A method for diagnosing fluid accumulation in downhole throttling gas wells

Abstract

This invention relates to a method for diagnosing fluid accumulation in downhole choked gas wells, belonging to the field of gas field development technology. The method includes the following steps: obtaining the pressure before and after the choke nozzle of the gas well to be diagnosed; substituting the pressure before the choke nozzle as the oil pressure and the annular pressure at the choke location as the casing pressure into a mathematical calculation model of the average pressure gradient of the wellbore in non-downhole choked gas wells, calculating the average pressure gradient at different depths in the pipe flow section below the choke, then obtaining the flowing pressure at different depths in the pipe flow section below the choke, and analyzing whether there are points of varying flowing pressure density in the pipe flow section below the choke; if there are points of varying flowing pressure density, the gas well to be diagnosed has fluid accumulation; if there are no points of varying flowing pressure density, the gas well to be diagnosed has no fluid accumulation. This method for diagnosing fluid accumulation in downhole choked gas wells solves the problem of large errors in existing methods for judging fluid accumulation in downhole choked gas wells, especially for directional and horizontal wells.

Description

Technical Field

[0001] This invention relates to a method for diagnosing fluid accumulation in downhole throttling gas wells, belonging to the field of gas field development technology. Background Technology

[0002] During the continuous development of gas fields, as gas well pressure and production decrease, water and liquid accumulation gradually occurs in the wells. The advancement of water and liquid accumulation on the wellbore and bottom, along with the hazards caused by improper extraction methods, and the gradual decrease in gas content within the reservoir leading to a continuous drop in internal pressure, prevent water or liquid droplets from being discharged with the gas, resulting in water and liquid accumulation within the well. This affects the efficiency of natural gas production and can even lead to premature well shutdown. Drainage gas production technology can effectively solve the problem of water and liquid accumulation within gas wells, reducing the hazards caused by this accumulation, thereby increasing natural gas production and extending the well's lifespan. Currently, foam drainage gas production technology is the most widely used method among various drainage gas production processes. The application of this technology requires comprehensive optimization of the foaming agent injection volume and injection system based on factors such as well water production, degree of accumulation, and accumulation cycle to achieve economical and efficient foaming drainage.

[0003] Because the timing, cycle, and dosage of the foam drainage process for gas wells all require accurate understanding of whether fluid has accumulated in the well, the degree of accumulation, and the accumulation cycle, it is also necessary to understand the bottom hole pressure data to further optimize the drainage system while rationally allocating gas production. Therefore, diagnosing fluid accumulation in gas wells is crucial for the effective implementation and optimization of the drainage and gas production process. Currently, methods for judging fluid accumulation in self-flowing wells include empirical methods based on production changes, wellhead and casing pressure methods, critical flow velocity methods, kinetic energy factor methods, measured pressure gradient curve methods, condensate volume calculation methods, and well test curve analysis methods. Among these methods, empirical methods based on production changes and wellhead and casing pressure methods are empirical and have poor accuracy. Critical flow velocity methods, kinetic energy factor methods, condensate volume calculation methods, and well test curve analysis methods are all calculation and analysis methods, applicable under certain conditions, and their effectiveness is generally limited. The measured pressure gradient curve method directly tests the actual pressure distribution and variation characteristics in the wellbore, analyzes the sudden changes in pressure gradient to determine whether the gas well has liquid accumulation and the degree of liquid accumulation, and its application effect is very good.

[0004] The methods described above for judging wellbore fluid accumulation in self-flowing gas wells are all based on wells that are producing gas without downhole throttling devices. However, more and more gas fields are now adopting downhole throttling for production. Downhole throttling transfers the surface nozzles to the wellbore, achieving pressure reduction while utilizing geothermal heat to heat the gas flow after throttling. This reduces surface pipeline pressure, prevents hydrate formation, eliminates the need for surface heating devices, and reduces alcohol injection. However, because the pressure and temperature systems change before and after throttling, the calculation and analysis methods commonly used for judging wellbore fluid accumulation in non-downhole throttling gas wells cannot accurately judge fluid accumulation in downhole throttling gas wells. Furthermore, due to the presence of the throttling device, conventional methods cannot be used to judge fluid accumulation in downhole throttling gas wells by conducting pressure tests on the entire wellbore. Summary of the Invention

[0005] The purpose of this invention is to provide a highly accurate method for diagnosing fluid accumulation in downhole throttling gas wells.

