A quantitative judgment method for a wellbore plugging position

Abstract

The present application provides a kind of quantitative judgment method of wellbore plugging position, specific steps are as follows: S1 obtains single well pressure change point pressure recovery curve, obtains pressure recovery time T;S2 respectively obtains the single well daily production Q under the pressure condition of upper and lower plugging point, obtains the fluid velocity υ in wellbore according to single well daily production Q and compression coefficient Z at plugging point;S3 is calculated according to pressure recovery time T and the fluid velocity υ in wellbore, and the depth H of plugging point in wellbore is obtained.The quantitative judgment method of the present application accurately judges the plugging position by pressure recovery method after plugging occurs, changes the approximate plugging point judged according to the nature of fluid in the past, quantifies the risk research of pipe string, guides the stress research of plugging point on site through plugging position, thereby controls the risk, provides basis for single well risk control and plugging removal.

Description

Technical Field

[0001] This invention belongs to the field of oil and gas technology, specifically to a method for quantitatively determining the location of wellbore blockage. Background Technology

[0002] During gas well production, changes in formation fluid pressure and temperature often lead to problems such as wax deposition, scaling, and sand blockage in the wellbore. Wellbore blockage has a significant impact on the stress on the tubing in ultra-deep and ultra-high-pressure gas wells, often resulting in tubing collapse and breakage. However, current domestic methods for determining the location of wellbore blockages are still in the qualitative stage, relying on experience-based judgments combined with fluid properties. This leads to unclear stress points, inaccurate risk point predictions, and insufficient accuracy in assessing the impact on well integrity. Summary of the Invention

[0003] To address the problems existing in the prior art, this invention provides a quantitative method for determining the location of wellbore blockage. By using the pressure recovery method, the depth of the blockage point can be accurately determined quantitatively, providing a basis for single-well risk control and blockage removal.

[0004] To achieve the above objectives, the present invention provides the following technical solution: a method for quantitatively determining the location of wellbore blockage, the specific steps of which are as follows: S1 obtains the pressure recovery curve at the single-well pressure change point and obtains the pressure recovery time T; S2 obtains the daily production Q of a single well under pressure conditions above and below the blockage point, and then calculates the daily production Q of the single well and the natural gas volume coefficient B at the blockage point. g The fluid velocity υ inside the wellbore is obtained; S3 calculates the depth H of the blockage point in the wellbore based on the pressure recovery time T and the fluid velocity υ in the wellbore.

[0005] Furthermore, in S1, when the pressure in the pressure recovery curve of a single well pressure change point continues to rise, the difference between the pressure start time T1 and the pressure peak time T2 is selected as the pressure recovery time T.

[0006] Furthermore, on the pressure recovery curve of the single-well pressure change point, the pressure value corresponding to the time point T1 when the pressure begins to rise is the pressure P1 above the blockage point, and the pressure value corresponding to the time point T2 when the pressure is at its highest is the pressure P2 below the blockage point.

[0007] Furthermore, in S1, when the pressure rises and then falls in the pressure recovery curve at the single-well pressure change point, the difference between the pressure start time T1 and the increase time T2-1 is selected as the pressure recovery time T.

[0008] Furthermore, in S1, the average pressure value of the wellhead pressure P0 during normal production and the wellhead pressure P01 under the conditions of bottom hole flowing pressure Pwf after blockage is the time point corresponding to the pressure recovery curve of the single well pressure change point, which is the increase time point T2-1.

[0009] Furthermore, on the pressure recovery curve of the single-well pressure change point, the pressure value corresponding to the time point T1 when the pressure begins to rise is the pressure P1 above the blockage point, and the pressure value corresponding to the time point T2-1 is the pressure P2 below the blockage point.

[0010] Furthermore, in S2, the formula for calculating the fluid velocity υ is: (3) Where Z is the compressibility coefficient, dimensionless; Q is the daily production per well, in meters. 3 ; d is the pipe diameter, mm; t is the temperature at different points in the wellbore, °C; P 00 P represents standard atmospheric pressure, MPa; P represents pressure at different points in the wellbore, MPa.

[0011] Furthermore, the daily output Q1 under the pressure P1 condition above the blockage point is obtained, and the fluid velocity υ1 above the blockage point is calculated according to formula (3); the daily output Q2 under the pressure P2 condition below the blockage point is obtained according to formula (3), and the fluid velocity υ2 below the blockage point is calculated. The average value of the fluid velocity υ1 above the blockage point and the fluid velocity υ2 below the blockage point is the fluid velocity υ.

