Guided wave detection and quantitative evaluation method for route deviation of submarine pipeline

Abstract

The invention discloses a guided wave detection and quantitative evaluation method for submarine pipeline routing deviation. The method comprises the steps that S1, an excitation end module periodically injects stable guided wave signals into a pipeline; s2, an annular receiving module for synchronously receiving signals in the whole annular direction is installed at a terminal of the pipeline, and guided wave signals propagated for a long distance are accurately captured; s3, filtering and enhancing the originally collected noisy signals; s4, performing time-frequency analysis and waveform inversion on the received signal, and respectively extracting: calculating the equivalent curvature radius of the offset section according to the propagation velocity change; extracting phase lag information according to the phase change, and calculating a vibration path increment; calculating the overall transmission loss according to the amplitude attenuation degree; and S5, establishing a comprehensive identification criterion fusing the three types of feature parameters. The low-attenuation long-distance propagation characteristic of the L (0, 1) mode is utilized, the excitation device and the receiving array are arranged at the two ends of the pipeline, and online periodic remote monitoring under the non-stop production state is achieved.

Description

TECHNICAL FIELD

[0001] The application belongs to the technical field of submarine pipeline integrity detection, and particularly relates to a guided wave detection and quantitative evaluation method for submarine pipeline route deviation. BACKGROUND

[0002] Submarine pipelines are key lifeline projects for transporting oil and gas resources. With the rapid development of deep-sea oil and gas, power and communication industries, the number of submarine pipelines has increased significantly. Submarine pipelines are in long-term service in complex marine environments and are prone to be affected by factors such as current scour, geological activity and anchor drag impact, thereby causing large-scale route deviation.

[0003] These large-scale defects can greatly change the stress state of the pipeline, cause serious stress concentration at the wave crest and wave trough, and increase the cumulative fatigue damage of the pipeline. If not discovered and evaluated in time, the pipeline may be broken, and oil and gas may be leaked, causing catastrophic accidents.

[0004] Current monitoring methods mainly include underwater ROV visual detection, side-scan sonar and multi-beam depth sounding, built-in inertial measurement and magnetic measurement positioning (ILI intelligent detector) and distributed optical fiber strain / temperature monitoring. The above methods have limitations: ROV inspection depends on good underwater visibility and has high scheduling cost, and can only be operated intermittently; the resolution of the sonar is affected by water depth and sand covering, and the identification ability of the sonar for subtle deviation of buried pipeline sections is insufficient; ILI requires stopping production and opening holes to throw the detector, which interferes with production and can only obtain discrete time data; distributed optical fiber requires additional laying of sensing optical cable, which has complex construction, high investment and maintenance cost.

[0005] Therefore, there is an urgent need for a new monitoring method that does not require frequent manual intervention, can be laid in situ on the pipeline surface, and can continuously quantify the degree of deviation. Mechanical guided waves have been applied in the detection of long-distance pipelines on land due to their characteristics of long-distance propagation and sensitivity to structural damage and geometric changes; however, for submarine pipelines, especially overall route deviation, there is still a lack of reliable and rapid guided wave detection quantitative evaluation system and criterion model due to the complex dynamic environment of the seabed. SUMMARY

[0006] The technical problem to be solved by the present application is to provide a guided wave detection and quantitative evaluation method for submarine pipeline route deviation, which realizes online and periodic monitoring without interrupting production and accurately quantifies macroscopic geometric deformation.