[0006] To achieve the above objectives, the technical solution adopted by this invention is as follows:

[0007] A method for diagnosing fluid accumulation in downhole choke gas wells includes the following steps: obtaining the pressure before and after the choke nozzle of the gas well to be diagnosed; substituting the pressure before the choke nozzle as the oil pressure and the annular pressure at the choke location as the casing pressure into a mathematical calculation model for the average pressure gradient of the wellbore in non-downhole choke gas wells, calculating the average pressure gradient at different depths in the pipe flow section below the choke, then obtaining the flowing pressure at different depths in the pipe flow section below the choke, and analyzing whether there are points of varying flowing pressure density in the pipe flow section below the choke; if there are points of varying flowing pressure density, then the gas well to be diagnosed has fluid accumulation; if there are no points of varying flowing pressure density, then the gas well to be diagnosed has no fluid accumulation.

[0008] The mathematical calculation model for the average pressure gradient of the wellbore in the non-downhole throttling gas well is established using the following steps: Based on the gas-liquid ratio or liquid-gas ratio data corresponding to the wellbore flowing pressure test dates of multiple non-downhole throttling gas wells in the gas field where the gas well to be diagnosed is located, which use self-flowing production and have tested wellbore flowing pressure, the average pressure gradient data of the wellbore corresponding to each flowing pressure test point of each non-downhole throttling gas well, as well as the depth measurement data, vertical depth data, and well inclination angle data in the well depth trajectory, a mathematical calculation model is established using statistical analysis methods with the average pressure gradient of the gas wellbore as the dependent variable and the well inclination angle, gas-liquid ratio or liquid-gas ratio, casing pressure, and oil pressure as independent variables.

[0009] This invention provides a method for diagnosing fluid accumulation in downhole choke gas wells. It fully utilizes measured wellbore flowing pressure data, production dynamics data, and static data from non-downhole choke gas wells within the gas field to establish mathematical relationships between the wellbore pressure gradient and key pressure-influencing factors such as oil pressure, casing pressure, fluid production, gas production, and well inclination angle. This relationship is then combined with the pressure before the choke nozzle to derive the flowing pressure distribution characteristics of the lower tubing section of the choke. This allows for analysis of the gas well's density variation surface and evaluation of whether fluid accumulation has occurred. This diagnostic method is applicable to gas wells without fluid accumulation above the choke nozzle. It not only solves the problem that traditional tubing-based wellbore fluid accumulation assessment methods are unsuitable for downhole choke gas wells but also addresses the issue of large errors in existing downhole choke gas well fluid accumulation assessment methods, particularly for directional and horizontal wells. This diagnostic method offers advantages such as comprehensive parameter consideration, simplified calculation, and wide applicability.

[0010] Furthermore, the pressure before the nozzle of the choke in the gas well to be diagnosed is calculated based on the downhole choke gas-liquid two-phase flow model. For chokes with a pressure sensor installed before the nozzle, the pressure before the nozzle can also be obtained through actual measurement.

[0011] Further, the method for obtaining the pressure after the choke nozzle of the gas well to be diagnosed includes the following steps: substituting the casing pressure, oil pressure, gas-liquid ratio or liquid-gas ratio of the gas well to be diagnosed, as well as the well inclination angle of the choke position, into the mathematical calculation model of the average pressure gradient of the wellbore in the upper pipe section of the downhole choke gas well to obtain the pressure after the choke nozzle of the gas well to be diagnosed; the mathematical calculation model of the average pressure gradient of the wellbore in the upper pipe section of the downhole choke gas well is established by a method including the following steps: based on the gas-liquid ratio or liquid-gas ratio data of multiple downhole choke gas wells in the gas field where the gas well to be diagnosed is located, which use self-flowing production and have tested wellbore flowing pressure, the average pressure gradient data of the wellbore corresponding to each flowing pressure test point of each downhole choke gas well, as well as the depth measurement data, vertical depth data, and well inclination angle data in the well depth trajectory, a statistical analysis method is used to establish a mathematical calculation model with the average pressure gradient of the gas wellbore as the dependent variable and the well inclination angle, gas-liquid ratio or liquid-gas ratio, casing pressure, and oil pressure as independent variables. In addition, the pressure after the throttle nozzle of the gas well to be diagnosed can also be obtained by the flowing pressure test of the well to be evaluated.

