Method, apparatus and storage medium for monitoring lost circulation during a drilling process

Abstract

The application discloses a well leakage monitoring method for a drilling process. The method comprises the following steps: acquiring a first pressure and a first temperature at a first annular space measuring point of a target well, a second pressure and a second temperature at a second annular space measuring point of the target well, a drilling fluid inlet flow rate and an inlet density in real time; determining drilling fluid densities at the first annular space measuring point and the second annular space measuring point according to a ground pressure and a ground temperature in real time; determining a first annular space fluid flow rate of the target well under a no-leakage condition based on the first pressure, the first temperature, the second pressure, the second temperature, the inlet flow rate and the inlet density; determining a second annular space fluid flow rate of the target well in real time; determining a leakage monitoring coefficient of the target well based on the first annular space fluid flow rate and the second annular space fluid flow rate; and determining that the target well has well leakage in the case that the leakage monitoring coefficient is less than or equal to a preset leakage monitoring threshold. The application can monitor well leakage and calculate a leakage rate in real time, so as to ensure drilling safety.

Description

Technical Field

[0001] This application relates to the field of well leakage monitoring technology, specifically to a method, device, and storage medium for well leakage monitoring during the drilling process. Background Technology

[0002] As the focus of my country's oil exploration and development shifts from shallow to deep and ultra-deep reservoirs, which are characterized by high temperature and pressure and narrow safety density windows, complex well leakage conditions frequently occur during drilling. Existing well leakage monitoring methods are mainly divided into surface logging data monitoring and wellbore data monitoring methods based on the source of characteristic parameters. Surface logging data monitoring primarily monitors the mud pit level and the inlet / outlet flow difference; this method is the most widely used, but its response time is lagging. Wellbore data monitoring mainly monitors changes in parameters such as annular micro-flow and annular pressure, offering stronger timeliness. If existing monitoring methods fail to detect leaks in a timely manner, reservoir contamination can easily occur, potentially leading to secondary complex conditions such as leakage turning into overflow, stuck pipe, and wellbore instability, posing a significant challenge to safe drilling. Summary of the Invention

[0003] The purpose of this application is to provide a well leakage monitoring method for the drilling process, in order to solve the problem in the prior art that the well leakage early warning time is delayed and the leakage rate cannot be calculated in a timely and accurate manner, thereby affecting drilling safety.

[0004] To achieve the above objectives, the first aspect of this application provides a method for monitoring lost circulation during drilling, the method comprising:

[0005] Real-time acquisition of the first pressure and first temperature at the first annulus measuring point of the target well, the second pressure and second temperature at the second annulus measuring point of the target well, and the drilling fluid inlet velocity and inlet density;

[0006] The drilling fluid density at the first and second annulus measuring points is determined in real time based on ground pressure and surface temperature.

[0007] The first annular fluid velocity of the target well under the condition of no leakage is determined based on the first pressure, first temperature, second pressure, second temperature, inlet velocity, and inlet density.

[0008] Real-time determination of the second annular fluid velocity in the target well;

[0009] The leakage monitoring coefficient of the target well is determined based on the fluid velocity of the first and second annulus.

[0010] If the leakage monitoring coefficient is less than or equal to the preset leakage monitoring threshold, the target well is determined to have experienced well leakage.

[0011] In this embodiment of the application, determining the second annular fluid velocity in real time based on the annular fluid velocity calculation equation includes determining the second annular fluid velocity according to formula (1):

[0012] (1)

[0013] in, This represents the pressure difference between the first and second ring empty measuring points. This is a drilling fluid density correction factor. This is the friction coefficient correction factor. It is the acceleration due to gravity. The inclination angle of the target well. Fanning friction coefficient, Equivalent diameter The distance between the two preset measuring points. Let be the area of ​​the annular flow channel. The drilling fluid density is located between the first and second annular measuring points. The velocity of the fluid in the second annulus.

[0014] In this embodiment of the application, determining the first annular fluid velocity of the target well under the condition of no leakage includes determining the first annular fluid velocity according to formula (2):

[0015] (2)

[0016] in, As the primary pressure, The first temperature, As the second pressure, The second temperature, For the inlet density, For inlet flow rate, The drilling fluid density at the first annular measuring point. The drilling fluid density at the second annular measuring point. The velocity of the fluid in the first annulus is denoted as .

[0017] In this embodiment of the application, determining the drilling fluid density at the first and second annular measuring points in real time based on ground pressure and surface temperature includes determining the drilling fluid density at the first and second annular measuring points according to formula (3):

[0018] (3)

[0019] in, For ground pressure, For surface temperature, For annular pressure, Circulation temperature The first parameter is preset. The second parameter is preset. The third parameter is preset. The fourth parameter is preset. This is the preset fifth parameter.