[0007] To solve the above technical problems, the technical solution adopted by the present application is as follows: a guided wave detection and quantitative evaluation method for submarine pipeline route deviation, comprising the following steps:

[0008] S1: The excitation end module periodically injects a stable guided wave signal into the pipeline

[0009] An integrated annular excitation / receiving transducer module is installed on the outer wall of the topside end of the marine riser of the pipeline near-end platform; the annular excitation / receiving transducer module comprises an annular piezoelectric transducer array adhering to the outer wall of the pipeline; through its integrated phased driving circuit, a specific low-frequency, low-attenuation axisymmetric longitudinal guided wave mode L(0, 1) is selectively excited in a common mode excitation manner; the annular excitation / receiving transducer module is also used to capture reflected wave signals generated by significant bending points at the far end or in the middle of the pipeline;

[0010] S2: At the terminal of the pipeline, an annular receiving module for synchronously receiving signals is installed to accurately capture guided wave signals after long-distance propagation;

[0011] S3: Filtering and enhancing the original collected noisy signals

[0012] The multi-channel signals collected by the receiving node are coherently superimposed to improve the signal-to-noise ratio of the main transmission wave packet; a matching filter technology is used, and the known excitation signal waveform is used as a template to process the received signals, so as to accurately identify and locate the transmission wave packet and the possible weak reflected wave packet;

[0013] The short-time Fourier transform is used for time-frequency analysis of the signals, and according to the dispersion characteristics of different guided wave modes, the L(0, 1) main wave and the converted different mode waves are preliminarily separated and identified in the time-frequency domain;

[0014] S4: Three types of key characteristic parameters are extracted by time-frequency analysis and waveform inversion of the received signals:

[0015] The equivalent curvature radius of the offset section is calculated from the change of the propagation velocity; the phase lag information is extracted from the phase change to calculate the vibration path increment; the overall transmission loss is calculated from the amplitude attenuation degree;

[0016] S5: Establish a comprehensive identification criterion integrating the above three types of characteristic parameters

[0017] Through physical simulation, a pipeline model database containing different degrees and bending offset types is established; the above characteristic parameters actually collected are input into the offset identification criterion model calibrated and simulated by a large number of experiments, and an offset index representing the current routing offset severity of the pipeline is output.

[0018] As a preferred scheme, in step S4, the equivalent curvature radius of the offset section is calculated from the change of the propagation velocity, specifically:

[0019] The pipeline bending causes the lengthening of the guided wave propagation path and the change of the local propagation velocity; the equivalent path increment ΔL of the arrival time difference method is calculated from the arrival time difference Δt t : ΔL t = cg ·Δt; where c g Let L be the propagation speed of the straight pipe baseline L(0,1) mode.

[0020] As a preferred embodiment, in step S4, phase hysteresis information is extracted from the phase change, and the vibration path increment is calculated, specifically as follows:

[0021] Due to the phase lag of the dominant mode Calculate the equivalent path increment using the phase difference method

[0022] Where f is the excitation center frequency, c0 is the phase velocity of the L(0,1) mode in the straight tube at frequency f, and λ is the working wavelength;

[0023] This can be cross-checked with the time difference of arrival method to inversely deduce the equivalent radius of curvature R of the offset segment. c The details are as follows:

[0024] The results of the time-of-arrival (TOA) method and the phase lag method are cross-validated and weighted, including the calculation of the uncertainty σ based on the TOA and phase lag methods. L,t , Depend on σ is derived L,t ≈c g σ Δt ; Where σ Δt The time difference of arrival is the uncertainty, B is the effective signal bandwidth, and SNR is the signal-to-noise ratio.

[0025] Calculate the variance weight w t and The final equivalent path increment ΔL is obtained by weighting the data.

[0026]

[0027] And perform a consistency check if the following condition is true:

[0028] κ can take any value between 2 and 3;

[0029] If the above formula is not true, it is judged to be inconsistent, and it is necessary to check whether there is a significant mode transition that leads to an incorrect selection upon arrival;

[0030] The equivalent radius of curvature R of the lower offset segment under small deflection approximation c The path increment ΔL satisfies:

[0031] Therefore, we get: Where L b This is the length of the offset segment.

[0032] As a preferred solution, the step S4 is to calculate the overall transmission loss from the amplitude attenuation degree, specifically:

[0033] The additional transmission loss per unit length α is calculated from the baseline amplitude Aref of the straight pipe and the amplitude Acur of the offset section:

[0034] Where L is the effective distance of the total propagation.

