Continental facies high thermal evolution region condensate gas reservoir shaft liquid accumulation judgment method

Abstract

The invention relates to a continental facies high thermal evolution zone condensate gas reservoir wellbore liquid accumulation judgment method, and belongs to the technical field of oil and gas reservoir exploration and development. Temperature during oil and gas interface tension calculation is limited, different conditions are divided, corresponding interface tension of a gas-liquid mixture is obtained through calculation according to the oil and gas interface tension, and the oil and gas interface tension is determined. According to the method, the critical fluid-carrying flow is obtained by substituting the critical fluid-carrying flow into a Lie Fujian model or a Wangyi Zhongzhong model for calculation, shaft fluid accumulation judgment is finally carried out according to the calculated critical fluid-carrying flow, and the calculation result of the oil-gas interfacial tension is more accurate by limiting the temperature, so that the judgment of the shaft fluid accumulation of the gas reservoir is more accurate.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and gas reservoir exploration and development, and in particular relates to a method for judging liquid accumulation in a wellbore of a condensate gas reservoir in a continental high-thermal evolution zone. Background Art

[0002] Liquid accumulation in the wellbore is a major problem faced in the later stage of condensate gas reservoir production. As the bottom hole pressure decreases, condensate oil or formation water is produced, and these liquids can be carried to the wellhead by high-speed airflow. However, when the flow rate of the airflow in the wellbore is not enough to carry the liquid droplets to the wellhead, it may cause liquid accumulation in the wellbore of the gas well. If the liquid accumulation in the wellbore cannot be discharged in time, it will cause the gas well to stop flowing and cannot be produced in serious cases. Therefore, when allocating gas well production, it is necessary to consider the problem of liquid carrying in the gas well and improve the gas well's liquid discharge capacity.

[0003] The critical liquid-carrying flow rate is an important indicator for judging whether a gas well has a risk of liquid accumulation. When the gas production of a gas well is lower than the critical liquid-carrying flow rate, stirring flow or slugging flow occurs in the wellbore, and liquid gradually accumulates at the bottom of the well until it is flooded and production stops. There are three main methods for judging liquid accumulation in gas wells in the prior art: ① a direct judgment method based on well site testing, which mainly focuses on gas well pressure gradient testing. However, this method requires testing by opening and closing wells, which affects the normal production of gas wells and has a high testing cost. ② an empirical judgment method based on field production data analysis, which mainly judges whether a gas well is liquid-accumulated by analyzing abnormal fluctuations in gas well production, wellhead oil-casing pressure difference, calculation of condensate volume, and abnormal changes in well test curves. However, the changes in these field data are usually affected by multiple factors and cannot accurately judge the liquid accumulation in gas wells. ③ a critical liquid-carrying flow rate model based on a droplet (film) model, which mainly considers the critical liquid-carrying flow rate calculation model under conditions such as droplet deformation, interfacial tension, critical slip density, and wellbore variable flow rate. However, these models do not consider the changes in actual interfacial tension and natural gas deviation factor with wellbore pressure and temperature, resulting in a certain deviation between the judgment results used in the field and the actual state of the wellbore of the condensate gas reservoir.

[0004] Therefore, in the process of using existing technical methods to judge the situation of liquid accumulation in gas reservoir wellbores, there are defects such as high testing cost, strong artificial experience in the judgment results, incomplete consideration of interference factors, inaccuracy, and large deviation between the results and the actual values, which in turn affects the accurate judgment of liquid accumulation in gas reservoir wellbores and brings obstacles to the rational and efficient development of such gas reservoirs. Summary of the invention

[0005] The purpose of the present invention is to provide a method for judging liquid accumulation in a condensate gas reservoir wellbore in a continental high thermal evolution zone, so as to solve the problem that the results are not accurate enough in the process of judging the liquid accumulation in the gas reservoir wellbore.

[0006] In order to solve the above technical problems, the present invention provides a method for judging liquid loading in a wellbore of a condensate gas reservoir in a continental high thermal evolution zone, the method comprising the following steps:

[0007] 1) Calculate the oil-gas interfacial tension of the target gas well as follows: If the current wellhead temperature T is greater than or equal to the first temperature T1, the interfacial tension σ corresponding to T1 is calculated as T1 As the phase interface tension corresponding to the current wellhead temperature, if the current wellhead temperature T is less than or equal to the second temperature T2, the phase interface tension σ corresponding to T2 is T2 As the interfacial tension corresponding to the current wellhead temperature, where T1<T2, if T1<T<T2, then according to σ T1 , σ T2 , the interfacial tension within the range of T1 and T2 is interpolated to obtain the interfacial tension σ corresponding to T T ; The obtained interfacial tension is multiplied by the correction coefficient C to obtain the oil-gas interfacial tension, wherein the correction coefficient C is calculated according to the current wellhead pressure; and then the interfacial tension of the corresponding gas-liquid mixture is calculated according to the oil-gas interfacial tension;

[0008] 2) Substitute the interfacial tension of the gas-liquid mixture into the Li Min model or Wang Yizhong model to calculate and obtain the critical liquid carrying flow rate;

[0009] 3) Determine the amount of liquid accumulation in the wellbore based on the calculated critical liquid carrying rate.

