WO2014189943A1

WO2014189943A1 - Method and system for tracking movement trajectory of a pipeline tool

Info

Publication number: WO2014189943A1
Application number: PCT/US2014/038807
Authority: WO
Inventors: Sergey MAYOROV
Original assignee: Weatherford/Lamb, Inc.
Priority date: 2013-05-22
Filing date: 2014-05-20
Publication date: 2014-11-27
Also published as: RU2013123586A

Abstract

The invention relates to systems for inspection of mainline and flowline oil pipelines, gas pipelines and oil product pipelines and may be used for tracking in-line diagnostic tools passing inside the inspected pipelines and for determining of locations of pipeline features. The technical result consists in an improved accuracy of determining the time when the pipeline tool passes near the reference points and thus accuracy of determining the location of pipeline features. This result is achieved by passing the tool inside the pipeline, measuring physical quantities characterizing the status and/or characteristics of the tool and/or of the pipeline by a measurement system, and recording them in a tool data storage such that they are associated with time determined by a tool clock. A logger installed near a reference point in the pipeline is used to measure physical quantities that allow to identify the passing of the tool near the logger, characteristics that identify the respective time instants of the passing of the tool according to the logger clock are generated and recorded onto the logger data storage. A transmitter arranged in one of the tool and the logger is used to transmit a signal having a temporal characteristic associated with the clock time on the transmitter side; the transmitted signal is received by a receiver arranged in the other one of the logger and the tool, and a characteristic related to the temporal characteristic of the received signal is recorded onto the data storage on the receiver side such that it is associated to the clock time on the receiver side. A difference between the clock times on the transmitter side on the receiver side is determined, and hence a value of time difference according to the logger clock and the tool clock, and is used in the reference point to determine the characteristics of the pipeline.

Description

METHOD AND SYSTEM FOR TRACKING MOVEMENT

TRAJECTORY OF A PIPELINE TOOL

BACKGROUND OF THE DISCLOSURE

[0001] The invention relates to pipeline monitoring systems, in particular to systems for in-line inspection of mainline and flowline oil pipelines, gas pipelines and oil product pipelines. The invention may be used for tracking in-line inspection tools and diagnostic tools passing inside the inspected pipelines, and for subsequent determining of locations of the identified pipeline defects and features.

PRIOR ART

[0002] Systems for diagnostic inspection of pipelines are known, which include a pipeline tool and a logger (US Patent No. US6023986, published 25.02.2000, as well as US Patent No. US6243657, published 05.06.2001). A measurement system is arranged in the tool, which comprises non-destructive inspection sensors in the form of magnetic flux leakage (MFL) sensors, inertial navigation system sensors in the form of triaxial gyroscopes and accelerometers, as well as an odometer (a device for measuring the distance traveled by the tool), a clock and means for processing and recording the measured data. In order to track the movement trajectory of the tool inside the pipeline, a low- frequency electromagnetic signal transmitter is arranged in the tool. The logger comprises a low-frequency electromagnetic signal receiver, a GPS receiver, a clock and means for processing and recording the received signals.

[0003] The mode of operation of the known systems is as follows. Before passing the pipeline tool, the logger clock is synchronized with the tool clock. When passing the tool, data measured by the non-destructive inspection sensors and by inertial navigation system sensors, as well as odometer readings is recorded in the data storage arranged in the tool such that it is associated with the tool clock time. In reference points near the pipeline, signals from the electromagnetic signal transmitter are received by means of the logger, signals from the GPS receiver are received, and the time instants when the tool has passed near the logger according to the logger clock, as well as GPS coordinates received from the GPS receiver are recorded in the logger.

[0004] After completing the passing of the tool, data recorded in the tool data storage are matched with the data recorded in the logger data storage, defects and features of the inspected pipeline are identified based on the data of nondestructive inspection sensors and odometer readings, and their location is determined based on the distance. Pipeline laying trajectory is determined according to the data of inertial navigation system sensors. The location of pipeline features and defects relative to the reference points where the loggers were arranged, as well as GPS coordinates of pipeline defects and features and GPS coordinates of the pipeline laying trajectory are determined based on the matched data.

[0005] A drawback of known systems consists in an unevenness of onboard tool clock and logger clock rate. If the pipeline is long and the passing of the tool takes a long time, a difference between the tool clock time and the logger clock time is accumulated and may amount to several seconds. This leads to a several meters' error in determining the location of a pipeline feature or defect.

SUMMARY OF THE INVENTION

[0006] The object of invention consists in providing a method and system for tracking a movement trajectory of a pipeline tool, which allow to improve the accuracy of determining the time when the pipeline tool passes near the ground reference points, which would enable an improved accuracy of determining the location of pipeline features, wherein, depending on the nature of measurements performed by the measurement system, pipeline features may be fitting elements, cross-section constraints, wall defects, as well as pipeline infrastructure curvatures that characterize its laying trajectory.

[0007] The above-mentioned result is achieved in that the claimed method for tracking a movement of a pipeline tool comprises

passing the tool inside the pipeline, measuring physical quantities characterizing the status and/or characteristics of the tool and/or of the pipeline by means of a measurement system of the tool, and recording same in a data storage of the tool such that they are associated with time determined by a tool clock; measuring, from the outer side of the pipeline, by means of at least one logger arranged near a reference point of the pipeline, a magnetic field intensity or other physical quantities, which allow to identify the passing of the tool near the logger, such that they are associated with time determined by logger clock, and generating characteristics, which allow to identify the time instants when the tool passes near the logger according to the logger clock, based on said measured physical quantities and time values corresponding thereto, and recording the generated characteristics onto a logger data storage;

while passing the tool inside the pipeline, transmitting, by means of a transmitter arranged in one of the tool and the logger, a signal having a temporal characteristic associated with a clock time on the transmitter side;

receiving the transmitted signal having the temporal characteristic by means of a receiver arranged in the other one of the tool and the logger, and recording at least one characteristic associated with the temporal characteristic of the received signal onto a data storage on the receiver side, such that it is associated with the clock time on the receiver side,

determining a difference between the clock time on the transmitter side and the clock time on the receiver side and hence a time difference between the logger clock and the tool clock, and using said time difference in the reference point to determine the characteristics of the pipeline.

