METHOD FOR MONITORING THE INTERIOR OF AN UNDERWATER PIPELINE

Abstract

The invention relates to a method for monitoring the interior of a pipeline (1) placed in contact with a bed (S) under a body of water (E), the method comprising the implementation, by data-processing means (11), of steps of: (a) for at least one position along said pipeline (1), obtaining acoustic data that are descriptive of at least one transverse cross section of said pipeline (1) at said position, said data being acquired by an acoustic acquiring device (20) that may be moved through said body of water (E); (b) estimating, via quantitative migration, on the basis of said acoustic data, an estimated profile of relative impedance perturbations in at least said transverse cross section of said pipeline (1).

Description

[0001] METHOD FOR MONITORING THE INSIDE OF A SUBWATER PIPELINE

[0002] The present invention relates to a method for monitoring the interior of a subsea pipeline. By pipeline, we mean a conduit intended for the transport of fluids such as hydrocarbons.

[0003] STATE OF THE ART

[0004] In hydrocarbon transport pipelines, blockages can form for various reasons and halt production. They can be cleared by localized heating, but this first requires being able to locate them with a minimum degree of precision (to within a few meters, whereas pipelines can be several kilometers long).

[0005] We know of a number of techniques for this purpose, but these encounter limitations in terms of acquisition constraints.

[0006] Indeed, techniques such as acoustic reflectometry (based on the principle that the propagation of an acoustic wave in a fluid medium is very sensitive to each discontinuity in the properties of the fluid, see Wang et al, 2011) or the use of guided waves (Kippersund et al., 2011; Chapuis et al., 2014; Pomié et al., 2014) require access to the inside of the pipe, which is complex in particular for pipelines positioned in deep water and / or at least partially buried.

[0007] Alternatively, ultrasonic methods as described in patent applications FR3001162, WO2014 / 114887, WO2013 / 169984 and

[0008] WO201 1 / 133046 uses devices mounted on the pipeline (emitters and sensors all around the pipeline). Access to the inside of the pipeline is no longer necessary, but this remains difficult to implement, particularly with pipelines that may be buried or even encased in concrete.

[0009] The worst-case scenario involves buried, deep-sea pipelines, which require delicate and very costly excavations. Furthermore, acquisition times with known methods are very long, up to ten minutes to achieve sufficient resolution in a cross-section, which is impractical for investigating tens or even hundreds of kilometers of pipeline.

[0010] It would be desirable to have a new universal solution for detecting blockages in submarine pipelines, including buried ones, which is efficient, reliable, and inexpensive compared to the existing methods mentioned above.

[0011] The invention improves the situation.

[0012] The following documents will be cited during the description:

[0013] - Beylkin, G., 1984, The inversion problem and applications of the generalized Radon transform: Comm. Pure Appl. Math., 37, 579-599.

[0014] - Chapuis, B., Baronian, V., Jenson, F. and Pomié, L., 2014, Hydrate plug localization and characterization using guided waves. 11th European Conference on Non-Destructive Testing (ECNDT 2014), October 6-10, 2014, Prague, Czech Republic.

[0015] - Gerea, C., Nicolétis, L, and Granger, PY, 2000, “Multicomponent true amplitude anisotropic imaging”, proceedings of the 9th IWSA workshop, SEG.

[0016] - Kippersund, R. A., Lunde, P., and Frøysa, K. E., 2011. Hydrate Deposit Détection in Pipes Using Ultrasonic Guided Waves. In Proceedings of the 34th Scandinavian Symposium on Physical Acoustics.

[0017] - Lambaré, G., Virieux, J., Madariaga, R., Side, J., 1992, Itérative asymptotic inversion in the acoustic approximation. Geophysics, 57, 1138-1154.

[0018] - Miller, D., Oristaglio, M., and Beylkin, G., 1987, A new slant on seismic imaging: Migration and intégral geometry: Geophysics, 52, 943-964.

[0019] - Nicolétis, L., Svay-Lucas, J., Clochard, V., and Compte, P., 1997, 3D true amplitude migration of 3-C compressional and converted shear wave: J. of Seismic Explo., 6, 127-142.

[0020] - Pomié, L., Tzotzi, C., Faderne, C., Chapuis, B., and Jenson, F., 2014. Hydrate Plug Localization and Characterization With Ultrasonic and Guided Waves Technologies. In 9th North American Conference on Multiphase Technology. BHR Group. - Wang, Journal of Mechanical Engineering Science. 226(7) 1800-1810. DOI: 10.1177 / 0954406211431029

[0021] PRESENTATION OF THE INVENTION

[0022] The invention, according to a first aspect, proposes a method for monitoring the interior of a pipeline placed in contact with the ground beneath a body of water, the method comprising the implementation, by means of data processing, of the following steps:

[0023] (a) For at least one position along said pipeline, obtaining descriptive acoustic data of at least one cross-section of said pipeline at said position, acquired by means of a mobile acoustic acquisition device in said water body;

[0024] (b) Estimation by quantitative migration from said acoustic data of an estimated profile of relative impedance disturbances along at least said cross-section of said pipeline.

[0025] According to other advantageous and non-limiting characteristics:

[0026] The said acoustic acquisition device comprises at least one acoustic wave source and at least one acoustic wave sensor, the said descriptive acoustic data of a cross-section of said pipeline at said position being a reflected acoustic field received by at least one sensor following the generation of an acoustic field by at least one source.

[0027] The said acoustic acquisition device comprises a plurality of sensors and / or sources arranged in a direction substantially orthogonal to a longitudinal direction of said pipeline at said position.

[0028] Step (b) includes the calculation at the positions of each source and each sensor of so-called Green's functions representative of a response to a point acoustic emission at any point of said cross-section, and then the estimation at any point of said cross-section of said pipeline of a relative impedance perturbation value as a function of said received acoustic field and of parameters of said calculated Green's functions.

