A method for generating a gas well liquid loading identification chart based on oil-casing pressure difference

Abstract

The present invention discloses a method for generating a gas well liquid accumulation discrimination chart based on oil-casing pressure difference, which belongs to the field of oil and gas exploration technology, and includes the following steps: collecting actual gas production well data in the oil field, calculating the bottom hole pressure of the gas well bore; combining the static gas column pressure formula and the natural gas compression factor calculation formula to calculate the wellhead casing pressure, and then obtain the oil-casing pressure difference; selecting different pressure drop algorithms for different well inclination angles; analyzing the sensitivity and variation range of the oil-casing pressure difference to all influencing factors, and determining the key influencing factors for the oil-casing pressure difference per kilometer; after completing the oil-casing pressure difference calculation and sensitivity analysis, taking the oil-casing pressure difference per kilometer as the ordinate and the daily gas production as the abscissa, combining the liquid-gas ratio, the wellhead oil pressure and the pipe diameter, a liquid accumulation discrimination chart is generated. The present invention forms an intuitive liquid accumulation discrimination chart within a reasonable variation range of gas well production parameters by comprehensively analyzing the key parameters in the gas well production process.

Description

Technical Field

[0001] The invention belongs to the technical field of oil and natural gas exploration, and in particular relates to a method for generating a gas well liquid accumulation discrimination chart based on oil-casing pressure difference. Background Art

[0002] In recent years, with the continuous development of gas reservoirs, the problem of liquid accumulation at the bottom of gas wells has become increasingly important. Liquid accumulation will significantly hinder the flow of natural gas, increase the flow resistance in the wellbore, and lead to a decrease in gas well production. In the Sulige gas field, due to the problem of liquid accumulation, the production of the gas field has dropped by more than 30%, and some wells have even stopped production.

[0003] At present, the methods for determining whether there is liquid accumulation at the bottom of a gas well mainly include field testing, critical liquid-carrying flow rate, and oil-casing pressure difference method. However, the field testing method relies on directly measuring the bottom-hole liquid and judging the liquid accumulation by monitoring the pressure profile; the critical liquid-carrying flow rate method is based on the principle of fluid mechanics and determines the liquid accumulation by calculating the fluid flow rate in the wellbore. When the gas well production is lower than the critical liquid-carrying flow rate, it can be inferred that there may be liquid accumulation at the bottom of the well. This method involves difficulties such as wellbore pressure and temperature calculation and the selection of the critical liquid-carrying flow rate formula, and the method is not universal and generalizable; while the oil-casing pressure difference method infers whether there is liquid accumulation at the bottom of the well by measuring the difference between the wellhead oil pressure and the casing pressure. Although it is easy to implement, it lacks accurate basis for judgment. Due to the complex and changeable production conditions of gas wells, the accuracy of the oil-casing pressure difference method under different conditions varies. How to accurately determine the liquid accumulation limit of gas wells under different conditions has always been a problem that has troubled technicians. Forming a set of gas well liquid accumulation identification charts can not only quickly and accurately identify gas well liquid accumulation, but also provide scientific guidance for gas well liquid accumulation treatment under different production conditions, improve the production efficiency and safety of gas wells, and ensure efficient production of gas wells. Summary of the invention

[0004] In order to solve the above problems, the present invention proposes a method for generating a gas well liquid accumulation discrimination chart based on oil-casing pressure difference, which forms an intuitive liquid accumulation discrimination chart within a reasonable range of gas well production parameter changes by comprehensively analyzing key parameters in the gas well production process.

[0005] The technical solution of the present invention is as follows:

[0006] A method for generating a gas well liquid loading identification chart based on oil-casing pressure difference comprises the following steps:

[0007] Step 1: Collect actual gas well data in the oil field and calculate the bottom hole pressure of the gas well bore;

[0008] Step 2: Calculate the wellhead casing pressure by combining the static gas column pressure formula and the natural gas compression factor calculation formula, and then obtain the oil casing pressure difference;

[0009] Step 3, select different pressure drop algorithms for different well inclination angles;

[0010] Step 4: Analyze the sensitivity and variation range of the oil-casing pressure difference to all influencing factors, and determine the key influencing factors for the oil-casing pressure difference per kilometer;

[0011] Step 5: After completing the calculation of the oil-casing pressure difference and the sensitivity analysis, the oil-casing pressure difference per kilometer is used as the vertical coordinate, the daily gas production is used as the horizontal coordinate, and the liquid-gas ratio, wellhead oil pressure and pipe diameter are combined to generate a liquid accumulation identification chart.

[0012] Furthermore, in step 1, the gas production well data includes: natural gas composition, natural gas properties, gas production, liquid-gas ratio, wellhead oil pressure, well depth, and pipe diameter.

[0013] Furthermore, in step 1, the specific process of calculating the bottom hole pressure of the gas wellbore is:

[0014] Step 1.1, the pressure drop in the gas wellbore consists of friction pressure drop, gravity pressure drop and acceleration pressure drop. The friction pressure drop, gravity pressure drop and acceleration pressure drop are calculated respectively;

[0015] The calculation formula for friction pressure drop is:

[0016] (1);

[0017] in, is the friction pressure drop; is the friction coefficient; is the wellbore length; is the wellbore diameter; is the fluid density; is the flow rate;

[0018] The formula for calculating gravity pressure drop is:

[0019] (2);

[0020] in, is the gravity pressure drop; is the fluid density; is the acceleration due to gravity; is the wellbore length; is the angle between the wellbore and the horizontal direction;

[0021] The calculation formula for the acceleration voltage drop is:

[0022] (3);

[0023] in, is the acceleration pressure drop; is the flow velocity gradient;

[0024] Step 1.2: Calculate the pressure distribution section by section from the wellhead to the bottom of the well according to the friction pressure drop, gravity pressure drop and acceleration pressure drop. First, set the known wellhead oil pressure and wellhead temperature at the wellhead position. Then, start from the wellhead position and calculate downward section by section. The starting pressure of each section is the ending pressure of the previous section. The calculation formula is:

[0025] (4);

[0026] in, is the sequence number of the current segment; is the serial number of the next paragraph; For the next section of pressure; is the starting pressure of the current segment; is the friction pressure drop of the current section; is the gravity pressure drop of the current segment; is the acceleration pressure drop of the current section;

[0027] Step 1.3: Use the step-by-step accumulation method in step 1.2 to gradually calculate the pressure change from the wellhead to the bottom of the well. The pressure in the last section is the bottom hole pressure.