[0020] In this embodiment of the application, determining the leakage monitoring coefficient includes determining the leakage monitoring coefficient according to formula (4):

[0021] (4)

[0022] in, The velocity of the first annular fluid. The second annular fluid velocity, This represents the leakage monitoring coefficient.

[0023] In this embodiment of the application, determining that a well has lost power when the leakage monitoring coefficient is less than or equal to a preset leakage monitoring threshold includes:

[0024] Determine whether the leakage monitoring coefficient is less than or equal to The absolute value of, where, The preset leakage risk threshold;

[0025] If the leakage monitoring coefficient is less than or equal to the absolute value, it is determined that the target well has experienced leakage.

[0026] If the leakage monitoring coefficient is greater than its absolute value, it is determined that no well leakage has occurred in the target well.

[0027] In this embodiment of the application, the monitoring method further includes:

[0028] After determining that the target well has lost circulation, the leakage rate of the target well is determined according to formula (5):

[0029] (5)

[0030] in, The leakage rate, The velocity of the first annular fluid. The velocity of the fluid in the second annulus.

[0031] A second aspect of this application provides a well leakage monitoring device for use in drilling processes, the device comprising:

[0032] The data acquisition module is used to acquire in real time the first pressure and first temperature at the first annulus measuring point of the target well, the second pressure and second temperature at the second annulus measuring point of the target well, and the drilling fluid inlet velocity and inlet density;

[0033] The data processing module is used to determine the drilling fluid density at the first and second annulus measuring points in real time based on the ground pressure and surface temperature; determine the first annulus fluid velocity of the target well under no-leakage conditions based on the first pressure, first temperature, second pressure, second temperature, inlet flow velocity, and inlet density; determine the second annulus fluid velocity of the target well in real time; and determine the leakage monitoring coefficient of the target well based on the first and second annulus fluid velocities.

[0034] The early warning module is used to determine that well leakage has occurred in the target well when the leakage monitoring coefficient is less than or equal to the preset leakage monitoring threshold.

[0035] A third aspect of this application provides an electronic device, the device comprising:

[0036] The memory is configured to store instructions; and

[0037] The processor is configured to retrieve instructions from memory and, when executing instructions, to implement a method for monitoring well leakage during the drilling process.

[0038] A fourth aspect of this application provides a machine-readable storage medium storing instructions for causing a machine to perform a method for monitoring lost circulation during drilling.

[0039] The above technical solution allows for real-time acquisition of the first pressure and temperature at the first annulus measuring point of the target well, the second pressure and temperature at the second annulus measuring point of the target well, the drilling fluid inlet velocity, and the inlet density. It also allows for real-time determination of the drilling fluid density at the first and second annulus measuring points based on surface pressure and temperature. Furthermore, it allows for the determination of the first annulus fluid velocity of the target well under no-leakage conditions based on the first pressure, first temperature, second pressure, second temperature, inlet velocity, and inlet density. The solution also allows for real-time determination of the second annulus fluid velocity of the target well. Finally, it allows for the determination of the leakage monitoring coefficient of the target well based on the first and second annulus fluid velocities. If the leakage monitoring coefficient is less than or equal to a preset leakage monitoring threshold, it determines that leakage has occurred in the target well. This application can monitor whether leakage has occurred in the target well in real time and calculate the current leakage rate when leakage occurs, thereby ensuring drilling safety.

[0040] Other features and advantages of the embodiments of this application will be described in detail in the following detailed description section. Attached Figure Description

[0041] The accompanying drawings are provided to further illustrate the embodiments of this application and form part of the specification. They are used together with the following detailed description to explain the embodiments of this application, but do not constitute a limitation on the embodiments of this application. In the drawings:

[0042] Figure 1A flowchart illustrating a method for monitoring well leakage during drilling according to an embodiment of this application is shown schematically.

[0043] Figure 2 The diagram illustrates a calculation process of a walrus optimization algorithm according to an embodiment of this application.

[0044] Figure 3 The illustration shows a schematic diagram of a walrus optimization algorithm for solving annular current velocity according to an embodiment of this application;

[0045] Figure 4 This schematic diagram illustrates a structural diagram of a well leakage monitoring device for drilling processes according to an embodiment of this application;

[0046] Figure 5 A schematic block diagram of an electronic device according to an embodiment of this application is shown.