[0029] The calculation at the positions of each source and each sensor of said Green's functions includes the interpolation, based on the actual positions of said sources and sensors, of Green's functions pre-calculated for a set of fictitious positions.

[0030] This quantitative migration estimation is obtained at a point x0 of the pipeline cross-section, for a collection of source(s) and sensor(s) if they are coplanar, using the formula and otherwise thanks to the formula with Ψ S and Φ S translating the angular coverage of the seismic acquisition device, p the diffraction wavenumber, and the Fourier transform of disturbances in the environment.

[0031] The method further includes a step (c) of comparing said estimated profile of relative impedance disturbances with at least one reference model of relative impedance disturbances representative of the presence of a blockage in the pipeline at said position.

[0032] In step (c) said estimated profile of relative impedance disturbances is compared with a plurality of reference models of relative impedance disturbances representative of a set of possible plug configurations in the pipeline at said position.

[0033] Said set of possible plug configurations in the pipeline at said position includes at least one total plug configuration, one partial plug configuration at the bottom, and one partial plug configuration in the crown.

[0034] In step (c) said estimated profile of relative impedance disturbances is further compared with a reference model of relative impedance disturbances representative of an absence of a blockage in the pipeline at said position.

[0035] The process further includes a step (d) of destroying the detected plug. Said pipeline is a hydrocarbon pipeline, and said plug is a hydrate plug.

[0036] A second aspect proposes equipment for monitoring the interior of a pipeline located in contact with the ground beneath a body of water; the equipment includes data processing means configured to:

[0037] - For at least one position along said pipeline, obtain descriptive acoustic data of at least one cross-section of said pipeline at said position, acquired by a mobile acoustic acquisition device in said water mass;

[0038] - Estimate by quantitative migration from said acoustic data an estimated profile of relative impedance disturbances along at least said cross-section of said pipeline.

[0039] According to a third aspect, a computer program product is proposed that can be downloaded from a communication network and / or recorded on a computer-readable medium and / or executable by a processor, comprising program code instructions for implementing the process according to the first aspect, when said program is executed on a computer.

[0040] PRESENTATION OF THE FIGURES

[0041] Other features, purposes and advantages of the invention will become apparent from the following description, which is purely illustrative and not limiting, and which should be read in conjunction with the accompanying drawings on which:

[0042] - Figure 1 represents a system architecture for implementing the process according to the invention;

[0043] - Figure 2 schematically represents the method for detecting a blockage in a pipeline according to a preferred embodiment of the invention;

[0044] - Figure 3 describes the relationship between angles, i.e. the dips investigated in the medium (angular coverage) as a function of a 2D and 3D acoustic acquisition device; - Figure 4a represents three examples of synthetic models (acoustic impedance) of plugs for three plug configurations;

[0045] - Figure 4b represents three examples of relative impedance perturbation models corresponding to the three synthetic plug model examples in Figure 4a;

[0046] - Figure 4c represents three examples of relative impedance perturbation profiles estimated by an implementation of the quantitative migration according to the invention corresponding to the three examples of relative impedance perturbation models in Figure 4b;

[0047] - Figure 5a represents two examples of synthetic plug models and corresponding relative impedance perturbation models, respectively for a configuration of total plug presence and a configuration of no plug;

[0048] - Figure 5b represents two example profiles of relative impedance perturbations estimated by an implementation of the quantitative migration according to the invention, corresponding to the two example models of relative impedance perturbations in Figure 5a.

[0049] DETAILED DESCRIPTION

[0050] Principle of the invention

[0051] The present process proposes to use acoustic data, for example of the CHIRP (Compressed High Intensity Radar) type, which can be recorded by an acquisition system on board a boat (shallow waters) or a remotely operated underwater vehicle (ROV) which can travel kilometers at a few tens of centimeters (50 cm minimum) or a few meters above a pipeline laid or (semi-)buried under the seabed.

[0052] More specifically, sonar systems are known to be used as "subbottom profilers" due to their ability to record the acoustic energy reflected by layers of marine sediment in the first few meters below the seabed. For example, the Sub-Bottom Imager™ (SBI) from Pangeo Subsea can provide real-time mapping with a width of a few meters and a penetration depth of a few meters, or even a few tens of meters, into marine sediments. The processing technique used employs a beamforming method, focusing the acoustic waves received by the sonar to calculate an image in the first few meters, down to about twenty meters, below the seabed (depending on the frequency content of the acoustic sources).

[0053] These known techniques are only directed towards the exploration of the subsoil (at best they allow, when coupled with a magnetometer, to locate a pipeline, see US patent 4422166) and are incapable of characterizing the inside of a pipeline and a fortiori of detecting a blockage in a pipeline.

[0054] In a particularly ingenious manner, the applicant demonstrated, as will be seen later, that applying a suitable quantitative migration technique to acoustic data makes it possible to recover relative impedance perturbations (recall that the impedance of a medium for an acoustic wave corresponds to the product of the medium's density and the acoustic wave's propagation velocity) which can be used to monitor the inside of the pipeline and, in particular, to detect a blockage. These perturbations are indeed linked both to the pipeline's construction and to the presence of partial or total blockages, thus making it possible to characterize the pipeline's interior along a cross-sectional plane.

[0055] Thus, acquiring adequate acoustic data using a device that "flys" over the pipeline (along its entire length if one wishes to be exhaustive) is all that is needed to detect any blockage. This technique is therefore completely non-invasive (no access to the pipeline, near or far, is required), reliable, and less expensive.

[0056] Architecture With reference to Figure 1, a method is proposed for monitoring the inside of a pipeline 1 placed in contact with a soil S under a body of water E. By "placed in contact with a soil", it is understood that at least part of the pipeline 1 can be laid directly on the soil S and / or be at least partially buried under the soil S.

