Drilling fluid leakage real-time monitoring system

Abstract

The invention belongs to the technical field of underground working condition monitoring, and particularly relates to a drilling fluid leakage real-time monitoring system which comprises an underground sensing unit, a ground monitoring verification unit and a central control unit. The underground sensing units are distributed along a drill column and used for collecting local temperature and vibration signals and generating abnormal trigger signals. The ground monitoring and verifying unit comprises a flow subsystem for monitoring the total flow of an inlet and an outlet, and an active pressure subsystem capable of being controlled to apply specific waveform pressure excitation to the circulating system; after receiving the underground trigger signal, the central control unit starts the pressure subsystem and synchronously monitors the flow response, evaluates the shaft sealing performance by analyzing the lagging and weakening degree between the pressure and the flow fluctuation, and finally carries out cooperative judgment and leakage confirmation and outputs an alarm signal in combination with an underground abnormal signal and a ground evaluation result. According to the invention, early warning, accurate positioning and low false alarm rate diagnosis of drilling fluid leakage are realized.

Description

Technical Field

[0001] This invention belongs to the field of downhole working condition monitoring technology, and particularly relates to a real-time monitoring system for drilling fluid leakage. Background Technology

[0002] In drilling operations, drilling fluid is a crucial medium for maintaining wellbore pressure balance, carrying cuttings, and cooling the drill bit. Drilling fluid loss refers to the uncontrolled leakage of drilling fluid into formation pores, fractures, or caverns under pressure differential. Loss not only causes significant economic losses but can also lead to serious accidents such as wellbore instability, stuck pipe, and even runaway blowouts. Therefore, timely and accurate monitoring and early warning of drilling fluid loss are core aspects of drilling safety. Currently, drilling fluid loss monitoring mainly relies on two types of technologies: surface monitoring and downhole monitoring, both of which have significant limitations. Mainstream surface monitoring involves installing flow meters at the inlet and outlet of the circulation system and calculating the difference. This method is indirect, only detecting loss when it accumulates to a certain level, resulting in severe delays in early warning. Furthermore, surface parameters are easily affected by routine operations, leading to a high false alarm rate and an inability to pinpoint the location of the loss. Downhole monitoring tools are expensive, complex, and difficult to deploy routinely. Data typically needs to be read after tripping out of the well or uploaded via low-speed telemetry, resulting in poor real-time performance and failing to meet the rapid decision-making requirements for emergency response to loss. Summary of the Invention

[0003] The purpose of this invention is to provide a real-time drilling fluid leakage monitoring system to solve the technical problems of surface monitoring methods for drilling fluid leakage, such as severe delay in early warning, high false alarm rate, inability to determine the location of leakage, high cost of downhole monitoring tools, complex systems, difficulty in routine deployment, poor real-time performance, and inability to meet the rapid decision-making requirements for leakage emergency response.

[0004] To achieve the above objectives, the specific technical solution of the drilling fluid leakage real-time monitoring system of the present invention is as follows: A real-time drilling fluid loss monitoring system includes a downhole sensing unit, a surface monitoring and verification unit, and a central control unit. The downhole sensing unit comprises multiple sensing modules spaced along the drill string axis, used to collect local drilling fluid parameters at different well depths and generate local anomaly signals. The surface monitoring and verification unit includes a flow monitoring subsystem and an active pressure subsystem. The flow monitoring subsystem monitors the total flow rate at the drilling fluid inlet and outlet. The active pressure subsystem applies controlled characteristic pressure excitation to the drilling fluid circulation system. The central control unit is bidirectionally connected to both the downhole sensing unit and the surface monitoring and verification unit and is configured to execute... The procedure is as follows: (a) receiving and analyzing data from the downhole sensing unit, and generating a primary trigger command when a local abnormal signal matching the early characteristics of leakage is identified; (b) in response to the primary trigger command, activating the active pressure subsystem to apply the characteristic pressure excitation; (c) during the application of the characteristic pressure excitation by the active pressure subsystem, synchronously monitoring the response of the flow monitoring subsystem, and assessing the existence and severity of additional leakage channels in the wellbore based on the hysteresis and attenuation between pressure fluctuations and flow fluctuations; (d) confirming the occurrence of leakage and outputting a graded alarm signal based on the synergistic relationship between the local abnormal signal and the assessment results.

