phase flow of CO 2 , crude oil, and water;

[0076] When the oil well is a vertical well, the liquid production rate is calculated by Equation 3;

[0077]

[0078] In Equation 3, q o is the oil well production rate, with the unit of m 3 / d; J o is the liquid production index, with the unit of m 3 / (d·MPa); p r is the average formation pressure, with the unit of MPa; p wf is the bottom-hole flowing pressure, with the unit of MPa; p b is the saturation pressure of the crude oil, with the unit of MPa;

[0079] When the oil well is a horizontal well, the liquid production rate is calculated by Equation 4;

[0080]

[0081] In Equation 4, q o is the oil well production rate, with the unit of m 3 / d; J oh is the liquid production index of the horizontal well, m 3 / (d·MPa); p r is the average formation pressure, with the unit of MPa; p wf is the bottom-hole flowing pressure, with the unit of MPa; p b is the saturation pressure of the crude oil, with the unit of MPa;

[0082] According to different bottom-hole flowing pressures and the calculated liquid production rates, the inflow performance relationship curve can be plotted on the bottom-hole flowing pressure - liquid production rate coordinate axis;

[0083] When the bottom-hole flowing pressure is 0, the open flow potential q omax of the oil well corresponding to the formation pressure of the reference inflow performance relationship curve can be calculated. q omax refers to the situation where when the bottom-hole pressure is 0, there is no resistance to inflow, and the production rate reaches the maximum. At this time, the production rate is called the absolute open flow potential, which is the maximum production rate that this well can obtain.

[0084] The inflow performance relationship of the oil well refers to the relationship between the liquid production rate of the oil well and the bottom-hole flowing pressure under a certain formation pressure, abbreviated as IPR.

[0085] Step 3: Plot the outflow dynamic curve of the carbon dioxide flooding production well;

[0086] The specific content of the above Step 3 is to collect the pipeline transportation pressure, surface temperature, surface gas-liquid ratio, water cut, tubing size and well depth parameters of the production well, and combine with the solubility of CO in crude oil in Step 1 to calculate the wellbore pressure drop by using the iterative method; The wellbore pressure calculation needs to adopt the micro-element method, divide the several-kilometer wellbore into several small sections, and solve them iteratively in turn. Therefore, before solving, it is necessary to divide the entire well section into iterative segments, including the following steps: 2 In the solubility of CO in crude oil, the iterative method is adopted to calculate the wellbore pressure drop; The wellbore pressure calculation needs to adopt the micro-element method, divide the several-kilometer wellbore into several small sections, and solve them iteratively in turn. Therefore, before solving, it is necessary to divide the entire well section into iterative segments, including the following steps:

[0087] S3.1: Divide the liquid production rate into N parts, and respectively make them equal to q omax ; Divide the wellbore into sections according to the well depth, and divide the number of iterative segments N I ;

[0088] S3.2: Give a liquid production rate in ascending order of the liquid production rate in Step S3.1;

[0089] S3.3: Give the boundary conditions: wellhead condition p i0 = p t , wherein, p i0 is the initial wellhead pressure, with the unit of MPa; p t is the wellhead oil pressure, with the unit of MPa; g is the gravitational acceleration, with the unit of m / s 2 ; ρ g is the gas density, with the unit of kg / m 3 ;

[0090] S3.4: Calculate p i (j = 1): j is the number of well sections, and i is the number of iterations;

[0091] S3.5: Let p = 0.5[p i-1 + p i (j)];

[0092] The apparent gas flow velocity v sg is calculated by formula 5;

[0093]

[0094] In formula 5, B g is the gas volume coefficient; A is the tubing area, with the unit of m 2 ; Q g is the gas production;

[0095] Calculate the true liquid flow velocity v of the wellbore by using the p value sl, calculated by Equation 6;

[0096]

[0097] In Equation 6, Q g is the gas production rate, with the unit of m 3 / d; v sl is the liquid-phase flow velocity, with the unit of m / s; f w is the water cut, with the unit of %; GLR is the gas-liquid ratio; B oc is the oil-phase volume factor; C Bo is the oil-phase compressibility;

[0098] Calculate d / d p (j + 1) using the p value. The d / d z (j + 1) value is calculated by Equation 7; p d / d z (j + 1)

[0099]