[0057] The present process is typically implemented using equipment 10 as shown in Figure 1 (for example, a computer workstation) equipped with data processing means 11 (a processor) and data storage means 12 (memory, in particular a hard disk), typically provided with an input and output interface 13 for capturing data and outputting the results of the process.

[0058] The pipeline 1 is typically a roughly circular pipe, forming a wall (which may be made of metal and possibly covered with one or more types of insulation, up to a total thickness of about fifteen centimeters) separating an "inside" from an "outside". The inside is normally empty (the pipeline is hollow) and is most often intended for the transport of hydrocarbons in a mixed gaseous, liquid, or solid form, for example, natural gas. This empty space that the pipeline 1 normally has inside is called a "hole" 2. As explained, a blockage 3 may have formed inside the pipeline 1.

[0059] By plug 3, we mean a solid mass, or at least a mass significantly more viscous than the fluid normally flowing in pipeline 1, which reduces (partial plug) or obstructs (total plug) the lumen 2, and thus limits the fluid flow in pipeline 1. In the remainder of this description, we will consider two examples of partial plugs 3: one "at the bottom" (i.e., the remaining lumen 2 is at the top), and the other "in a ring" (i.e., the remaining lumen 2 is in the center). However, it is clear that the shape of a plug according to the invention can be any shape. In the case of hydrocarbons, the plug 3 that can form is generally a hydrate plug, and this example (gas hydrate) will also be used in the remainder of the description.

[0060] Pipeline 1 is positioned in contact with a soil S beneath a body of water E, meaning it is a submarine pipeline (the water body S is typically several hundred, or even thousands, of meters thick), laid or at least partially buried. More precisely, the interface between the solid soil S (generally composed of sediments) and the overlying water body E is called the "waterbed." Pipeline 1 then rests either on the waterbed (and is therefore surrounded by water), or it is partially buried (its upper part is in contact with the water and its lower part is surrounded by the soil material S), or it is completely buried (it is then below the waterbed and no longer in contact with the water).

[0061] The term "monitoring" of the inside of pipeline 1 broadly refers to any acquisition of descriptive information about the inside of pipeline 1, in particular any characteristic indicating the presence or absence of a blockage 3. More precisely, the result of said monitoring may be a characterization of the inside of pipeline 1 (values ​​of various physical quantities), an image of the inside of pipeline 1, or even direct information on the presence or absence of a blockage 3 in pipeline 1 (a Boolean value, a classification of the potential blockage 3, etc.). In other words, the present method may be a method for characterizing the inside of pipeline 1, a method for imaging the inside of pipeline 1, and / or a method for detecting a blockage 3 in pipeline 1.

[0062] In the latter case, which will be described in more detail later in this document, we are referring to an attempt to detect at least one blockage. More precisely, this procedure can be implemented in response to the detection of a problem (flow drop), but also preventively, or upon restarting pipeline operation. This means that it is possible that the conclusion after implementing the procedure will be that there is no blockage. Furthermore, as will be seen later, this procedure can be implemented on a specific section of pipeline 1, or over a longer length, or even along the entire length of pipeline 1. Since the position of pipeline 1 is generally georeferenced, pipeline 1 can be traversed quite accurately along its entire length.

[0063] We will now explain how the present method is implemented for a position along pipeline 1. It will suffice to repeat it for a large number of positions if extensive monitoring is desired. Figure 2 describes an example of implementing the method according to the invention.

[0064] Obtaining acoustic data The process uses, as explained, so-called acoustic or improperly "seismic" data.

[0065] With reference to Figure 2, in a step (a), in a manner known in marine seismics, the data processing means 11 obtain for a position along said pipeline 1 descriptive acoustic data of a cross-section of said pipeline 1 at said position, acquired from an acoustic acquisition device 20 mobile in said water mass E.

[0066] By "mobile acoustic acquisition device in the water mass", we mean an acoustic acquisition device capable of moving from one position along the pipeline to another.

[0067] The mobile acoustic acquisition device 20 is, as explained, typically a "sediment echo sounder" such as a boat or an ROV. It comprises at least one source 21 (for example, in conventional marine seismics, a water gun, i.e., a chamber for the explosion of a gas mixture) and at least one sensor 22 (also called a "receiver," typically a transducer), meaning that it emits and records reflected acoustic waves. Preferably, the acquisition device 20 comprises a plurality of sources 21 and / or a plurality of sensors 22 (this is then referred to as a sensor array) arranged in a direction substantially orthogonal to a longitudinal direction of said pipeline 1. It will be understood that this direction is obtained by properly positioning the complete device 20 in the water E.

[0068] Most often, there is a single source 21 located in the middle of a sensor array 22 extending on either side (this example will be used in the rest of the description). This array can have a span of several meters, or even tens of meters if, for example, several ROVs are placed side by side. Alternatively, there can be multiple sources 21 for a single sensor 22, or even multiple sources 21 and sensors 22, possibly arranged in a complex (non-aligned) manner, which will require 3D reconstruction, see below. For example, sources 21 can be placed every meter to provide information redundancy and improve the signal-to-noise ratio. In all cases, the acquisition device 20 "flys over" (that is, it moves above the pipeline, within the water mass) the pipeline's trajectory a few meters above it (specifically between 0.5m and 10m).

[0069] In this case, it is understood that the acquisition device 20 emits and records acoustic waves in a frequency range compatible with the diameter of the pipeline 1 under study, specifically in the range between 600 Hz and 20 kHz. For example, for a diameter of 30 cm for pipeline 1, a frequency band between 3 kHz and 15 kHz is required. A person skilled in the art will be able to select the appropriate frequencies. It is quite clear that such frequency ranges are very different from those used in conventional marine seismic surveys (generally below 200 Hz), which often aim to image objects located several kilometers below the seabed.