[0028] Furthermore, in step 2, the calculation formula of the static air column pressure is:

[0029] (5);

[0030] in, To go down from the gas well; is the static air column pressure; is the wellhead casing pressure; is an exponential function with base e; is the gas density under standard conditions; is the temperature under standard conditions; is the pressure under standard conditions; is the average temperature; is the gas compressibility factor at average temperature and average pressure;

[0031] The calculation formula of natural gas compression factor is:

[0032] (6);

[0033] (7);

[0034] (8);

[0035] (9);

[0036] in, is the natural gas compression factor; is the relative temperature of natural gas; is the thermodynamic temperature of natural gas; is the apparent critical temperature of natural gas; is the relative density of natural gas; is the relative pressure of natural gas; is the pressure of natural gas; is the apparent critical pressure of natural gas; and The calculation formula is as follows:

[0037] (10);

[0038] (11);

[0039] in, is the relative density of natural gas; , , , are different coefficients related to the properties of natural gas.

[0040] Furthermore, in step 2, the specific process of calculating the wellhead casing pressure is:

[0041] Step 2.1, set the initial natural gas compression factor to 1;

[0042] Step 2.2: According to formula (5), when the natural gas compression factor is 1, calculate the initial value of the wellhead casing pressure: ;

[0043] Step 2.3: Read the coefficients related to natural gas properties based on the gas well data , , , ;

[0044] Step 2.4: Calculate the apparent critical temperature of natural gas according to formula (10) and formula (11) respectively: and apparent critical pressure ;

[0045] Step 2.5, calculating the relative temperature, relative pressure and relative density of natural gas according to formula (7) to formula (9);

[0046] Step 2.6, continuously update the value of the natural gas compression factor according to formula (6) until it converges to a stable value;

[0047] Step 2.7: Substitute the updated natural gas compression factor and the bottom hole pressure obtained in step 1 into formula (5) to calculate the wellhead casing pressure: ;

[0048] Step 2.8: Make a difference between the wellhead casing pressure and the initial value of the wellhead casing pressure to make a judgment. When the wellhead casing pressure is output, otherwise, the wellhead casing pressure is set to the initial value of the inlet casing pressure, and the process from step 2.3 to step 2.8 is repeated;

[0049] The wellhead oil pressure has been preset, and the casing pressure difference can be obtained by subtracting the wellhead oil pressure from the wellhead casing pressure.

[0050] Furthermore, in step 3, when the well inclination angle of the gas well is less than 45°, the Hagedorn-Brown model is used to calculate the pressure drop, and when the well inclination angle is greater than or equal to 45°, the Beggs-Brill model is used to calculate the pressure drop.

[0051] Furthermore, in step 4, all influencing factors include liquid-gas ratio, well depth, wellhead oil pressure, pipe diameter and gas production;

[0052] Select the liquid-gas ratio range from 0 to 3m 3 / 10 4 m 3 The wellhead oil pressure range is 1 MPa ~5 MPa, the well depth range is 3500m~3800m, and the gas production range is 0~3×10 4 m 3 , pipe diameter range is 2 3 / 8 and 2 7 / 8 for analysis;

[0053] The analysis shows that well inclination will only affect the friction pressure drop. When the vertical depth is determined, the increase of well inclination angle will increase the friction pressure drop in the wellbore. However, when the well inclination angle is less than 40°, the effect of well inclination on the oil-casing pressure difference is small. Therefore, in the selection of parameters for drawing the chart, the effect of well inclination on the oil-casing pressure difference is ignored.

[0054] There is a linear relationship between the well depth and the oil-casing pressure difference per kilometer. Therefore, the oil-casing pressure difference per kilometer is used as the ordinate of the plate, eliminating the influence of the well depth on the number of plates drawn and reducing the number of plates drawn.

[0055] By calculating the sensitivity coefficients of various factors affecting the oil-casing pressure difference per kilometer, the sensitivity coefficients of well depth, wellhead oil pressure, pipe diameter, and liquid-gas ratio are quantitatively analyzed. The sensitivity coefficient calculation formula is as follows:

[0056] (13);

[0057] in, is the casing pressure per kilometer of wellhead; is the oil pressure per kilometer at the wellhead; It is the difference between the casing pressure per kilometer at the wellhead and the oil pressure per kilometer at the wellhead, that is, the oil-casing pressure difference per kilometer; is the change in oil-casing pressure difference; For the Influencing factors; For the The amount of change of the influencing factors; is the sensitivity coefficient;

[0058] The sensitivity coefficient of a single influencing factor is calculated by changing it; the sensitivity coefficient of a single influencing factor is determined by taking the average value of the sensitivity coefficient at each gas production rate; then the sensitivity coefficients of all influencing factors are calculated; finally, by comparing the sensitivity coefficients and the changes in the oil-casing pressure difference, it is determined that the key influencing factors for the oil-casing pressure difference per kilometer are the liquid-gas ratio, wellhead oil pressure and pipe diameter.

[0059] Furthermore, the specific process of step 5 is as follows: first, the wellhead oil pressure is input into the Gray model, and the Gray model obtains the pressure distribution of the well section with a well inclination angle less than 45° after iterative calculation of the multiphase pipe flow; then, the starting point pressure is input into the Beggs-Brill model, and the Beggs-Brill model obtains the pressure distribution of the well section with a well inclination angle greater than or equal to 45° after iterative calculation of the multiphase pipe flow, and finally the bottom hole pressure of the entire gas well is obtained; then, the wellhead casing pressure is calculated using the bottom hole pressure through the MATLAB programming software; the oil casing pressure difference per kilometer is selected as the ordinate, and the gas production is selected as the abscissa to construct a gas well liquid accumulation discrimination plate; through this plate, the on-site technicians can judge whether the current gas well has a bottom hole liquid accumulation problem according to the changes in the wellhead oil pressure and the daily gas production; in the gas well liquid accumulation discrimination plate, the wells above the critical liquid accumulation curve are judged as liquid accumulation wells, and the wells below the critical liquid accumulation curve are judged as non-liquid accumulation wells.

[0060] The beneficial technical effects brought about by the present invention are as follows.