[0005] Furthermore, the downhole sensing unit includes a miniature fiber optic temperature sensing array and a piezoelectric vibration sensing array, which are deployed at the same point or adjacent to each other; the miniature fiber optic temperature sensing array is used to monitor local temperature field anomalies caused by drilling fluid leakage into the formation; the piezoelectric vibration sensing array is used to monitor specific frequency band vibration signals generated by high-speed fluid leakage impacting fractures; the local anomaly signal is a correlation combination of temperature anomaly signal and vibration anomaly signal.

[0006] Furthermore, the flow monitoring subsystem includes a first electromagnetic flowmeter installed on the drilling fluid pump outlet pipe for monitoring and measuring the total inlet flow; and a second electromagnetic flowmeter and a microwave radar flowmeter installed in parallel on the return outlet pipe for jointly monitoring and measuring the total return flow.

[0007] Furthermore, the active pressure subsystem includes an electronically controlled throttle valve and a booster pump assembly, which are controlled by the central control unit and are used to inject a characteristic pressure excitation into the drilling fluid riser or annulus. The waveform of this excitation is a low-frequency sine wave.

[0008] Furthermore, the central control unit is configured to evaluate the following method: analyze the phase difference and amplitude attenuation ratio between the input waveform of the characteristic pressure excitation and the output flow response waveform measured by the flow monitoring subsystem; and convert the phase difference and amplitude attenuation ratio into a quantitative assessment of the existence and severity of the leakage channel.

[0009] Furthermore, the logic for the central control unit to perform the collaborative judgment is as follows: if only the local abnormal signal exists, and the evaluation result does not show a significant deterioration in wellbore sealing, it is determined to be downhole interference, and an alert signal is output; if the local abnormal signal persists, and after applying characteristic pressure excitation, the evaluation result synchronously confirms that the wellbore sealing has decreased beyond a threshold, it is determined to be a confirmed leak, an advanced alarm signal is output, and the leaking section is initially located by combining the spatial location information of the downhole sensing unit.

[0010] Furthermore, the system also includes a mud tank level calibration unit, including a static pressure level sensor group installed in the main circulation tank; when the central control unit determines that there is no leakage and the operating condition is stable, it periodically starts the level calibration unit to perform online calibration and drift compensation for the mud tank level sensor used for total material balance calculation.

[0011] Furthermore, the drilling fluid loss monitoring method based on the monitoring system includes the following steps: S1. Continuously monitor and identify abnormal correlations between local temperature and vibration signals through distributed downhole sensing units, and generate a primary trigger signal; S2. After receiving the primary trigger signal, the central control unit controls the active pressure subsystem to start and inject characteristic pressure excitation into the drilling fluid circulation system. S3. The central control unit synchronously collects the inlet and outlet flow response data measured by the flow monitoring subsystem during the application of excitation. S4. The central control unit assesses whether there are additional leakage channels in the wellbore and their severity based on the hysteresis and attenuation between pressure fluctuations and flow fluctuations. S5. The central control unit integrates the local abnormal signals from the well and the surface assessment results for collaborative analysis and judgment. If both meet the characteristics of leakage, leakage is confirmed and an alarm is triggered; otherwise, interference is eliminated.

[0012] The drilling fluid loss real-time monitoring system of the present invention has the following advantages: By constructing a collaborative working system of downhole sensing unit, central control unit, and ground monitoring and verification unit, the sensitivity of direct downhole sensing is combined with the reliability of ground verification. Through downhole screening and ground verification, the location of leakage can be detected and confirmed in the early stage of drilling fluid leakage, achieving highly reliable and locatable early warning of drilling fluid leakage. The combination of a miniature fiber optic temperature sensor array and a piezoelectric vibration sensor array forms a downhole sensing unit. By correlating and combining the signals of the two, it is possible to accurately judge downhole abnormal signals from both temperature and vibration perspectives, eliminate interference from downhole drilling fluid circulation, drill string friction, etc., significantly improve the accuracy of the initial trigger command, and reduce the probability of false start of subsequent verification processes. By setting up an active pressure subsystem to apply excitation with a specific waveform, and cooperating with the central control unit to analyze the phase difference and amplitude attenuation ratio of the pressure and flow response for evaluation, the change in wellbore sealing is assessed by observing the degree of distortion of the response, and the drilling fluid is clearly distinguished from normal flow fluctuations or real leakage by dynamic impedance testing, which greatly improves the reliability of alarm information. Attached Figure Description

[0013] Figure 1 This is a flowchart of the present invention. Detailed Implementation

[0014] To better understand the purpose, structure, and function of this invention, the following detailed description of a drilling fluid leakage real-time monitoring system, in conjunction with the accompanying drawings, is provided.