[0070] Acoustic waves generated by a source 21 are converted into elastic waves on the seabed. The resulting disturbance propagates through the ground S as progressive waves. When these waves reach a discontinuity surface separating two media with different elastic properties or densities, some of the energy rises to the surface through complex phenomena of reflection, refraction, or wave conversion. The rising wave field is recorded by sensors 22 as a function of time since emission from source 21. Each pair (source 21, sensor 22) corresponds to a temporal recording, called a "seismic trace." The set of recordings thus obtained is called a seismogram. The shape of a reflection recorded on the seismogram (more commonly called an event) is closely linked to the geological discontinuity surface that generated it, as well as to the type of wave that was recorded.

[0071] The seismogram (actual data) therefore contains the direct arrival of the source 21 at the sensor 22 (without reflection), the reflection of the acoustic waves off the waterbed, and the wave field diffracted by the pipeline 1, or "acoustic field," and possibly by other heterogeneities in the medium. A seismogram is generated for each position of the acquisition device 20 as it moves along the path of the pipeline 1 if extended detection is desired.

[0072] The information relevant for monitoring the inside of the pipeline, and more specifically for detecting blockages (3), concerns the reflections / diffractions of pipeline 1 recorded in the seismogram, i.e., the acoustic field. Using the acquisition device 20, the velocity model, and the bottom profile, the first reflection on the waterbed can be modeled. When pipeline 1 is buried, the useful information will therefore arrive just after this reflection and can thus be isolated for imaging. This process can be more precise if the pipeline's position and diameter are known accurately, as this allows for direct modeling of the diffractions at the top and bottom of the pipe, and the useful diffractions related to a potential blockage (3) will therefore be located in between.This process can also benefit from seismic processing techniques already known and commonly used in classical marine seismics, such as deconvolution by the source signal.

[0073] Note that in certain seabed configurations (mudflows, collapses), pipeline 1 can move laterally / vertically, and after automatic identification of diffraction hyperbolas on the pipe, these displacements can then be estimated to recalculate the position of the pipeline.

[0074] Quantitative migration

[0075] In oil exploration, the main objective of imaging is to translate a volume over time (the seismogram) into a volume at depth, equivalent to a vertical geological cross-section. This transformation is called migration. This problem is all the more difficult when dealing with complex geological environments. In the acoustic case, migration can be formulated as a pseudo-inverse operator of the modeling operator.

[0076] It was established by Beylkin, who, in the acoustic case, developed an amplitude-preserving migration theory (Beylkin, 1984) that reconstructs the perturbations of the physical parameter (compressibility). The geophysical application of this theory is highlighted in (Miller et al., 1987). Beylkin's theoretical work was subsequently generalized to the elastic case. Through this fundamental contribution, the authors exploit data redundancy to decouple the three physical parameters of the elastic problem (impedance P, impedance S, and density). These theoretical formulations are therefore well-suited to acquisition systems known as "multi-coverage surface seismic" systems, as they consist of numerous sources and sensors distributed regularly over a large area, providing seismic recordings with redundant information.The same seismic reflector in the subsoil will be seen by seismic waves that propagate in different ways; in other words, the rays that are perpendicular to the wave fronts arrive at the seismic reflector with different angles of incidence.

[0077] Thus, the present process includes a step (b) of quantitative migration estimation from said acoustic data of an estimated profile of relative impedance perturbations according to said cross-section of said pipeline 1. Said profile generally takes the form of a 2D image of the cross-section (i.e., step (b) involves estimating for each point of the cross-section - or rather of a predefined domain around pipeline 1 - a value of relative impedance perturbation; one can also speak of 2D reconstruction).

[0078] Quantitative migration, known as GRT for "Generalized Radon Transform", refers to a migration based precisely on the inverse generalized Radon transform.

[0079] For an event recorded at time t for a pair (source 21, sensor 22), the principle consists of distributing the amplitude of this event along an isochrone characterized by: t = ts + tr, where ts represents the travel time taken by the wave to go from the source to a point to be imaged x0, and tr the time taken by the wave to go from the same point to the sensor. The isochrones are constructed in the depth domain, and the migrated image, obtained by summing all the isochrones, will be a depth image (i.e., according to the aforementioned cross-section). The reconstructed reflectors are then constituted by the envelope of the isochrones. Locally, the isochrone curve can be approximated by a straight line segment.When the entire system 20 is taken into account, we have an analogy between the reconstruction of the subsurface by the weighted summation of isochrone curves (quantitative migration) and the inverse Radon transform at a point in the subsurface (x0). This summation principle is valid regardless of the position of the sources 21 and the sensors 22. It is therefore generalizable to any architecture of acquisition devices 20. Quantitative migration GRT relies on the use of so-called Green's functions (response of the medium to a point emission, i.e., to a Dirac distribution). It is then possible to calculate them in isotropic heterogeneous models, at reasonable costs even in 3D. By Green's functions intended for quantitative migration, we mean a set of quantities determined for each point x0 of the subsurface and each source / each sensor, including:

[0080] - the travel time of an acoustic wave going from point x0 to the source / sensor;

[0081] - a geometric divergence value which corresponds to an amplitude correction that is a function of the distance traveled by the acoustic wave between the source / sensor and the point to be imaged x0;

[0082] - the polarization angle of the acoustic wave having traveled the path from the source / sensor to the point to be imaged x0.