[0012] It is understood that the average pressure gradient data of the wellbore corresponding to the flowing pressure test point is the average pressure drop per unit vertical depth between the corresponding flowing pressure test point and the wellhead oil pressure, calculated using the flowing pressure and wellhead oil pressure at the corresponding flowing pressure test point. The unit vertical depth can be 1m, 10m, 20m, 50m, or 100m. Since the average pressure gradient at different depths in the pipe flow section below the choke is calculated using the oil pressure as the pressure before the choke nozzle of the gas well to be diagnosed, and employing a mathematical calculation model for the average pressure gradient of the wellbore in a non-downhole choking gas well, the average pressure gradient at different depths in the pipe flow section below the choke is the average pressure drop per unit vertical depth between the corresponding depth point and the position before the choke nozzle. For the pipe flow section below the choke, a depth point can be taken at each increase in well inclination angle from the choke position, with the depth point reaching a well inclination angle of 65~75°. A depth point reaching a well inclination angle of 65~75° is sufficient for the judgment requirement; for example, a depth point reaching a well inclination angle of 70° is acceptable. Furthermore, a depth point is taken for every increase of 0.3° to 7°, for example, a depth point is taken for every increase of 0.5° to 5°.

[0013] The flow pressure at different depths in the pipe section below the throttle can be obtained based on the average pressure gradient. The flow pressure at each depth is the sum of the pressure in front of the throttle nozzle and the pressure drop from the in front of the throttle nozzle to the corresponding depth. The pressure drop from the in front of the throttle nozzle to the corresponding depth is calculated based on the average pressure gradient at that depth.

[0014] Furthermore, the statistical analysis method used in establishing the mathematical calculation model of the average pressure gradient of the wellbore in non-downhole throttling gas wells and the mathematical calculation model of the average pressure gradient of the wellbore in the upper pipe section of the throttling device in downhole throttling gas wells is the multiple regression analysis method.

[0015] Furthermore, the mathematical model for calculating the average pressure gradient of the wellbore in the upper section of the flow channel of the downhole choke gas well is as follows:

[0016] P avg1 =a1+b1×sin(90-θ) +c1×lnGLR+d1×ln(P c -P t )+e1×P c ;

[0017] In the formula, P avg1 The gas wellbore average pressure gradient is expressed in MPa / 100m; θ is the well inclination angle in degrees; GLR is the gas-liquid ratio in units of 10. 4 m 3 / m 3 ;P c The pressure is measured in MPa; P t The pressure is measured in MPa; a1, b1, c1, d1, and e1 are multiple regression coefficients, which are constants.

[0018] Furthermore, the mathematical model for calculating the average pressure gradient in the wellbore of a non-downhole throttling gas well is as follows:

[0019] P avg2 =a2+b2×sin(90-θ) +c2×lnGLR+d2×ln(P c -P t )+e2×P c ;

[0020] In the formula, P avg2 The gas wellbore average pressure gradient is expressed in MPa / 100m; θ is the well inclination angle in degrees; GLR is the gas-liquid ratio in units of 10. 4 m 3 / m 3 ;P c The pressure is measured in MPa; P t 1 represents oil pressure, in MPa; a2, b2, c2, d2, and e2 are multiple regression coefficients, which are constants.

[0021] Furthermore, the method for determining whether there are points of varying flow pressure density in the pipe section below the flow throttle is as follows: Using the vertical depth and flow pressure values ​​corresponding to each depth point in the pipe section below the flow throttle, a linear fit is performed between the vertical depth and the flow pressure values. If the correlation coefficient after linear fitting of all depth points is less than a set value A, a point of varying flow pressure density exists; if the correlation coefficient after linear fitting of all points is greater than or equal to the set value A, then no point of varying flow pressure density exists. The set value A is 0.7 to 0.8. A value between 0.7 and 0.8 is acceptable to meet the judgment requirements; for example, a set value A of 0.75 is used. Furthermore, when performing linear fitting of vertical depth and flow pressure values, the vertical depth is used as the ordinate and displayed in reverse order, while the flow pressure value is used as the abscissa.

[0022] Furthermore, when diagnosing the presence of a flow pressure variation point in the wellbore, the downhole throttling gas well fluid accumulation diagnosis method further includes the following steps: dividing all depth points into upper and lower segments according to their vertical depth from smallest to largest, performing linear fitting between the vertical depth and the flow pressure value, and obtaining the intersection point of the two fitted lines when the correlation coefficients of both the upper and lower linear fitting segments are ≥ a set value A. The set value A is 0.7~0.8, such as setting A to 0.75. The intersection point of the two fitted lines is recorded as the specific location of the flow pressure variation point.