[0008] Furthermore, an electromagnetic oscillation transmitter may be used as said transmitter, and an electromagnetic oscillation receiver may be used as said receiver, the transmitted signal being encoded by changing the frequency of electromagnetic oscillations depending on the value of the temporal characteristic being transmitted; when receiving said transmitted encoded signal, determining frequency characteristics of the electromagnetic oscillations corresponding to the transmitted encoded signal and recording same onto the data storage on the receiver side together with a clock time on the receiver side. After passing the tool, the data recorded in the tool data storage are matched with the data recorded in the logger data storage, a difference between the clock time on the transmitter side and the clock time on the receiver side being determined based on the frequency characteristics of the transmitted encoded signal of said transmitter stored in the data storage on the receiver side; the characteristics associated with the clock time on the transmitter side being read from the data storage on the transmitter side, and the characteristics associated with the clock time on the receiver side being read from the data storage on the receiver side, and said characteristics being overwritten such that they are associated with the clock time of an identical clock for both the characteristics recorded on the receiver side and the characteristics recorded on the transmitter side.

[0009] Preferably, a frequency of electromagnetic oscillations within a period of measuring said frequency is determined as the frequency characteristic of electromagnetic oscillations. The frequency of electromagnetic oscillations may change discretely or smoothly or periodically, wherein the sequence of set values of frequency of electromagnetic oscillations may be periodically repeated, for instance, with a period being in the least significant digits of a full time value. Further, the sign of frequency change in the discrete sequence of set values of frequencies of electromagnetic oscillations may be reversed at each subsequent change in the frequency of electromagnetic oscillations.

[0010] Preferably, a value in one or more of the least significant digits of the clock time value on the transmitter side is used as the transmitted temporal characteristic, wherein, in the signal with the temporal characteristic being transmitted as a signal with a set frequency, the frequency uniquely corresponds to the value in one or more least significant digits.

[0011] Frequency characteristics of the received electromagnetic oscillations may be determined by measuring the phase of the electromagnetic oscillations being received and determining the frequency of the received electromagnetic oscillations based on the measured phase. The frequency characteristics of the received electromagnetic oscillations are analyzed to identify the value of said temporal characteristic, and phase and/or frequency characteristics of the electromagnetic oscillations and/or the temporal characteristic are recorded onto the data storage on the receiver side.

[0012] Preferably, a distance traveled by the tool inside the pipeline is measured by means of a measurement system arranged in the tool and recorded in the tool data storage such that it is associated with the tool clock time, for further determining the distance between the respective pipeline feature and the reference point.

[0013] Preferably, a satellite time signal is received from an artificial earth satellite by means of a satellite signal receiver arranged in the logger and the satellite time values are recorded onto the logger data storage; after passing the tool, the data recorded such that they are associated with the clock time on the receiver side and/or on the transmitter side are matched with the recorded satellite time values, and said characteristics are overwritten such that they are associated with the satellite time.

[0014] Satellite positioning system signals are also received by means of a satellite signal receiver, geodesic coordinates of the logger are determined based on said signals and recorded onto the logger data storage, and, after passing the tool, the characteristics, which allow to identify the time instants when the tool passes near the logger according to the logger clock, are matched with the geodesic coordinates of the logger, and the geodesic coordinates of the tool in the reference points, in which the passing of the tool near the logger is detected, are determined.

[0015] In an embodiment, a distance traveled by the tool inside the pipeline is measured by means of the measurement system of the tool, as well as the characteristics of a pipeline wall, which allow to identify wall defects, and, after passing the tool, the wall defects are identified and their geodesic coordinates are determined.

[0016] The difference between the clock time on the transmitter side and the clock time on the receiver side may be determined in the course of or after passing the tool.

[0017] In an embodiment, accelerations and angular velocities of the tool on several orthogonal axes are measured by means of an inertial navigation system unit included in the measurement system of the tool, and the geographical location of the tool movement trajectory is determined after passing the tool based on the temporal dependencies of the distance traveled inside the pipeline, accelerations and angular velocities, as well as on the values of geodesic coordinates of reference points where the tool has passed near the logger. [0018] In another embodiment, a magnetic field is further generated when passing the tool by means of a magnetic field source arranged in the tool, a value of the magnetic field is measured by means of the logger and the passing of the tool near the logger is identified based on the temporal dependency of the value of the magnetic field.

[0019] In still another embodiment, acoustic oscillations related to the passing of the tool inside the pipeline are received by means of the logger, and the characteristics of acoustic oscillations are measured, on the basis of which the passing of the tool near the logger is identified.

[0020] In one embodiment, the transmitter is arranged in the logger and the receiver is arranged in the tool.

[0021] In another embodiment, the transmitter is arranged in the tool and the receiver is arranged in the logger.

[0022] The clock on the receiver side may be synchronized with the clock on the transmitter side before passing the tool or in the course of passing the tool.

[0023] The above-mentioned technical result is also achieved in the inventive system for tracking a movement trajectory of a pipeline tool, comprising:

a pipeline tool configured to move inside a pipeline;

a measurement system of the tool for measuring physical quantities characterizing the status and/or characteristics of the tool and/or the pipeline; a tool data storage for recording the measured data such that they are associated with time determined by the tool clock;

at least one logger arranged near a reference point on the outer side of the pipeline for measuring a magnetic field intensity or other physical quantities, which allow to identify the passing of the tool near the logger, such that they are associated with time determined by a logger clock, and for generating characteristics, which allow to identify the time instants when the tool passes near the logger according to the logger clock, based on said measured physical quantities and time values corresponding thereto, and comprising a logger data storage for recording the generated characteristics such that they are associated with time determined by the logger clock; a transmitter arranged in one of the logger and the tool for transmitting a signal with a temporal characteristic associated with a clock time on the transmitter side;

a receiver arranged in the other one of the logger and the tool, for receiving the transmitted signal with the temporal characteristic, and comprising a data storage for recording at least one characteristic associated with the temporal characteristic of the received signal, such that it is associated with a clock time on the receiver side,

a processing device for determining a difference between the clock time on the transmitter side and the clock time on the receiver side and hence a time difference between the logger clock and the tool clock, and determining the characteristics of the pipeline using said time difference in the reference point.

[0024] In an embodiment, the transmitter is an electromagnetic oscillation transmitter having a means for encoding the transmitted signal by changing the frequency of electromagnetic oscillations depending on the value of the temporal characteristic being transmitted; the receiver is an electromagnetic oscillation receiver having a means for processing the transmitted encoded signal and determining frequency characteristics of the electromagnetic oscillations corresponding to the transmitted encoded signal; and the processing device is configured to determine the difference between the clock time on the transmitter side and the clock time on the receiver side based on the frequency characteristics of the transmitted encoded signal of the transmitter recorded in the data storage on the receiver side, based on the matching of the data recorded in the tool data storage with the data recorded in the logger data storage, and to overwrite said characteristics such that they are associated with the clock time of an identical clock.

[0025] In an embodiment, the receiver is configured to measure the phase of the electromagnetic oscillations being received and to determine the frequency of the received electromagnetic oscillations based on the measured phase, and the processing device is configured to analyze the frequency characteristics of the received electromagnetic oscillations and to identify the value of said temporal characteristic for recording the phase and/or frequency characteristics of the electromagnetic oscillations and/or the temporal characteristic onto the data storage on the receiver side.