[0010] The beneficial effects of the above technical solution are: using the oil-gas interfacial tension considering different temperature conditions to calculate the interfacial tension of the gas-liquid mixture, so that the obtained interfacial tension of the gas-liquid mixture is more accurate, and using the interfacial tension of the gas-liquid mixture to correct the Li Min-Wang Yizhong model can effectively improve the accuracy of the model, so that the method of judging wellbore liquid accumulation by critical liquid carrying production can be optimized.

[0011] Further, the first temperature T1 is 68°F, and the second temperature T2 is 100°F.

[0012] The beneficial effect of the above technical solution is: when the first temperature T1 is 68°F and the second temperature T2 is 100°F, the temperatures are specifically limited, making the calculation result of the oil-gas interfacial tension more accurate.

[0013] Furthermore, the interfacial tension σ corresponding to the first temperature T1 is 68 , and the interfacial tension σ corresponding to the second temperature T2 100 The specific calculation formula is as follows:

[0014] σ 68 =39-0.2571(API)

[0015] σ100 =37.5-0.2571(API)

[0016] API = (141.5 / γ o )-131.5

[0017] Where: API is heavy; γ o is the relative density of the oil phase.

[0018] The beneficial effect of the above technical solution is: when the first temperature T1 is 68°F and the second temperature T2 is 100°F, the corresponding interfacial tension is calculated, making the calculation result of the oil-gas interfacial tension more accurate.

[0019] Furthermore, the specific calculation formula of the linear interpolation phase interface tension at the intermediate temperature is as follows:

[0020]

[0021] Where: T is the linear interpolation interfacial tension at the intermediate temperature; T is the intermediate temperature; σ 68 is the interfacial tension at a temperature of 68°F; 100 is the interfacial tension of the lower phase at a temperature of 100°F.

[0022] The beneficial effect of the above technical solution is that the phase interface tension at the intermediate temperature is calculated by linear interpolation, so that the calculation result of the oil-gas interface tension is more accurate.

[0023] Furthermore, the specific calculation formula of the correction coefficient is as follows:

[0024] C=1.0-0.024p 0.45

[0025] Where: C is the correction coefficient; p is the wellhead pressure.

[0026] The beneficial effect of the above technical solution is: the correction coefficient is obtained by performing relevant calculation correction on the wellhead pressure, so that the calculation result of the oil-gas interface tension is more accurate.

[0027] Furthermore, the parameters substituted into the Li Min model or the Wang Yizhong model for calculation also include a natural gas deviation factor, and the formula of the natural gas deviation factor is:

[0028] M=∑x j M j

[0029] γ g =M / Ma=M / 28.96413

[0030] T pc =171(γ g -0.5)+182

[0031] T r =(T+273) / T pc

[0032] P pc =[46.7-32.1(γ g -0.5)]×0.09869

[0033] P r =P / P pc

[0034]

[0035] a=1.39(T r -0.92) 0.5 -0.36T r -0.101

[0036]

[0037] c=0.132-0.32logT pr

[0038] d = exp(0.7153-1.1285T r +0.4201T r 2 )

[0039] Where: T r is the simulated temperature of natural gas; p r is the quasi-comparison pressure; Z is the natural gas deviation factor; M is the kilomolar mass of natural gas; x j is the mole fraction of the jth component; M j The kilomolar mass of the component in the jth; γ g is the relative density of natural gas; Ma is the average kmol mass of air, measured in the laboratory, Ma = 28.96413 kg / kmol; T pc is the pseudo-critical temperature of natural gas; P pc is the pseudo-critical pressure of natural gas; P r is the simulated comparative pressure of natural gas; P is the wellhead pressure; T is the wellhead temperature; a, b, c, d are intermediate parameters.

[0040] The beneficial effect of the above technical solution is that the natural gas deviation factor is calculated to make the calculation result of the critical liquid carrying capacity more accurate.