[0061] 1. Improved accuracy of liquid accumulation identification: The present invention significantly improves the scientific nature of liquid accumulation identification by accurately calculating the oil-casing pressure difference and combining a variety of production parameters, solves the problem of excessive reliance on experience in existing methods for liquid accumulation identification, and reduces human errors.

[0062] 2. The engineering application of liquid loading identification has been realized; the liquid loading identification chart can be applied to the production conditions of different gas wells, has strong applicability, can be quickly applied at the production site, and does not rely on complex equipment or calculation models. The technicians can draw conclusions intuitively based on the horizontal and vertical coordinates of the chart.

[0063] 3. Reduced operating costs and improved production efficiency. Compared with existing methods, the present invention simplifies the steps of liquid accumulation identification through diagrams. Technical personnel no longer need to perform a large number of on-site measurements and calculations, which greatly reduces the complexity and cost of production management and improves the production efficiency of gas wells.

[0064] 4. Provide comprehensive production guidance: The chart of the present invention can not only determine whether there is a liquid accumulation problem in the gas well, but also provide quantitative guidance to help technicians choose the best drainage measures to ensure efficient production and long-term operation of the gas well. BRIEF DESCRIPTION OF THE DRAWINGS

[0065] Figure 1 The present invention is a flow chart of a method for generating a gas well liquid accumulation identification chart based on oil-casing pressure difference.

[0066] Figure 2 The present invention is a flow chart for calculating the wellhead casing pressure by means of MATLAB programming software.

[0067] Figure 3 This is a comparison diagram of the change of oil-casing pressure difference with gas production at different well inclination angles in an embodiment of the present invention.

[0068] Figure 4 This is a comparison chart of the change of oil-casing pressure difference per kilometer with gas production at different well depths in an embodiment of the present invention.

[0069] Figure 5 In the embodiment of the present invention, the well depth is 3500m, the wellhead oil pressure is 1Mpa, and the pipe diameter is 2 3 A comparison of the change in casing pressure difference per kilometer with gas production under different liquid-gas ratios under the condition of / 8.

[0070] Figure 6 In the embodiment of the present invention, the well depth is 3500m, the liquid-gas ratio is 1 cubic meter / 10,000 cubic meter, and the pipe diameter is 2 3 A comparison of the change in casing pressure difference per kilometer with gas production under different wellhead oil pressures under the condition of / 8.

[0071] Figure 7 This is a comparison chart of the change of the oil-casing pressure difference per kilometer with the gas production obtained for different pipe diameters under the conditions of a well depth of 3500m, a liquid-gas ratio of 1 cubic meter / 10,000 cubic meter, and a wellhead oil pressure of 1 MPa in an embodiment of the present invention.

[0072] Figure 8 It is a comparison diagram of sensitivity coefficients of parameters of various gas production wells in the embodiment of the present invention.

[0073] Fig. 9 This is a comparison chart of the change of casing pressure difference per kilometer with gas production at different liquid-to-gas ratios in an embodiment of the present invention.

[0074] Fig.10This is a comparison chart of the change of casing pressure difference per kilometer with gas production under different wellhead oil pressures in an embodiment of the present invention.

[0075] Fig.11 The pipe diameter in the embodiment of the present invention is 2 7 / 8 and the pipe diameter 2 as the reference value 3 / 8Comparison chart of the change of casing pressure difference per kilometer with gas production after difference calculation.

[0076] Fig.12 In the embodiment of the present invention, the wellhead oil pressure is 1Mpa, the pipe diameter is 2 7 Schematic diagram of the plate in the case of / 8.

[0077] Fig.13 In the embodiment of the present invention, the wellhead oil pressure is 2Mpa, the pipe diameter is 2 7 Schematic diagram of the plate in the case of / 8.

[0078] Fig.14 In the embodiment of the present invention, the wellhead oil pressure is 3Mpa and the pipe diameter is 2 7 Schematic diagram of the plate in the case of / 8.

[0079] Fig.15 In the embodiment of the present invention, the wellhead oil pressure is 4Mpa and the pipe diameter is 2 7 Schematic diagram of the plate in the case of / 8.

[0080] Fig.16 In the embodiment of the present invention, the wellhead oil pressure is 5 MPa and the pipe diameter is 2 7 Schematic diagram of the plate in the case of / 8.

[0081] Fig.17 In the embodiment of the present invention, the wellhead oil pressure is 1 Mpa, the pipe diameter is 2 3 Schematic diagram of the plate in the case of / 8.

[0082] Fig.18 In the embodiment of the present invention, the wellhead oil pressure is 2Mpa, the pipe diameter is 2 3 Schematic diagram of the plate in the case of / 8.

[0083] Fig.19 In the embodiment of the present invention, the wellhead oil pressure is 3Mpa and the pipe diameter is 2 3 Schematic diagram of the plate in the case of / 8.

[0084] Fig. 20 In the embodiment of the present invention, the wellhead oil pressure is 4Mpa and the pipe diameter is 2 3 Schematic diagram of the plate in the case of / 8.

[0085] Fig.21 In the embodiment of the present invention, the wellhead oil pressure is 5 MPa and the pipe diameter is 2 3 Schematic diagram of the plate in the case of / 8.

[0086] Fig. 22 It is a schematic diagram of the actual application of the gas well liquid accumulation identification chart in the embodiment of the present invention. DETAILED DESCRIPTION

[0087] The present invention is further described in detail below with reference to the accompanying drawings and specific embodiments:

[0088] like Figure 1 As shown, the present invention proposes a method for generating a gas well liquid accumulation discrimination chart based on the oil-casing pressure differential. The present invention mainly determines the oil-casing pressure differential by calculating the difference between the wellhead oil pressure and the casing pressure of the gas wellbore. This process is crucial because it provides basic data for subsequent analysis. Using PIPESIM software, and combining the wellhead oil pressure and bottom hole flow pressure, the oil-casing pressure differential is calculated through a multiphase pipe flow pressure drop model. This calculation process involves a comprehensive consideration of gravity pressure drop, friction pressure drop, and acceleration pressure drop, ensuring the accuracy of the oil-casing pressure differential. The calculation of these pressure drops not only reflects the various resistances and pressure changes when the fluid flows in the wellbore, but also provides the necessary theoretical basis for subsequent pressure distribution calculations. The method of the present invention specifically includes the following steps:

[0089] Step 1: Collect the actual gas well data of the oil field, and calculate the bottom hole pressure of the gas well bore through PIPESIM software; the gas well data includes: natural gas composition, natural gas physical properties, gas production, liquid-gas ratio, wellhead oil pressure, well depth, and pipe diameter. The specific process of calculating the bottom hole pressure of the gas well bore is:

[0090] Step 1.1, the pressure drop in the gas wellbore consists of friction pressure drop, gravity pressure drop and acceleration pressure drop. The friction pressure drop, gravity pressure drop and acceleration pressure drop are calculated respectively;

[0091] The friction pressure drop is caused by the friction between the fluid and the wellbore wall when it flows in the wellbore. The calculation formula is:

[0092] (1);

[0093] in, is the friction pressure drop, Pa; is the friction coefficient, dimensionless; is the wellbore length, m; is the wellbore diameter, m; is the fluid density, kg / m 3 ; is the flow velocity, m / s.