[0026] Preferably, the logger of the system further comprises a satellite signal receiver for receiving satellite time signals from an artificial earth satellite and recording the satellite time values onto the logger data storage; wherein the processing device provides for matching the data recorded such that they are associated with the clock time on the receiver side and/or on the transmitter side, with the recorded satellite time values, and for overwriting said characteristics such that they are associated with the satellite time.

[0027] The satellite signal receiver preferably receives satellite positioning system signals for determining geodesic coordinates of the logger and recording them onto the logger data storage, and the processing device is configured to match, after passing the tool, the characteristics, which allow to identify the time instants when the tool passes near the logger according to the logger clock, with the geodesic coordinates of the logger, and to determine the geodesic coordinates of the tool in the reference points, in which the passing of the tool near the logger has been detected.

[0028] The measurement system of the tool preferably comprises a means for measuring the distance traveled by the tool inside the pipeline and for measuring the characteristics of a pipeline wall, which allow to identify wall defects, and the processing device is configured to identify the wall defects and to determine their geodesic coordinates.

[0029] The measurement system of the tool preferably comprises an inertial navigation system unit for measuring accelerations and angular velocities of the tool on several orthogonal axes, wherein the processing device is configured to determine the geographical location of the tool movement trajectory based on the temporal dependencies of the distance traveled inside the pipeline, accelerations and angular velocities, as well as on the values of geodesic coordinates of reference points where the tool has passed near the logger.

[0030] In an embodiment, the tool of the system further comprises a magnetic field source and the logger further comprises a means for measuring a value of the magnetic field for identifying the passing of the tool near the logger based on the temporal dependency of the value of the magnetic field.

[0031] In another embodiment, the logger of the system further comprises a means for receiving acoustic oscillations related to the passing of the tool inside the pipeline, and for measuring the characteristics of acoustic oscillations for identifying the passing of the tool near the logger.

BRIEF DESCRIPTION OF THE DRAWINGS

[0032] The invention is explained below on exemplary embodiments illustrated by the drawings, wherein:

Fig. 1 is a scheme of arrangement of the tool and the logger according to the first embodiment;

Fig. 2 is a diagram showing the temporal dependency of the frequency of electromagnetic oscillations;

Fig. 3 is a structural diagram of pipeline tool equipment in the first embodiment;

Fig. 4 is a structural diagram of the logger in the first embodiment;

Fig. 5 is a scheme of arrangement of the tool and the logger according to the second embodiment;

Fig. 6 is a structural diagram of pipeline tool equipment in the second embodiment;

Fig. 7 is a structural diagram of the logger in the second embodiment.

FIRST EMBODIMENT OF THE INVENTION

[0033] In the first embodiment shown on Fig. l, the system for tracking a movement trajectory of a pipeline tool comprises a transmitter 1, arranged in the pipeline tool 2, as well as a logger with a receiver 6, arranged above the ground outside the pipe 3. Fig. 1 shows a scheme of arrangement of the tool 2 with the transmitter 1 and of the logger with the receiver 6. The transmitter 1 is arranged in the body of the pipeline tool 2, which is passed inside the pipeline 3, the axis of which is shown by reference numeral 4. The logger with the receiver 6 is arranged on the ground surface 5 near the pipeline 3. The transmitter 1 is an electromagnetic signal generator with controllable frequency.

[0034] The structural diagram of the equipment of the tool is shown on Fig. 3.

[0035] The measurement system of the tool 2 comprises a tool clock 3 1, traveled distance sensors 32, sensor units 33 of sensors that are sensitive to defects of wall 3, an inertial navigation sensor unit 34, a control and data processing unit 35, a tool data storage 36. In the shown embodiment, an electromagnetic signal transmitter 37 is also arranged in the tool 2. Traveled distance sensors 32 are designed as odometers, an odometer comprises a wheel pressed onto the inner surface of the pipeline and capable of rolling thereon when the tool moves inside the pipeline, as well as a wheel movement sensor capable of generating pulses, the number of which is proportional to the distance traveled by the tool. The inertial navigation sensor unit 34 includes three mutually orthogonal accelerometers and three mutually orthogonal rotation angle sensors.

[0036] Sensor unit 33 of sensors that are sensitive to pipeline wall defects may include non-destructive inspection sensors, as well as electronic units for initializing or scanning of sensors, analog to digital conversion, transformation and encoding of the measurement data. Non-destructive inspection sensors may be designed as ultrasound sensors capable of generating ultrasound pulses perpendicular to the inner surface of a pipeline wall and to receive respective ultrasound pulses reflected by the inner and the outer surface of the wall to determine the thickness of the pipe wall and hence to identify wall thinning locations. In an alternative embodiment, non-destructive inspection sensors may be designed as ultrasound sensors capable of emitting ultrasound pulses at an acute angle to the pipe wall surface to detect cracks, or as magnetostrictive or electromagnetic-acoustic transducers, as well as magnetic field sensors or other non-destructive inspection sensors.

[0037] Control and data processing unit 35 may be designed as an integrated circuit board comprising a central microprocessor, microcontrollers, data buses, as well as connectors for coupling to sensor units 33, 34, odometer 32, data storage 36 and electromagnetic signal transmitter 37. Tool clock 3 1 may be installed on the same integrated circuit board. The electromagnetic signal transmitter 37 comprises an onboard clock time encoding unit and a low frequency electromagnetic oscillation generator with a frequency of 20-25 Hz connected thereto, comprising an antenna in the form of a ferrite-core coil.

[0038] Fig. 4 shows a structural diagram of the logger equipment in accordance with the first embodiment. In the discussed embodiment the logger comprises concatenated antenna 41 , antenna amplifier 42, filter 43, amplifier 44 with automatic adjustment, synchronous detector 45, as well as clock 46, data processing unit 47, logger data storage 48, satellite signal receiver 49, indication unit 50. Data processing unit 47 comprises an analog-to-digital converter and a microcontroller for processing digital data. Synchronous detector 45 is a signal decoding unit. Indication unit 50 may include light emitting diodes and a loudspeaker or a liquid crystal panel.

[0039] The system operates as follows. Before passing the tool 2, onboard tool clock 3 1 is synchronized with logger clock 46, wherein identical time is set on both clocks 31 and 46. The tool 2 is put into the launching station of the pipeline 3, and the pumping of the product to be transported by the pipeline 3 is activated. Under the pressure of the product being pumped the tool 2 moves inside the pipeline 3. Reference points are selected along the pipeline 3 route at a distance of 2 to 5 kilometers from each other, in which the logger for receiving signals from the tool must be arranged. As a rule, reference points are selected in the locations where the pipeline 3 crosses roads, rivers, communication lines, at bends in the pipeline 3 and in locations where pipeline fittings are installed.