[0047] Explanation of reference numerals in the attached figures

[0048] Detailed Implementation

[0049] To make the objectives, technical solutions, and advantages of the embodiments of this application clearer, the technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. It should be understood that the specific embodiments described herein are only for illustration and explanation of the embodiments of this application and are not intended to limit the embodiments of this application. All other embodiments obtained by those skilled in the art based on the embodiments of this application without creative effort are within the scope of protection of this application.

[0050] It should be noted that if the embodiments of this application involve directional indicators (such as up, down, left, right, front, back, etc.), the directional indicators are only used to explain the relative positional relationship and movement of each component in a certain specific posture (as shown in the figure). If the specific posture changes, the directional indicators will also change accordingly.

[0051] Furthermore, if the embodiments of this application involve descriptions such as "first" or "second," these descriptions are for descriptive purposes only and should not be construed as indicating or implying their relative importance or implicitly specifying the number of technical features indicated. Therefore, features defined with "first" or "second" may explicitly or implicitly include at least one of those features. Additionally, the technical solutions of various embodiments can be combined with each other, but this must be based on the ability of those skilled in the art to implement them. If the combination of technical solutions is contradictory or impossible to implement, it should be considered that such a combination of technical solutions does not exist and is not within the scope of protection claimed in this application.

[0052] Figure 1 A flowchart illustrating a method for monitoring lost circulation during drilling, according to an embodiment of this application, is shown schematically. Figure 1 As shown in the figure, this application provides a method for monitoring well leakage during the drilling process, which may include the following steps.

[0053] Step 101: Real-time acquisition of the first pressure and first temperature at the first annulus measuring point of the target well, the second pressure and second temperature at the second annulus measuring point of the target well, and the drilling fluid inlet velocity and inlet density;

[0054] In one embodiment, dual measuring points refer to two measuring points in the target well: the first annular measuring point and the second annular measuring point. The dual measuring point system can acquire real-time parameters such as pressure and temperature at these two measuring points. The drilling fluid inlet flow rate and density can be acquired in real-time using a surface logging instrument. The drilling fluid inlet velocity refers to the speed at which the drilling fluid enters the wellhead, and the drilling fluid inlet density refers to the density of the drilling fluid upon entering the wellhead. These acquired parameters will serve as observation variables for solving the annular fluid velocity problem.

[0055] Step 102: Determine the drilling fluid density at the first and second annular measuring points in real time based on the ground pressure and surface temperature.

[0056] In one embodiment, since the drilling fluid density changes dynamically under high temperature and pressure, it is necessary to determine the drilling fluid density at the first and second annulus measuring points in real time based on the ground pressure and surface temperature to ensure the accuracy of the basic data when calculating the fluid velocity in the first annulus.

[0057] Step 103: Determine the first annular fluid velocity of the target well under the condition of no leakage based on the first pressure, first temperature, second pressure, second temperature, inlet flow rate, and inlet density;

[0058] In one embodiment, the first annular fluid velocity of the target well under no-leakage conditions is determined according to the mass conservation equation, i.e., the annular fluid velocity of the target well under normal operating conditions is determined. The annular fluid velocity under normal operating conditions is the first annular fluid velocity. The first annular fluid velocity is a key parameter for subsequent calculation of the leakage monitoring coefficient.

[0059] Step 104: Determine the second annular fluid velocity of the target well in real time;

[0060] In one embodiment, the second annular fluid velocity of the target well is determined in real time. Obtaining the second annular fluid velocity is a key factor for subsequent calculation of the leakage monitoring coefficient.

[0061] Step 105: Determine the leakage monitoring coefficient of the target well based on the first annular fluid velocity and the second annular fluid velocity;

[0062] In one embodiment, the leakage monitoring coefficient is the ratio of the second annular fluid velocity to the first annular fluid velocity.

[0063] Step 106: If the leakage monitoring coefficient is less than or equal to the preset leakage monitoring threshold, it is determined that the target well has experienced well leakage.

[0064] In one embodiment, a wellbore leakage is determined to have occurred in the target well when the leakage monitoring coefficient is less than or equal to a preset leakage monitoring threshold. The preset leakage monitoring threshold is the absolute value of 1 minus a preset leakage risk threshold, i.e., | |, among which This is the preset threshold for leakage risk.