[0094] The gravity pressure drop is caused by the gravity of the fluid and is calculated as:

[0095] (2);

[0096] in, is the gravity pressure drop, Pa; is the fluid density, kg / m 3 ; is the acceleration due to gravity, m / s 2 ; is the wellbore length, m; is the angle between the wellbore and the horizontal direction, °.

[0097] The accelerated pressure drop is caused by the change in fluid flow rate, which is usually more significant when the gas phase flow rate is large. The calculation formula is:

[0098] (3);

[0099] in, is the acceleration pressure drop, Pa; is the velocity gradient, m / s. These pressure drop calculations comprehensively reflect the various resistances and pressure changes when the fluid flows in the wellbore.

[0100] Step 1.2: Calculate the pressure distribution section by section from the wellhead to the bottom of the well based on the friction pressure drop, gravity pressure drop and acceleration pressure drop. First, set the known wellhead oil pressure and wellhead temperature at the wellhead. Then, starting from the wellhead, calculate downward section by section. The starting pressure of each section is the ending pressure of the previous section. The calculation formula is:

[0101] (4);

[0102] in, is the sequence number of the current segment; is the serial number of the next paragraph; For the next section of pressure; is the starting pressure of the current segment, Pa; is the friction pressure drop of the current section, Pa; is the gravity pressure drop of the current segment, Pa; is the acceleration pressure drop of the current section, Pa.

[0103] Step 1.3: PIPESIM software can gradually calculate the pressure change from the wellhead to the bottom of the well by using the step-by-step accumulation method in step 1.2. The pressure in the last section is the bottom hole pressure.

[0104] Step 2: Calculate the wellhead casing pressure by using MATLAB programming software and combining the static gas column pressure formula and the natural gas compression factor calculation formula to obtain the oil-casing pressure difference.

[0105] The calculation formula for the static air column pressure distribution is:

[0106] (5);

[0107] in, is the vertical depth from the gas well, m; is the static air column pressure, MPa; is the wellhead casing pressure, MPa; is an exponential function with base e; is the gas density under standard conditions, kg / m 3 ; is the temperature under standard conditions, K; is the pressure under standard conditions, Pa; is the average temperature, K; is the gas compressibility factor at mean temperature and mean pressure, dimensionless.

[0108] Since the natural gas compression factor is affected by temperature and pressure, an iterative algorithm is needed to calculate the natural gas compression factor. The calculation formula for the natural gas compression factor is:

[0109] (6);

[0110] (7);

[0111] (8);

[0112] (9);

[0113] in, is the natural gas compression factor, dimensionless; is the relative temperature of natural gas, dimensionless; is the thermodynamic temperature of natural gas, K; is the apparent critical temperature of natural gas, K; is the relative density of natural gas, dimensionless; is the relative pressure of natural gas, dimensionless; is the pressure of natural gas, kPa; is the apparent critical pressure of natural gas; and The calculation formula is as follows:

[0114] (10);

[0115] (11);

[0116] in, is the relative density of natural gas; , , , are different coefficients related to the properties of natural gas.

[0117] Assuming that the casing is a pure static air column, Figure 2 As shown in the figure, the specific process of calculating the wellhead casing pressure with the help of MATLAB programming software is as follows:

[0118] Step 2.1, set the initial natural gas compression factor to 1;

[0119] Step 2.2: According to the static gas column pressure distribution calculation formula (5), when the natural gas compression factor is 1, calculate the initial value of the wellhead casing pressure: ;

[0120] Step 2.3: Read the coefficients related to natural gas properties based on the gas well data of Changqing Sulige Gas Field , , , ;

[0121] Step 2.4: Calculate the apparent critical temperature of natural gas according to formula (10) and formula (11) respectively: and apparent critical pressure ;

[0122] Step 2.5, calculating the relative temperature, relative pressure and relative density of natural gas according to formula (7) to formula (9);

[0123] Step 2.6, continuously updating the value of the natural gas compression factor according to the natural gas compression factor calculation formula (6) until it converges to a stable value; in the embodiment of the present invention, after five iterations, the value of the natural gas compression factor converges to a stable value;

[0124] Step 2.7: Substitute the updated natural gas compression factor and the bottom hole pressure obtained in step 1 into the static gas column pressure distribution calculation formula (5), and calculate the wellhead casing pressure according to formula (5): ;

[0125] Step 2.8: Make a difference between the wellhead casing pressure and the initial value of the wellhead casing pressure to make a judgment. When the wellhead casing pressure is output, otherwise, the wellhead casing pressure is set to the initial value of the inlet casing pressure, and the process from step 2.3 to step 2.8 is repeated.

[0126] The wellhead oil pressure has been preset, and the casing pressure difference can be obtained by subtracting the wellhead oil pressure from the wellhead casing pressure.

[0127] in, , , , The specific values ​​are shown in Table 1.

[0128] Table 1 Value table of different coefficients

[0129] .