[0040] While the tool 2 moves inside the pipeline 3, the operator moves out to the location of the nearest set reference point, places a logger 6 in close proximity of the reference point of pipeline 3 and switches the logger 6 on for receiving the signals from the tool 2. When the logger 6 begins to receive signals from the electromagnetic signal transmitter 1 of the tool 2, the indication unit 50 of the logger 6 informs the operator respectively. The indication unit 50 signals that the tool 2 has passed the reference point of the pipeline 3 and is moving away from the operator. After that the operator moves over to the next set reference point of the pipeline 3. [0041] While the tool 2 moves inside the pipeline 3, the measurement system arranged in the tool 2 is used to measure the parameters that characterize the movement of the tool 2 inside the pipeline 3, and to measure the characteristics of a wall of the pipeline 3, which allow to identify wall defects. Odometers 32 are used to measure the distance traveled inside the pipeline 3, the inertial navigation sensors 34 (accelerometers and angular velocity sensors) are used to measure the accelerations and angular velocities of the tool 2, non-destructive inspection sensors 33 designed as ultrasound sensors are used to emit sounding ultrasound signals in the direction of the wall of the pipeline 3, and signals corresponding to the ultrasound waves reflected by the inner surface of the pipe of the pipeline 3 being received, are received from said sensors 33. Tool 2 clock signals are received from the clock 3 1 arranged in the tool 2. Signals obtained from the clock 31 , units 32, 33, 34, are processed in the control and data processing unit 35 and recorded in the data storage 36 arranged in the tool 2 such that they are associated with the clock 31 time.

[0042] While the tool 2 moves inside the pipeline 3, an onboard clock time encoding unit 38 is used to encode the signal of the electromagnetic oscillation transmitter 1. The value of the last decimal digit in the onboard clock 3 1 time value is used as a temporal characteristic, which is transmitted by means of the electromagnetic oscillation transmitter 1.

[0043] To encode the signal of the electromagnetic oscillation transmitter 1, the frequency of electromagnetic oscillations changes with a period of 1 second depending on the value of the last digit of the onboard clock time (0 to 9). Fig. 2 shows a possible dependence of the frequency of electromagnetic oscillations emitted by the transmitter 1 on the time t. T is a frequency change period. T is a time discrete (slice) - a time interval, within which the frequency of electromagnetic oscillations does not change. In the preferred embodiment, the period T is one second. Frequencies v may have the following values:

vl = 22.05 Hz;

v2 = 22.40 Hz;

v3 = 22.20 Hz; v4 = 22.35 Hz;

v5 = 22.15 Hz;

v6 = 22.25 Hz;

v7 = 22.10 Hz;

v8 = 22.45 Hz;

v9 = 22.30 Hz;

vO = 22.50 Hz

[0044] The frequency of electromagnetic oscillations in the discussed embodiment changes discretely, in a discrete sequence of set values of frequencies of electromagnetic oscillations, and at each subsequent change in the frequency of electromagnetic oscillations the sign of frequency change is reversed. The electromagnetic signal transmitter 37 is a transmitter with controllable frequency of electromagnetic oscillations. A control signal, to which the frequency of electromagnetic signals transmitted by the transmitter 37 uniquely corresponds, is provided from the output of the onboard clock time encoding unit 38 to the input of the electromagnetic signal transmitter 37. If the value of 2403 (2403 seconds from the moment of synchronizing the clocks before the launch of the tool 2) comes from the output of the tool clock 3 1, the value of the last decimal digit, i.e. 3, is used. Frequency v3 = 22.20 Hz corresponds to the value of 3, therefore an electromagnetic signal at the frequency of 22.20 Hz starts being emitted at this moment and is emitted for 1 second. In 1 second a value of 2404 comes from the output of the tool clock 3 1 and, as the value of the least significant decimal digit equals 4, the frequency of the electromagnetic signal emitted by the transmitter 37 changes and becomes 22.35 Hz.

[0045] A temporal characteristic transmitted by means of the electromagnetic signal transmitter 37, according to which it is possible to determine a difference between onboard tool clock 3 1 time and logger clock 46 time at the moment when the tool passes near the logger is received by means of the logger 6 in the locations of the logger 6 on the outer side of the pipeline 3 near the reference points. The electromagnetic signal is received at the antenna 41 , amplified in the amplifier 42, filtered in the filter 43, further amplified in the amplifier 44 with automatic adjustment, after which the signal is provided to the input of the synchronous detector 45, by means of which the frequency of the received electromagnetic signal is determined. An encoded digital signal, which uniquely corresponds to the frequency of the received electromagnetic signal, is generated at the output of the synchronous detector 45 and is provided to the input of the data processing unit 47. Signals from the logger clock 46 are also provided to the input of the data processing unit 47.

[0046] Satellite signal receiver 49 is used to receive satellite time values from the artificial earth satellites, as well as characteristics that allow to determine the geographical location of the logger 6, said values being recorded onto the logger data storage 48. The operator may also record geometrical parameters that characterize the location of the logger 6 relative to the pipeline 3 onto the logger data storage 48.

[0047] From the output of the amplifier 44 with automatic adjustment, the signal is provided to the input of the data processing unit 47, where the phase of the signals being received is measured, and the time instant when the tool 2 passes near the logger 6 is identified based on the temporal dependency of the phase change. When the passing of the tool 2 near the logger 6 is identified, the data processing unit 47 generates a control signal, which is provided to the indication unit 50 and informs the operator that the tool 2 has passed near the logger 6. Besides, a data unit is generated, which comprises a code that uniquely corresponds to the frequency of the received electromagnetic signal, which has been determined by means of the synchronous detector 45. Said data unit also comprises a logger clock 46 time value, as well as satellite time value and GPS coordinates determined by means of the satellite signal receiver 49. Said data unit is recorded onto the data storage 48 arranged in the logger 6. In an alternative embodiment, the temporal dependency of the phase of the received electromagnetic signal may be recorded onto the data storage 48 such that it is associated with the clock 46 time values, satellite time and geodesic coordinates in order to further determine the time instant when the tool 2 has passed near the logger 6 after the passing of the tool 2 inside the pipeline 3 is completed. [0048] After the passing of the tool 2 through the pipeline 3, the tool 2 is taken out of the receiving station of the pipeline 3, a portable computer (laptop) is connected to the electronic system of the tool 2, and data from the tool data storage 36 are copied to the laptop data storage. A laptop is also connected to the electronic system of the logger 6 and data are copied from the logger data storage 48 to the laptop data storage. Further data processing is carried out in an external computer, which may be a laptop or any other computer, to which the data are transferred from the laptop data storage. When processing data in the external computer, data associated with the onboard clock 31 time are matched with data associated with the logger 6 clock 46 time, and, if necessary, also with the recorded satellite time values and geodesic coordinates (GPS or GLONASS coordinates).