[0015] like Figure 1 As shown, this invention discloses a real-time drilling fluid leakage monitoring system, comprising a downhole sensing unit, a surface monitoring and verification unit, and a central control unit. The downhole sensing unit includes multiple sensing modules spaced at intervals along the drill string axis, used to collect local drilling fluid parameters at different well depths and generate local anomaly signals. The surface monitoring and verification unit includes a flow monitoring subsystem and an active pressure subsystem. The flow monitoring subsystem monitors the total flow rate at the drilling fluid inlet and outlet. The active pressure subsystem applies controlled characteristic pressure excitation to the drilling fluid circulation system. The central control unit is bidirectionally connected to both the downhole sensing unit and the surface monitoring and verification unit, and is controlled by… Configuration execution: (a) Receive and analyze the data from the downhole sensing unit, and generate a primary trigger command when a local abnormal signal matching the early characteristics of leakage is identified; (b) In response to the primary trigger command, activate the active pressure subsystem to apply the characteristic pressure excitation; (c) During the application of the characteristic pressure excitation by the active pressure subsystem, synchronously monitor the response of the flow monitoring subsystem, and assess whether there are additional leakage channels in the wellbore and their severity based on the hysteresis and attenuation between pressure fluctuations and flow fluctuations; (d) Based on the synergistic change relationship between the local abnormal signal and the assessment results, confirm the occurrence of leakage and output a graded alarm signal.

[0016] Combination Figure 1As shown, the system setup process involves fixing multiple sensor modules of the downhole sensing unit onto the drill string body in a distributed manner along the drill string axis. These modules are then lowered into the wellbore along with the drill string to collect drilling fluid information at different well depths. The surface monitoring and verification unit is connected to the surface drilling fluid circulation system via pipelines. Sensors from the flow monitoring subsystem are installed on the drilling fluid pump outlet pipeline to monitor the total inlet flow rate and on the drilling fluid return line outlet pipeline to monitor the total outlet flow rate. The active pressure subsystem is connected in parallel to the riser or annulus pipeline of the drilling fluid circulation system. The central control unit establishes bidirectional electrical signal communication connections with each unit both downhole and on the surface via communication cables, coordinating and driving the entire monitoring process.

[0017] During operation, when a module in the downhole sensing unit detects an anomaly in local parameters that matches early signs of leakage, it generates a local anomaly signal and uploads it via the communication link. The central control unit receives and analyzes this signal, then generates a primary trigger command. This command immediately activates the active pressure subsystem connected to the pipeline, injecting a controlled characteristic pressure excitation into the circulation system. Unlike static pressurization, this involves actively generating a dynamic pressure signal with specific waveform characteristics and injecting it into the drilling fluid circulation system as a known, periodic test signal. Simultaneously, the central control unit collects response data from the flow monitoring subsystem. By analyzing the lag and attenuation between the actively applied pressure fluctuation and the outlet flow fluctuation, it assesses whether the wellbore sealing has deteriorated and the severity of the leakage. Finally, the central control unit integrates the local anomaly signal reported from downhole with the assessment results obtained from active verification on the surface, makes a coordinated judgment, and outputs a graded alarm signal upon confirmation of leakage.

[0018] This system tightly integrates physical deployment with intelligent diagnostic logic. By fixing sensor modules to the drill string to collect information downhole, and integrating the surface verification unit into the existing circulation pipeline, the system forms a complete monitoring network from downhole to the surface. This design provides the physical and informational foundation for early warning and preliminary location through distributed downhole measurement. Furthermore, by actively injecting excitation into the drilling fluid pipeline and observing the response, a reliable dynamic verification link is constructed, enabling the system to have the sensitivity of downhole monitoring and the reliability of surface testing, achieving highly reliable early diagnosis and alarm of drilling fluid leakage.