[0130] Step 3, select different pressure drop algorithms for different well inclination angles;

[0131] Optimizing the tubing pressure drop algorithm and quantitatively analyzing the parameters affecting the oil-casing pressure difference are the key to improving the accuracy of diagnosis. The present invention compares the Hagedorm-Brown model, the Gray model and the Beggs-Brill model to optimize the pressure drop algorithm suitable for different well inclination angles. This selection process ensures the accuracy and consistency of the pressure drop calculation under different gas well conditions. The most commonly used gas-liquid two-phase flow pressure drop calculation models are the Hagedorm-Brown model, the Gray model and the Beggs-Brill model; the Hagedorm-Brown model and the Gray model are mainly applicable to vertical wells, and the Beggs-Brill model has a wider range of applications and is more accurate for the calculation of inclined sections and horizontal sections. Therefore, for different gas wells, the Hagedorn-Brown model or the Gray model is used when the well inclination angle is less than 45°, and the Beggs-Brill model is used when the well inclination angle is greater than or equal to 45°, and the Hagedorm-Brown model, the Beggs-Brill model and the Gray model are verified using the measured data of the Sulige gas well.

[0132] Table 2 shows the error analysis results of different gas-liquid two-phase flow pressure drop calculation models. Among them, the average percentage relative error was used for analysis and evaluation. In fact, a total of 24 flow pressure test data were analyzed, and the final average percentage relative error of the Gray model was 5.05%, and the average percentage relative error of the Hagedorn-Brown model was 21.42%. Therefore, the Gray model is used when the gas well inclination angle is less than 45°, and the Beggs-Brill model is used when the gas well inclination angle is greater than or equal to 45° to minimize the pressure drop calculation error.

[0133] Table 2 Error analysis table of different gas-liquid two-phase flow pressure drop calculation models

[0134] .

[0135] The average percentage relative error can reflect the overall error of the model prediction results, and the calculation formula is:

[0136] (12);

[0137] in, is the average percentage relative error; is the test number, times; is the total number of tests, times; is the calculated value, MPa; is the measured value, MPa.

[0138] Step 4: Analyze the sensitivity and variation range of the oil-casing pressure difference to all influencing factors, and determine the key influencing factors for the oil-casing pressure difference per kilometer. The influencing factors include parameters such as liquid-gas ratio, well depth, wellhead oil pressure, pipe diameter, and gas production.

[0139] After determining the calculation method and model selection of the oil-casing pressure difference, further sensitivity analysis is performed to identify the key influencing factors affecting the oil-casing pressure difference. This analysis can not only help identify the key influencing factors, but also optimize the drawing of the chart and reduce unnecessary complexity. By calculating the sensitivity coefficients of the various influencing factors affecting the oil-casing pressure difference, the sensitivity of well depth, wellhead oil pressure, pipe diameter, and liquid-gas ratio can be quantitatively analyzed. This process is the key to understanding the changes in the oil-casing pressure difference and reveals the degree of influence of different parameters on the oil-casing pressure difference.

[0140] Combined with the principle of critical liquid carrying flow rate test method, it is believed that gas production can most affect the liquid loading condition of gas wells and is the key factor affecting the liquid loading condition of gas wells. Therefore, gas production is selected as the horizontal axis of the subsequent chart. According to the measured data of gas wells in Changqing Sulige Gas Field, the liquid-gas ratio range is selected as 0~3m 3 / 10 4 m 3 The wellhead oil pressure range is 1 MPa ~5 MPa, the well depth range is 3500m ~3800m, and the gas production range is 0~3×10 4 m 3 , pipe diameter range is 2 3 / 8 and 2 7 / 8 for analysis.

[0141] Figure 3 The following is a comparison of the oil-casing pressure difference with gas production at different well inclination angles. It can be seen that well inclination will only affect the friction pressure drop. When the vertical depth is determined, the increase in well inclination will increase the friction pressure drop in the wellbore. However, when the well inclination angle is less than 40°, the effect of well inclination on the oil-casing pressure difference is small. Therefore, in the selection of parameters for drawing the chart, the effect of well inclination on the oil-casing pressure difference can be ignored.

[0142] Figure 4 This is a comparison chart of the change of oil-casing pressure difference per kilometer with gas production at different well depths. It can be seen that the well depth and the oil-casing pressure difference per kilometer are almost linearly related. Therefore, using the oil-casing pressure difference per kilometer as the vertical coordinate of the plate can eliminate the influence of well depth on the number of drawn plates, thereby reducing the number of drawn plates.

[0143] Figure 5 The well depth is 3500m, the wellhead oil pressure is 1Mpa, and the pipe diameter is 23 The comparison of the pressure difference per kilometer of oil casing obtained with different liquid-gas ratios under the condition of / 8 with the change of gas production shows that with the increase of gas production, the pressure difference per kilometer of oil casing will gradually decrease, and the decreasing trend will gradually become gentle. The greater the gas production, the greater the impact of the liquid-gas ratio on the pressure difference per kilometer of oil casing.

[0144] Figure 6 The well depth is 3500m, the liquid-gas ratio is 1 cubic meter / 10,000 cubic meter, and the pipe diameter is 2 3 The comparison of the pressure difference per kilometer of oil casing obtained by different wellhead oil pressures under the condition of / 8 with the change of gas production shows that when the gas production is small and large, the influence of wellhead oil pressure on the pressure difference per kilometer of oil casing is small. 4 m 3 / d ~1.5×10 4 m 3 / d range, the wellhead oil pressure has a greater impact on the oil-casing pressure difference per kilometer.

[0145] Figure 7 This is a comparison chart of the change in the oil-casing pressure difference per kilometer with gas production under the conditions of a well depth of 3500m, a liquid-gas ratio of 1 cubic meter / 10,000 cubic meter, and a wellhead oil pressure of 1MPa. It can be seen that the large diameter (diameter 2 7 / 8) When the gas production is low, the pressure difference of the oil casing per kilometer is greater than that of the small diameter (pipe diameter 2 3 / 8), while when the gas production is high, the oil-casing pressure difference per kilometer of the small diameter pipe is greater than the oil-casing pressure difference per kilometer of the large diameter pipe.

[0146] By calculating the sensitivity coefficients of various factors affecting the oil-casing pressure difference per kilometer, the sensitivity coefficients of well depth, wellhead oil pressure, pipe diameter, and liquid-gas ratio can be quantitatively analyzed. The sensitivity coefficient calculation formula is as follows:

[0147] (13);

[0148] in, is the casing pressure per kilometer of wellhead, MPa; is the oil pressure per kilometer at the wellhead, MPa; It is the difference between the casing pressure per kilometer at the wellhead and the oil pressure per kilometer at the wellhead, that is, the oil-casing pressure difference per kilometer; is the change in oil-casing pressure difference; For the Influencing factors; For the The amount of change of the influencing factors; is the sensitivity coefficient, dimensionless.