[0023] Furthermore, the above-mentioned downhole throttling gas well fluid accumulation diagnosis method also includes the following steps: calculating the wellbore fluid accumulation volume based on the specific location of the flow pressure change density point. The plane where the change density point is located is the equivalent fluid surface position for calculating the fluid accumulation volume. For horizontal wells, the fluid volume V1 in the tubing from the tubing shoe to the plane where the change density point is located, the fluid volume V2 in the annulus above the tubing shoe, and the fluid volume V3 from the tubing shoe to target point A are calculated separately. The sum of V1, V2, and V3 is the wellbore fluid accumulation volume above target point A of the gas well to be diagnosed; target point A refers to the starting position of the horizontal segment in the wellbore trajectory of the horizontal well. For vertical or directional wells, the fluid volume V1 in the tubing from the tubing shoe to the plane where the change density point is located, the fluid volume V2 in the annulus above the tubing shoe, and the fluid volume V3 between the tubing shoe and the top of the perforated section are calculated separately. The sum of V1, V2, and V3 is the wellbore fluid accumulation volume above the top of the perforated section of the gas well to be diagnosed. Attached Figure Description

[0024] Figure 1 This is a flowchart of the downhole throttling gas well liquid accumulation diagnosis method of the present invention;

[0025] Figure 2 This is a schematic diagram of the wellbore for fluid accumulation diagnosis in Embodiment 1 of the present invention;

[0026] Figure 3 This is a schematic diagram of the wellbore for fluid accumulation diagnosis in Embodiment 2 of the present invention. Detailed Implementation

[0027] The technical solution of the present invention will be further described below with reference to specific embodiments.

[0028] In the following examples, well A1 in Example 1 and well A2 in Example 2 are both gas wells in the M gas field that produce gas using downhole throttling. Well A1 is a horizontal well in the M gas field (e.g., Figure 2 As shown), target point A has an inclination depth of 3211m (corresponding to a vertical depth of 3018m), the choke is placed at a depth of 1990m (vertical well section) with a nozzle diameter of 2.9mm, and the gas production tubing shoe is located at an inclination depth of 3014m (corresponding to a well inclination angle of 80°). To analyze the flowing pressure below the choke in the downhole choke well, storage-type temperature and pressure monitoring devices were installed at vertical depths of 2494m (corresponding to a well inclination angle of 0.7°) and 2887m (corresponding to a well inclination angle of 37° and an inclination depth of 2906m). Later data recovery showed that on the diagnosis date, the flowing pressure at a vertical depth of 2494m was 16.5MPa, and the flowing pressure at 2887m was 17MPa. On the day of the fluid accumulation diagnosis, the wellhead oil pressure was 1.3MPa, the casing pressure was 13.8MPa, and the daily gas production was 2.57 × 10⁻⁶. 4 m 3 Daily liquid production 1.3m 3 Gas-liquid ratio 1.98 × 10 4 m 3 / m 3 .

[0029] A2 gas well is a horizontal well in the M gas field (e.g.) Figure 3 As shown), target point A has an inclination depth of 2925m (corresponding to a vertical depth of 2712.08m), the choke has a depth of 1998m (vertical well section) and a nozzle diameter of 2.86mm, and the gas production tubing shoe has an inclination depth of 2681.5m (corresponding to a well inclination angle of 67°). The corresponding wellhead oil pressure on the day of fluid accumulation diagnosis was 1.5MPa, casing pressure was 8.4MPa, and daily gas production was 0.812×10⁻⁶. 4 m 3 Daily liquid production 1.43m 3 Gas-liquid ratio 0.57 × 10 4 m 3 / m 3 .

[0030] Example 1

[0031] The downhole throttling gas well fluid accumulation diagnosis method in this embodiment is used to diagnose fluid accumulation in gas well A1, such as... Figure 1 As shown, it includes the following steps:

[0032] 1) Collect the flow pressure test data of test gas wells in M ​​gas field that use self-flowing production and have tested wellbore flow pressure, as well as the daily gas production, daily liquid production, oil pressure, casing pressure, and well depth trajectory data, vertical depth, and well inclination angle data corresponding to the flow pressure test date. Calculate the gas-liquid ratio data of the gas wells on that day by using the daily gas production and daily liquid production. Some of the data are summarized in Table 1.

[0033] Table 1. Compiled data on flow pressure tests and production dynamics of some self-flowing jet wells in the M gas field.