[0100] In Equation 7, p is the pressure, with the unit of Pa; θ is the well deviation angle (the angle between the well axis and the horizontal direction); v m is the two-phase mixture flow velocity, with the unit of m / s; D is the inner diameter of the tubing, with the unit of m; f m is the two-phase friction factor; ρ m is the average density of the gas-liquid mixture at any cross-section Z. Among them, the two-phase friction factor f m is calculated by the Mukherjee-Brill model method;

[0101] The average density ρ of the gas-liquid mixture m is calculated by Equation 8;

[0102] ρ m = ρ l H L + ρ g (1 - H L ) (8)

[0103] In Equation 8, ρ g is the gas density, with the unit of kg / m 3 ; ρ l is the liquid density, with the unit of kg / m 3 ; H L is the liquid holdup, calculated by Equation 9 established by fitting based on experimental data;

[0104]

[0105] In Equation 9, c 1 = -1.089, c 2 = 1.319, c3 = -0.961, c 4 = 0.362, c 5 = 0.061; σ is the gas-water interfacial tension, N / m;

[0106] S3.6: Calculate p i (j + 1):

[0107] S3.7: Judge convergence: If |p i (j + 1) - p i (j)| / p i (j + 1) > ε, then let p i (j) = p i (j + 1), and repeat steps S3.5 - S3.7; otherwise let p i+1 = p i (j + 1), i = i + 1, repeat steps S3.4 - S3.7 until i = N I , and obtain the bottom-hole pressure p wf under the given liquid production rate; ε = 0.001

[0108] S3.8: Change the liquid production rate according to the requirements of step S3.2, and repeat steps S3.2 - S3.8.

[0109] Step Four: Predict the formation inflow performance curves at different future formation pressures for CO2 flooding;

[0110] The specific steps of the above-mentioned Step Four are as follows:

[0111] (1) As Figure 2 shown, different from conventional depletion-type production, in the CO2 flooding block, as the injection time and injection volume increase, the reservoir pressure will be replenished to a certain extent and thus increase. Given a series of formation pressures pr1, pr2,... prM, when the formation pressure is higher than the bubble point pressure, the corresponding relationship between the future liquid production index and the liquid production index of the reference inflow performance curve can be determined, and the future liquid production index is calculated by formula 10;

[0112] J f = J p (μ o B o ) f / (μ o B o ) p (10)

[0113] In formula 10, J f is the liquid production index under the future formation pressure, with the unit of m 3 / (d·MPa); J pis the liquid production index at the current formation pressure, with the unit of m 3 / (d·MPa); μ o is the crude oil viscosity, with the unit of mPa·s; B o is the crude oil volume factor.

[0114] (2) When the formation pressure is lower than the bubble point pressure, the corresponding relationship of the open flow potential is calculated by Formula 11;

[0115] q omaxF = q omaxb (p rF / p rb ) 3 (11)

[0116] In Formula 11, q omaxF is the open flow potential corresponding to the formation pressure p rF , with the unit of m 3 / d; q omaxb is the open flow potential corresponding to the formation pressure p rb , with the unit of m 3 / d; p rb is the bubble point pressure, with the unit of MPa; p rF is the future formation pressure, with the unit of MPa;

[0117] According to the above results of J f and q omaxF , the inflow performance relationship curve under the predicted future formation pressure conditions can be obtained.

[0118] Step Five: Plot the self-flow prediction curve of the carbon dioxide flooding production well.

[0119] As Figure 2 shown, the specific content of Step Five is to read the liquid production rate and bottom-hole flowing pressure at the intersection of the inflow performance and the outflow performance under different formation pressure conditions. If they do not intersect, it indicates that the liquid production rate is 0, that is, the solid IPR curve and the TPC curve do not intersect, and at this time, the oil well has not reached the self-flow condition; with the increase of the injection time and injection volume in the carbon dioxide flooding block, the reservoir pressure will be replenished and increased to a certain extent. Given a series of formation pressures pr1, pr2,... prM, make the dotted IPR curve intersect with the TPC curve. Finally, the formation pressure, bottom-hole flowing pressure, and liquid production rate data corresponding to the intersection point are the self-flow corresponding parameters, that is, the intersection of the dotted IPR curve and the TPC curve reaches the self-flow condition of the carbon dioxide flooding production well.