[0041] Furthermore, the parameters substituted into the Li Min model or the Wang Yizhong model for calculation also include a natural gas deviation factor, and the calculation method of the natural gas deviation factor also includes a DAK method, and the calculation formula is:

[0042] M=∑x j M j

[0043] γ g =M / Ma=M / 28.96413

[0044] T pc =171(γ g -0.5)+182

[0045] T r =(T+273) / T pc

[0046] P pc =[46.7-32.1(γ g -0.5)]×0.09869

[0047] P r =P / P pc

[0048]

[0049]

[0050]

[0051]

[0052] Where: M is the kilomolar mass of natural gas; x j is the mole fraction of the jth component; M j The kilomolar mass of the component in the jth; γ g is the relative density of natural gas; Ma is the average kmol mass of air, measured in the laboratory, Ma = 28.96413 kg / kmol; T pc is the pseudo-critical temperature of natural gas; T r is the simulated temperature of natural gas; P pc is the pseudo-critical pressure of natural gas; P r is the quasi-relative pressure of natural gas; ρ r is the simulated relative density of natural gas; Z is the natural gas deviation factor; a1-a11 are coefficients.

[0053] The beneficial effect of the above technical solution is that the natural gas deviation factor is calculated to make the calculation result of the critical liquid carrying yield more accurate. Further, the calculation formula for the interfacial tension of the gas-liquid mixture in step 2) is:

[0054]

[0055] Where: wis the gas-water interfacial tension when the wellhead temperature is T and the wellhead pressure is p; σ o is the oil-gas interfacial tension when the wellhead temperature is t and the wellhead pressure is p; σ l is the interfacial tension of the gas-liquid mixture when the wellhead temperature is T and the wellhead pressure is p; GWR is the gas-water ratio; GOR is the gas-oil ratio.

[0056] The beneficial effects of the above technical solution are: taking into account the possible gas-liquid mixture situation, making the model more perfect and the judgment result more accurate.

[0057] Furthermore, the specific calculation formulas of the Li Min model and the Wang Yizhong model described in step 2) are:

[0058]

[0059]

[0060]

[0061] Where: a is the model coefficient, the value of Li Min model is 2.5, and the value of Wang Yizhong model is 2.25; v g is the critical liquid-carrying velocity; σ1(p,T) is the interfacial tension of the gas-liquid mixture when the wellhead temperature is T and the wellhead pressure is p; ρ1 is the formation water density; ρ g is the density of natural gas; γ g is the relative density of natural gas; p is the wellhead pressure at a certain moment; T is the wellhead temperature; Z(p,T) is the natural gas deviation factor when the wellhead temperature is T and the wellhead pressure is p; q c is the critical liquid carrying flow rate; A is the cross-sectional area of ​​the oil pipe; D is the diameter of the oil pipe; M g is the average kilomolar mass of air.

[0062] The beneficial effects of the above technical solution are as follows: the Li Min model and the Wang Yizhong model are models with relatively high reliability in this field, and the Li Min model and the Wang Yizhong model are selected to make the calculation of the critical liquid carrying capacity more accurate.

[0063] Furthermore, the means for judging liquid accumulation in the wellbore according to the calculated critical liquid-carrying flow rate is as follows: comparing the calculated critical liquid-carrying flow rate with the gas production volume of the gas well; if the current gas production volume is much larger than the critical liquid-carrying flow rate and the difference between the two is outside the set threshold range, it is determined that there is no liquid accumulation; if the difference between the current gas production volume and the critical liquid-carrying flow rate is within the set threshold range, it is determined that there is near liquid accumulation; if the current gas production volume is less than the critical liquid-carrying production volume and the difference between the two is outside the set threshold range, it is determined that there is liquid accumulation.

[0064] The beneficial effect of the above technical solution is: the produced gas volume is compared with the critical liquid carrying flow rate, and the difference between the two is compared with the set threshold value, so as to determine the liquid accumulation situation of the gas well. BRIEF DESCRIPTION OF THE DRAWINGS

[0065] Figure 1 It is a flowchart of the method for judging liquid loading in a wellbore of a condensate gas reservoir in a continental high thermal evolution zone of the present invention;

[0066] Figure 2-1 is a relationship diagram between the calculation result of the Li Min model and the gas production before correction of the A well in the A gas field of Example;

[0067] Figure 2-2 is a relationship diagram between the calculation result of the modified Li Min model and the produced gas volume of the A well of the A gas field in Example;

[0068] Figure 3-1 A graph showing the relationship between the calculation results of the Wang Yizhong model and the gas production volume before correction for the A well in the A gas field in Example;

[0069] Figure 3-2 This is a relationship diagram between the calculation results of the modified Wang Yizhong model and the produced gas volume of Well A in Gas Field A of Example 1. DETAILED DESCRIPTION

[0070] To judge the liquid loading in the wellbore of condensate gas reservoirs in the continental high thermal evolution zone, firstly, the oil-gas interfacial tension of the target gas well is calculated, and then the interfacial tension of the corresponding gas-liquid mixture is calculated based on the oil-gas interfacial tension; secondly, the interfacial tension of the gas-liquid mixture is substituted into the Li Min model or the Wang Yizhong model for calculation to obtain the critical liquid carrying flow rate; finally, the liquid loading in the wellbore is judged based on the calculated critical liquid carrying flow rate.