[0035] As a preferred solution, in the step S5,

[0036] Through physical simulation, a pipeline model database is established containing different degrees of slight, significant, severe and different bending offset types of vertical and lateral;

[0037] The feature vector is constructed:

[0038] Where x2 is the phase lag normalized to the wavelength unit; x3 is the attenuation coefficient of the additional loss per unit length, which is dB / m;

[0039] The offset index D is obtained by weighted fusion:

[0040] u = β0 + β1x1 + β2x2 + β3x3;

[0041] Where: D ∈ (0, 1), representing the offset index, the closer to 1 indicating the more serious offset; σ(u) is the Sigmoid function, which compresses the linear combination result to 0-1; The parameters β0, β1, β2, β3 are calibrated by joint calibration of finite element simulation samples, bench and field data; Threshold grading is set according to operation and maintenance requirements.

[0042] As a preferred solution, the excitation action of the ring-shaped excitation / receiving transducer module is remotely triggered by the platform master station through the composite cable, and the excitation period is set as needed to realize long-term online monitoring.

[0043] As a preferred solution, the ring-shaped receiving module is a ring-shaped sensor array, including a plurality of high-sensitivity accelerometers or piezoelectric sensor units uniformly distributed on the circumference of the pipeline. These nodes realize sub-microsecond synchronization with the excitation module through high-precision clock synchronization technology, so as to collect the attenuated transmission L(0, 1) mode guided wave and completely capture the spatial distribution characteristics of the newly generated non-axisymmetric bending mode wave on the pipeline cross section due to the overall bending of the pipeline.

[0044] As a preferred solution, the axial distances Sf, Sp, Sg from the flange / guide saddle / girth weld to the annular piezoelectric transducer array arranged behind the straight section of the near-shore end riser respectively satisfy the following qualitative length constraints: Sf, Sp, Sg ≥ 10D0, Sf, Sp, Sg ≥ 5D0, Sf, Sp, Sg ≥ 3D0. f P g

[0045] As a preferred solution, the standoff distance s from the center of the annular piezoelectric transducer array to the nearest bend / transition arc segment satisfies: s ≥ smin, where the minimum standoff distance smin is given by the "early reflection time separation": min

[0046]

[0047] Here τ = N / f is the Hann windowed excitation pulse width of N cycles, t g ≈0.5τ is the guard interval.

[0048] The beneficial effects of the present application are:

[0049] (1) The present application uses the low-attenuation long-distance propagation characteristics of L(0,1) mode to arrange excitation devices and receiving arrays at both ends of the pipeline, realizing "two-end excitation, full-line coverage" online periodic remote monitoring without shutdown, which fundamentally reduces the need for frequent scheduling of ROVs or shutdown detection, and greatly improves the continuity and economy of monitoring.

[0050] (2) The present application uses the high sensitivity of guided waves to geometric disturbances to construct a three-class coupling index system of curvature radius R c , phase lag transmission loss α, and realizes multi-source feature mutual verification and comprehensive evaluation by fusion model calculation of the deviation index D, significantly improving the accuracy, stability and anti-interference ability of route deviation identification.

[0051] (3) The guided wave detection scheme of the present application is not sensitive to pipeline covering, sand covering and surrounding geological conditions, and the excitation and receiving devices can be arranged at accessible positions such as pipeline risers, without the need to expose the entire pipeline to achieve long-distance coverage, thus having a wide range of applications.

[0052] ​​​​(4)In view of the problems of complex construction, permanent change or additional optical cable on the surface of the pipeline in the traditional sensing scheme, the annular transducer array module is adopted, the quick installation and disassembly are realized through the clamp type structure, the original pipeline structure is not damaged, the maintenance and replacement are convenient, the pipeline can be implemented under the condition of not affecting the normal operation, and the application in various engineering sites is facilitated. BRIEF DESCRIPTION OF DRAWINGS

[0053] Figure 1 It is a schematic diagram of the overall layout of the submarine pipeline guided wave monitoring device

[0054] Figure 2 It is a structural composition diagram of the annular piezoelectric transducer array excitation module.