[0065] The above technical solution allows for real-time acquisition of the first pressure and temperature at the first annulus measuring point of the target well, the second pressure and temperature at the second annulus measuring point of the target well, and the drilling fluid inlet velocity and density. It also allows for real-time determination of the drilling fluid density at the first and second annulus measuring points based on surface pressure and temperature. Furthermore, it allows for the determination of the first annulus fluid velocity of the target well under no-leakage conditions based on the first pressure, first temperature, second pressure, second temperature, inlet velocity, and inlet density. The solution also allows for real-time determination of the second annulus fluid velocity of the target well. Finally, it allows for the determination of the leakage monitoring coefficient of the target well based on the first and second annulus fluid velocities. If the leakage monitoring coefficient is less than or equal to a preset leakage monitoring threshold, it determines that leakage has occurred in the target well. This application can monitor whether leakage has occurred in the target well in real time and calculate the current leakage rate when leakage occurs, thereby ensuring drilling safety.

[0066] In one embodiment, determining the second annular fluid velocity in real time based on the annular fluid velocity calculation equation may include determining the second annular fluid velocity according to formula (1):

[0067] (1)

[0068] in, This represents the pressure difference between the first and second ring empty measuring points. This is a drilling fluid density correction factor. This is the friction coefficient correction factor. It is the acceleration due to gravity. The inclination angle of the target well. Fanning friction coefficient, Equivalent diameter The distance between the two preset measuring points. Let be the area of ​​the annular flow channel. The drilling fluid density is located between the first and second annular measuring points. The velocity of the fluid in the second annulus.

[0069] In one embodiment, since it is necessary to consider the impact of inaccuracies in the calculation of drilling fluid density and annular fluid friction loss under high temperature and high pressure on the accurate solution of annular fluid velocity, this application introduces a drilling fluid density correction factor (…). ) and friction coefficient correction factor ( These two correction factors are also parameters to be solved. Taking the calculation equation of the annular pressure difference at the two measuring points as the objective function and the walrus optimization algorithm as the solution method, the annular fluid velocity is solved in real time, including the following steps: (1) Set the parameters of the walrus optimization algorithm, including the population size and the number of iterations; (2) Randomly initialize several individuals (second annular fluid velocity, friction coefficient correction factor and drilling fluid density correction factor) and calculate the objective function value corresponding to each individual; (3) Obtain the individual with the smallest objective function in the population, and update the position of each individual in turn through feeding, migration and competition strategies; (4) Repeat step (3) until the set number of iterations is met. The individual with the smallest objective function in the current population is the optimal solution, and the corresponding optimal annular fluid velocity is the second annular fluid velocity. The preset distance between the two measuring points refers to the distance between the first annular measuring point and the second annular measuring point.

[0070] In one embodiment, determining the first annular fluid velocity of the target well under no-leakage conditions may include determining the first annular fluid velocity according to formula (2):

[0071] (2)

[0072] in, As the primary pressure, The first temperature, As the second pressure, The second temperature, For the inlet density, For inlet flow rate, The drilling fluid density at the first annular measuring point. The drilling fluid density at the second annular measuring point. The velocity of the fluid in the first annulus is denoted as .

[0073] In one embodiment, the drilling fluid density changes dynamically under high temperature and pressure; therefore, the real-time annular fluid velocity during normal drilling of the target well is not equal to the inlet velocity. Based on the mass conservation equation, the annular fluid velocity under normal drilling conditions, i.e., the first annular fluid velocity, can be calculated. In one embodiment, substituting data from two measuring points into the formula can more accurately determine the first annular fluid velocity.

[0074] In one embodiment, determining the drilling fluid density at the first and second annular measuring points in real time based on ground pressure and surface temperature includes determining the drilling fluid density at the first and second annular measuring points according to formula (3):

[0075] (3)

[0076] in, For ground pressure, For surface temperature, For annular pressure, Circulation temperature The first parameter is preset. The second parameter is preset. The third parameter is preset. The fourth parameter is preset. This is the preset fifth parameter.

[0077] In one embodiment, the density of the drilling fluid is determined based on ground pressure and surface temperature. The first parameter is preset. The second parameter is preset. The third parameter is preset. The fourth parameter is preset. This is the preset fifth parameter. Preferably, the first parameter can be... The second parameter can be The third parameter can be The fourth parameter can be And the fifth parameter can be The density of the drilling fluid is used to determine the density in equation (2) above.

[0078] In one embodiment, determining the leakage monitoring coefficient may include determining the leakage monitoring coefficient according to formula (4):

[0079] (4)

[0080] in, The velocity of the first annular fluid. The second annular fluid velocity, This represents the leakage monitoring coefficient.

[0081] In one embodiment, the leakage monitoring coefficient can be determined by substituting the real-time calculated second annular fluid velocity into formula (4), i.e., the leakage monitoring coefficient (LRI) calculation equation.