[0019] like Figure 1As shown, the downhole sensing unit includes a miniature fiber optic temperature sensing array and a piezoelectric vibration sensing array, both deployed at the same point or adjacent to each other. The miniature fiber optic temperature sensing array is used to monitor local temperature field anomalies caused by drilling fluid leakage into the formation. The piezoelectric vibration sensing array is used to monitor specific frequency vibration signals generated by high-speed fluid leakage impacting fractures. The local anomaly signal is a correlated combination of temperature anomaly signals and vibration anomaly signals. The miniature fiber optic temperature sensing array and the piezoelectric vibration sensing array are integrated at the same point or adjacent to each other in a reserved cavity on the outer wall of the drill string or inside, and are lowered into the well along with the drill string. During monitoring, the fiber optic array senses in real time the abnormal drop in the local temperature field of the wellbore caused by drilling fluid leakage into the low-temperature formation, while the piezoelectric array simultaneously captures specific high-frequency vibration signals excited by high-speed fluid injection into fractures. The central control unit performs real-time correlation analysis on these two types of signals. Only when a temperature drop and a specific vibration frequency energy increase that conform to the leakage characteristics occur simultaneously at the same or adjacent locations are they fused and determined as a valid local anomaly signal (correlated combination signal), and a primary trigger command is generated. By deploying spatially in tandem, synchronous acquisition and native correlation of temperature and vibration signals were achieved. Utilizing the dual characteristics that leakage events physically inevitably cause changes in both the temperature and vibration fields, cross-validation was performed from two independent physical dimensions. This effectively eliminated interference from single parameters caused by drill string friction, local turbulence, or sensor noise, significantly improving the specificity of downhole anomaly identification and the reliability of early warning, and providing a highly reliable triggering basis for subsequent active verification on the ground.

[0020] The flow monitoring subsystem includes a first electromagnetic flowmeter installed on the drilling fluid pump outlet pipe for monitoring and measuring the total inlet flow rate; and a second electromagnetic flowmeter and a microwave radar flowmeter installed in parallel on the return outlet pipe for jointly monitoring and measuring the total return flow rate. During the monitoring of the drilling fluid system, data is measured at the two measurement points and transmitted in real time to the central control unit to calculate the real-time difference between the inlet and outlet flow rates. When a characteristic pressure excitation is applied to the drilling fluid system, the second electromagnetic flowmeter and the microwave radar flowmeter on the return outlet pipe are used to accurately measure and cross-verify the return outlet flow rate. By utilizing the high accuracy and fast response of the electromagnetic flowmeter for measuring clean fluids, and the strong adaptability of the microwave radar flowmeter to complex working conditions such as gas and debris in the medium, highly reliable and interference-resistant monitoring of the return flow rate under different drilling fluid conditions is achieved. This design effectively overcomes the possibility of mismeasurement or missed measurement caused by a single flow meter due to changes in the medium, instrument drift, or temporary malfunction. It provides a solid and reliable data foundation for the central control unit to perform accurate dynamic system analysis (calculating the pressure-flow response phase difference and amplitude attenuation), thereby significantly improving the accuracy of the ground verification process.

[0021] The active pressure subsystem includes an electrically controlled throttle valve and a booster pump assembly, controlled by the central control unit. It injects a characteristic pressure excitation into the drilling fluid riser or annulus. This excitation waveform is a low-frequency sine wave. The electrically controlled throttle valve and the booster pump assembly are connected in parallel to the surface drilling fluid system pipeline. During operation, after receiving a primary trigger command, the central control unit sends a control signal to the active pressure subsystem, driving the electrically controlled throttle valve and the booster pump assembly to work together. By adjusting the opening of the electrically controlled throttle valve and the pumping rate of the booster pump assembly, the drilling fluid circulation system... A low-frequency sinusoidal pressure fluctuation with controllable amplitude and frequency, i.e., characteristic pressure excitation, is superimposed on the existing pressure of the system and injected into the drilling fluid circulation system. The pressure wave propagates effectively to the wellbore through the drilling fluid medium, providing a clean and periodic reference signal for subsequent analysis. By actively and controllably applying the characteristic excitation, the system can be transformed from a traditional passive monitoring state to an active testing state, providing a basis for quantitative evaluation based on the system's dynamic response and significantly improving the sensitivity and reliability of wellbore sealing change detection.