[0083] Green's functions are generally presented as travel time maps (or cubes), spherical divergence maps (or cubes), and polarization angle maps (or cubes). Green's functions can be calculated by plotting 2D or 3D ray tracing (see, for example, [Lambaré et al., 1992]) as a function of the propagation medium, and advantageously analytically when the medium is tabular (see, for example, [Gerea et al., 2000]). These quantities are used as weights in quantitative migration. The reconstruction and quantification of the medium's physical parameters are obtained by summing weighted diffraction curves. The weighting was defined using the inverse generalized Radon transform, which depends on the imaged point.One of the key aspects of quantitative migration is the calculation of the Jacobian, also known as the Beylkin Jacobian, which involves transforming summations over the source (or sensor, depending on the device type) positions into summations over the reconstructed dips of the medium. Quantitative GRT migration therefore aims to determine not only the position of the reflectors but also their amplitude. In this respect, it is more precise than a conventional non-quantitative migration. In particular, it allows us to compare the relative impedance perturbations obtained by quantitative migration with relative perturbations of reference impedances, in order to more reliably deduce the presence or absence of a blockage, its geometry, or even its nature.

[0084] In the present case, if we consider an acquisition device to follow pipelines 1 buried in deep water, which can for example be carried on an ROV, it is possible to encounter the problem of a potentially limited coverage of the acquisition device 20 and the lack of redundancy of the information of the acoustic data, especially if it only makes one pass over the pipeline 1. In Nicolétis et al (1997), the authors developed a single-parameter representation of the subsurface: zero perturbation in density and Poisson's ratio, or relative perturbations of impedance P equal to those of the S waves and relative perturbations in density of zero.

[0085] As will be demonstrated later, the expression of the 2D imaging formula for estimating relative impedance perturbations (in the case of a collection, i.e., a set of sources 21 and sensors 22 arranged coplanarly) at a point x0 of the cross-section according to a preferred embodiment of the invention can be:

[0086] The vector p is also called the diffraction wavenumber, the angle Ψ S translates the angular coverage of the seismic acquisition device 20, the transform of Fourier transformation of the disturbances in the medium. The expression l(x0) obtained is close to the 2D inverse Fourier transform in polar coordinates.

[0087] Similarly, the expression of the imaging formula, this time in 3D (case of sources 21 and sensors 22 arranged in any way), at point x0 according to a preferred embodiment of the invention can be:

[0088] The two Euler angles Ψ S and Φ S The angular coverage of the seismic acquisition device 20 is represented (this time in two coordinates due to its non-coplanar nature). The resulting expression l(x0) is close to the 3D inverse Fourier transform in spherical coordinates. In practice, a quantized image of the subsurface is obtained for each collection with a common source 21 / sensor 22. The quantized image of the subsurface for the complete device 20 is obtained by simply summing the images obtained for the different collections.

[0089] Green's Functions

[0090] As explained, once the wave field diffracted by pipeline 1 (i.e., the acoustic field) is isolated / identified, quantitative imaging can be applied. This relies on calculating Green's functions at each position (source, sensor). In other words, step (b) specifically includes calculating, at the positions of each source 21 and each sensor 22, so-called Green's functions representative of the medium's response to a point acoustic emission, and then estimating, at every point of the cross-section of pipeline 1, a relative impedance perturbation value as a function of the received acoustic field and parameters of the calculated Green's functions.

[0091] Knowing the velocity model, Green's functions can be very advantageously pre-calculated for certain positions of sources and sensors, and possibly re-interpolated in order to save computation time, especially in the case of 3D imaging.

[0092] In this respect, the calculation at the positions of each source 21 and each sensor 22 of the Green functions may include the interpolation according to the real positions of the sources 21 and the sensors 22 of pre-calculated Green functions for a set of fictitious positions.

[0093] The idea is to define a fictitious acquisition system whose sources and sensors are distributed in a known, and in particular regularly distributed, way, so that the real positions can be easily expressed relative to these fictitious positions. For example, these fictitious positions can be chosen at the vertices of a regular geometric structure, such as a square grid. Note that we are not limited to a regular arrangement and that we can take any fictitious positions (for example, by statistically distributing them relative to a set of 20 known systems); it is sufficient that these fictitious positions are numerous enough and sufficiently distributed so that we can express the real positions as a function of the fictitious positions.

[0094] Each actual source 21 / sensor 22 position can therefore be associated with a group of fictitious source 21 / sensor 22 positions (typically the group of neighboring vertices). Pre-calculating the Green's functions involves calculating them at each fictitious source and sensor position, ideally well upstream in the process and, in particular, before calculating the quantitative migration in step (b). This saves computation time and can be crucial for achieving real-time processing.

[0095] Interpolation involves defining an interpolation coefficient that will be associated with each fictitious position within a group. For example, if there are four fictitious positions at the vertices of a square, this weight will be ¼ for each. More precisely, since a Green's function is characterized by parameter maps / cubes (travel time, geometric divergence, polarization angles), interpolating Green's functions consists of interpolating these maps / cubes. Because the velocity model is sufficiently smooth, linear interpolation can be considered.

[0096] Note that if we do not want to do interpolation (for example in 2D), it is enough to associate a real position with a fictitious position and an interpolation coefficient equal to 1.

[0097] Performing the quantitative migration calculation

[0098] The velocity model of acoustic waves in the water mass E (salty or not) and in the first few meters of the soil S (often having the characteristics of mud and / or poorly consolidated sediments) at the level of the area of ​​interest encompassing the pipeline 1 to be monitored is assumed to be known.

[0099] Quantitative migration is similar to the weighted summation of isochrone curves associated with each amplitude of a seismic trace and therefore with a pair (source 21, sensor 22). For example, if the velocity model is homogeneous, an isochrone curve is a portion of an ellipse whose foci correspond to the position of source 21 and sensor 22.

[0100] The general formulation of the imaging problem proposed by Beylkin is given by the following relation:

[0101] As explained before, x0 is a point in the domain (that is, a point in the middle) that we want to image, and the quantity l(x0) represents the result of the quantized image of the subsurface at point x. 0, in this case the relative impedance perturbation value at this point, the whole constituting said profile.

[0102] The summation over the frequencies is limited by the upper bound of the frequency spectrum of the observed data (ω max ).