[0071] In order to make the purpose, technical solutions and advantages of the present invention more clear, the present invention is further described in detail below with reference to the accompanying drawings and embodiments.

[0072] Example of a method for judging liquid loading in a wellbore of a condensate gas reservoir in a continental high thermal evolution zone:

[0073] 1) Obtain the production data and phase data of the target gas well. The production data includes the wellhead pressure, wellhead temperature, daily gas production, daily water production, and daily oil production corresponding to the current production date; the phase data includes the natural gas composition or gas phase relative density, oil phase relative density, and formation water density; the deviation factor of the natural gas is calculated by the relevant data. It is necessary to calculate the relative density, pseudo-critical temperature, pseudo-comparison temperature, pseudo-critical pressure, and pseudo-comparison pressure of the natural gas. Finally, the natural gas deviation factor is calculated by the formula using the above data. The calculation formulas for the relative density, pseudo-critical temperature, pseudo-comparison temperature, pseudo-critical pressure, pseudo-comparison pressure, and deviation factor of the natural gas in the DAK method are as follows:

[0074] M=∑x j M j

[0075] γ g =M / Ma=M / 28.96413

[0076] T pc =171(γ g -0.5)+182

[0077] T r =(T+273) / T pc

[0078] P pc =[46.7-32.1(γ g -0.5)]×0.09869

[0079] P r =P / P pc

[0080]

[0081]

[0082]

[0083]

[0084] Where: M is the kilomolar mass of natural gas; x j is the mole fraction of the jth component; M j The kilomolar mass of the component in the jth; γ g is the relative density of natural gas; Ma is the average kmol mass of air, measured in the laboratory, Ma = 28.96413 kg / kmol; T pc is the pseudo-critical temperature of natural gas; T r is the simulated temperature of natural gas; P pc is the pseudo-critical pressure of natural gas; P r is the quasi-relative pressure of natural gas; ρ r is the simulated relative density of natural gas; Z is the natural gas deviation factor; a1-a11 are coefficients.

[0085] The calculation method of the natural gas deviation factor can also be as follows:

[0086] M=∑x j M j

[0087] γ g =M / Ma=M / 28.96413

[0088] T pc =171(γ g -0.5)+182

[0089] T r =(T+273) / T pc

[0090] P pc =[46.7-32.1(γ g -0.5)]×0.09869

[0091] P r =P / P pc

[0092]

[0093] a=1.39(T r -0.92) 0.5 -0.36T r -0.101

[0094]

[0095] c=0.132-0.32logT pr

[0096] d = exp(0.7153-1.1285T r +0.4201T r 2 )

[0097] Where: T r is the simulated temperature of natural gas; p r is the quasi-comparison pressure; Z is the natural gas deviation factor; M is the kilomolar mass of natural gas; x j is the mole fraction of the jth component; M j The kilomolar mass of the component in the jth; γ g is the relative density of natural gas; Ma is the average kmol mass of air, measured in the laboratory, Ma = 28.96413 kg / kmol; T pc is the pseudo-critical temperature of natural gas; P pc is the pseudo-critical pressure of natural gas; P r is the simulated comparative pressure of natural gas; P is the wellhead pressure; T is the wellhead temperature; a, b, c, d are intermediate parameters.

[0098] The formulas for calculating the gas-water interfacial tension, oil-gas interfacial tension, and gas-liquid mixed interfacial tension are:

[0099] Air-water interfacial tension:

[0100]

[0101] σ1=76exp(-0.036257p)

[0102] σ2=52.5-0.8701p

[0103] Where: w is the interfacial tension of gas and water at a temperature of t℃; σ1 is the interfacial tension of water at a temperature of 23.33℃; σ2 is the interfacial tension of water at a temperature of 137.78℃; t is the temperature of water at a certain moment; p is the wellhead pressure.

[0104] The oil-gas interfacial tension of the target gas well is calculated as follows: If the current wellhead temperature T is greater than or equal to the first temperature T1, the interfacial tension σ corresponding to T1 is calculated. T1 As the phase interface tension corresponding to the current wellhead temperature, if the current wellhead temperature T is less than or equal to the second temperature T2, the phase interface tension σ corresponding to T2 is T2 As the interfacial tension corresponding to the current wellhead temperature, where T1<T2, if T1<T<T2, then according to σ T1 , σ T2 , the interfacial tension within the range of T1 and T2 is interpolated to obtain the interfacial tension σ corresponding to T T ; The obtained interfacial tension is multiplied by the correction coefficient C to obtain the oil-gas interfacial tension, wherein the correction coefficient C is calculated according to the current wellhead pressure; and then the interfacial tension of the corresponding gas-liquid mixture is calculated according to the oil-gas interfacial tension;