[0055] Figure 3 Schematic diagram of the propagation effect of mechanical guided waves in the pipeline bending section

[0056] Figure 4 It is a flow chart of offset comprehensive quantitative evaluation

[0057] Figure 5 It is a time domain comparison diagram of guided wave signals with and without offset

[0058] Explanation of reference numerals: 1, offshore platform; 2, annular piezoelectric transducer array excitation module; 3, riser; 4, flat pipe; 5, ring receiving module; 6, incident wave; 7, reflected wave; 8, mode conversion wave; 9, transmitted wave; 10, straight pipe section; 11, offset pipe section. DETAILED DESCRIPTION

[0059] The specific implementation scheme of the present application will be described in detail below with reference to the drawings.

[0060] As shown in Figures 1 to 4 , the method is suitable for in-situ, long-term, non-stop offset monitoring and discrimination of long-distance conveying pipelines laid on the seabed or shallow buried section of the seabed. The long-distance conveying pipeline includes two risers 3 connecting two offshore platforms 1 and a submarine flat pipe 4.

[0061] The guided wave detection and quantitative evaluation method for the pipeline offset includes the following steps: S1: the excitation end module periodically injects stable guided wave signals into the pipeline

[0062] An integrated annular excitation / receiving transducer module is installed on the outer wall of the water riser end of the pipeline near the platform; the annular excitation / receiving transducer module includes an annular piezoelectric transducer array attached to the outer wall of the pipeline; through the integrated phased drive circuit, a specific low-frequency and low-attenuation axisymmetric longitudinal guided wave mode L(0,1) is selectively excited in a common mode excitation manner; the annular excitation / receiving transducer module is also used to capture reflected wave signals generated by the far end or significant bending point of the pipeline.

[0063] A waveguide coupling agent is applied between the transducing surface of the ring-shaped piezoelectric transducer array and the steel pipe to improve the waveguide excitation efficiency. The waveguide excitation mode is selected as L(0, 1), which has strong axial propagation ability, low dispersion characteristics, and strong response to geometric disturbance. The ring-shaped piezoelectric transducer array excitation module 2 is connected to the shore station control center through an underwater composite cable, realizing remote periodic excitation with a period of 1 time / hour. The ring-shaped piezoelectric transducer array excitation module 2 periodically outputs L(0, 1) waveguide with a center frequency of 500 Hz to form incident wave 6. The low frequency selection makes the attenuation constant of the waveguide in the steel pipe wall α0≈3×10 -5 Np·m -1 , which can realize long-distance low-loss propagation.

[0064] To improve the signal-to-noise ratio and reduce the early interference of the near-end structure on the waveguide, the excitation / receiving ring array is arranged at the straight pipe section of the near-shore riser, and the following qualitative length constraints are met:

[0065] Avoiding discontinuity and rigid constraint: After the ring-shaped piezoelectric transducer array is arranged at the straight pipe section of the near-shore riser, the axial distances Sf, Sp, and Sg of the ring-shaped piezoelectric transducer array to the flange / guide saddle / girth weld and the nominal outer diameter D0 of the submarine pipeline respectively meet the following qualitative length constraints: S f ≥10D0, S P ≥5D0, S g ≥3D0;

[0066] Taking the pipe material of API 5L X65, the nominal outer diameter D0=508mm, and the wall thickness t=19.1mm of the steel conveying pipeline as the object:

[0067] 10D0≈5.1m, 5D0≈2.5m, 3D0≈1.5m;

[0068] Avoiding the nearest bend: The retreat distance s of the center of the ring-shaped piezoelectric transducer array to the nearest bend / transition arc section is s≥s min , where the minimum retreat distance is given by the "early reflection time separation":

[0069]

[0070] Here τ=N / f is the Hann window excitation pulse width of N cycles, t g ≈0.5τ is the protection gap; Taking f=500Hz, λ≈10.2m in this embodiment, s=4-8λ (about 40-80m) is taken;

[0071] The incident wave 6 propagates along the straight pipe section 4, and when it reaches the transition area of the straight pipe section 10 and the offset pipe section 11, different responses are generated due to the destruction of geometric continuity.