[0103] The spatial summation over the parametric variables σ(s) and / or σ(r) depends on the seismic acquisition devices and the dimension of the seismic acquisition (line, curve, surface).

[0104] (B b )* is the adjoint of the rai-Born modeling operator (direct modeling problem) δU b obs = U b obs - U refis the linearized diffracted field recorded at sensor r along the direction b. To the first order, it represents the observed upwelling waves.

[0105] Q is a weighting to be defined, a function of the point x0 considered, so that the reconstructed quantified image is as close as possible to the disturbances of the medium (which is what is sought here).

[0106] In the following, we describe a way of determining the imaging formula of a preferred mode of implementation of the invention already described above.

[0107] In general, the weighting used to quantitatively reconstruct the physical parameters of the subsurface is defined using the Beylkin Jacobian [Beylkin, 1984], which transforms a discrete summation over source positions 21 (and / or sensors 22, depending on the acquisition devices 10) into an integration over the reconstructed dips of the medium. This Jacobian is expressed as a function of Green's function parameters that can be calculated by plotting 2D or 3D rays.

[0108] The weighting calculation relies on several assumptions: local approximation, spatial dimension (2D, 3D), spatial sampling of the sources 21 and sensors 22, and whether or not the waves are converted. In practice, the acquisition devices 20 have limited coverage; the quantized image of the subsurface then resembles a filter of the subsurface's elastic parameters.

[0109] Furthermore, it is not always possible to decouple the three parameters characterizing an isotropic elastic medium (impedance P, denoted Ip; impedance S, denoted Is; and density, denoted p). This is particularly true for devices used to detect blockages in pipelines. In other words, the angular coverage of a single point is limited, and only one parameter can be estimated. It is worth recalling that a distinction is made between "P-waves," i.e., pressure waves or primary waves, and "S-waves," i.e., shear waves or secondary waves.

[0110] In the following, we initially neglect density, as its influence is negligible up to a 40° angle of incidence in the chosen parameterization (impedance and density). We can then make the so-called single-parameter assumption for P-waves. This is based on the correlation of the P and S reflectivities of the subsurface. This assumption therefore translates, for P-waves, into a relative perturbation at zero density and relative perturbations with equal P and S impedances (δI). P / I P = δI S / L S , δρ / ρ = 0). For PS waves acquired with Ocean Bottom Cable (OBC) or Ocean Bottom Sea (OBS), it will simply be translated as ( δρ / ρ = 0).

[0111] In the formulation of the imaging problem above, we can replace the ray-Born operator (B b )*(s,x0,r, ) and the linearized diffracted field δU b obs (s,r,ω ) by the integral modeling operator rai-Born which is expressed in the form:

[0112] With f k the k element of the perturbation column vector in ( δI P / I P , δI S / I S , δρ / ρ).

[0113] The single-parameter hypothesis gives a generic expression for B bk of the shape

[0114] With 3D: director s p is the source directivity s, pol r p the polarization P at the sensor r, and (pol r S1 )

[0115] W k S1 + (pol r S2 ) W k S1 the S polarization at the r sensor.

[0116] So we have And so that the formulation of the imaging problem becomes:

[0117] The high-frequency asymptotic hypothesis allows us to make a local approximation at the point to be imaged x0 [Lambaré et al., 1992], we can therefore perform a first-order Taylor expansion of the total travel time T(s,x0,r) around the considered point x0, that is to say that and to zero order

[0118] Substituting these two expressions into the imaging formula yields:

[0119] In the integral term, we can perform the change of variable

[0120] This vector is also called the diffraction wavenumber. We then recover the Fourier transform. disturbances in the environment, so the imaging formula can simply be expressed as:

[0121] Therefore, the weighting Q must be constructed so that the operator R is as close as possible to the inverse Fourier transform. Note that when switching to polar (2D) or spherical (3D) coordinates, the operator R then resembles an inverse generalized Radon transform. The key point is to move from finite discrete summations to continuous integrals to reveal the inverse generalized Radon transform.

[0122] For continuous frequency integration, we can assume that frequency sampling is regular in the interval [-ω max ;+ ω max with a constant step size Δω. The transition from a discrete finite sum to a continuous integral presents no problem. Furthermore, integration over negative frequencies disappears when the coefficient 2 is introduced, resulting in:

[0123] [math

[0124] At this stage, no assumptions have been made regarding the type of seismic acquisition. To construct the Q weighting, it is necessary to move from spatial sampling (in sources or sensors) to angular variations of the dip normal vector, or more simply, to an investigation of the dips of the medium for each point in the area of ​​interest. Continuous integration of the variables associated with the acquisition device allows the Q weighting to be constructed to recover the expression of the inverse generalized Radon transform. This demonstrates the importance of the angular coverage of the acquisition device 20 for reconstructing the geological environment [Miller et al., 1987]. Figure 3 illustrates the 2D (top) and 3D (bottom) angles of the acoustic wave rays at the image point x0 in the case of a device composed of a source 21 and a sensor 22.This figure also illustrates how a triangulation based on source positions can provide a solution for calculating an elementary surface Es, which will be used in the weighting construction. According to one embodiment of the invention, this elementary surface can be based on a triangulation constructed from the actual positions of the sources 21. The same principle would apply to a surface device with sensor positions 22. This depends on the type of recording collection (organized according to a common source 21 or according to a common sensor 22). Hereafter, a common-source collection is defined as a set of recordings made for different pairs (source 21, sensor 22), with the source 21 being identical for all these pairs 22. A common-sensor collection is defined as a set of recordings made for different pairs (source 21, sensor 22), with the sensor being identical for all these pairs 22.