[0105] When the first temperature T1 is 68°F, the interfacial tension corresponding to the first temperature T1 is σ 68 ; The second temperature T2 is 100℉, then the interfacial tension corresponding to the second temperature T2 is σ 100 , the linear interpolation phase interface tension at the intermediate temperature, and the specific calculation formula of the correction coefficient are as follows:

[0106] σ o (p,T)=Cσ T

[0107]

[0108] C=1.0-0.024p 0.45

[0109] σ 68 =39-0.2571(API)

[0110] σ 100 =37.5-0.2571(API)

[0111] API = (141.5 / γ o )-131.5

[0112]

[0113] Where: o is the oil-gas interfacial tension; 68 is the interfacial tension at a temperature of 68°F; 100 is the interfacial tension of the lower phase at a temperature of 100°F; T is the linear interpolation interfacial tension at the intermediate temperature; T is the temperature of water at a certain moment; API is the gravity; γ o is the relative density of the oil phase; σ l is the interfacial tension of gas-liquid mixture; GWR is the gas-water ratio, GOR is the gas-oil ratio; C is the correction coefficient; p is the wellhead pressure.

[0114] 2) According to step 1), the deviation factor of natural gas and the interfacial tension of gas-liquid mixture are calculated, and the conventional Li Min model and Wang Yizhong model are respectively modified to obtain a critical liquid carrying flow model that considers the interfacial tension of gas-liquid mixture and the variation of natural gas deviation factor with temperature and pressure. The difference between the modified Li Min model and Wang Yizhong model is the different values ​​of the a model coefficient. The Li Min model takes a value of 2.5, and the Wang Yizhong model takes a value of 2.25. The specific formula is:

[0115]

[0116]

[0117]

[0118] Where: v g is the critical liquid-carrying velocity; σ1(p,T) is the interfacial tension of the gas-liquid mixture; ρ l is the formation water density; ρ g is the density of natural gas; γ g is the relative density of natural gas; p is the wellhead pressure at a certain moment; T is the wellhead temperature; Z is the natural gas deviation factor; γ g is the critical liquid carrying flow rate; A is the cross-sectional area of ​​the oil pipe; D is the diameter of the oil (casing) pipe; M g is the average kilomolar mass of air.

[0119] 3) The critical liquid carrying flow rate model corrected by step 2) is used to determine the wellbore liquid accumulation according to the calculated critical liquid carrying flow rate. The calculated critical liquid carrying flow rate is compared with the gas production volume of the gas well. If the current gas production volume is much larger than the critical liquid carrying flow rate and the difference between the two is outside the set threshold range, it is determined that there is no liquid accumulation. If the difference between the current gas production volume and the critical liquid carrying flow rate is within the set threshold range, it is determined that there is near liquid accumulation. If the current gas production volume is less than the critical liquid carrying volume and the difference between the two is outside the set threshold range, it is determined that there is liquid accumulation.

[0120] The technical scheme of the method for judging liquid loading in wellbore of condensate gas reservoir in continental high thermal evolution zone of the present invention is further described below in conjunction with the accompanying drawings. Well A is a typical well of continental condensate gas reservoir in gas field A, and its condensate oil content is 156.02 g / m 3 , dew point pressure 38.93MPa, ground-to-water pressure difference 6.5MPa. Wax content 2.19-4.46%, preliminary analysis shows that it is a tight condensate gas reservoir with low wax content and medium condensate oil content. Well A was put into production on December 12, 2021. The well opening pressure is high and the initial gas production index is large, but the daily gas production of high-end configuration is 10-20×10 4 m 3 / d, fast pressure drop rate (0.5MPa / d), severe stress sensitivity, stable daily gas production 5.2-6.5×10 4 m 3 / d, the oil pressure drop rate is 0.15MPa / d. At present, intermittent production is carried out, and the daily gas production is 1-2×10 4 m 3 / d, the current stable gas-oil ratio is 10000-12000m 3 / m 3 The daily gas production is too low to meet the critical liquid-carrying condition. The wellbore may have accumulated liquid, and timely drainage and gas production measures are needed. Therefore, the rapid and accurate judgment of the wellbore liquid accumulation in Well A is of guiding significance for the efficient development of continental condensate gas reservoirs.

[0121] This embodiment takes Well A in Gas Field A as an example to introduce a method for determining liquid loading in a condensate gas reservoir in a continental high thermal evolution zone. Figure 1 The flowchart shown includes the following steps:

[0122] 1) Obtain the production data and phase data of the target gas well, where the production data includes the wellhead pressure, wellhead temperature, daily gas production, daily water production, and daily oil production corresponding to the current production date; the phase data includes the natural gas composition or gas phase relative density, oil phase relative density, and formation water density.