[0149] The sensitivity coefficient of a single influencing factor is calculated by changing a single influencing factor. For example, the process of calculating the sensitivity coefficient of the liquid-gas ratio influencing factor is: when the well depth is 3500m, the wellhead oil pressure is 1Mpa, and the pipe diameter is 2 3 / 8, liquid-gas ratio 1m 3 / 10 4 m 3 , gas production 0.2×10 4 m 3 When the oil-casing pressure difference is 3.54Mpa, only the liquid-gas ratio is changed to 1.5m 3 / 10 4 m 3 , the oil-casing pressure difference in this case is calculated to be 3.61MPa. From this, we can calculate: ; ; ; ; available .

[0150] By using the sensitivity coefficient at each gas production rate Average values ​​to determine individual influencing factors The sensitivity of the

[0151] Finally, through a large number of calculations, the sensitivity coefficients of all influencing factors were calculated.

[0152] The range of oil-casing pressure difference is analyzed. First, the liquid-gas ratio is 0.5 m 3 / 10 4 m 3 , wellhead oil pressure 1MPa, well depth 3500m, pipe diameter 2 3 The gas well in the case of / 8 is used as a reference benchmark. The casing differential pressure value in this case is calculated by changing one of the influencing factors. Then, the casing differential pressure value is subtracted from the casing differential pressure benchmark value before the variable is changed to obtain the casing differential pressure change value. Furthermore, the influence of the change range of a single influencing factor on the casing differential pressure can be analyzed through the casing differential pressure change range.

[0153] Figure 8 This is a comparison chart of the sensitivity coefficients of various influencing factors of gas production wells. It can be seen that the sensitivity of the oil-casing pressure difference per kilometer to the liquid-gas ratio, wellhead oil pressure, and pipe diameter is similar.

[0154] Fig. 9 The following is a comparison chart of the change of oil-casing pressure difference per kilometer with gas production under different liquid-gas ratios. It can be seen that with the increase of gas production, the influence of liquid-gas ratio on oil-casing pressure difference per kilometer becomes greater and greater, and the liquid-gas ratio is positively correlated with gas production. The oil-casing pressure difference is obtained by subtracting the calculated oil-casing pressure difference from the reference oil-casing pressure difference.

[0155] Fig.10This is a comparison chart of the change of oil-casing pressure difference per kilometer with gas production under different wellhead oil pressures. It can be seen that with the increase of gas production, the influence of wellhead oil pressure on oil-casing pressure difference becomes smaller and smaller, and the size of wellhead oil pressure is negatively correlated with the size of gas production. After the gas production exceeds the threshold, the influence of wellhead oil pressure on oil-casing pressure difference can be ignored. The oil-casing pressure difference is obtained by subtracting the calculated oil-casing pressure difference from the benchmark oil-casing pressure difference.

[0156] Fig.11 For pipe diameter 2 7 / 8 and the pipe diameter 2 as the reference value 3 / 8Comparison of the change of oil-casing pressure difference per kilometer with gas production after difference analysis. This figure is a difference analysis, using a pipe diameter of 2 3 / 8 as the reference value, pipe diameter 2 7 / 8The analysis results after subtracting it show that as the gas production increases, the effect of the change in pipe diameter on the oil-casing pressure difference first decreases and then increases after exceeding the threshold. Under low and high gas production conditions, the effect of pipe diameter on the oil-casing pressure difference is more obvious. The oil-casing pressure difference is obtained by subtracting the calculated oil-casing pressure difference from the benchmark oil-casing pressure difference.

[0157] Table 3 shows the influence of various influencing factors on the oil-casing pressure difference within their respective ranges. It can be seen that the liquid-gas ratio has the greatest influence on the change of the oil-casing pressure difference, while the well depth has the least influence on the change of the oil-casing pressure difference. Although the sensitivity coefficient of the wellhead oil pressure is the smallest, the range of change of the wellhead oil pressure is much larger than the change response of other parameters, and its influence on the oil-casing pressure difference cannot be ignored.

[0158] Table 3 Summary of range analysis results

[0159] .

[0160] By comparing the sensitivity coefficients and the changes in the oil-casing pressure difference, it is determined that the key factors affecting the oil-casing pressure difference per kilometer are the liquid-gas ratio, wellhead oil pressure and pipe diameter.

[0161] Step 5: After completing the calculation of the oil-casing pressure difference and the sensitivity analysis, the oil-casing pressure difference per kilometer is used as the ordinate, and the daily gas production is used as the abscissa, combined with parameters such as liquid-gas ratio, wellhead oil pressure and pipe diameter, to generate a liquid accumulation discrimination chart. This process is the key link in converting the above analysis results into practical applications. The specific process is:

[0162] After determining the key influencing factors of the pressure drop algorithm and the oil-casing pressure difference, the wellhead oil pressure is first input into the Gray model. After the Gray model is iteratively calculated by multiphase pipe flow, the pressure distribution of the well section with a well inclination angle less than 45° is obtained; then, the starting point pressure is input into the Beggs-Brill model. After the Beggs-Brill model is iteratively calculated by multiphase pipe flow, the pressure distribution of the well section with a well inclination angle greater than or equal to 45° is obtained, and finally the bottom hole pressure of the entire gas well is obtained; then the wellhead casing pressure is calculated using the bottom hole pressure through the MATLAB programming software. The oil-casing pressure difference per kilometer is selected as the vertical coordinate of the plate, and through the critical liquid carrying flow principle analysis, the gas production can better reflect the liquid accumulation of the gas well than other parameters, so the gas production is selected as the horizontal coordinate variable of the plate.

[0163] Through this chart, on-site technicians can quickly and accurately determine whether a gas well has a bottom-hole liquid accumulation problem based on changes in wellhead oil pressure and daily gas production.

[0164] The present invention aims at the actual production situation of gas wells, normalizes the influence of well depth to per kilometer through unified processing of well depth, and significantly reduces the number of plates drawn. At the same time, the value points of liquid-gas ratio and daily gas production are optimized to ensure that the plates have wide applicability and cover gas wells of different types and conditions. This optimization process is based on the results of sensitivity analysis, which ensures the practicality and accuracy of the plates.