[0034]

[0035] 2) Organize and preprocess the collected basic data, establish the wellbore average pressure gradient data for each test point of each test well through conversion of flow pressure and depth, establish the daily gas production, daily fluid production, oil pressure, casing pressure, gas-liquid ratio data of each gas well corresponding to each flow pressure test point, and establish the depth, vertical depth, and well inclination angle data in the well depth trajectory corresponding to each flow pressure test point, and establish the original test data database; then, establish two types of gas well original databases according to downhole throttling gas wells and non-downhole throttling gas wells;

[0036] Specifically, the average pressure gradient data of the wellbore at the flow pressure test point of the test gas well is the average pressure gradient data calculated with the wellhead as the starting point. In this embodiment, the average pressure gradient of the wellbore at the flow pressure test point is calculated as follows: (flow pressure at the flow pressure test point - wellhead oil pressure) × 100 / vertical depth of the flow pressure test point relative to the wellhead. The units of the flow pressure at the flow pressure test point and the wellhead oil pressure are MPa, the unit of the vertical depth of the flow pressure test point relative to the wellhead is m, and the unit of the average pressure gradient of the wellbore is MPa / 100m.

[0037] 3) Using sample data from the original database of downhole choke gas wells, a mathematical relationship was established between the average pressure gradient of the wellbore in the upper tubing section of the downhole choke and the dynamic and static data of the gas well using multiple regression analysis. The results are as follows:

[0038] P avg1 =a1+b1×sin(90-θ) +c1×lnGLR+d1×ln(P c -P t )+e1×P c ;

[0039] Among them, P avg1 The gas wellbore average pressure gradient is expressed in MPa / 100m; θ is the well inclination angle in degrees; GLR is the gas-liquid ratio in units of 10. 4 m 3 / m 3 ;P c The pressure is measured in MPa; P t The pressure is measured in MPa; a1, b1, c1, d1, and e1 are multiple regression coefficients. In this example, a1=0.01507, b1=-0.00419, c1=-0.01375, d1=0.00133, and e1=0.004364.

[0040] Using sample data from the original database of non-downhole choke gas wells, a mathematical relationship was established (Formula 2) between the average pressure gradient of the entire wellbore flow section of non-downhole choke wells and dynamic and static data of the gas wells using multiple regression analysis. The results are as follows:

[0041] P avg2 =a2+b2×sin(90-θ) +c2×lnGLR+d2×ln(P c -P t )+e2×P c ;

[0042] Among them, P avg2 The gas wellbore average pressure gradient is expressed in MPa / 100m; θ is the well inclination angle in degrees; GLR is the gas-liquid ratio in units of 10. 4 m 3 / m 3 ;P c The pressure is measured in MPa; P t1 represents oil pressure, in MPa; a2, b2, c2, d2, and e2 are multiple regression coefficients. In this embodiment, a2=0.03507, b2=-0.00418, c2=-0.01376, d2=0.00257, and e2=0.00964.

[0043] 4) For well A1, its current gas-liquid ratio (GLR) is 1.98 × 10⁻⁶. 4 m 3 / m 3 , sleeve pressure P c The oil pressure is 13.8 MPa, P t The pressure is 1.3 MPa, and the well inclination angle θ corresponding to the position of the throttle is 0.4°. Based on this, according to mathematical formula one, the pressure P2 after the throttle nozzle of A1 can be calculated to be 2.6 MPa.

[0044] Using the downhole throttling gas-liquid two-phase flow model to predict the pressure value P1 before the throttling nozzle in well A1, the downhole throttling gas-liquid two-phase flow model is as follows:

[0045] P1=a×GLR b ×Q L / d c

[0046] Where: P1 is the pressure at the nozzle, in MPa; GLR is the gas-liquid ratio, in m³ / s. 3 / m 3 Q L Daily liquid production, unit is m³ 3 d is the diameter of the throttle nozzle in mm; a, b, and c are empirical constants, which can be referenced from previous scholars. In this embodiment, a is 0.14, b is 0.65, and c is 1.88.

[0047] The current gas-liquid ratio (GLR) of well A1 is 1.98 × 10⁻⁶. 4 m 3 / m 3 Daily liquid production 1.3m 3 With a throttle nozzle diameter of 2.9 mm, and substituting it into the above downhole throttle gas-liquid two-phase nozzle flow model, the pressure value P1 in front of the throttle nozzle in well A1 is 15.6 MPa.