[0022] The central control unit is configured to evaluate the following: analyze the phase difference and amplitude attenuation ratio between the input waveform of the characteristic pressure excitation and the return flow response waveform measured by the flow monitoring subsystem; convert the phase difference and amplitude attenuation ratio into a quantitative assessment of the existence and severity of the leakage channel. The logic for the central control unit to perform the collaborative judgment is as follows: if only the local abnormal signal exists, and the evaluation result does not show a significant deterioration in wellbore sealing, it is determined to be downhole interference, and an alert signal is output; if the local abnormal signal persists, and after applying the characteristic pressure excitation, the evaluation result simultaneously confirms a decrease in wellbore sealing exceeding a threshold, it is determined to be a confirmed leak, and a high-level alarm signal is output, combined with the spatial position information of the downhole sensing unit. The system initially locates the leakage zone. After the active pressure subsystem injects a low-frequency sinusoidal characteristic pressure excitation, the central control unit initiates high-speed synchronous acquisition to accurately acquire the original waveform of the pressure excitation and the flow response waveform returned by the flow monitoring subsystem at the return outlet. Subsequently, the processing algorithm within the unit performs cross-correlation analysis and spectrum calculation on these two sets of time-series signals to quantitatively determine the phase difference and amplitude attenuation ratio between them. Finally, the central control unit compares the calculated phase difference and amplitude attenuation ratio values ​​with a preset threshold-mapping relationship calibrated based on the wellbore hydraulic model and experimental data, thereby directly converting and outputting a quantitative assessment result on the existence and severity of the leakage channel (such as no leakage, micro-leakage, severe leakage, etc., or specific leakage equivalent).

[0023] The system also includes a mud pit level calibration unit, comprising a static pressure level sensor array installed inside the main circulation tank. Under stable operating conditions determined to be leak-free, the central control unit periodically activates the level calibration unit to perform online calibration and drift compensation for the mud pit level sensors used for total mass balance calculations. The static pressure level sensor array is directly installed on the internal sidewall or bottom of the drilling fluid main circulation tank and is electrically connected to the central control unit. During system operation, the central control unit continuously monitors the operating conditions and automatically and periodically calibrates and compensates for drift when a stable operating period with no leakage is determined. The mud pit level calibration unit is activated. During calibration, the central control unit compares and calculates the reference level value provided by the hydrostatic level sensor group with the readings of the original mud pit level sensor used for total mass balance calculation in real time. Algorithms compensate and correct the zero-point drift and sensitivity deviation of the original sensor online, thus achieving continuous calibration. By introducing an independent, highly reliable hydrostatic sensor group as a calibration benchmark under stable, leak-free operating conditions, the system can automatically and online correct the cumulative error and drift of the main level monitoring sensor. This ensures that the key basis for judging leakage—the total drilling fluid volume calculation based on total mass balance—has long-term, reliable measurement accuracy, effectively avoiding false alarms or missed alarms caused by slow changes in sensor performance, and significantly improving the long-term stability and reliability of the entire monitoring system.