[0165] After analyzing the liquid-filled gas wells in Sulige, Changqing, it was found that the daily gas production of most liquid-filled gas wells is mainly concentrated in the range of 0~1×10 4 m 3 Therefore, the data points with daily gas production less than 10,000 cubic meters should be encrypted. The calculation point for daily gas production is: 0.2×10 4 m, 0.4×10 4 m, 0.6×10 4 m, 0.8×10 4 m, 1×10 4 m, 1.5×10 4 m, 2×10 4 m, 2.5×10 4 m, 3×10 4 m 3 After analyzing the range of changes, it can be seen that the changes in the oil-casing pressure difference caused by the change in the liquid-gas ratio and the wellhead oil pressure are relatively uniform, so the values ​​are uniformly taken within the range of changes of these independent variables. The calculation point for the liquid-gas ratio is: 0.5m 3 / 10 4 m 3 , 1m 3 / 10 4 m 3 , 1.5m 3 / 104 m 3 , 2m 3 / 10 4 m 3 , 2.5m 3 / 10 4 m 3 、3m 3 / 10 4 m 3 The calculation points for wellhead oil pressure are 1Mpa, 2Mpa, 3Mpa, 4Mpa, and 5MPa. The pipe diameter is 2 7 / 8 and 2 3 / 8 calculation. To complete the plate drawing, 10 plates need to be drawn, including 60 data curves in total, such as Figure 12-Figure 21 shown. Fig.12 The wellhead oil pressure is 1Mpa and the pipe diameter is 2 7 Schematic diagram of the plate in the case of / 8. Fig.13 The wellhead oil pressure is 2Mpa and the pipe diameter is 2 7 Schematic diagram of the plate in the case of / 8. Fig.14 The wellhead oil pressure is 3Mpa and the pipe diameter is 2 7 Schematic diagram of the plate in the case of / 8. Fig.15 The wellhead oil pressure is 4Mpa and the pipe diameter is 2 7 Schematic diagram of the plate in the case of / 8. Fig.16 The wellhead oil pressure is 5Mpa and the pipe diameter is 2 7 Schematic diagram of the plate in the case of / 8. Fig.17 The wellhead oil pressure is 1Mpa and the pipe diameter is 2 3 Schematic diagram of the plate in the case of / 8. Fig.18 The wellhead oil pressure is 2Mpa and the pipe diameter is 2 3 Schematic diagram of the plate in the case of / 8. Fig.19 The wellhead oil pressure is 3 Mpa and the pipe diameter is 2 3 Schematic diagram of the plate in the case of / 8. Fig. 20 The wellhead oil pressure is 4 MPa and the pipe diameter is 2 3 Schematic diagram of the plate in the case of / 8. Fig.21 The wellhead oil pressure is 5Mpa and the pipe diameter is 2 3 Schematic diagram of the plate in the case of / 8.

[0166] Fig. 22 This is an example of the actual application of the gas well liquid loading identification chart, showing the liquid-gas ratio of 1 m 3 / 10 4 m 3 , wellhead oil pressure is 1 Mpa, pipe diameter is 2 7 / 8 gas well critical liquid accumulation curve. The gas wells with the closest wellhead oil pressure, well depth, pipe diameter and curve parameters in the field test data are selected for analysis. According to the oil-casing pressure difference discrimination mechanism, wells above the critical liquid accumulation curve are judged as liquid accumulation wells, and wells below the critical liquid accumulation curve are judged as non-liquid accumulation wells.

[0167] Of course, the above description is not a limitation of the present invention, and the present invention is not limited to the above examples. Changes, modifications, additions or substitutions made by technicians in this technical field within the essential scope of the present invention should also fall within the protection scope of the present invention.

Claims

1. A method for generating a gas well liquid loading identification chart based on oil-casing pressure difference, characterized in that: The steps include: Step 1: Collect the actual gas production well data of the oil field and calculate the bottom hole pressure of the gas well bore. The specific process of calculating the bottom hole pressure of the gas well bore is as follows: Step 1.1, the pressure drop in the gas wellbore consists of friction pressure drop, gravity pressure drop and acceleration pressure drop. The friction pressure drop, gravity pressure drop and acceleration pressure drop are calculated respectively; Step 1.2, according to the friction pressure drop, gravity pressure drop and acceleration pressure drop, the pressure distribution is calculated section by section from the wellhead to the bottom of the well; first, the known wellhead oil pressure and wellhead temperature are set at the wellhead position; then, starting from the wellhead position, the pressure is calculated downward section by section, and the starting pressure of each section is the ending pressure of the previous section; Step 1.3: Use the step-by-step accumulation method in step 1.2 to gradually calculate the pressure change from the wellhead to the bottom of the well. The pressure in the last section is the bottom hole pressure. Step 2: Calculate the wellhead casing pressure by combining the static gas column pressure formula and the natural gas compression factor calculation formula, and then obtain the oil casing pressure difference; The specific process of calculating the wellhead casing pressure is: Step 2.1, set the initial natural gas compression factor to 1; Step 2.2: According to the static gas column pressure calculation formula, when the natural gas compression factor is 1, calculate the initial value of the wellhead casing pressure. ; The calculation formula for static air column pressure is: (5)； in, To go deep from the gas well; is the static air column pressure; is the wellhead casing pressure; is an exponential function with base e; is the gas density under standard conditions; is the temperature under standard conditions; is the pressure under standard conditions; is the average temperature; is the gas compressibility factor at average temperature and average pressure; Step 2.3: Read the coefficients related to natural gas properties based on the gas well data , , , ; Step 2.4: Calculate the apparent critical temperature of natural gas and apparent critical pressure ; Step 2.5, calculating the relative temperature, relative pressure and relative density of natural gas; Step 2.6, continuously updating the value of the natural gas compression factor according to the natural gas compression factor calculation formula until it converges to a stable value; Step 2.7: Substitute the updated natural gas compression factor and the bottom hole pressure obtained in step 1 into the static gas column pressure calculation formula to calculate the wellhead casing pressure. ; Step 2.8: Make a difference between the wellhead casing pressure and the initial value of the wellhead casing pressure to make a judgment. When the wellhead casing pressure is output, otherwise, the wellhead casing pressure is set to the initial value of the inlet casing pressure, and the process from step 2.3 to step 2.8 is repeated; The wellhead oil pressure has been preset, and the oil-casing pressure difference can be obtained by subtracting the wellhead oil pressure from the wellhead casing pressure; Step 3, select different pressure drop algorithms for different well inclination angles; Step 4: Analyze the sensitivity and variation range of the oil-casing pressure difference to all influencing factors, and determine the key influencing factors for the oil-casing pressure difference per kilometer; By calculating the sensitivity coefficients of various factors affecting the oil-casing pressure difference per kilometer, the sensitivity coefficients of well depth, wellhead oil pressure, pipe diameter, and liquid-gas ratio are quantitatively analyzed; The sensitivity coefficient of a single influencing factor is calculated by changing the single influencing factor; the sensitivity coefficient of a single influencing factor is determined by the average value of the sensitivity coefficient at each gas production rate; then the sensitivity coefficients of all influencing factors are calculated; finally, by comparing the sensitivity coefficients and the change in the oil-casing pressure difference, it is determined that the key influencing factors for the oil-casing pressure difference per kilometer are the liquid-gas ratio, the wellhead oil pressure and the pipe diameter; Step 5: After completing the calculation of the oil-casing pressure difference and the sensitivity analysis, the oil-casing pressure difference per kilometer is used as the vertical coordinate, the daily gas production is used as the horizontal coordinate, and the liquid-gas ratio, wellhead oil pressure and pipe diameter are combined to generate a liquid accumulation identification chart.