[0125] If the integration variable relates to the sources 21 (recordings organized according to a common sensor 22), continuous integration is prepared by assigning an integration increment Δs and using an elementary surface E s and the above expression becomes:

[0126] Note that if the integration variable relates to sensors 22 (recordings organized according to a common source), we replace E in the expression above s by E r , Δs by Δr and ds by dr.

[0127] In 2D, a single angle is used to describe a vector with respect to the vertical axis. The Q weighting is constructed so that the R operator is as close as possible to the 2D inverse Fourier transform or an inverse Radon transform in Euclidean R space 2 To do this, a change of variable in polar coordinates (s,lwl) → (IpI,Ψ s ) is enough, hence where J represents Jacobians associated with changes of variables [Nicolétis et al., 1997]. A 2D imaging formula (for coplanar sources and sensors) is thus determined according to a preferred embodiment of the invention. Note that for a common source collection (instead of a common sensor), it suffices to replace s with r, ts with tr, Δs with Δr, and Ψ S by Ψ r .

[0128] In 3D, two (Euler) angles are used to describe a vector with respect to the vertical axis. This time, the weighting Q is constructed so that the operator R is as close as possible to the 3D inverse Fourier transform or an inverse Radon transform in Euclidean R space 3 For this, the change of variable in spherical coordinates becomes (s,lwl) → (IpI,Ψ S ,Φ S ), hence

[0129] A 3D imaging formula is thus determined (case of non-coplanar sources 21 and sensors 22) according to a preferred embodiment of the invention. Again, it is noted that for a collection with a common source 21 (instead of a common sensor 22), it suffices to replace s with r, ts with tr, Δs with Δr, Ψ S by Ψ r and Φ S by Φ r .

[0130] Relative impedance perturbation models

[0131] At the end of step (b), we have the estimated profile of relative impedance disturbances, constituting a result of the monitoring of pipeline 1, which can, if necessary, be returned in raw form on interface 13.

[0132] Advantageously, the method includes a post-processing step (c) of this profile to extract synthetic information, such as certain characteristic parameters of the pipeline interior (thresholding, averaging, etc.) or a visual representation. For example, as will be seen later, an image of the cross-section of pipeline 1 can be generated in which each point is colored according to the value of the impedance disturbance at that point.

[0133] Alternatively or in addition, in step (c) said estimated profile of relative impedance disturbances (i.e. the result of the quantitative migration) is preferentially compared with at least one reference model of relative impedance disturbances representative of the presence of a plug 3 in pipeline 1 at said position, or even with a plurality of reference models of relative impedance disturbances representative of a set of possible configurations of plug 3 in pipeline 1 at said position (in particular three configurations and therefore three models), so as to detect a possible plug 3 at said position.

[0134] Indeed, even when displayed as an image, the estimated profile of relative impedance disturbances is difficult to interpret on its own.

[0135] On the other hand, it is possible to construct realistic synthetic models for the plug configuration(s). In particular, with reference to Figure 4a (which illustrates an example of gas hydrate plugs in a 30 cm diameter pipeline), there are three possible plug configurations 3 in pipeline 1, including at least one total plug configuration (left, there is no longer a light 2), a partial plug configuration at the bottom (middle, the light 2 is only at the top), and a partial plug configuration in a ring (right, the light is in the center). In Figure 4a, the following impedance values ​​were taken in the model: low value of 50 (g / cm3)x(m / s) (white color) for the impedance of the gas flowing in the lumen 2, intermediate value of 2700 (g / cm3)x(m / s) Pa.s / m (grey color) for the independence of the plug 3, and high value of 46400 (g / cm3)x(m / s) Pa.s / m (black color) for the independence of the wall of the pipeline 1.

[0136] From these models, relative impedance perturbations can be calculated by sequentially considering the vertical columns of the model, thus obtaining the so-called reference models of relative impedance perturbations. Figure 4b represents the relative impedance perturbation models corresponding to the synthetic models of Figure 4a, on a scale from -1 to +1.

[0137] The ideal reflected acoustic field is calculated by considering the contribution of each diffracting point in the model, which consists of relative impedance perturbations. This eliminates the need for any preprocessing required for field-acquired data.

[0138] Thus, quantitative migration results corresponding to the three aforementioned plug configurations are represented in Figure 4c. It is noted that when plug 3 is partial, the discontinuity between plug 3 and light 2 is quite well recovered (a flat segment in the middle, and a circular shape on the right).

[0139] To facilitate the detection of a total blockage, in step (c) said estimated profile of relative impedance disturbances is further advantageously compared with a reference model of relative impedance disturbances representative of an absence of blockage 3 in pipeline 1 at said position.

[0140] Indeed, if, with reference to Figures 5a and 5b, we construct two synthetic models with a pipeline containing a total hydrate plug (Figure 5a, top left) and only gas, i.e., an absence of the plug (Figure 5a, top right), and if we compare their corresponding reference models of relative impedance perturbations (Figure 5a, bottom), the contrast at the top of pipeline 1 is similar but still stronger (by approximately 11%) in the case of an absence of the plug. This trend is also observed when comparing the results of the quantitative migration (Figure 5b), where we observe a difference of approximately 12% (with an uncertainty of 1%).

[0141] It should be noted that the comparison can be made in many different ways. For example, for a given profile of relative impedance disturbances, one can choose from the different reference models (presence of a total blockage, presence of a partial blockage at the bottom, presence of a partial blockage in the ring, absence of a blockage), the one closest by a distance function.

[0142] Locating and removing the blockage

[0143] At the end of step (c), depending on the result of the comparison, we can conclude whether there is a plug 3 in pipeline 1, and if so, have descriptive information about said plug 3 (shape, whether it is total or not, size, etc.).

[0144] Advantageously, the process includes the repetition of steps (a) and (b), or even (c), for a plurality of positions along the pipeline 1, thanks to the mobile nature of the acoustic acquisition device 20. In particular, it is possible to compare step (c) profile by profile, or group of profiles by group of profiles.