[0024] The drilling fluid loss monitoring method based on the monitoring system includes the following steps: S1. Downhole Correlation Anomaly Identification and Primary Triggering: The miniature fiber optic temperature sensor array and piezoelectric vibration sensor array in the distributed downhole sensing unit operate continuously. The fiber optic array monitors abnormal local temperature drops caused by drilling fluid leakage into the formation, while the piezoelectric array captures specific frequency band (e.g., high-frequency) vibration signals generated by the impact of high-speed fluid leakage on fractures. The central control unit receives these two types of signals in real time and executes a correlation analysis algorithm: only when a temperature drop and a specific vibration energy increase that meet a preset threshold simultaneously occur at the same well depth or adjacent measuring points, and the two are highly correlated in time, is it determined to be a valid correlation anomaly, and a primary triggering signal is generated. This step effectively filters out single-factor interference such as drill string friction and local eddies through dual physical parameter correlation. S2. Active Injection of Controlled Characteristic Pressure Excitation: Upon receiving the primary trigger signal, the central control unit immediately sends a start command and waveform parameters to the active pressure subsystem. The electronically controlled throttle valve and booster pump unit of this subsystem work in a controlled coordinated manner to precisely inject a pre-set characteristic pressure excitation—typically a low-frequency sinusoidal pressure fluctuation with a frequency of 0.01-0.1 Hz—into the riser or annulus manifold of the drilling fluid circulation system. This excitation is a dynamic test signal superimposed on the current circulation pressure, and its amplitude and frequency are set by the central control unit according to the current well conditions. S3. Synchronous Acquisition of Flow Response During Excitation: Throughout the entire cycle of the active pressure subsystem applying characteristic pressure excitation, the central control unit records two key data streams synchronously via a high-speed data acquisition card: one stream is the command / feedback waveform of the pressure excitation itself; the other stream is the inlet flow rate (from the first electromagnetic flowmeter at the pump outlet pipe) measured in real time by the flow monitoring subsystem and the return flow rate at the drilling fluid return outlet (fusion data from the second electromagnetic flowmeter and microwave radar flowmeter connected in parallel at the drilling fluid return outlet pipe). All data are precisely timestamped to ensure the temporal consistency of subsequent analysis. S4. Quantitative Assessment of Wellbore Sealing Based on Dynamic Response: The central control unit calls the signal processing module to perform cross-correlation analysis and spectrum calculation on the synchronously acquired pressure waveform and outlet flow response waveform. The core is to quantitatively extract two key features: one is the phase difference between the two waveforms (i.e., the degree of lag), and the other is the amplitude attenuation ratio of the outlet flow wave relative to the pressure wave (i.e., the degree of attenuation). Subsequently, the unit substitutes the calculated phase difference and attenuation ratio into the assessment algorithm based on the hydraulic model and experimental calibration, converting it into a quantitative assessment result of whether there is a leakage channel in the wellbore and the severity of the leakage (e.g., classified as slight, moderate, severe, or estimated leakage equivalent). S5. Final Collaborative Judgment and Decision: The central control unit executes the final collaborative judgment logic. It fuses and analyzes the local anomaly signals from downhole (the results of S1, including anomaly type, intensity, and location information) with the quantitative assessment results from the surface (the results of S4, i.e., the degree of sealing deterioration). The judgment logic is as follows: If the downhole anomaly signal persists and the surface assessment clearly shows that the wellbore sealing has decreased beyond the safety threshold, it is judged as "confirmed leakage." At this time, the central control unit outputs an advanced alarm signal and can preliminarily locate the leakage section by combining the location of the downhole sensor module with the strongest anomaly signal. Otherwise, if there is only an anomaly downhole and no significant change in the surface assessment, it is judged as "downhole interference," and only a prompt message is output to avoid false alarms. Thus, a complete monitoring cycle from early perception and active verification to comprehensive decision-making is completed.

[0025] It is understood that the present invention has been described through some embodiments, and those skilled in the art will recognize that various changes or equivalent substitutions can be made to these features and embodiments without departing from the spirit and scope of the invention. Furthermore, under the teachings of the present invention, these features and embodiments can be modified to adapt to specific situations and materials without departing from the spirit and scope of the invention. Therefore, the present invention is not limited to the specific embodiments disclosed herein, and all embodiments falling within the scope of the claims of this application are within the protection scope of the present invention.

Claims

1. A real-time monitoring system for drilling fluid loss, characterized in that, It includes a downhole sensing unit, a surface monitoring and verification unit, and a central control unit. The downhole sensing unit includes multiple sensing modules spaced apart along the drill string axis, used to collect local parameters of drilling fluid at different well depths and generate local anomaly signals. The surface monitoring and verification unit includes a flow monitoring subsystem and an active pressure subsystem. The flow monitoring subsystem is used to monitor the total flow rate of the drilling fluid at the inlet and outlet. The active pressure subsystem is used to apply characteristic pressure excitation to the drilling fluid circulation system in a controlled manner. The central control unit is bidirectionally connected to the downhole sensing unit and the surface monitoring and verification unit, and is configured to perform: (a) receive and analyze the data from the downhole sensing unit, and generate a primary trigger command when a local abnormal signal that matches the early characteristics of leakage is identified; (b) in response to the primary trigger command, start the active pressure subsystem to apply the characteristic pressure excitation. (c) During the application of characteristic pressure excitation by the active pressure subsystem, the response of the flow monitoring subsystem is monitored synchronously, and the presence and severity of additional leakage channels in the wellbore are assessed based on the hysteresis and attenuation between pressure fluctuations and flow fluctuations; (d) Based on the synergistic relationship between the local abnormal signals and the assessment results, leakage is confirmed and a graded alarm signal is output.