[0123] The production data and phase data of Well A from the time of production to the present are obtained. The production data include the wellhead oil (casing) pressure, wellhead temperature, gas production, water production, oil production and daily production time corresponding to the current production date. The obtained production dynamic data are screened by production time, and abnormal data points with production time less than 10 hours due to intermittent well opening and closing, wax cleaning and plugging removal are removed to obtain 267 days of production data. The phase data include natural gas composition or gas phase relative density, oil phase relative density and formation water density.

[0124] 2) According to the natural gas composition or gas phase relative density of the gas well, the pseudo-critical pressure and pseudo-critical temperature of the natural gas are calculated, and then the pseudo-comparative pressure and pseudo-comparative temperature of the natural gas are calculated, and finally the deviation factor of the natural gas is calculated.

[0125] The natural gas composition and relative density of the gas phase in Well A are known, and the pseudo-critical pressure, pseudo-critical temperature, pseudo-comparative temperature, pseudo-comparative pressure, and deviation factor can be calculated by empirical formulas. The empirical formulas are:

[0126] M=∑x j M j

[0127] γ g =M / Ma=M / 28.96413

[0128] T pc =171(γ g -0.5)+182

[0129] T r =(T+273) / T pc

[0130] P pc =[46.7-32.1(γ g -0.5)]×0.09869

[0131] P r =P / P pc

[0132]

[0133]

[0134]

[0135]

[0136] Where: M is the kilomolar mass of natural gas; x j is the mole fraction of the jth component; M j The kilomolar mass of the component in the jth; γg is the relative density of natural gas; Ma is the average kmol mass of air, measured in the laboratory, Ma = 28.96413 kg / kmol; T pc is the pseudo-critical temperature of natural gas; T r is the simulated temperature of natural gas; P pc is the pseudo-critical pressure of natural gas; P r is the quasi-relative pressure of natural gas; ρ r is the simulated relative density of natural gas; Z is the natural gas deviation factor; a1-a11 are coefficients.

[0137] 3) According to the wellhead pressure and temperature of the gas well, the gas-water interfacial tension and the oil-gas interfacial tension are calculated, and then the interfacial tension of the gas-liquid mixture is obtained according to the daily oil and water production;

[0138] The formulas for calculating the gas-water interfacial tension, the oil-gas interfacial tension and the gas-liquid mixture interfacial tension are:

[0139]

[0140] σ1=76exp(-0.036257p)

[0141] σ2=52.5-0.8701p

[0142] σ o (p,T)=Cσ T

[0143]

[0144] C=1.0-0.024p 0.45

[0145] σ 68 =39-0.2571(API)

[0146] σ 100 =37.5-0.2571(API)

[0147] API = (141.5 / γ o )-131.5

[0148]

[0149] Where: w is the interfacial tension of gas and water at a temperature of t℃; σ1 is the interfacial tension of water at a temperature of 23.33℃; σ2 is the interfacial tension of water at a temperature of 137.78℃; t is the temperature of water at a certain moment; p is the wellhead pressure; σ o is the oil-gas interfacial tension; Tis the linear interpolation interfacial tension at intermediate temperature; API is heavy; γ o is the relative density of the oil phase; σ l is the interfacial tension of gas-liquid mixture; GWR is the gas-water ratio, GOR is the gas-oil ratio; C is the correction coefficient; T is the temperature of water at a certain moment.

[0150] 4) According to the deviation factor calculated in step 2) and the interfacial tension of the gas-liquid mixture calculated in step 3), the conventional Li Min model and Wang Yizhong model are modified to obtain a critical liquid carrying flow model that considers the interfacial tension and the deviation factor changing with temperature and pressure;

[0151] The modified Li Min model and Wang Yizhong model are:

[0152]

[0153]

[0154]

[0155] Where: v g is the critical liquid-carrying velocity; σ1(p,T) is the interfacial tension of the gas-liquid mixture; ρ l is the formation water density; ρ g is the density of natural gas; γ g is the relative density of natural gas; p is the wellhead pressure at a certain moment; T is the wellhead temperature; Z is the natural gas deviation factor; γ g is the critical liquid carrying flow rate; A is the cross-sectional area of ​​the oil pipe; D is the diameter of the oil (casing) pipe; M g is the average kilomolar mass of air.