[0012] Furthermore, the compressibility factor Z utilizes the natural gas volume factor B. g The calculation yields the following formula: (2) Where t represents the temperature at different points in the wellbore, in °C; P 00 P represents standard atmospheric pressure, MPa; P represents pressure at different points in the wellbore, MPa.

[0013] Furthermore, in S3, the depth H of the blockage point in the wellbore is calculated based on the fluid velocity υ and the pressure recovery time T. The calculation formula is as follows: (4) Where υ is the fluid velocity (m / s), T is the pressure recovery time (min), and H is the blockage depth (m).

[0014] Compared with the prior art, the present invention has at least the following beneficial effects: This invention provides a quantitative method for determining the location of wellbore blockage. After blockage occurs, the pressure recovery time T and the fluid velocity υ in the wellbore are obtained by using the pressure recovery method, thereby accurately determining the depth H of the blockage point in the wellbore. This method changes the previous method of judging the approximate blockage point based on fluid properties, making the risk assessment of the tubing string more quantitative. Furthermore, the blockage location can guide the on-site stress assessment of the blockage point, thereby controlling the risk. Furthermore, the method of the present invention can also generate a table to determine the relationship between the blockage time and location of a single well, which can be used as part of the integrity management of high-pressure gas wells, improve the safety management level of high-risk wells on site, and ensure the safe and efficient production of gas wells. Attached Figure Description

[0015] Figure 1 Oil pressure recovery curve of a certain well; Figure 2 Schematic diagram of pressure rise at different depths of blockage in a well; Figure 3 Timetable of pressure recovery at different depths of blockage in a well; Figure 4 Early warning table of wellbore blockage depth; Figure 5 Standard chart for the depth of blockage points. Detailed Implementation

[0016] The present invention will be further described below with reference to the accompanying drawings and specific embodiments.

[0017] This invention provides a method for quantitatively determining the location of wellbore blockage, the specific steps of which are as follows: Step 1: Analyze the propagation pattern of wellhead pressure to determine that after blockage occurs, production continues. The changes in wellhead pressure are mainly reflected in the increase in flow rate and volume. When the blockage weakens or disappears, the high-pressure zone below the blockage is transmitted to the low-pressure zone above, the flow rate begins to increase, the volume increases, and the pressure rises. The pressure rise is related to the fluid volume, that is, it is related to the fluid velocity. For a fluid, taking a small variable element and approximating constant volume, the pressure is expressed as a function of the fluid velocity υ, i.e.: f(P) = f(υ)·f(T) Where P is pressure; υ is fluid velocity; and T is pressure recovery time. Therefore, it can be seen that after the blockage (throttling) is reduced, the wellhead pressure increases with the increase of volume. This volume is the gas volume under standard conditions. Therefore, the pressure recovery is related to the fluid volume, and the fluid volume is related to the fluid velocity. Thus, it can be seen that when the blockage is removed, the pressure recovery time T is related to the fluid velocity υ. Step 2: Export the pressure curve and analyze the recovery. Currently, most high-pressure gas well production is automated, with big data constantly recording well production pressure and output. Therefore, before calculating the depth of the blockage point, the pressure recovery curve at the single-well pressure change point is exported, such as... Figure 1 As shown, the analysis of the pressure recovery is as follows: When gas well production and wellhead pressure continuously or rapidly decline, blockage is confirmed. At this point, the wellhead pressure will gradually decrease as the blockage forms, and the rate of decrease will gradually accelerate. Since the blockage in the wellbore is not firmly attached, it is common to observe instances where the blockage is broken up, resulting in a short-term rise in wellhead pressure. The pressure recovery curve of a single well pressure change point is obtained. The difference between the time T1 when the pressure at the single wellhead pressure change point begins to rise and the time T2 when the pressure reaches its maximum is the pressure recovery time T. This step primarily determines the pressure recovery time T. In actual operation, data curves should be retrieved for easy monitoring of curve changes.

[0018] At this point, based on the multiple pressure recovery events in the deep well, two scenarios can be summarized: 1. The blockage point is at the wellhead.

[0019] The node is defined as the gas volume in the upper part of the wellbore equal to the gas volume in the lower part of the wellbore plus the make-up gas volume. In a full-bore well, if the blockage occurs in more than one-third of the wellbore, the pressure will initially rise and then fall once the blockage disappears or its intensity decreases. See the schematic diagram. Figure 2 The pressure recovery time cutoff point is before the pressure peak time point T2, and the value should be taken forward to T2-1.