[0049] To match the data, characteristics associated with the tool clock 3 1 time, as well as characteristics associated with logger clock 46 time and satellite clock time are read out based on the frequency of the transmitted encoded signal initially recorded onto the logger 6 data storage 48, and a difference between the tool clock 31 time and logger clock 46 time is determined. Thus, if the frequency of the received electromagnetic signal makes 22.20 Hz, it means that tool clock 3 1 time had a value of 3 (3 seconds). If a logger clock 46 time value was 5 at the same moment, the difference between the clock times in this reference point makes +2 seconds for the logger clock 46 relatively to the tool clock 31.

[0050] If the time difference in the previous reference point and in the next reference point also made +2 seconds, then, in order to bring the values into accordance with one common clock - logger clock 46 - for the characteristics initially recorded onto the tool data storage, 2 seconds are added to the time association according to the tool clock 3 1, and said characteristics are overwritten with a new time association.

[0051] If the difference between the clock times in the previous reference point made +1 second, then, in order to bring the values into accordance with one common clock - logger clock 46 - for the characteristics initially recorded onto the tool data storage, a value defined as a linear function that changes from 1 second in the previous reference point to 2 seconds in the predetermined reference point is added to the time association according to the tool clock 31. Thus, a linear approximation of the time shift is carried out as the tool 2 moves from one reference point to another one. The association of the recorded characteristics with the satellite clock time is carried out in a similar manner if necessary.

[0052] After passing the tool, defects of the wall of the pipeline 3 are identified in said external computer, and their locations in the pipeline are determined based on the dependencies of the distance traveled inside the pipeline 3. Movement trajectory of the tool 2 is determined based on the tool acceleration and angular velocity values with a time association that corresponds to the laying trajectory of the pipeline 3 being inspected. As all measured physical quantities are recorded such that they are associated with time, among them the characteristics of the pipeline wall, a time stamp that corresponds to the detected defect allows to find a point on said movement trajectory of the tool, which corresponds to the same time stamp, which allows to determine the location of the detected defect in the pipeline 3 in a local coordinate system.

[0053] As geodesic coordinates of the logger (GPS or GLONASS coordinates) and geometrical parameters that characterize the location of the logger 6 relative to the pipeline 3 were recorded onto the logger data storage 48, this allows to determine the geodesic coordinates of the reference points of pipeline 3, which the tool 2 has passed in the course of its movement inside the pipeline 3. Since the pipeline laying trajectory in the local coordinate system and geodesic coordinates of reference points of the pipeline 3 are known, this allows to determine the pipeline laying trajectory in geodesic coordinates, as well as geodesic coordinates of the detected defects in pipeline 3.

[0054] In the second embodiment shown on Fig. 5 the system for tracking a movement trajectory of a pipeline tool comprises a transmitter arranged in the logger 56, as well as a receiver 53 arranged in the pipeline tool 52. Constant magnets are arranged on the body of the tool 52 such that magnetic field of said magnets could be detected outside the pipeline. Receiver 53 is arranged in the body of the pipeline tool 52, which is passed inside the pipeline 3. Logger 56 with the transmitter is arranged on the ground surface 5 near the pipeline 3. The transmitter is an electromagnetic signal generator with controllable frequency. [0055] The structural diagram of pipeline tool equipment according to the second embodiment is shown on Fig. 6. Measurement system of the tool 52 comprises a tool clock 61, traveled distance sensors 62, non-destructive inspection sensor unit 63 sensitive to defects in a wall of the pipeline 3, an inertial navigation sensor unit 64, a control and data processing unit 65, a tool data storage 66, as well as concatenated antenna 71 , antenna amplifier 72, filter 73, synchronous detector 74. The outputs of the filter 73 and synchronous detector 74 are connected to the inputs of the control and data processing unit 65. In the discussed embodiment, an electromagnetic signal receiver is also arranged in the tool 52. Traveled distance sensors 62 are designed as odometers, the inertial navigation sensor unit 64 includes three mutually orthogonal accelerometers and three mutually orthogonal rotation angle sensors. Sensor unit 63 may include nondestructive inspection sensors, as well as electronic units for initializing or scanning of sensors, analog to digital conversion, transformation and encoding of the measurement data. Non-destructive inspection sensors may be designed as ultrasound sensors.

[0056] The control and data processing unit 65 may be designed as an integrated circuit board comprising a central microprocessor, microcontrollers, data buses, as well as connectors for coupling to sensor units 63, 64, an odometer 62, a data storage 66 and an electromagnetic signal receiver 53. Tool clock 61 may be installed on the same integrated circuit board. The synchronous detector 74 is a signal decoding unit.

[0057] Fig. 7 shows a structural diagram of the logger equipment according to the second embodiment. In the discussed embodiment the logger 56 comprises a clock 81 , a magnetic field sensor 82, a satellite signal receiver 83, a data processing unit 84, a logger data storage 85, an indication unit 86, an electromagnetic signal transmitter 87. The data processing unit 84 comprises an analog-to-digital converter and a microcontroller for processing digital data. Indication unit 80 may include light emitting diodes and a loudspeaker or a liquid crystal panel. [0058] The system operates as follows. Before passing the tool 52 the onboard tool clock 61 is synchronized with the logger clock 81, wherein identical time is set on both clocks 61 and 81. The tool 52 is put into the launching station of the pipeline 3, and the pumping of the product to be transported by the pipeline 3 is activated. Under the pressure of the product being pumped the tool 52 moves inside the pipeline 3. Reference points are selected along the pipeline 3 route at a distance of 2 to 5 kilometers from each other, in which the logger for detecting the time instant when the tool passes by the logger must be arranged. As a rule, reference points are selected in the locations where the pipeline 3 crosses roads, rivers, communication lines, at bends in the pipeline 3 and in locations where pipeline fittings are installed.

[0059] While the tool 52 moves inside the pipeline 3, the operator moves out to the location of the nearest set reference point, places a logger 56 in close proximity of the reference point of pipeline 3 and switches the logger 56 on for receiving the signals from the magnetic field sensor 82 of the logger 56. When the logger 56 detects the growth of magnetic field intensity near the reference point, the indication unit 86 of the logger 56 informs the operator respectively, which means that the tool 52 is approaching the reference point. The operator switches on the emission of the electromagnetic signal by means of the electromagnetic signal transmitter 87 arranged in the body of the logger 56 or coupled to the control unit of the logger 56. The data processing unit 84 is used to encode the signal of the electromagnetic oscillation transmitter 87 depending on the logger clock 81 time. The value of the last decimal digit in the logger clock 81 time value is used as a temporal characteristic, which is transmitted by means of the electromagnetic oscillation transmitter 87.