[0082] In one embodiment, determining that a well has lost power when the leakage monitoring coefficient is less than or equal to a preset leakage monitoring threshold includes: determining whether the leakage monitoring coefficient is less than or equal to... The absolute value of, where, The preset leakage risk threshold is used; if the leakage monitoring coefficient is less than or equal to the absolute value, the target well is determined to have experienced well leakage; if the leakage monitoring coefficient is greater than the absolute value, the target well is determined not to have experienced well leakage.

[0083] In one embodiment, the preset leakage monitoring threshold refers to The absolute value is | |, among which This is a preset leakage risk threshold. When the leakage monitoring coefficient is less than or equal to the preset leakage monitoring threshold, then the condition is met. When a well leakage warning signal is issued, indicating that well leakage has occurred in the target well, the following condition is met: When the leakage monitoring coefficient exceeds the preset leakage monitoring threshold, the condition is satisfied. At that time, there was no well leakage warning signal, and the target well did not experience well leakage.

[0084] In one embodiment, the method may further include: after determining that a wellbore has lost power in the target well, determining the loss rate of the target well according to formula (5):

[0085] (5)

[0086] in, The leakage rate, The velocity of the first annular fluid. The velocity of the fluid in the second annulus.

[0087] In one embodiment, if a well leakage warning signal is issued, the target well will experience well leakage. In this case, the leakage rate needs to be calculated in real time using formula (5).

[0088] Figure 2 The diagram illustrates a calculation process for a walrus optimization algorithm according to an embodiment of this application. Figure 2 As shown in the figure, this application embodiment provides a calculation process for a walrus optimization algorithm, which may include the following steps.

[0089] The walrus optimization algorithm is an optimization algorithm designed based on the behavioral characteristics of walruses in the process of searching for food. Its steps are as follows:

[0090] 1. Population initialization: After determining the problem to be solved, a number of individuals are randomly initialized.

[0091] 2. Calculate the objective function value: We use the objective function value as a standard to evaluate the quality of individuals; the smaller the value, the better the individual. Calculate the objective function value for all individuals in the population and determine the individual with the smallest objective function value.

[0092] 3. Feeding: The feeding phase mainly involves updating the positions of all individuals in the population under the guidance of the optimal individual, based on the walrus feeding mechanism. This process can be expressed by formulas (6) and (7):

[0093] (6)

[0094] (7)

[0095] in, For the first phase The location where the walrus was newly formed For its first One dimension, For its objective function value, A random number in the interval [0,1]; It is the walrus with the minimum objective function; An integer randomly selected between 1 and 2.

[0096] 4. Migration: The migration phase mainly guides each individual in the population to find the optimal location based on the walrus migration process. This process can be expressed by formulas (8) and (9):

[0097] (8)

[0098] (9)

[0099] in, For the second phase The location where the walrus was newly formed For its first One dimension, Let it be the value of its objective function; The selected walrus's location will be the first The walruses migrated towards it. It is its first One dimension, It is the value of its objective function.

[0100] 5. Competition: The competition phase mainly involves updating the position of each individual in the population based on the walruses' behavior in escaping and fighting enemies. This process can be expressed by formulas (10), (11), and (12):

[0101] (10)

[0102] (11)

[0103] (12)

[0104] in, For the third phase The location where the walrus was newly formed For its first One dimension, Let it be the value of its objective function; This represents the number of iterations. and The first Minimum and maximum values ​​of each dimension and The first Each dimension allows for local lower and upper bounds.

[0105] 6. Termination: Repeat steps 2-5 until the maximum number of iterations is reached, and output the optimal parameter combination.

[0106] Figure 3 This diagram illustrates a process for solving annular current velocities using a walrus optimization algorithm according to an embodiment of this application. Figure 3 As shown in the figure, this application embodiment provides a process for solving the annular current velocity using a walrus optimization algorithm, which may include the following steps.

[0107] 1. No. Real-time data acquisition: Utilizing a dual-point downhole measurement system to acquire data in real time. Pressure and temperature at both measurement points are monitored in real time using a surface logging instrument. The drilling fluid inlet flow rate and density at constant times are used as observation variables for the walrus optimization algorithm to solve for the annular fluid velocity.

[0108] 2. Randomly initialize several individuals, each individual consisting of ( , , It consists of three parameters.

[0109] 3. Calculate the objective function value F( for each individual in the population). , , The goal is to select the individual with the smallest objective function and use it as the optimal individual.

[0110] 4. Update the population's corresponding ( ) for each individual sequentially through feeding, migration, and competition strategies. , , )value.

[0111] 5. Repeat steps 2-4 until the maximum number of iterations is reached, and output the optimal annular fluid velocity at the current moment. .