2. The method for generating a gas well liquid loading identification chart based on oil-casing pressure difference according to claim 1, characterized in that: In step 1, the gas production well data include: natural gas composition, natural gas properties, gas production, liquid-gas ratio, wellhead oil pressure, well depth, and pipe diameter.

3. The method for generating a gas well liquid loading discrimination chart based on oil-casing pressure difference according to claim 1, characterized in that: In step 1.1, the calculation formula of friction pressure drop is: (1)； in, is the friction pressure drop; is the friction coefficient; is the wellbore length; is the wellbore diameter; is the fluid density; is the flow rate; The formula for calculating gravity pressure drop is: (2)； in, is the gravity pressure drop; is the fluid density; is the acceleration due to gravity; is the wellbore length; is the angle between the wellbore and the horizontal direction; The calculation formula for the acceleration voltage drop is: (3)； in, is the acceleration pressure drop; is the flow velocity gradient; The calculation formula for step 1.2 is: (4)； in, is the sequence number of the current segment; is the serial number of the next paragraph; For the next section of pressure; is the starting pressure of the current segment; is the friction pressure drop of the current section; is the gravity pressure drop of the current segment; is the acceleration voltage drop of the current segment.

4. The method for generating a gas well liquid loading discrimination chart based on oil-casing pressure difference according to claim 3, characterized in that: In step 2, the calculation formula of the natural gas compression factor is: (6)； (7)； (8)； (9)； in, is the natural gas compression factor; is the relative temperature of natural gas; is the thermodynamic temperature of natural gas; is the apparent critical temperature of natural gas; is the relative density of natural gas; is the relative pressure of natural gas; is the pressure of natural gas; is the apparent critical pressure of natural gas; and The calculation formula is as follows: (10)； (11)； in, is the relative density of natural gas; , , , are different coefficients related to the properties of natural gas.

5. The method for generating a gas well liquid loading identification chart based on oil-casing pressure difference according to claim 1, characterized in that: In step 3, when the well inclination angle of the gas well is less than 45°, the Hagedorn-Brown model is used to calculate the pressure drop, and when the well inclination angle is greater than or equal to 45°, the Beggs-Brill model is used to calculate the pressure drop.

6. The method for generating a gas well liquid loading discrimination chart based on oil-casing pressure difference according to claim 1, characterized in that: In step 4, all influencing factors include liquid-gas ratio, well depth, wellhead oil pressure, pipe diameter and gas production; Select the liquid-gas ratio range from 0 to 3m 3 / 10 4 m 3 The wellhead oil pressure range is 1 MPa ~5 MPa, the well depth range is 3500m ~3800m, and the gas production range is 0~3×10 4 m 3 , pipe diameter range is 2 3 / 8 and 2 7 / 8 for analysis; The analysis shows that well inclination will only affect the friction pressure drop. When the vertical depth is determined, the increase of well inclination angle will increase the friction pressure drop in the wellbore. However, when the well inclination angle is less than 40°, the effect of well inclination on the oil-casing pressure difference is small. Therefore, in the selection of parameters for drawing the chart, the effect of well inclination on the oil-casing pressure difference is ignored. There is a linear relationship between the well depth and the oil-casing pressure difference per kilometer. Therefore, the oil-casing pressure difference per kilometer is used as the ordinate of the plate, eliminating the influence of the well depth on the number of plates drawn and reducing the number of plates drawn. The sensitivity coefficient calculation formula is as follows: (13)； in, is the casing pressure per kilometer of wellhead; is the oil pressure per kilometer at the wellhead; It is the difference between the casing pressure per kilometer at the wellhead and the oil pressure per kilometer at the wellhead, that is, the oil-casing pressure difference per kilometer; is the change in oil-casing pressure difference; For the Influencing factors; For the The amount of change of the influencing factors; is the sensitivity coefficient.

7. The method for generating a gas well liquid loading identification chart based on oil-casing pressure difference according to claim 1, characterized in that: The specific process of step 5 is as follows: first, the wellhead oil pressure is input into the Gray model, and the Gray model obtains the pressure distribution of the well section with a well inclination angle less than 45° after iterative calculation of the multiphase pipe flow; then, the starting point pressure is input into the Beggs-Brill model, and the Beggs-Brill model obtains the pressure distribution of the well section with a well inclination angle greater than or equal to 45° after iterative calculation of the multiphase pipe flow, and finally the bottom hole pressure of the entire gas well is obtained; then, the wellhead casing pressure is calculated using the bottom hole pressure through the MATLAB programming software; the oil casing pressure difference per kilometer is selected as the ordinate, and the gas production is selected as the abscissa to construct a gas well liquid accumulation discrimination chart; Through this chart, on-site technicians can determine whether the current gas well has a bottom hole liquid accumulation problem based on changes in wellhead oil pressure and daily gas production. In the gas well liquid accumulation identification chart, wells above the critical liquid accumulation curve are identified as liquid accumulation wells, and wells below the critical liquid accumulation curve are identified as non-liquid accumulation wells.

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