2. The drilling fluid leakage real-time monitoring system according to claim 1, characterized in that, The downhole sensing unit includes a miniature fiber optic temperature sensing array and a piezoelectric vibration sensing array, which are deployed at the same point or adjacent to each other. The miniature fiber optic temperature sensing array is used to monitor local temperature field anomalies caused by drilling fluid leakage into the formation. The piezoelectric vibration sensing array is used to monitor specific frequency vibration signals generated by high-speed fluid leakage impacting fractures. The local anomaly signal is a correlation combination of temperature anomaly signal and vibration anomaly signal.

3. The drilling fluid leakage real-time monitoring system according to claim 1, characterized in that, The flow monitoring subsystem includes a first electromagnetic flowmeter installed on the drilling fluid pump outlet pipe for monitoring and measuring the total inlet flow; and a second electromagnetic flowmeter and a microwave radar flowmeter installed in parallel on the return outlet pipe for jointly monitoring and measuring the total return flow.

4. The drilling fluid leakage real-time monitoring system according to claim 3, characterized in that, The active pressure subsystem includes an electronically controlled throttle valve and a booster pump assembly, which are controlled by the central control unit and are used to inject a characteristic pressure excitation into the drilling fluid riser or annulus. The waveform of this excitation is a low-frequency sine wave.

5. The drilling fluid leakage real-time monitoring system according to claim 1, characterized in that, The central control unit is configured to evaluate the following method: analyze the phase difference and amplitude attenuation ratio between the input waveform of the characteristic pressure excitation and the output flow response waveform measured by the flow monitoring subsystem; and convert the phase difference and amplitude attenuation ratio into a quantitative assessment of the existence and severity of the leakage channel.

6. The drilling fluid leakage real-time monitoring system according to claim 1, characterized in that, The logic for the central control unit to perform the collaborative judgment is as follows: if only the local abnormal signal exists and the evaluation result does not show a significant deterioration in wellbore sealing, it is determined to be downhole interference and an alert signal is output; if the local abnormal signal persists and, after applying characteristic pressure excitation, the evaluation result simultaneously confirms that the wellbore sealing has decreased beyond a threshold, it is determined to be a confirmed leak, an advanced alarm signal is output, and the leaking section is initially located by combining the spatial location information of the downhole sensing unit.

7. The drilling fluid leakage real-time monitoring system according to claim 6, characterized in that, The system also includes a mud tank level calibration unit, which includes a static pressure level sensor group installed in the main circulation tank. When the central control unit determines that there is no leakage and the operating condition is stable, it periodically starts the level calibration unit to perform online calibration and drift compensation for the mud tank level sensor used for total material balance calculation.

8. A drilling fluid loss monitoring method based on a drilling fluid loss real-time monitoring system according to any one of claims 1-7, characterized in that, Including the following steps: S1. Continuously monitor and identify abnormal correlations between local temperature and vibration signals through distributed downhole sensing units, and generate a primary trigger signal; S2. After receiving the primary trigger signal, the central control unit controls the active pressure subsystem to start and inject characteristic pressure excitation into the drilling fluid circulation system. S3. The central control unit synchronously collects the inlet and outlet flow response data measured by the flow monitoring subsystem during the excitation application period; S4. The central control unit assesses whether there are additional leakage channels in the wellbore and their severity based on the hysteresis and attenuation between pressure fluctuations and flow fluctuations. S5. The central control unit integrates the local abnormal signals from the well and the surface assessment results for collaborative analysis and judgment. If both meet the characteristics of leakage, leakage is confirmed and an alarm is triggered; otherwise, interference is eliminated.

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