[0112] 6. Order Skip to step 1.

[0113] Figure 4 This schematically illustrates a structural diagram of a well leakage monitoring device for drilling processes according to an embodiment of this application. Figure 4 As shown in this embodiment, a well leakage monitoring device for drilling processes is provided. The device includes: a data acquisition module 410, used to acquire in real time the first pressure and first temperature at the first annulus measuring point of the target well, the second pressure and second temperature at the second annulus measuring point of the target well, and the drilling fluid inlet velocity and inlet density; a data processing module 420, used to determine the drilling fluid density at the first annulus measuring point and the second annulus measuring point in real time based on the surface pressure and surface temperature; determine the first annulus fluid velocity of the target well under no leakage conditions based on the first pressure, first temperature, second pressure, second temperature, inlet velocity, and inlet density; determine the second annulus fluid velocity of the target well in real time; determine the leakage monitoring coefficient of the target well based on the first annulus fluid velocity and the second annulus fluid velocity; and an early warning module 430, used to determine that well leakage has occurred in the target well when the leakage monitoring coefficient is less than or equal to a preset leakage monitoring threshold.

[0114] In one embodiment, the data acquisition module 410 acquires in real time the first pressure and first temperature at the first annulus measuring point of the target well, the second pressure and second temperature at the second annulus measuring point of the target well, and the drilling fluid inlet velocity and density. The data acquisition module 410 transmits the above data to the data processing module 420. The data processing module 420 determines the drilling fluid density at the first and second annulus measuring points in real time based on the surface pressure and surface temperature; determines the first annulus fluid velocity of the target well under no-leakage conditions based on the first pressure, first temperature, second pressure, second temperature, inlet velocity, and inlet density; determines the second annulus fluid velocity of the target well in real time; and determines the leakage monitoring coefficient of the target well based on the first and second annulus fluid velocities. The data processing module 420 transmits the processed drilling fluid density, first annulus fluid velocity, second annulus fluid velocity, and leakage monitoring coefficient to the early warning module 430. If the leakage monitoring coefficient is less than or equal to a preset leakage monitoring threshold, the early warning module 430 determines that leakage has occurred in the target well and issues an early warning signal.

[0115] Figure 5 A schematic block diagram of an electronic device according to an embodiment of this application is shown. Figure 5As shown, this application provides an electronic device that may include:

[0116] Memory 510 is configured to store instructions; and

[0117] The processor 520 is configured to retrieve instructions from the memory 510 and, when executing the instructions, to implement the aforementioned method for monitoring well leakage during the drilling process.

[0118] Specifically, in this embodiment of the application, the processor 520 can be configured to:

[0119] Real-time acquisition of the first pressure and first temperature at the first annulus measuring point of the target well, the second pressure and second temperature at the second annulus measuring point of the target well, and the drilling fluid inlet velocity and inlet density;

[0120] The drilling fluid density at the first and second annulus measuring points is determined in real time based on ground pressure and surface temperature.

[0121] The first annular fluid velocity of the target well under the condition of no leakage is determined based on the first pressure, first temperature, second pressure, second temperature, inlet velocity, and inlet density.

[0122] Real-time determination of the second annular fluid velocity in the target well;

[0123] The leakage monitoring coefficient of the target well is determined based on the fluid velocity of the first and second annulus.

[0124] If the leakage monitoring coefficient is less than or equal to the preset leakage monitoring threshold, the target well is determined to have experienced well leakage.

[0125] Furthermore, the processor 520 can also be configured to: determine the second annular fluid velocity in real time based on the annular fluid velocity calculation equation, including determining the second annular fluid velocity according to formula (1):

[0126] (1)

[0127] in, This represents the pressure difference between the first and second ring empty measuring points. This is a drilling fluid density correction factor. This is the friction coefficient correction factor. It is the acceleration due to gravity. The inclination angle of the target well. Fanning friction coefficient, Equivalent diameter The distance between the two preset measuring points. Let be the area of ​​the annular flow channel. The drilling fluid density is located between the first and second annular measuring points. The velocity of the fluid in the second annulus.

[0128] Furthermore, the processor 520 can also be configured to: determine the first annular fluid velocity of the target well under no-leakage conditions, including determining the first annular fluid velocity according to formula (2):

[0129] (2)

[0130] in, As the primary pressure, The first temperature, As the second pressure, The second temperature, For the inlet density, For inlet flow rate, The drilling fluid density at the first annular measuring point. The drilling fluid density at the second annular measuring point. The velocity of the fluid in the first annulus is denoted as .