[0048] Currently, the annulus pressure drop between the choke point and the wellhead in well A1 is 2.0 MPa. This pressure drop is achieved through the casing pressure P. c And the calculation of annular static pressure drop, throttle position, and annular pressure value P of the oil jacket. cj The result was 15.8 MPa.

[0049] 5) The pressure value P1 before the throttle nozzle and the pressure value P of the annulus cavities at the throttle position calculated in step 4) are used to calculate the pressure value P. cjSubstitute the oil pressure data and casing pressure data into the mathematical relationship in step 3) to calculate the average pressure gradient at different depth points in the pipe flow section below the throttle (taking one depth point for every 5° increase in well inclination angle starting from the throttle position). The average pressure gradient at different depth points is calculated with the position in front of the throttle nozzle as the starting point (the initial oil pressure is the pressure value P1 in front of the throttle nozzle, which is 15.6 MPa), and is distributed in the range of 0.170-0.178 MPa / 100m, with corresponding pressure values ​​in the range of 15.648-17.341 MPa. The results are shown in Table 2.

[0050] The average pressure gradient at the bottom of the throttle was used to calculate the flowing pressure at each depth point in the lower pipe section of the throttle. Then, using the vertical depth and flowing pressure values ​​corresponding to each depth point in the lower pipe section of the throttle, a linear fit was performed on the vertical depth and flowing pressure values. The vertical depth was used as the ordinate and displayed in reverse order, and the flowing pressure value was used as the abscissa. The fitted linear formula for vertical depth and flowing pressure is: y = 574.55x - 6971.5 (R = 0.9968), where: y is the vertical depth in meters; x is the flowing pressure value in MPa. Since the correlation coefficient reached 0.9968, which is greater than 0.75, no density variation points were found, and it was determined that the well did not accumulate fluid.

[0051] Table 2. Calculation results of pressure gradient and flowing pressure value at the lower part of the choke point in Well A1.

[0052]

[0053] Furthermore, the bottom hole flowing pressure was calculated to be 17.39 MPa by using a linear relationship between the vertical depth and the flowing pressure value at different depth points in the lower section of the throttle pipe.

[0054] To determine the accuracy of the downhole throttling gas well fluid accumulation diagnosis method in this embodiment, a multi-point flow temperature and pressure monitoring tool was inserted into the lower part of the throttling device in well A1 to be evaluated. The monitoring results were compared and analyzed with the calculation results of the method in this embodiment, as shown in Table 3. The analysis results in Table 3 show that the absolute error of the flow pressure is less than 0.2 MPa, and the relative error is less than 1%, indicating high accuracy in the calculation results and accurate diagnosis of wellbore fluid accumulation. The actual production process of well A1 also exhibited continuous and stable production characteristics, with a production rate of 100%.

[0055] Table 3 Comparison of Flow Pressure Monitored and Calculated by Instruments at the Lower Part of the Choke in Well A1

[0056]

[0057] Example 2

[0058] The downhole throttling gas well fluid accumulation diagnosis method of this embodiment is used to diagnose fluid accumulation in gas well A2, including the following steps:

[0059] Steps 1), 2), and 3) are the same as steps 1), 2), and 3) in Example 1, and will not be repeated here;

[0060] 4) The pressure P2 after the throttle nozzle of the A2 gas well was obtained by testing with a flow pressure testing tool installed in the wellbore. The results showed that the pressure P2 after the throttle nozzle of the A2 gas well to be diagnosed was 3.1 MPa, and there was no density change surface on the upper part of the throttle and no liquid accumulation on the upper part of the throttle.

[0061] The pressure value P1 before the choke nozzle in well A2 was calculated using the established downhole choke gas-liquid two-phase flow model. The downhole choke gas-liquid two-phase flow model used is as follows:

[0062] P1=a×GLR b ×Q L / d c

[0063] Where: P1 is the pressure at the nozzle, in MPa; GLR is the gas-liquid ratio, in m³ / s. 3 / m 3 Q L Daily liquid production, unit is m³ 3 d represents the throttle nozzle diameter in mm; a, b, and c are empirical constants. In this embodiment, a is 0.14, b is 0.65, and c is 1.88.

[0064] The current gas-liquid ratio in well A2 is 0.57 × 10⁻⁶. 4 m 3 / m 3 Daily liquid production 1.43m 3 With a throttle nozzle diameter of 2.86 mm, substituting into the above downhole throttle gas-liquid two-phase nozzle flow model, the pressure value P1 in front of the throttle nozzle in well A2 is 7.83 MPa.