[0120] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of the present invention, rather than to limit them; although the present invention has been described in detail with reference to the foregoing embodiments, those of ordinary skill in the art should understand that they can still modify the technical solutions described in the foregoing embodiments, or perform equivalent replacements on some or all of the technical features; and these modifications or replacements do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of the embodiments of the present invention.

Claims

1. A method for predicting the natural flow of oil production wells suitable for carbon dioxide flooding, characterized in that, it includes the following steps: Step 1: Calculate the solubility of CO 2 in crude oil and determine the gas-liquid ratio; Step two: Plot the inflow performance curve of the carbon dioxide flooding oil production well; Step three: Plot the outflow performance curve of the carbon dioxide flooding oil production well; Step four: Predict the formation inflow performance curve under different formation pressures in the future for carbon dioxide flooding; Step five: Plot the prediction curve for the natural flow of the carbon dioxide flooding oil production well.

2. The method for predicting the natural flow of oil production wells suitable for carbon dioxide flooding according to claim 1, characterized in that, Step 1 specifically involves measuring the solubility of CO 2 in liquid paraffin-based oil and its influencing factors, and through the correlation regression of pressure and temperature among the influencing factors, a calculation method for the solubility of CO 2 in crude oil is obtained and calculated by Equation 1: In Equation 1, S is the solubility of CO 2 in crude oil, with the unit of kmol / m 3 ; P is the pressure under corresponding conditions, with the unit of MPa; T is the temperature under corresponding conditions, with the unit of °C; R is the ideal gas constant, with the unit of J / (mol·K); Let the production gas-liquid ratio under surface standard conditions be GLR 0 , and the produced gas is CO 2 . Then the gas-liquid ratio under different working conditions can be calculated by Equation 2: In Equation 2, P 0 is the atmospheric pressure under standard conditions, with the unit of MPa; P is the pressure under corresponding conditions, with the unit of MPa; T 0 is the temperature under standard conditions, with the unit of °C; T is the temperature under corresponding conditions, with the unit of °C; Z is the CO 2 deviation factor.

3. The method for predicting the natural flow of oil production wells suitable for carbon dioxide flooding according to claim 2, characterized in that, Step 2 specifically refers to the fact that during the middle and late production stages of a carbon dioxide flooding oil production well, the bottom-hole flowing pressure is less than the crude oil saturation pressure. Therefore, the flow in the formation is a three-phase flow of CO 2 , crude oil, and water; When the oil production well is a vertical well, the liquid production is calculated by formula 3; In Equation 3, q o is the oil well production rate, with the unit of m 3 / d; J o is the liquid production index, with the unit of m 3 / (d·MPa); p r is the average formation pressure, with the unit of MPa; p wf is the bottom-hole flowing pressure, with the unit of MPa; p b is the oil saturation pressure, with the unit of MPa; When the oil production well is a horizontal well, the liquid production is calculated by formula 4; In Equation 4, q o is the oil well production rate, with the unit of m 3 / d; J oh is the liquid production index of the horizontal well, m 3 / (d·MPa); p r is the average formation pressure, with the unit of MPa; p wf is the bottom hole flowing pressure, with the unit of MPa; p b is the oil saturation pressure, with the unit of MPa; According to different bottom hole flowing pressures and the calculated liquid production, the inflow performance curve can be plotted on the bottom hole flowing pressure - liquid production coordinate axis; When the bottom-hole flowing pressure is 0, the open-flow potential q of the well corresponding to the formation pressure of the reference inflow performance curve can be calculated omax .