[0131] Furthermore, the processor 520 can also be configured to: determine the drilling fluid density at the first and second annular measuring points in real time based on the ground pressure and surface temperature, including determining the drilling fluid density at the first and second annular measuring points according to formula (3):

[0132] (3)

[0133] in, For ground pressure, For surface temperature, For annular pressure, Circulation temperature The first parameter is preset. The second parameter is preset. The third parameter is preset. The fourth parameter is preset. This is the preset fifth parameter.

[0134] Furthermore, the processor 520 can also be configured to: determine the leakage monitoring coefficient by means of formula (4):

[0135] (4)

[0136] in, The velocity of the first annular fluid. The second annular fluid velocity, This represents the leakage monitoring coefficient.

[0137] Furthermore, the processor 520 can also be configured to: determine that a well has lost power in the target well when the leakage detection coefficient is less than or equal to a preset leakage detection threshold, including:

[0138] Determine whether the leakage monitoring coefficient is less than or equal to The absolute value of, where, The preset leakage risk threshold;

[0139] If the leakage monitoring coefficient is less than or equal to the absolute value, it is determined that the target well has experienced leakage.

[0140] If the leakage monitoring coefficient is greater than its absolute value, it is determined that no well leakage has occurred in the target well.

[0141] Furthermore, the processor 520 can also be configured to: after determining that leakage has occurred in the target well, determine the leakage rate of the target well according to formula (5):

[0142] (5)

[0143] in, The leakage rate, The velocity of the first annular fluid. The velocity of the fluid in the second annulus.

[0144] Through the above technical solution, firstly, the processor 520 acquires in real time the first pressure and first temperature at the first annulus measuring point of the target well, the second pressure and second temperature at the second annulus measuring point of the target well, and the drilling fluid inlet velocity and density; the processor 520 determines the drilling fluid density at the first and second annulus measuring points in real time based on the surface pressure and surface temperature; the processor 520 determines the first annulus fluid velocity of the target well under no-leakage conditions based on the first pressure, first temperature, second pressure, second temperature, inlet velocity, and inlet density; the processor 520 determines the second annulus fluid velocity of the target well in real time; the processor 520 determines the leakage monitoring coefficient of the target well based on the first and second annulus fluid velocities; and the processor 520 determines that well leakage has occurred in the target well if the leakage monitoring coefficient is less than or equal to a preset leakage monitoring threshold. This application can monitor whether well leakage has occurred in the target well in real time and calculate the current leakage rate in real time when well leakage occurs, thereby ensuring drilling safety.

[0145] This application also provides a machine-readable storage medium storing instructions that cause a machine to perform the above-described well leakage monitoring method during drilling.

[0146] Those skilled in the art will understand that embodiments of this application can be provided as methods, systems, or computer program products. Therefore, this application can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, this application can take the form of a computer program product embodied on one or more computer-usable storage media (including, but not limited to, disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0147] This application is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of this application. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart... Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0148] These computer program instructions may also be stored in a computer-readable storage medium that can direct a computer or other programmable data processing device to function in a particular manner, such that the instructions stored in the computer-readable storage medium produce an article of manufacture including instruction means, which are implemented in a process Figure 1 One or more processes and / or boxes Figure 1 The function specified in one or more boxes.

[0149] These computer program instructions may also be loaded onto a computer or other programmable data processing equipment to cause a series of operational steps to be performed on the computer or other programmable equipment to produce a computer-implemented process, thereby providing instructions that execute on the computer or other programmable equipment for implementing the process. Figure 1 One or more processes and / or boxes Figure 1 The steps of the function specified in one or more boxes.

[0150] In a typical configuration, a computing device includes one or more processors (CPU), input / output interfaces, network interfaces, and memory.

[0151] Memory may include non-persistent memory in computer-readable media, such as random access memory (RAM) and / or non-volatile memory, such as read-only memory (ROM) or flash RAM. Memory is an example of computer-readable media.

[0152] Computer-readable media includes both permanent and non-permanent, removable and non-removable media that can store information using any method or technology. Information can be computer-readable instructions, data structures, modules of programs, or other data. Examples of computer storage media include, but are not limited to, phase-change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), other types of random access memory (RAM), read-only memory (ROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other memory technologies, CD-ROM, digital versatile optical disc (DVD) or other optical storage, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other non-transferable medium that can be used to store information accessible by a computing device. As defined herein, computer-readable media does not include transient computer-readable media, such as modulated data signals and carrier waves.

[0153] It should also be noted that the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such process, method, article, or apparatus. Unless otherwise specified, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes that element.

[0154] The above are merely embodiments of this application and are not intended to limit the scope of this application. Various modifications and variations can be made to this application by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principles of this application should be included within the scope of the claims of this application.