[0065] Currently, at the location of the choke point in well A2, the pressure drop of the static gas column in the annulus between the casing and the wellhead is 1.3 MPa. This pressure drop is achieved through the casing pressure P... c And the calculation of annular static pressure drop, throttle position, and annular pressure value P of the oil jacket. cj The result was 9.7 MPa.

[0066] 5) The pressure value P1 before the throttle nozzle and the pressure value P of the annulus cavities at the throttle position calculated in step 4) are used to calculate the pressure value P. cjSubstitute the oil pressure data and casing pressure data into the mathematical relationship in step 3) to calculate the average pressure gradient at different depth points in the pipe flow section below the throttle (taking one depth point for every 5° increase in well inclination angle starting from the throttle position); the average pressure gradient at different depth points calculated at this time is the average pressure gradient with the position in front of the throttle nozzle as the starting point of the calculation (the initial oil pressure is the pressure value P1 in front of the throttle nozzle, which is 7.83MPa).

[0067] The flow pressure values ​​at each depth point in the lower pipe section of the throttle were calculated using the average pressure gradient at the bottom of the throttle. Then, the vertical depth and flow pressure values ​​corresponding to each depth point in the lower pipe section of the throttle were used to perform a linear fit between the vertical depth and flow pressure values. The correlation coefficient was 0.67, which is less than 0.75. The overall linear relationship was not linear, and it was determined that there were points where the flow pressure density varied.

[0068] To further determine the location of the pressure-density variation point, the lower pipe section of the downhole choke was divided into upper and lower segments. Linear fitting was performed using the vertical depth and pressure values ​​corresponding to all depth points in each segment. Since there are many methods for dividing the lower pipe section of the downhole choke into upper and lower segments, the case where the correlation coefficients of the upper and lower linear fitting segments are both greater than or equal to 0.75 was determined from various methods. In this case, the fitted vertical depth and pressure relationship of the upper linear fitting segment is y = 370.37x - 899.24 (R = 0.9847), and the fitted vertical depth and pressure relationship of the lower linear fitting segment is y = 188.46x + 770.04 (R = 0.8963). In the fitted vertical depth and pressure relationship formulas, y is the vertical depth in meters (m), and x is the pressure value in MPa. The intersection of the two fitted linear relationships is the location of the density variation point. Analysis shows a density variation surface exists below the throttle (located at a depth of 2498m, corresponding to a well inclination angle of 26°), but the pressure gradient below this surface is 0.56 MPa / 100m. This well is considered to have slight fluid accumulation. Figure 3 As shown.

[0069] Furthermore, the bottom hole pressure was calculated to be 10.3 MPa using the vertical depth and pressure line fitted by the calculation point below the variable density surface.

[0070] Furthermore, in this embodiment, there is liquid accumulation below the variable density surface in the tubing of well A2, and it is a gas-liquid two-phase fluid, considering only gravity pressure drop; if the fluid level in the annulus is above the tubing shoe (judged by bottom hole pressure, casing pressure, and static gas column pressure drop), it consists of a pure liquid section and a pure gas section; the distance from the tubing shoe to target point A is a gas-liquid two-phase flow, considering only gravity pressure drop. Using the calculated bottom hole pressure, casing pressure, and pressure at the variable density point, the fluid volume V1 (52L) in the tubing from the tubing shoe to the variable density point, the fluid volume V2 (326L) in the annulus above the tubing shoe, and the fluid volume V3 (0L) from the tubing shoe to target point A are calculated. The sum of V1, V2, and V3 is the amount of fluid accumulation in the wellbore above target point A of the gas well to be diagnosed. The calculated bottom hole fluid accumulation above target point A is 0.38m. 3 .

[0071] In the later stages, foam drainage measures were strengthened in Well A2, and the daily gas production increased from 8120 m³ / h. 3 / d increased to 9270m 3 The data ( / d) shows that fluid accumulation diagnosis can effectively guide the implementation of fluid drainage measures in gas wells, thereby increasing gas production. The assessment of production dynamics and the implementation of fluid drainage measures demonstrate the effectiveness of the diagnostic results in guiding gas well production.