[0072] Three typical responses can be observed on the guided wave propagation path in the area of straight pipe section 10 and offset pipe section 11: ① When the axisymmetric guided wave 6 injected by the annular piezoelectric transducer array excitation module 2 encounters the starting point of the structural geometric change, partial reflection wave 7 is generated due to the destruction of the boundary conditions and cross-section continuity. ② The guided wave 6 enters the interior of the offset area, and the smaller curvature radius leads to energy leakage and mode conversion, exciting the asymmetric mode of the mode conversion wave 8. ③ The guided wave forms a transmission wave 9 after passing through the curved area, but shows amplitude attenuation, phase lag and mode mixing.

[0073] S2: The circumferential receiving module 5 captures the transmission wave 9 and the mode conversion wave 8 generated by the geometric disturbance in the full circumferential direction, and the excitation module 2 synchronously captures the reflection wave 7, realizing two-end measurement.

[0074] The circumferential receiving module 5 supporting multi-mode guided wave reception is deployed at the end of the riser 3, and is installed in the same way as the excitation module 2, also adopting an annular array structure. Each channel is connected to the local embedded signal processing unit through a multi-channel synchronous sampling module, and communicates at high speed with the shore station data server. In order to improve the spatial resolution and mode recognition accuracy, the array supports multi-mode guided wave reception, which can be used for L(0,1) mode, and can also sense F(1,1), T(0,1) and other mode energy.

[0075] In the normal working process, the system starts the excitation module 2 to send guided wave signals 6 according to the set time interval, and synchronously starts the receiving module to start collecting response signals reflection wave 7, mode conversion wave 8, transmission wave 9. The data acquisition window length is set according to the propagation distance and dispersion characteristics, generally 0.3s.

[0076] S3: Filtering and enhancing the original collected noisy signals

[0077] The multi-channel signals collected by the receiving node are coherently superimposed to improve the signal-to-noise ratio of the main transmission wave packet; the matching filter technology is used, and the known excitation signal waveform is used as a template to process the received signal, so as to accurately identify and locate the transmission wave packet and the possible weak reflection wave packet;

[0078] The short-time Fourier transform is used for time-frequency analysis of the signal, and according to the dispersion characteristics of different guided wave modes, the L(0,1) main wave and the converted different mode waves (including reflection wave 7, mode conversion wave 8, transmission wave 9) are preliminarily separated and identified in the time-frequency domain; the signal propagation time t, envelope amplitude A, phase lag amount

[0079] S4: Extract three types of key characteristic parameters by time-frequency analysis and waveform inversion on the received signal: the equivalent curvature radius of the offset section is calculated from the change of propagation velocity; the phase lag information is extracted from the phase change to calculate the vibration path increment; the overall transmission loss is calculated from the amplitude attenuation degree;

[0080] The equivalent curvature radius of the offset section is calculated from the change of propagation velocity, specifically:

[0081] The pipe bending causes the lengthening of the wave propagation path and the change of local propagation velocity; the equivalent path increment ΔL of the arrival time difference method is calculated from the arrival time difference Δt t : ΔL t = c g · Δt; where c g is the propagation velocity of the straight pipe baseline L(0,1) mode.