[0145] In a particularly preferred manner, in step (c) (especially if it is common to a group of profiles) a comparison of the profiles estimated for two successive positions is also carried out, which makes it possible to highlight, in the event of a significant difference in relative impedance disturbances, a beginning and / or an end of plug 3, which strengthens the certainty of detection and makes it possible to define a location of plug 3.

[0146] In all cases, if a blockage 3 has been detected, action can be taken. The process therefore preferably includes, if a blockage 3 has been detected in pipeline 1, a step (d) of destroying the detected blockage 3, in particular by heating or any other technique known to those skilled in the art.

[0147] Computer equipment and software

[0148] According to a second aspect, equipment 10 is proposed for the implementation of this method of monitoring the inside of a pipeline 1 according to any of the variants or combinations of variants described above.

[0149] This equipment 10 includes, as explained, data processing means 11, and advantageously data storage means 12, and an interface 13.

[0150] The data processing means 11 are configured to implement:

[0151] - For a position along said pipeline 1, obtain descriptive acoustic data of a cross-section of said pipeline 1 at said position, acquired by an acoustic acquisition device 20 mobile in said water mass E;

[0152] - Estimate by quantitative migration from said acoustic data an estimated profile of relative impedance disturbances according to said cross-section of said pipeline 1;

[0153] - Advantageously compare said estimated profile of relative impedance disturbances with at least one reference model of relative impedance disturbances representative of the presence of a plug 3 in pipeline 1 at said position.

[0154] Preferably, the invention also relates to the entire equipment 10 and the acoustic acquisition device 20. For example, the equipment 10 can be located on a boat equipped with the acoustic acquisition device 20, for real-time operation.

[0155] According to a third aspect, the invention also relates to a computer program product downloadable from a communication network and / or recorded on a computer-readable medium and / or executable by a processor, comprising program code instructions for implementing the method according to the first aspect, when said program is executed on a computer.

Claims

DEMANDS 1. A method for monitoring the interior of a pipeline (1) disposed in contact with soil (S) under a body of water (E), the method comprising the implementation, by means of data processing equipment (11), of the following steps: (a) For at least one position along said pipeline (1), obtaining descriptive acoustic data of at least one cross-section of said pipeline (1) at said position, acquired by means of an acoustic acquisition device (20) movable in said water mass (E); (b) Estimation by quantitative migration from said acoustic data of an estimated profile of relative impedance disturbances along at least said cross-section of said pipeline (1).

2. Method according to claim 1, wherein said acoustic acquisition device (20) comprises at least one acoustic wave source (21) and at least one acoustic wave sensor (22), said descriptive acoustic data of a cross-section of said pipeline (1) at said position being a reflected acoustic field received by at least one sensor (22) following the generation of an acoustic field by at least one source (21).

3. Method according to claim 2, wherein said acoustic acquisition device (20) comprises a plurality of sensors (22) and / or sources (21) arranged in a direction substantially orthogonal to a longitudinal direction of said pipeline (1) at said position.

4. A method according to claim 2 or 3, wherein step (b) comprises calculating, at the positions of each source (21) and each sensor (22), so-called Green's functions representative of a response to a point acoustic emission at any point in said cross-section, and then estimating, at any point in said cross-section of said pipeline (1), a relative disturbance value impedance as a function of said received acoustic field and of parameters of said calculated Green's functions.

5. Method according to claim 4, wherein the calculation at the positions of each source (21) and each sensor (22) of said Green's functions comprises the interpolation as a function of the actual positions of said sources (21) and said sensors (22) of Green's functions pre-calculated for a set of fictitious positions.

6. A method according to any one of claims 2 to 5, wherein said quantitative migration estimation is obtained at a point x0 of the cross-section of the pipeline (1), for a collection of source(s) (21) and sensor(s) (22) if they are coplanar, by means of the formula and otherwise, using the formula with Ψ s and Φ s translating the angular coverage of the seismic acquisition device (20), p the diffraction wavenumber, and the Fourier transform of the disturbances of the medium.

7. A method according to any one of claims 1 to 6, further comprising a step (c) of comparing said estimated relative impedance disturbance profile with at least one reference model of relative impedance disturbances representative of the presence of a plug (3) in the pipeline (1) at said position.

8. Method according to claim 7, wherein in step (c) said estimated profile of relative impedance disturbances is compared with a plurality of reference models of relative impedance disturbances representative of a set of possible plug configurations (3) in the pipeline (1) at said position.

9. A method according to claim 8, wherein said set of possible plug configurations (3) in the pipeline (1) at said position comprises at least one total plug configuration, one partial plug configuration at the bottom, and one partial plug configuration in the crown.

10. A method according to any one of claims 7 to 9, wherein in step (c) said estimated relative impedance disturbance profile is further compared with a reference relative impedance disturbance model representative of an absence of a plug (3) in the pipeline (1) at said position.

11. A method according to any one of claims 7 to 10, further comprising a step (d) of destroying the detected plug (3).

12. A method according to any one of claims 1 to 11, wherein said pipeline (1) is a hydrocarbon pipeline, said plug (3) being a hydrate plug.

13. Equipment (10) for monitoring the interior of a pipeline (1) disposed in contact with soil (S) under a body of water (E), the equipment comprising data processing means (11) configured to: - For at least one position along said pipeline (1), obtain descriptive acoustic data of at least one cross-section of said pipeline (1) at said position, acquired by an acoustic acquisition device (20) mobile in said water mass (E); - Estimate by quantitative migration from said acoustic data an estimated profile of relative impedance disturbances along at least said cross-section of said pipeline (1).

14. Product computer program downloadable from a communication network and / or recorded on a computer-readable medium and / or executable by a processor, comprising program code instructions for implementing the method according to any one of claims 1 to 12, when said program is executed on a computer.