Claims

1. A method for monitoring lost circulation during drilling, characterized in that, The method includes: The first pressure and first temperature at the first annulus measuring point of the target well, the second pressure and second temperature at the second annulus measuring point of the target well, and the drilling fluid inlet velocity and inlet density are acquired in real time. The drilling fluid density at the first and second annular measuring points is determined in real time based on ground pressure and surface temperature. The first annular fluid velocity of the target well under no-leakage conditions is determined based on the first pressure, the first temperature, the second pressure, the second temperature, the inlet flow rate, and the inlet density. The second annular fluid velocity of the target well is determined in real time; The ratio of the first annular fluid velocity to the second annular fluid velocity is used as the leakage monitoring coefficient of the target well. If the leakage monitoring coefficient is less than or equal to a preset leakage monitoring threshold, it is determined that the target well has experienced well leakage. The velocity of the first annular fluid is determined according to formula (1): （1） in, For the first pressure, The first temperature, For the second pressure, The second temperature, The inlet density, The inlet flow rate is... The drilling fluid density at the first annular measuring point. The drilling fluid density at the second annular measuring point. The velocity of the first annular fluid.

2. The method according to claim 1, characterized in that, The real-time determination of the second annular fluid velocity based on the annular fluid velocity calculation equation includes determining the second annular fluid velocity according to formula (2): （2） in, The pressure difference between the first annular measuring point and the second annular measuring point. This is a drilling fluid density correction factor. This is the friction coefficient correction factor. It is the acceleration due to gravity. The inclination angle of the target well. Fanning friction coefficient, Equivalent diameter The distance between the two preset measuring points. Let be the area of ​​the annular flow channel. The drilling fluid density is located between the first annular measuring point and the second annular measuring point. The velocity of the second annular fluid.

3. The method according to claim 1, characterized in that, The real-time determination of drilling fluid density at the first and second annular measuring points based on ground pressure and surface temperature includes determining the drilling fluid density at the first and second annular measuring points according to formula (3): （3） in, The ground pressure, The surface temperature is [value missing]. For annular pressure, The annular temperature. The first parameter is preset. The second parameter is preset. The third parameter is preset. The fourth parameter is preset. This is the preset fifth parameter.

4. The method according to claim 1, characterized in that, Determining the leakage monitoring coefficient includes determining the leakage monitoring coefficient according to formula (4): （4） in, The velocity of the first annular fluid. The second annular fluid velocity, The leakage monitoring coefficient is denoted as .

5. The method according to claim 1, characterized in that, Determining that the target well has experienced well leakage when the leakage monitoring coefficient is less than or equal to a preset leakage monitoring threshold includes: Determine whether the leakage monitoring coefficient is less than or equal to The absolute value of, where, The preset leakage risk threshold; If the leakage monitoring coefficient is less than or equal to the absolute value, it is determined that the target well has experienced well leakage. If the leakage monitoring coefficient is greater than the absolute value, it is determined that the target well has not experienced well leakage.

6. The method according to claim 1, characterized in that, The method further includes: After determining that the target well has experienced well leakage, the leakage rate of the target well is determined according to formula (5): （5） in, The leakage rate is... The velocity of the first annular fluid. The velocity of the second annular fluid.

7. A well leakage monitoring device for use in drilling processes, characterized in that, To implement the method according to claim 1, comprising: The data acquisition module is used to acquire in real time the first pressure and first temperature at the first annulus measuring point of the target well, the second pressure and second temperature at the second annulus measuring point of the target well, and the drilling fluid inlet velocity and inlet density. The data processing module is used to determine the drilling fluid density at the first and second annular measuring points in real time based on the ground pressure and surface temperature; determine the first annular fluid velocity of the target well under no-leakage conditions based on the first pressure, first temperature, second pressure, second temperature, inlet flow velocity, and inlet density; determine the second annular fluid velocity of the target well in real time; and determine the leakage monitoring coefficient of the target well based on the first and second annular fluid velocities. The early warning module is used to determine that the target well has experienced well leakage when the leakage monitoring coefficient is less than or equal to a preset leakage monitoring threshold.

8. An electronic device, characterized in that, include: The memory is configured to store instructions; as well as The processor is configured to retrieve the instructions from the memory and, when executing the instructions, to implement the well leakage monitoring method for drilling operations according to any one of claims 1 to 6.

9. A machine-readable storage medium, characterized in that, The machine-readable storage medium stores instructions for causing the machine to perform a well leakage monitoring method for drilling operations according to any one of claims 1 to 6.

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