[0060] To encode the signal of the electromagnetic oscillation transmitter 87, the frequency of electromagnetic oscillations changes with a period of 1 second depending on the value of the last digit of the onboard clock time (0 to 9). Fig. 2 shows a possible dependence of the frequency of electromagnetic oscillations emitted by the transmitter 87 on the time t. T is a frequency change period. T is a time discrete (slice) - a time interval, within which the frequency of electromagnetic oscillations does not change. In the preferred embodiment, the period T is one second. Frequencies v may have the following values:

vl = 22.05 Hz;

v2 = 22.40 Hz;

v3 = 22.20 Hz;

v4 = 22.35 Hz;

v5 = 22.15 Hz;

v6 = 22.25 Hz;

v7 = 22.10 Hz;

v8 = 22.45 Hz;

v9 = 22.30 Hz;

vl0 = 22.50 Hz;

[0061] The frequency of electromagnetic oscillations in the discussed embodiment changes discretely, in a discrete sequence of set values of frequencies of electromagnetic oscillations, and at each subsequent change in the frequency of electromagnetic oscillations the sign of frequency change is reversed.

[0062] Satellite signal receiver 83 is used to receive satellite time values from the artificial earth satellites, as well as characteristics that allow to determine the geographical location of the logger 56. A data unit including a logger clock 81 time value, a satellite time value and geographical coordinates obtained by means of the satellite signal receiver 83, as well as a signal from the magnetic field sensor 82 is periodically generated in the data processing unit, said data units being recorded onto the logger data storage 85. The operator may also record geometrical parameters that characterize the location of the logger 56 relative to the pipeline 3 onto the logger data storage 85.

[0063] When the intensity of the magnetic field detected by the magnetic field sensor 82 decreases, the indication unit 86 provides a respective signaling, which means that the tool 52 has passed the reference points of the pipeline 3 and is moving away from the operator. After that, the operator moves over to the location of the next set point of the pipeline 3.

[0064] As the tool 52 moves inside the pipeline 3, the measurement system arranged in the tool 52 is used to measure parameters that characterize the movement of the tool 52 inside the pipeline 3, and also the characteristics of a wall of the pipeline 3, which allow to identify wall defects, are measured. Odometers 62 are used to measure the distance traveled inside the pipeline 3, inertial navigation sensors 64 (accelerometers and angular velocity sensors) are used to measure the accelerations and angular velocities of the tool 52; nondestructive inspection sensors 63 designed as ultrasound sensors are used to emit sounding ultrasound signals in the direction of the wall of the pipeline 3, and signals corresponding to the received ultrasound waves reflected from the inner surface of the pipe of the pipeline 3, as well as signals corresponding to the received ultrasound waves reflected from the outer surface of the pipe of the pipeline 3 are received from said sensors 63. Tool 52 clock time signals are received from the clock 61 arranged in the tool 52. Signals obtained from the clock 61 and from the units 62, 63, 64 are processed in the control and data processing unit 65 and recorded onto the data storage 66 arranged in the tool 52 such that they are associated with clock 61 time.

[0065] Receiver 53 arranged in the tool 52 is used to receive a temporal characteristic transmitted by means of the electromagnetic signal transmitter 87, according to which it is possible to determine the difference between the onboard tool clock 61 time and logger 81 time values at the moment when the tool 52 passes near the logger 56. The electromagnetic signal is received at the antenna 71 , amplified by the amplifier 72, filtered in the filter 73, after which the signal is provided to the input of the synchronous detector 74, which is used to determine the frequency of the received electromagnetic signal. An encoded digital signal, which uniquely corresponds to the frequency of the received electromagnetic signal is generated at the output of the synchronous detector 74 and is provided to the input of the control and data processing unit 65. Signals from the tool clock 61 are also provided to the input of the control and data processing unit 65. [0066] From the output of the filter 73 the signal is provided to the input of the control and data processing unit 65, where the phase of the received signals is measures, and the time instant when the tool 52 passes near the logger 56 is identified based on the temporal dependency of the phase change. When the passing of the tool 52 near the logger 56 is identified, the control and data processing unit 65 generates a data unit that comprises a code, which uniquely corresponds to the frequency of the received electromagnetic signal, which has been determined by means of the synchronous detector 74. Said data unit also comprises a tool clock 61 time value. Said data unit is recorded onto the data storage 66 arranged in the tool 52. In an alternative embodiment, a temporal dependency of the phase of the received electromagnetic sensor may be recorded onto the data storage 66 such that it is associated with the clock 61 time values in order to further determine the time instant when the tool 52 passes near the logger 56 after the passing of the tool 52 inside the pipeline 3 is completed.

[0067] After the passing of the tool 52 through the pipeline 3, the tool 52 is taken out of the receiving station of the pipeline 3, a portable computer (laptop) is connected to the electronic system of the tool 52, and data from the tool data storage 66 are copied to the laptop data storage. A laptop is also connected to the electronic system of the logger 56 and data are copied from the logger data storage 85 to the laptop data storage. Further data processing is carried out in an external computer, which may be a laptop or any other computer, to which the data are transferred from the laptop data storage. When processing data in the external computer, data associated with the onboard clock 61 time are matched with data associated with the logger 56 clock 81 time, and, if necessary, also with the recorded satellite time values and geodesic coordinates (GPS or GLONASS coordinates).

[0068] To match the data, characteristics associated with the tool clock 61 time, as well as characteristics associated with logger clock 81 time and satellite clock time are read out based on the frequency of the transmitted encoded signal initially recorded onto the tool data storage 66, and a difference between the tool clock 61 time and logger clock 81 time is determined. Thus, if the frequency of the electromagnetic signal received by the receiver 53 makes 22.15 Hz, it means that logger clock 81 time had a value of 5 (5 seconds) in the last digit. If a logger clock 61 time value in the last digit was 3 at the same moment, the difference between the clock times in this reference point makes -2 seconds for the tool clock 61 relatively to the logger clock 81.

[0069] If the time difference in the previous reference point and in the next reference point also made -2 seconds, then, in order to bring the values into accordance with one common clock - logger clock 81 - for the characteristics initially recorded onto the tool data storage, 2 seconds are added to the time association according to the tool clock 61, and said characteristics are overwritten with a new time association.