[0156] 5) The critical liquid-carrying gas production corresponding to the current wellhead pressure is calculated by using the modified critical liquid-carrying flow model of Li Min and Wang Yizhong;

[0157] As shown in Table 1, the critical liquid-carrying flow model of Li Min and Wang Yizhong before and after correction is used to calculate the critical liquid-carrying gas production corresponding to the current wellhead pressure of Well A. For gas wells, whether the actual gas-liquid interfacial tension and the natural gas deviation factor are considered has a great influence on the calculation results of the critical liquid-carrying flow. By comparing the field monitoring results, it is found that the judgment result of the critical liquid-carrying flow model after theoretical correction by considering the actual gas-liquid interfacial tension and the natural gas deviation factor is more accurate, and the judgment accuracy is improved by about 10%. On the whole, the corrected Wang Yizhong model has the highest liquid accumulation prediction accuracy, which can effectively guide the on-site liquid accumulation judgment and drainage process selection.

[0158] Table 1

[0159]

[0160] 6) Draw a relationship diagram between the critical liquid-carrying production and the gas production of the gas well calculated by the modified Li Min model and Wang Yizhong model. By observing the location of the scattered points, the liquid accumulation situation can be judged. When the scattered points are in the upper left area of ​​the diagonal, that is, the current gas production is much greater than the critical liquid-carrying production, there is no liquid accumulation; when the scattered points are within the ±15% deviation range of the diagonal (the area between the two dotted lines), there is near liquid accumulation; when the scattered points are in the lower right area of ​​the diagonal, the critical liquid-carrying condition is not met, that is, there is liquid accumulation; further, the time when the wellbore begins to accumulate liquid is obtained, so as to facilitate timely adoption of liquid drainage and gas production measures.

[0161] like Figure 2-1 , Figure 2-2 , Figure 3-1 , Figure 3-2 As shown, the wellbore liquid accumulation state and liquid accumulation degree of Well A can be quickly determined.

[0162] Specific implementation methods are given above, but the present invention is not limited to the described implementation methods. The basic idea of ​​the present invention lies in the above basic scheme. For ordinary technicians in this field, it does not take creative work to design various deformed models, formulas, and parameters according to the teachings of the present invention. Changes, modifications, substitutions, and variations of the implementation methods without departing from the principles and spirit of the present invention still fall within the scope of protection of the present invention.

Claims

1. A method for judging liquid loading in a wellbore of a condensate gas reservoir in a continental high thermal evolution zone, characterized in that: The following steps are involved: 1) Calculate the oil-gas interfacial tension of the target gas well as follows: If the current wellhead temperature T is greater than or equal to the first temperature T1, the interfacial tension σ corresponding to T1 is calculated as T1 As the phase interface tension corresponding to the current wellhead temperature, if the current wellhead temperature T is less than or equal to the second temperature T2, the phase interface tension σ corresponding to T2 is T2 As the interfacial tension corresponding to the current wellhead temperature, where T1<T2, if T1<T<T2, then according to σ T1 , σ T2 , the interfacial tension within the range of T1 and T2 is interpolated to obtain the interfacial tension σ corresponding to T T ; The obtained interfacial tension is multiplied by the correction coefficient C to obtain the oil-gas interfacial tension, wherein the correction coefficient C is calculated according to the current wellhead pressure; and then the interfacial tension of the corresponding gas-liquid mixture is calculated according to the oil-gas interfacial tension; 2) Substitute the interfacial tension of the gas-liquid mixture into the Li Min model or Wang Yizhong model to calculate and obtain the critical liquid carrying flow rate; 3) Determine the amount of liquid accumulation in the wellbore based on the calculated critical liquid carrying rate.

2. The method for determining liquid loading in a wellbore of a condensate gas reservoir in a continental high thermal evolution zone according to claim 1, characterized in that: The first temperature T1 is 68°F, and the second temperature T2 is 100°F.

3. The method for judging liquid loading in wellbore of condensate gas reservoir in continental high thermal evolution zone according to claim 2, characterized in that: The interfacial tension σ corresponding to the first temperature T1 68 , and the interfacial tension σ corresponding to the second temperature T2 100 The specific calculation formula is as follows: s 68 =39-0.2571(API) s 100 =37.5-0.2571(API) API=(141.5 / g o )-131.5 Where: API is heavy; γ o is the relative density of the oil phase.

4. The method for determining liquid loading in a wellbore of a condensate gas reservoir in a continental high thermal evolution zone according to claim 1, characterized in that: The specific calculation formula of the linear interpolation phase interface tension at the intermediate temperature is as follows: Where: T is the linear interpolation interfacial tension at the intermediate temperature; T is the intermediate temperature; σ 68 is the interfacial tension corresponding to the first temperature T1; σ 100 is the interfacial tension corresponding to the second temperature T2.

5. The method for determining liquid loading in a wellbore of a condensate gas reservoir in a continental high thermal evolution zone according to claim 1, characterized in that: The specific calculation formula of the correction coefficient is as follows: C=1.0-0.024p 0.45 Where: C is the correction coefficient; p is the wellhead pressure.