[0020] The method for determining the pressure rise rate is T2-1, where the pressure rise rate slows down. The pressure is used as the reference value. According to the production capacity equation, the wellhead pressure P0 during normal production is calculated, and the bottom hole flowing pressure Pwf after blockage is calculated. Under this flowing pressure condition, the wellhead pressure P01 with the nozzle unchanged is taken. The average value of P0 and P01 is taken. The time point corresponding to this on the pressure recovery curve is the time point T2-1.

[0021] 2. If the blockage is located in the lower part of the wellbore, the pressure will continue to rise once the blockage disappears or its intensity decreases. See the diagram below. Figure 3 At this point, the time point at which the pressure rises to its maximum is taken as the time point T2.

[0022] Step 3: Calculate the fluid velocity Because the gas velocity varies at different locations in a high-pressure gas well due to the influence of pipe diameter, after blockage occurs, the pressure difference above and below the blockage point increases, and the gas velocity no longer transitions uniformly. The compressibility coefficient Z at the blockage point, the pressure P1 above the blockage point, and the pressure P2 below the blockage point all affect the flow velocity. After the blockage is relieved or alleviated, the pressure P2 below the blockage point gradually approaches the pressure P1 above the blockage point, and the flow velocity relatively increases. Before reaching the wellhead, the flow velocity will be at the pressure P2 below the blockage point and the compressibility coefficient Z before the blockage point. Therefore, calculating the pressure P2 below the blockage point and the compressibility coefficient Z can preliminarily determine the fluid velocity υ. Specifically: (1) Where Q is the daily production of a single well, m 3 B g υ is the natural gas volume coefficient, dimensionless; d is the pipe diameter, mm; υ is the fluid velocity, m / s; 24 60 60 represents 24 hours, 60 minutes, and 60 seconds.

[0023] (2) Where Z is the compressibility coefficient, dimensionless; t is the temperature at different points in the wellbore, in °C; P 00 P represents standard atmospheric pressure, MPa; P represents pressure at different points in the wellbore, MPa.

[0024] Substitute formula (2) into formula (1) (3) In the formula, t, P, and d are fixed values ​​for different wellbore points, while Z can be determined based on PVT test data for different wells.

[0025] When calculating the flow velocity, the daily production rate Q1 is taken under the pressure P1 above the blockage point, which is the daily production rate before the blockage is cleared, to obtain the fluid flow velocity υ1 above the blockage point in the wellbore; the daily production rate Q2 is taken under the pressure P2 below the blockage point, which is the daily production rate after the blockage is cleared, to obtain the fluid flow velocity υ2 below the blockage point in the wellbore according to the above formula. The average value of the fluid flow velocities υ1 above the blockage point and υ2 below the blockage point is taken to obtain the fluid flow velocity υ in the wellbore. This velocity is the propagation velocity from the throttling point to the wellhead.

[0026] Preferably, the pressure P1 above the blockage point can be selected from the wellhead pressure before the blockage is cleared, and the pressure P2 below the blockage point can be selected from the wellhead pressure after the blockage is cleared. Specifically, for example... Figure 2 , 3 As shown, the pressure P1 above the blockage point is the pressure value corresponding to the time point T1 when the pressure starts to rise, and the pressure P2 below the blockage point is the pressure value corresponding to the time point T2 when the pressure is at its highest or the time point T2-1 when the pressure increases. The temperature t at different points in the wellbore is the wellhead temperature before and after the blockage. After calculating the blockage depth H1 in the wellbore for the first time, the t value is corrected again based on H1 to calculate the blockage depth. The changes in the field values ​​are small and their impact on the calculation is negligible.

[0027] Step 4: Calculate the location of the blockage The depth H of the blockage point in the wellbore is calculated based on the fluid velocity υ and the pressure recovery time T within the wellbore, using the following formula: (4) Where υ is the fluid velocity, m / s, and T is the pressure recovery time, min. Figure 4 The pressure rise time is given by H, where H is the depth of the blockage point, in meters. Because different pipe sections have different diameters and flow velocities, the accurate depth of the blockage point usually needs to be calculated repeatedly on-site based on the different pipe diameters.