[0082] The vibration path increment is calculated from the phase change to extract the phase lag information, specifically:

[0083] The equivalent path increment ΔL of the phase difference method is calculated from the main mode phase lag

[0084] Where f is the excitation center frequency, c0 is the phase velocity of the L(0,1) mode at frequency f in the straight pipe, and λ is the working wavelength;

[0085] Accordingly, the equivalent curvature radius R of the offset section can be cross-checked with the arrival time difference method and inversely calculated, specifically as follows: c

[0086] By cross-verification and weighted fusion of the results of the arrival time difference method and the phase lag method, including calculating the uncertainty σ L，t based on the arrival time difference method and the phase lag method σ L，t ≈ c g σ Δt ; Where σ Δt is the uncertainty of the arrival time difference, B is the effective signal bandwidth, and SNR is the signal-to-noise ratio;

[0087] Calculate the variance weight w t and perform weighted processing to obtain the final equivalent path increment ΔL:

[0088]

[0089] And perform consistency check, if the following judgment formula is established:

[0090] ​​​​κ takes any value between 2 and 3;

[0091] If the above formula is not true, it is determined that the consistency is inconsistent, and it is necessary to check whether there is a significant modal conversion leading to a selection error at the arrival time;

[0092] The equivalent curvature radius R of the offset section under the small deflection approximation c The path increment ΔL satisfies:

[0093] Thus: Where L b is the length of the offset section.

[0094] The overall transmission loss is calculated from the amplitude attenuation degree, specifically:

[0095] The additional transmission loss per unit length α is calculated based on the straight pipe baseline amplitude Aref and the offset section amplitude Acur:

[0096] Where L is the effective distance of the total propagation.

[0097] Characteristic parameter calculation, positioning of the main transmission wave L(0,1) in the guided wave response signal, combining the straight pipe 10 baseline data and the curved section sampling, sequentially calculating the following key physical indicators:

[0098] The pipeline material is API 5L X65, the nominal outer diameter D0 is 508 mm, the wall thickness t is 19.1 mm, and the steel conveying pipeline is taken as the object; the total propagation distance L of the measured section is approximately 1.2 km, and the offset section uses an equivalent circular arc curvature radius R c ∈[100m,5km], length L b =100m;

[0099] Where the length of the suspected offset (bend) region L b ≈100m; water depth 60-90m;

[0100] Medium and boundary conditions: an unreflective absorbing layer is applied to the outer boundary to simulate seawater, with a thickness of 0.6-1.0 working wavelengths; Winkler-Pasternak equivalent foundation and viscous damping terms are added to the outside of the pipe wall, with parameters taken from the range of field exploration.

[0101] The excitation frequency f is 500 Hz, the L(0,1) mode is selected, the straight pipe propagation speed c o ≈5.1km / s, and the working wavelength λ≈10.2m. The reflection is synchronously collected near the end, and the transmission and modal conversion response is received in the full circumferential direction at the far end.

[0102] Under the condition of L b =100m, c0=5.1km / s, the arrival time difference Δt of the main transmission wave and R cSeveral typical values:

[0103] R c =5000m: Δt≈0.00033ms; α≈0.0060dB / m;

[0104] R c =1000m: Δt≈0.0082ms; α≈0.0090dB / m;

[0105] R c =300m: Δt≈0.091ms; α≈0.0175dB / m;

[0106] R c =100m: Δt≈0.82ms; α≈0.042dB / m;

[0107] Δt and R c Approximate

[0108]

[0109] In this example, K t K is the equivalent coupling constant between geometry and wave velocity. t ≈8.16×10 3 ms·m 2 The regression fit determination coefficient R 2 ≈0.97;

[0110] Depend on have to:

[0111] In this example, The equivalent coupling constant between geometry and phase. Consistent with ΔL calculated using the time method R 2 ≈0.98;

[0112] In a free-layout environment, α and Nearly linear:

[0113] Based on 68 sets of coverage intervals R c For the simulation sample ∈ [100m, 5km], a = 3.67, b = 0.0053, the fitted R0 is... 2 ≈0.94. S5: The above three physical parameters (radius of curvature R) c Phase lag Transmission loss α) input three-dimensional deviation identification model based on finite element simulation and measured calibration, and output comprehensive deviation index D by using weighted fusion algorithm.