6. The method for determining liquid loading in a wellbore of a condensate gas reservoir in a continental high thermal evolution zone according to claim 1, characterized in that: The parameters substituted into the Li Min model or Wang Yizhong model for calculation also include the natural gas deviation factor, and the formula of the natural gas deviation factor is: M=∑x j M j γ g =M / Ma=M / 28.96413 T pc =171(c g -0.5)+182 T r =(T+273) / T pc P pc =[46.7-32.1(c g -0.5)]×0.09869 P r =P / P pc a=1.39(T r -0.92) 0.5 -0.36T r -0.101 c=0.132-0.32logT pr Where: T r is the simulated temperature of natural gas; p r is the quasi-comparison pressure; Z is the natural gas deviation factor; M is the kilomolar mass of natural gas; x j is the mole fraction of the jth component; M j The kilomolar mass of the component in the jth; γ g is the relative density of natural gas; Ma is the average kmol mass of air, measured in the laboratory, Ma = 28.96413 kg / kmol; T pc is the pseudo-critical temperature of natural gas; P pc is the pseudo-critical pressure of natural gas; P r is the simulated comparative pressure of natural gas; P is the wellhead pressure; T is the wellhead temperature; a, b, c, d are intermediate parameters.

7. The method for determining liquid loading in a wellbore of a condensate gas reservoir in a continental high thermal evolution zone according to claim 1, characterized in that: The parameters substituted into the Li Min model or the Wang Yizhong model for calculation also include the natural gas deviation factor, and the calculation method of the natural gas deviation factor also includes the DAK method, and the calculation formula is: M=∑x j M j γ g =M / Ma=M / 28.96413 T pc =171(c g -0.5)+182 T r =(T+273) / T pc P pc =[46.7-32.1(c g -0.5)]×0.09869 P r =P / P pc Where: M is the kilomolar mass of natural gas; x j is the mole fraction of the jth component; M j The kilomolar mass of the component in the jth; γ g is the relative density of natural gas; Ma is the average kmol mass of air, measured in the laboratory, Ma = 28.96413 kg / kmol; T pc is the pseudo-critical temperature of natural gas; T r is the simulated temperature of natural gas; P pc is the pseudo-critical pressure of natural gas; P r is the quasi-relative pressure of natural gas; ρ r is the simulated relative density of natural gas; Z is the natural gas deviation factor; a1-a11 are coefficients.

8. The method for determining liquid loading in a wellbore of a condensate gas reservoir in a continental high thermal evolution zone according to claim 1, characterized in that: The calculation formula for the interfacial tension of the gas-liquid mixture described in step 2) is: Where: w is the gas-water interfacial tension when the wellhead temperature is T and the wellhead pressure is p; σ o is the oil-gas interfacial tension when the wellhead temperature is t and the wellhead pressure is p; σ l is the interfacial tension of the gas-liquid mixture when the wellhead temperature is T and the wellhead pressure is p; GWR is the gas-water ratio; GOR is the gas-oil ratio.

9. The method for determining liquid loading in a wellbore of a condensate gas reservoir in a continental high thermal evolution zone according to claim 1, characterized in that: The specific calculation formulas of the Li Min model and the Wang Yizhong model described in step 2) are: Where: a is the model coefficient, the value of Li Min model is 2.5, and the value of Wang Yizhong model is 2.25; v g is the critical liquid-carrying velocity; σ1(p,T) is the interfacial tension of the gas-liquid mixture when the wellhead temperature is T and the wellhead pressure is p; ρ1 is the formation water density; ρ g is the density of natural gas; γ g is the relative density of natural gas; p is the wellhead pressure at a certain moment; T is the wellhead temperature; Z(p,T) is the natural gas deviation factor when the wellhead temperature is T and the wellhead pressure is p; q c is the critical liquid carrying flow rate; A is the cross-sectional area of ​​the oil pipe; D is the diameter of the oil pipe; M g is the average kilomolar mass of air.

10. The method for judging liquid loading in a wellbore of a condensate gas reservoir in a continental high thermal evolution zone according to claim 1, characterized in that: The method for judging liquid accumulation in the wellbore based on the calculated critical liquid-carrying flow rate is as follows: comparing the calculated critical liquid-carrying flow rate with the gas production volume of the gas well; if the current gas production volume is much larger than the critical liquid-carrying flow rate and the difference between the two is outside the set threshold range, it is determined to be a situation of no liquid accumulation; if the difference between the current gas production volume and the critical liquid-carrying flow rate is within the set threshold range, it is determined to be a situation of near liquid accumulation; if the current gas production volume is less than the critical liquid-carrying flow rate and the difference between the two is outside the set threshold range, it is determined to be a situation of liquid accumulation.

Images