4. The method for predicting the natural flow of oil production wells suitable for carbon dioxide flooding according to claim 3, characterized in that, Step 3 specifically involves collecting the pipeline transportation pressure, surface temperature, surface gas-liquid ratio, water cut, tubing size, and well depth parameters of the oil well, and combining with the solubility of CO 2 in crude oil, and adopting an iterative method to calculate the wellbore pressure drop; it includes the following steps: S3.1: Divide the liquid production volume into N parts, and respectively make them equal to q omax ; Segment the wellbore according to the well depth, and divide the number of iterative segments into N I ; S3.2: Give a liquid production in ascending order according to the liquid production in step S3.1; S3.3: Given boundary conditions: wellhead condition p i0 = p t , where p i0 is the initial wellhead pressure, in MPa; p t is the wellhead oil pressure, in MPa; g is the acceleration due to gravity, in m / s 2 ; ρ g is the gas density, in kg / m 3 ; S3.4: Calculate p i (j = 1): j is the number of well sections, and i is the number of iterations; S3.5: Let p = 0.5[p i-1 + p i (j)]; Apparent air velocity v sg Calculated by Equation 5; In Equation 5, B g is the gas volume coefficient; A is the tubing cross-sectional area in m 2 ; Q g is the gas production rate; Calculate the true fluid velocity v in the wellbore using the p-value sl , calculated by Equation 6; In Equation 6, Q g is the gas production rate, with the unit of m 3 / d; v sl is the liquid phase flow velocity, with the unit of m / s; f w is the water cut, with the unit of %; GLR is the gas-liquid ratio; B oc is the oil phase volume factor; C Bo is the oil phase compressibility; Calculate d using the p-value p / d z (j + 1), d p / d z (j + 1) value is calculated by Equation 7; In Equation 7, p is the pressure in Pa; θ is the well deviation angle (the angle between the well axis and the horizontal direction); v m is the two-phase mixture flow velocity in m / s; D is the inner diameter of the tubing in m; f m is the two-phase friction factor; ρ m is the average density of the gas-liquid mixture at any cross-section Z; among them, the two-phase friction factor f m is calculated by the Mukherjee-Brill model method; Average density ρ of gas-liquid mixture m Calculated by Equation 8; ρ m = ρ l H L + ρ g (1 - H L )(8) In Equation 8, ρ g is the gas density, with the unit of kg / m 3 ; ρ l is the liquid density, with the unit of kg / m 3 ; H L is the liquid holdup, which is calculated by Equation 9 established by fitting based on experimental data; In Equation 9, c 1 = -1.089, c 2 = 1.319, c 3 = -0.961, c 4 = 0.362, c 5 = 0.061; σ is the gas-water interfacial tension, N / m; S3.6: Calculate p i (j + 1): S3.7: Determine convergence: If ∣p i (j + 1) - p i (j)∣ / p i (j + 1)> ε, then let p i (j) = p i (j + 1), and repeat steps S3.5 - S3.7; otherwise let p i+1 = p i (j + 1), i = i + 1, and repeat steps S3.4 - S3.7 until i = N I , to obtain the bottom - hole pressure p wf ; S3.8: Change the liquid production according to the requirements of step S3.2, and repeat steps S3.2 - S3.

8.

5. The method for predicting the natural flow of oil production wells suitable for carbon dioxide flooding according to claim 4, characterized in that, ε = 0.

001.

6. The method for predicting the natural flow of oil production wells suitable for carbon dioxide flooding according to claim 4, characterized in that, Step four is specifically as follows: (1) The future liquid production index is calculated by formula 10; J f = J p (μ o B o ) f / (μ o B o ) p (10) In Equation 10, J f is the liquid production index under future formation pressure, with the unit of m 3 / (d·MPa); J p is the liquid production index under current formation pressure, with the unit of m 3 / (d·MPa); μ o is the crude oil viscosity, with the unit of mPa·s; B o is the crude oil volume factor. (2) When the formation pressure is lower than the bubble point pressure, the corresponding relationship of the open flow potential is calculated by formula 11; q omaxF = q omaxb (p rF / p rb ) 3 (11) In Equation 11, q omaxF is the open flow potential corresponding to the formation pressure p rF , with the unit of m 3 / d; q omaxb is the open flow potential corresponding to the formation pressure p rb , with the unit of m 3 / d; p rb is the bubble point pressure, with the unit of MPa; p rF is the future formation pressure, with the unit of MPa; According to the above J f and q omaxF Based on the obtained results, the inflow performance curve under future formation pressure conditions can be obtained.

7. The method for predicting the natural flow of oil production wells suitable for carbon dioxide flooding according to claim 6, characterized in that, Step five is specifically to read the liquid production and bottom hole flowing pressure at the intersection of the inflow performance and the outflow performance under different formation pressure conditions. If they do not intersect, it indicates that the liquid production is 0, and at this time, the oil well has not reached the condition of natural flow; If they intersect, the formation pressure, bottom hole flowing pressure, and liquid production data corresponding to the last intersection point are the corresponding parameters for natural flow, and the condition of natural flow of the carbon dioxide flooding oil production well is reached.

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