[0114] Taking features Wherein, x2 is phase lag normalized to wavelength unit; x3 is attenuation coefficient for additional loss unit per unit length, in dB / m;

[0115] Deviation index D is obtained by using weighted fusion:

[0116]

[0117] Wherein: D∈(0, 1), representing deviation index, the closer to 1 indicates the more serious deviation; σ(u) is Sigmoid function, which compresses linear combination result to 0-1; parameters β0, β1, β2, β3 are calibrated by finite element simulation sample, bench and field data; based on 68 groups of calibrated example weights: β0=-2.1, β1=2.4, β2=1.3, β3=0.9.

[0118] When D exceeds the preset threshold, the system triggers serious or moderate deviation alarm respectively; if D is lower than the safety threshold, it is determined as normal state.

[0119] The above embodiments only exemplarily illustrate the principles and effects of the present application, and part of the applied embodiments, and are not used to limit the present application; it should be noted that for ordinary skilled in the art, without departing from the concept of the present application, a number of modifications and improvements can be made, which all belong to the protection scope of the present application.

Claims

1. A method for guided wave detection and quantitative evaluation of pipeline route deviation, comprising the following steps: S1: periodically injecting a stable guided wave signal into the pipeline by the excitation end module An integrated annular excitation / receiving transducer module is installed on the outer wall of the water riser at the near-end platform of the pipeline; the annular excitation / receiving transducer module comprises an annular piezoelectric transducer array attached to the outer wall of the pipeline; through its integrated phased drive circuit, a specific low-frequency, low-attenuation axisymmetric longitudinal guided wave mode L(0, 1) is selectively excited in a common mode excitation manner; the annular excitation / receiving transducer module is also used to capture reflected wave signals generated by significant bending points at the far end or along the pipeline; S2: at the terminal of the pipeline, install a ring-shaped receiving module that synchronously receives signals in all directions to accurately capture the guided wave signals after long-distance propagation; S3: filtering and enhancing the original collected noisy signals Coherent superposition is performed on the multi-channel signals collected by the receiving node to improve the signal-to-noise ratio of the main transmission wave packet; a matching filter technology is used, and the known excitation signal waveform is used as a template to process the received signal, so as to accurately identify and locate the transmission wave packet and possible weak reflected wave packet; Time-frequency analysis is performed on the signal using short-time Fourier transform, and according to the dispersion characteristics of different guided wave modes, the L(0, 1) main wave and the converted different mode waves are preliminarily separated and identified in the time-frequency domain; S4: three types of key characteristic parameters are extracted by time-frequency analysis and waveform inversion of the received signal: The equivalent curvature radius of the deviation section is calculated from the change of the propagation velocity; the vibration path increment is calculated from the phase lag information; the overall transmission loss is calculated from the amplitude attenuation degree; S5: establish a comprehensive identification criterion integrating the above three types of characteristic parameters Through physical simulation, a pipeline model database containing different degrees and bending deviation types is established; the above characteristic parameters actually collected are input into the deviation identification criterion model established through a large number of experimental calibration and simulation training, and a deviation index representing the severity of the current pipeline route deviation is output.

2. A method of guided wave detection and quantitative assessment of a route deviation of a subsea pipeline as claimed in claim 1, characterized in that: In the step S4, the equivalent curvature radius of the deviation section is calculated from the change of the propagation velocity, specifically: Pipe bends cause a lengthening of the waveguide propagation path and a change in the local propagation velocity; the equivalent path increment AL is calculated from the arrival time difference At by the arrival time difference method t : AL t = c g • At; where c g is the propagation velocity of the straight pipe baseline L(0,1) mode.