[0070] If the difference between the tool clock 61 time and the logger clock 81 time in the previous reference point made -1 second, then, in order to bring the values into accordance with one common clock - logger clock 81 - for the characteristics initially recorded onto the tool data storage, a value defined as a linear function that changes from 1 second in the previous reference point to 2 seconds in the predetermined reference point is added to the time association according to the tool clock 61. Thus, a linear approximation of the time shift is carried out as the tool 52 moves from one reference point to another one. The association of the recorded characteristics with the satellite clock time determined by means of the satellite signal receiver 83 is carried out in a similar manner if necessary.

[0071] After passing the tool 52, defects of the wall of the pipeline 3 are identified in said external computer, and their locations in the pipeline are determined based on the dependencies of the distance traveled inside the pipeline 3. Movement trajectory of the tool 52 is determined based on the tool acceleration and angular velocity values with a time association that corresponds to the laying trajectory of the pipeline 3 being inspected. As all measured physical quantities are recorded such that they are associated with time, among them the characteristics of the wall of the pipeline 3, a time stamp that corresponds to the detected defect allows to find a point on said movement trajectory of the tool 52, which corresponds to the same time stamp, which allows to determine the location of the detected defect in the pipeline 3 in a local coordinate system. [0072] As geodesic coordinates of the logger 56 (GPS or GLONASS coordinates) and geometrical parameters that characterize the location of the logger 56 relative to the pipeline 3 were recorded onto the logger 56 data storage, this allows to determine the geodesic coordinates of the reference points of pipeline 3, which the tool 52 has passed in the course of its movement inside the pipeline 3. Since the pipeline laying trajectory in the local coordinate system and geodesic coordinates of reference points of the pipeline 3 are known, this allows to determine the pipeline laying trajectory in geodesic coordinates, as well as geodesic coordinates of the detected defects in pipeline 3.

Claims

WHAT IS CLAIMED IS:

1. A method for tracking a movement of a pipeline tool, comprising:

passing the tool inside the pipeline, measuring physical quantities characterizing the status and/or characteristics of the tool and/or of the pipeline by means of a measurement system of the tool, and recording same in a tool data storage such that they are associated with time determined by a tool clock;

measuring, from the outer side of the pipeline, by means of at least one logger arranged near a reference point of the pipeline, a magnetic field intensity or other physical quantities, which allow to identify the passing of the tool near the logger, such that they are associated with time determined by logger clock, and generating characteristics, which allow to identify the time instants when the tool passes near the logger according to the logger clock, based on said measured physical quantities and time values corresponding thereto, and recording the generated characteristics onto a logger data storage;

2. The method of claim 1, comprising:

using an electromagnetic oscillation transmitter as said transmitter, and using an electromagnetic oscillation receiver as said receiver, said transmitted signal being encoded by changing the frequency of electromagnetic oscillations depending on the value of the temporal characteristic being transmitted;

and, when receiving said transmitted encoded signal, determining frequency characteristics of the electromagnetic oscillations corresponding to the transmitted encoded signal and recording same onto the data storage on the receiver side together with a clock time on the receiver side,

after passing the tool, matching the data recorded in the tool data storage with the data recorded in the logger data storage, determining a difference between the clock time on the transmitter side and the clock time on the receiver side based on the frequency characteristics of the transmitted encoded signal of the transmitter stored in the data storage on the receiver side; reading the characteristics associated with the clock time on the transmitter side from the data storage on the transmitter side, and reading the characteristics associated with the clock time on the receiver side from the data storage on the receiver side, and overwriting said characteristics such that they are associated with the clock time of an identical clock for both the characteristics recorded on the receiver side and the characteristics recorded on the transmitter side.

3. The method of claim 2, comprising determining, as the frequency characteristic of electromagnetic oscillations, a frequency of electromagnetic oscillations within a period of measuring said frequency.

4. The method of claim 2, wherein the frequency of electromagnetic oscillations changes discretely.

5. The method of claim 2, wherein the frequency of electromagnetic oscillations changes smoothly.

6. The method of claim 4, wherein the frequency of electromagnetic oscillations changes periodically, the sequence of set values of frequency of electromagnetic oscillations being periodically repeated with a period being not smaller than a repetition period of a value in the least significant digits of a full time value.

7. The method of claim 6, comprising reversing the sign of frequency change in the discrete sequence of set values of frequencies of electromagnetic oscillations at each subsequent change in the frequency of electromagnetic oscillations.

8. The method of claim 2, comprising using a value in one or more of the least significant digits of the clock time value on the transmitter side as the transmitted temporal characteristic, wherein, in the signal with the temporal characteristic being transmitted as a signal with a set frequency, the frequency uniquely corresponds to the value in one or more least significant digits.

9. The method of any one of claims 2-8, comprising determining the frequency characteristics of the received electromagnetic oscillations by measuring the phase of the electromagnetic oscillations being received and determining the frequency of the received electromagnetic oscillations based on the measured phase, the frequency characteristics of the received electromagnetic oscillations being analyzed, the value of said temporal characteristic being identified and phase and/or frequency characteristics of the electromagnetic oscillations and/or the temporal characteristic being recorded onto the data storage on the receiver side.

10. The method of claim 1, comprising measuring a distance traveled by the tool inside the pipeline by means of a measurement system arranged in the tool, and recording same in the tool data storage such that it is associated with the tool clock time, for further determining the distance between the respective pipeline feature and the reference point.

11. The method of claim 1 , comprising receiving a satellite time signal from an artificial earth satellite by means of a satellite signal receiver arranged in the logger and recording the satellite time values onto the logger data storage; after passing the tool, matching the data recorded such that they are associated with the clock time on the receiver side and/or on the transmitter side, with the recorded satellite time values, and overwriting said characteristics such that they are associated with the satellite time.

12. The method of claim 1, comprising receiving satellite positioning system signals by means of a satellite signal receiver arranged in the logger, determining geodesic coordinates of the logger based on the same, and recording same onto the logger data storage, and, after passing the tool, matching the characteristics, which allow to identify the time instants when the tool passes near the logger according to the logger clock, with the geodesic coordinates of the logger, and determining the geodesic coordinates of the tool in the reference points, in which the passing of the tool near the logger is detected.

13. The method of claim 12, comprising measuring a distance traveled by the tool inside the pipeline by means of the measurement system of the tool, measuring the characteristics of a pipeline wall, which allow to identify wall defects, and, after passing the tool, identifying the wall defects and determining their geodesic coordinates.

14. The method of claim 1, wherein the difference between the clock time on the transmitter side and the clock time on the receiver side is determined in the course of or after passing the tool.