[0028] Step 5: Typically, the calculated depth H of the blockage point in the wellbore is converted into a table showing the pipe section length (including the depth of the tubing string and the length of the tubing string) versus the pressure recovery time, as shown below. Figure 4 As shown, the unit is pipe diameter in mm, and the output is in m³. 3 The depth of the tubing is m, and the compressibility coefficient has no unit.

[0029] Figure 4 For a certain well on site, which has been blocked, the daily output is fixed at 180,000 cubic meters and the wellhead pressure is 60 MPa. Based on the fitting calculation, the pressure recovery time of the blockage at different points in the wellbore is calculated according to the blockage section, and then the blockage section is determined by the time.

[0030] Adjustments can be made based on the actual situation on site.

[0031] Figure 5 To create a standard chart, for a specific downhole pipe section, calculate the pressure recovery time after the blockage is cleared under different production conditions. This allows for better comparison with the pressure recovery time in actual production, enabling rapid judgment. Step Six: [The text abruptly ends here, likely due to an incomplete sentence or missing information.] Figure 4 By correlating the pressure recovery time with the tubing string's pressure resistance, it's possible to identify which section of the tubing is blocked and determine the depth of the blockage. Combined with pressure resistance data, this allows for a quantitative calculation of the tubing string's pressure risk. Furthermore, this approach can be extended to other single wells to create a standard wellbore blockage early warning table, such as... Figure 5 As shown, the data includes the depth of the blockage point, the pressure recovery time, and the field data production. The depth of the blockage point in the wellbore of other single wells can be obtained based on the pressure recovery time and the field data production.

[0032] This method can not only predict wellbore blockage, but also calculate the throttling point for frozen and blocked surface pipelines when the upstream pressure rises.

Claims

1. A method for quantitatively determining the location of wellbore blockage, characterized in that, The specific steps are as follows: S1 obtains the pressure recovery curve at the single-well pressure change point and obtains the pressure recovery time T; S2 obtains the daily production Q of a single well under pressure conditions above and below the blockage point, and then calculates the daily production Q of the single well and the natural gas volume coefficient B at the blockage point. g The fluid velocity υ inside the wellbore is obtained; S3 calculates the depth H of the blockage point in the wellbore based on the pressure recovery time T and the fluid velocity υ in the wellbore. In S1, when the pressure rises and then falls in the pressure recovery curve at the single-well pressure change point, the difference between the pressure start time T1 and the increase time T2-1 is selected as the pressure recovery time T. In S1, the average pressure value of the wellhead pressure P0 during normal production and the wellhead pressure P01 under the conditions of bottom hole flowing pressure Pwf after blockage is the time point corresponding to the pressure recovery curve of the single well pressure change point, which is the increase time point T2-1. On the pressure recovery curve of the single well pressure change point, the pressure value corresponding to the time point T1 when the pressure starts to rise is the upper pressure P1 of the blockage point, and the pressure value corresponding to the time point T2-1 is the lower pressure P2 of the blockage point. Obtain the daily output Q1 under the pressure P1 above the blockage point and calculate the fluid velocity υ1 above the blockage point; obtain the daily output Q2 under the pressure P2 below the blockage point and calculate the fluid velocity υ2 below the blockage point. The average of the fluid velocity υ1 above the blockage point and the fluid velocity υ2 below the blockage point is the fluid velocity υ.

2. The method for quantitatively determining the location of wellbore blockage according to claim 1, characterized in that, In S2, the formula for calculating the fluid velocity υ is: Where Z is the compressibility coefficient, dimensionless; Q is the daily production per well, in meters. 3 ; d is the pipe diameter, mm; t is the temperature at different points in the wellbore, °C; P 00 P represents standard atmospheric pressure, MPa; P represents pressure at different points in the wellbore, MPa.

3. The method for quantitatively determining the location of wellbore blockage according to claim 1, characterized in that, The compressibility factor Z is based on the natural gas volume factor B. g The calculation yields the following formula: Where t represents the temperature at different points in the wellbore, in °C; P 00 P represents standard atmospheric pressure, MPa; P represents pressure at different points in the wellbore, MPa.

4. The method for quantitatively determining the location of wellbore blockage according to claim 1, characterized in that, In S3, the depth H of the blockage point in the wellbore is calculated based on the fluid velocity υ and the pressure recovery time T in the wellbore. The calculation formula is as follows: Where υ is the fluid velocity (m / s), T is the pressure recovery time (min), and H is the blockage depth (m).

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