3. A method of guided wave detection and quantitative assessment of a route shift of a subsea pipeline as defined in claim 1, wherein: In the step S4, the vibration path increment is calculated from the phase change and the phase lag information, specifically: by the primary mode phase lag equivalent path increment of the computed phase difference method Wherein, f is the excitation center frequency, c0 is the phase velocity of L(0, 1) mode at frequency f in the straight pipe, and λ is the working wavelength; Accordingly, the arrival time difference method can be cross-checked and the equivalent curvature radius R of the migration section can be deduced c Specifically as follows: By cross-validation and weighted fusion of the results of the arrival time difference method and the phase lag method, including calculating the uncertainty σ based on the arrival time difference method and the phase lag method L,t 、 From σ L,t ≈c g σ Δt ; Where σ Δt is the uncertainty of the arrival time difference, B is the effective signal bandwidth, and SNR is the signal-to-noise ratio; The variance weight w is calculated t With The final equivalent path increment ΔL is obtained by weighting processing Consistency check is performed, and if the following judgment formula is established: K takes any value between 2 and 3; If the above formula is not established, it is judged as inconsistent, and it is necessary to check whether there is a significant mode conversion leading to the arrival time selection error; Offset segment equivalent radius of curvature R under small deflection approximation c satisfies: Thus, we have where L b is the offset segment length.

4. A method of guided wave detection and quantitative assessment of a route shift of a subsea pipeline as defined in claim 1, wherein: In the step S4, the overall transmission loss is calculated from the amplitude attenuation degree, specifically: With straight pipe baseline amplitude A ref With offset segment amplitude A cur Calculate the additional transmission loss per unit length α: where L is the effective distance of total propagation.

5. A method of guided wave detection and quantitative evaluation of a route shift of a subsea pipeline as defined in claim 1, wherein: In the step S5, Through physical simulation, a pipeline model database containing different degrees - slight, significant, severe and different bending deviation types - vertical and lateral is established; Constructing the feature vector: Wherein, x2 is the phase lag normalized to the wavelength unit; x3 is the attenuation coefficient, which is the additional loss unit per unit length, in dB / m; The deviation index D is obtained by weighted fusion: Wherein: D∈(0,1), represents the deviation index, the closer to 1 indicates the more serious deviation; Sigma (u) is a Sigmoid function, which compresses the linear combination result to 0-1; Parameters β0, β1, β2, β3 are calibrated by joint calibration of finite element simulation samples, bench and field data; Threshold classification is set according to operation and maintenance requirements.

6. A method of guided wave detection and quantitative evaluation of a route shift of a subsea pipeline as defined in claim 1, wherein: The excitation action of the ring-shaped excitation / receiving transducer module is remotely triggered by the platform master station through the composite cable, and the excitation cycle is set as needed to realize long-term online monitoring.

7. A method of guided wave detection and quantitative evaluation of a route shift of a subsea pipeline as defined in claim 1, wherein: The ring-shaped receiving module is a ring-shaped sensor array, including a plurality of high-sensitivity accelerometers or piezoelectric sensor units uniformly distributed on the circumference of the pipeline, and these nodes are synchronized with the excitation module to sub-microsecond level through high-precision clock synchronization technology, so as to collect the attenuated transmission L(0,1) mode guided wave and completely capture the spatial distribution characteristics of the newly generated non-axisymmetric bending mode wave on the pipeline cross section due to the overall bending of the pipeline.

8. A method of guided wave detection and quantitative evaluation of a route shift of a subsea pipeline as defined in claim 1, wherein: The axial distances Sf, Sp, Sg of the annular piezoelectric transducer array arranged behind the straight pipe section of the near-shore end riser to the flange / guide saddle / girth weld of the subsea pipeline respectively satisfy the following qualitative length constraints: S f ≥ 10D0, S p ≥ 5D0, S g ≥ 3D0.

9. A method of guided wave detection and quantitative evaluation of a route shift of a subsea pipeline as defined in claim 1, wherein: The distance s from the center of the ring array of the annular piezoelectric transducer array to the nearest bend / transition arc segment satisfies: s≥s min where the minimum standoff is given by the early reflection time separation: Here τ = N / f is the Hann windowed excitation pulse width in N cycles, t g ≈0.5τ is the guard gap.

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