Claims

1. A method for diagnosing fluid accumulation in downhole throttling gas wells, characterized in that, Includes the following steps: Obtain the pressure before and after the choke nozzle of the gas well to be diagnosed; substitute the pressure before the choke nozzle as the oil pressure and the annular pressure at the choke location as the casing pressure into the mathematical calculation model of the average pressure gradient of the wellbore in non-downhole choking gas wells, calculate the average pressure gradient at different depths of the pipe flow section below the choke, and then obtain the flowing pressure at different depths of the pipe flow section below the choke, and analyze whether there are flowing pressure density change points in the pipe flow section below the choke; if there are flowing pressure density change points, the gas well to be diagnosed has fluid accumulation; if there are no flowing pressure density change points, the gas well to be diagnosed has no fluid accumulation. The method for determining whether there are flow pressure density variation points in the pipe flow section below the throttle is as follows: Using the vertical depth and flow pressure value corresponding to each depth point in the pipe flow section below the throttle, a linear fit is performed on the vertical depth and flow pressure value. If the correlation coefficient after linear fitting of all depth points is less than the set value A, a flow pressure density variation point exists; if the correlation coefficient after linear fitting of all points is greater than or equal to the set value A, then no flow pressure density variation point exists. The set value A is 0.7~0.

8. The mathematical calculation model for the average pressure gradient in the wellbore of the non-downhole throttling gas well is established using a method that includes the following steps: Based on the gas-liquid ratio or liquid-gas ratio data corresponding to the wellbore flowing pressure test dates of multiple non-downhole throttling gas wells in the gas field where the gas well to be diagnosed is located, which use self-flowing production and have tested wellbore flowing pressure, the average wellbore pressure gradient data corresponding to each flowing pressure test point of each non-downhole throttling gas well, as well as the depth measurement data, vertical depth data, and well inclination angle data in the well depth trajectory, a mathematical calculation model is established using statistical analysis methods with the average wellbore pressure gradient of the gas well as the well inclination angle, gas-liquid ratio or liquid-gas ratio, casing pressure, and oil pressure as independent variables.

2. The method for diagnosing fluid accumulation in downhole throttling gas wells according to claim 1, characterized in that, The pressure before the throttle nozzle of the gas well to be diagnosed was calculated based on the downhole throttle gas-liquid two-phase nozzle flow model.

3. The method for diagnosing fluid accumulation in downhole throttling gas wells according to claim 1 or 2, characterized in that, The method for obtaining the pressure after the choke nozzle of the gas well to be diagnosed includes the following steps: substituting the casing pressure, oil pressure, gas-liquid ratio or liquid-gas ratio of the gas well to be diagnosed and the well inclination angle of the choke position into the mathematical calculation model of the average pressure gradient of the wellbore in the upper pipe section of the downhole choke gas well to obtain the pressure after the choke nozzle of the gas well to be diagnosed. The mathematical model for calculating the average pressure gradient of the wellbore in the upper tubing section of the downhole choke gas well is established using a method that includes the following steps: Based on the gas-liquid ratio or liquid-gas ratio data corresponding to the wellbore flowing pressure test dates of multiple downhole choke gas wells in the gas field where the gas well to be diagnosed is located, which use self-flowing production and have tested wellbore flowing pressure, the average pressure gradient data of the wellbore corresponding to each flowing pressure test point of each downhole choke gas well, as well as the depth measurement data, vertical depth data, and well inclination angle data in the well depth trajectory, a mathematical calculation model is established using statistical analysis methods with the average pressure gradient of the gas wellbore as the dependent variable and the well inclination angle, gas-liquid ratio or liquid-gas ratio, casing pressure, and oil pressure as independent variables.

4. The method for diagnosing fluid accumulation in downhole throttling gas wells according to claim 3, characterized in that: The statistical analysis method used in establishing the mathematical calculation model of the average pressure gradient of the wellbore in non-downhole throttling gas wells and the mathematical calculation model of the average pressure gradient of the wellbore in the upper pipe section of the throttling device in downhole throttling gas wells is the multiple regression analysis method.

5. The method for diagnosing fluid accumulation in downhole throttling gas wells according to claim 1 or 2, characterized in that: When diagnosing the presence of a point of varying flow pressure density in the wellbore, the downhole throttling gas well liquid accumulation diagnosis method further includes the following steps: dividing all depth points into upper and lower segments according to the vertical depth from small to large, performing linear fitting of vertical depth and flow pressure value, and obtaining the intersection point of two fitted lines when the correlation coefficients of the upper and lower linear fitting segments are both ≥ a set value A; the set value A is 0.7~0.8.

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