15. The method of any one of claims 1-8, 10-14, comprising measuring accelerations and angular velocities of the tool on several orthogonal axes by means of an inertial navigation system unit included in the measurement system of the tool, and determining the geographical location of the tool movement trajectory after passing the tool based on the temporal dependencies of the distance traveled inside the pipeline, accelerations and angular velocities, as well as on the values of geodesic coordinates of reference points where the tool has passed near the logger.

16. The method of claim 1, further comprising generating a magnetic field when passing the tool by means of a magnetic field source arranged in the tool, measuring a value of the magnetic field by means of said logger and identifying the passing of the tool near the logger based on the temporal dependency of the value of the magnetic field.

17. The method of claim 1, comprising receiving, by means of the logger, acoustic oscillations related to the passing of the tool inside the pipeline, measuring the characteristics of acoustic oscillations, and identifying the passing of the tool near the logger based on the same.

18. The method of claim 1, wherein said electromagnetic oscillation transmitter is arranged in the logger and said electromagnetic oscillations receiver is arranged in the tool.

19. The method of claim 1, wherein said electromagnetic oscillation transmitter is arranged in the tool and said electromagnetic oscillation receiver is arranged in the logger.

20. The method of claim 1 or 2, comprising synchronizing the clock on the receiver side with the clock on the transmitter side before passing the tool.

21. The method of claim 1 or 2, comprising synchronizing the clock on the receiver side with the clock on the transmitter side in the course of passing the tool.

22. A system for tracking a movement trajectory of a pipeline tool, comprising:

a pipeline tool configured to move inside a pipeline;

at least one logger arranged near a reference point on the outer side of the pipeline for measuring a magnetic field intensity or other physical quantities, which allow to identify the passing of the tool near the logger, such that they are associated with time determined by a logger clock, and for generating characteristics, which allow to identify the time instants when the tool passes near the logger according to the logger clock, based on said measured physical quantities and time values corresponding thereto, and comprising a logger data storage for recording the generated characteristics such that they are associated with time determined by the logger clock;

a transmitter arranged in one of the logger and the tool for transmitting a signal with a temporal characteristic associated with a clock time on the transmitter side;

a receiver arranged in the other one of the logger and the tool, for receiving the transmitted signal with the temporal characteristic, and comprising a data storage for recording at least one characteristic associated with the temporal characteristic of the received signal, such that it is associated with a clock time on the receiver side, a processing device for determining a difference between the clock time on the transmitter side and the clock time on the receiver side and hence a time difference between the logger clock and the tool clock, and determining the characteristics of the pipeline using said time difference in the reference point

23. The system of claim 22, wherein

said transmitter is an electromagnetic oscillation transmitter having a means for encoding the transmitted signal by changing the frequency of electromagnetic oscillations depending on the value of the temporal characteristic being transmitted;

said receiver is an electromagnetic oscillation receiver having a means for processing the transmitted encoded signal and determining frequency characteristics of the electromagnetic oscillations corresponding to the transmitted encoded signal, and

said processing device is configured to determine the difference between the clock time on the transmitter side and the clock time on the receiver side based on the frequency characteristics of the transmitted encoded signal of the transmitter recorded in the data storage on the receiver side, based on the matching of the data recorded in the tool data storage with the data recorded in the logger data storage, and to overwrite said characteristics such that they are associated with the clock time of an identical clock.

24. The system of claim 23, wherein the frequency of electromagnetic oscillations changes discretely.

25. The system of claim 23, wherein the frequency of electromagnetic oscillations changes smoothly.

26. The system of claim 24, wherein the frequency of electromagnetic oscillations changes periodically, the sequence of values of frequencies of electromagnetic oscillations being periodically repeated.

27. The system of claim 26, wherein the sign of frequency change in the sequence of values of frequencies of electromagnetic oscillations is reversed at each subsequent change in the frequency of electromagnetic oscillations.

28. The system of claim 23, wherein a value in one or more of the least significant digits of the clock time value on the transmitter side is used as the transmitted temporal characteristic, wherein, in the signal with the temporal characteristic being transmitted as a signal with a set frequency, the frequency uniquely corresponds to the value in one or more least significant digits.

29. The system of any one of claims 23-28, wherein said receiver is configured to measure the phase of the electromagnetic oscillations being received and to determine the frequency of the received electromagnetic oscillations based on the measured phase, and the processing device is configured to analyze the frequency characteristics of the received electromagnetic oscillations and to identify the value of said temporal characteristic for recording the phase and/or frequency characteristics of the electromagnetic oscillations and/or the temporal characteristic onto the data storage on the receiver side.

30. The system of claim 22, wherein the measurement system of the tool comprises a means for measuring a distance traveled by the tool inside the pipeline.

31. The system of claim 22, wherein the logger further comprises a satellite signal receiver for receiving satellite time signals from an artificial earth satellite and recording the satellite time values onto the logger data storage; wherein the processing device is configured to match the data recorded such that they are associated with the clock time on the receiver side and/or on the transmitter side, with the recorded satellite time values, and to overwrite said characteristics such that they are associated with the satellite time.

32. The system of claim 22, wherein the logger further comprises a satellite positioning system signal receiver for determining geodesic coordinates of the logger and recording same onto the logger data storage, wherein the processing device is further configured to match, after passing the tool, the characteristics, which allow to identify the time instants when the tool passes near the logger according to the logger clock, with the geodesic coordinates of the logger, and to determine the geodesic coordinates of the tool in the reference points, in which the passing of the tool near the logger has been detected.

33. The system of claim 32, wherein the measurement system of the tool is configured to measure the distance traveled by the tool and to measure the characteristics of a pipeline wall, which allow to identify wall defects, and the processing device is configured to identify the wall defects and to determine their geodesic coordinates.

34. The system of claim 22, wherein the measurement system of the tool comprises an inertial navigation system unit for measuring accelerations and angular velocities of the tool on several orthogonal axes, wherein the processing device is configured to determine the geographical location of the tool movement trajectory based on the temporal dependencies of the distance traveled inside the pipeline, accelerations and angular velocities, as well as on the values of geodesic coordinates of reference points where the tool has passed near the logger.

35. The system of claim 22, wherein the tool further comprises a magnetic field source and the logger further comprises a means for measuring a value of the magnetic field for identifying the passing of the tool near the logger based on the temporal dependency of the value of the magnetic field.

36. The system of claim 22, wherein the logger further comprises a means for receiving acoustic oscillations related to the passing of the tool inside the pipeline, and for measuring the characteristics of acoustic oscillations for identifying the passing of the tool near the logger.

37. The system of claim 22, wherein said electromagnetic oscillation transmitter is arranged in the logger and said electromagnetic oscillation receiver is arranged in the tool.

38. The system of claim 22, wherein said electromagnetic oscillation transmitter is arranged in the tool and said electromagnetic oscillation receiver is arranged in the logger.