Testing an energy transmission network and localizing a fault location in an energy transmission cable

Abstract

To locate a fault point (6) in a power transmission cable (1), the following steps are applied: Detection of the first time point at which a specific partial discharge pulse in the power transmission cable (1) is detected at the first measurement point (E1) located at one end of the power transmission cable (1). Detection of the second time point at which a specific partial discharge pulse in the power transmission cable (1) is detected at the second measurement point (?6) located at the other end of the power transmission cable (1). Based on the first and second time points, identification of a fault point (6) along the power transmission cable (1) where the specific partial discharge pulse occurs. Determination of the third and fourth measurement points (?1 - ?6) from a set of measurement points located on the power transmission cable, such that the third and fourth measurement points limit the section of the power transmission cable (1) where the fault point (6) is located and where no other measurement points are present.Detection of a third time point at which another specific partial discharge pulse is detected at the third measurement point (1) in the power transmission cable. Detection of a fourth time point at which another specific partial discharge pulse is detected at the fourth measurement point. Correction of the specific fault point (6) depending on the third and fourth time points.

Description

[0001] The present invention relates, firstly, to checking an energy transmission network for faults (e.g., faults in the insulation) and, secondly, to locating such a fault by locating a fault location in an energy transmission cable.

[0002] In "Detecting The Fault Location Using Traveling Wave" by IV Barburas et al., 6th International Conference on Modern Power Systems, 18-21 May 2015, pages 23 to 26, a "traveling wave" technique for fault localization is described, in which the arrival times of a wave propagating from the fault location in both directions of a transmission line are used to locate the fault location.

[0003] CN 104 049 179 A discloses a method for acquiring "traveling wave" information using multiple monitoring terminals distributed along a power transmission line. Based on this information, a fault segment is determined in which the fault location is situated.

[0004] DE 10 2014 222 662 A1 concerns the data enrichment of measurement data sets from a low-voltage network. Measurement data sets arriving asynchronously from multiple network nodes are stored in chronological order for each network node. This allows for the easy selection of measurement data that were generated within a specific time period.

[0005] US 2009 / 289637 A1 describes the determination of the impedance of a voltage line.

[0006] US Patent 2014 / 074414 A1 discloses systems and methods for calculating a fault location in an electrical power supply system based on a traveling wave generated by an electrical fault in the system. An intelligent electronic device detects the transient traveling wave caused by the electrical fault. A first time associated with this first traveling wave is determined. The intelligent electronic device then receives a second time associated with a second traveling wave value, detected by a remote intelligent electronic device.

[0007] To inspect a power transmission network, and in particular to locate a fault, current technology involves recording an event (e.g., the effects of a partial discharge) at only one measuring point in the network. By determining the time at which this event occurs at the measuring point and a subsequent time at which a reflection of this event occurs at the measuring point, the fault can then be located.

[0008] This known method of localizing a fault in a power transmission network, or more precisely in a power transmission cable of the power transmission network, is, however, quite imprecise. Therefore, the present invention aims to improve the localization of a fault in a power transmission cable compared to the prior art. Since the solution to this problem is based on determining as accurately as possible the time at which a specific event occurs at a specific measuring point in the power transmission network, the invention additionally includes determining this time as accurately as possible.

[0009] According to the invention, this problem is solved by a method for testing an energy transmission network according to claim 1 and by a system according to claim 6. The dependent claims describe advantageous and preferred embodiments of the present invention.

[0010] According to an embodiment of the present invention, a method for locating a fault in a power transmission cable is provided, wherein the method according to the invention comprises the following steps: The first time point is recorded at which a specific partial discharge pulse, originating at the fault location, is detected in the power transmission cable at a first measuring point located at one end of the power transmission cable. This first time point thus defines when the effects of a specific partial discharge originating at the fault location have propagated along the power transmission cable to the first measuring point. The propagation of the effects of the partial discharge includes, in particular, charge attenuation and requires time to travel along the power transmission cable. A second time point is recorded at which the specific partial discharge pulse is detected in the power transmission cable at a second measuring point located at the other end of the power transmission cable.In the same way as the first time point, the second time point defines when the effects of the specific partial discharge pulse or partial discharge have propagated along the power transmission cable to the second measuring point. Determine the fault location along the power transmission cable where the specific partial discharge pulse or partial discharge was generated, as a function of the first and second time points. As will be explained in detail later, the fault location can be determined quite accurately as the distance from the first or second measuring point, particularly if the length of the power transmission cable and the propagation speed of the partial discharge pulse are known. Determine a third and a fourth measuring point from a set of measuring points arranged in or along the power transmission cable.The third and fourth measuring points are determined such that they define a section of the power transmission cable in which the fault, whose location was determined in the previous step, is situated and in which no other measuring points are located. In this step, therefore, the third and fourth measuring points are selected from the set of measuring points between which the fault lies and which exhibit the smallest possible distance to the fault among all measuring points. A third time point is recorded at which another specific partial discharge pulse is detected in the energy transmission cable at the third measuring point. A fourth time point is recorded at which the next specific partial discharge pulse is detected at the fourth measuring point. These last two steps are very similar to the first two steps of the method according to the invention, except that in the last steps the measuring points (i.e., the third and fourth measuring points) are arranged closer to the fault location than in the first two steps of the method according to the invention. The specific fault location is corrected depending on the third and fourth time points. The location of the fault location can be determined more accurately based on the third and fourth time points than based on the first and second time points, since the third and fourth measuring points are located closer to the fault location than the first and second measuring points.Correcting the specific fault location means, in particular, determining the precise location of the fault.

[0011] According to the invention, by determining the location or localizing the fault using two measuring points, which are figuratively arranged to the right and left of the fault in the power transmission cable, the fault location can be determined much more accurately than according to the prior art, which uses only one measuring point and the reflection of the partial discharge pulse. Furthermore, the fault location is advantageously determined in two stages. In a first stage, the fault is roughly located in order to optimally select two measuring points (i.e., the third and fourth measuring points) based on this rough localization (i.e., as close as possible to the fault). Based on these two optimally selected measuring points, the location of the fault can then be advantageously determined very precisely in the second stage.

[0012] A measuring point is understood to be, in particular, a cable joint or a cable termination.

[0013] The detection and measurement of partial discharge at a specific measuring point is carried out primarily using statistical methods. This detection and measurement is repeated based on numerous events (partial discharges) to avoid correlation errors.

[0014] Determining the point in time at which a specific partial discharge pulse is detected in the power transmission cable at a specific measuring point requires that it is possible to distinguish between that specific partial discharge pulse and another partial discharge pulse at that specific measuring point. In other words, the present invention requires that the effects of the same partial discharge at the fault location are detected at the first (third) and second (fourth) measuring points in order to locate the fault location based on these times.

[0015] Partial discharge pulses can be distinguished, for example, based on the properties of the partial discharge pulses being compared. For instance, the partial discharge pulse detected at a specific measuring point can be analyzed based on an energy pulse transmitted along the power transmission cable and on a specific point in time at which the partial discharge pulse exhibits certain properties. This allows the specific partial discharge pulse to be distinguished from other partial discharge pulses. This method for determining the point in time at which a specific partial discharge pulse is detected at a particular measuring point in the power transmission cable is known in the art and will therefore not be discussed further here.

[0016] According to a preferred embodiment of the invention, the fault location is determined as the distance I f from the third measuring point using the following equation (1): l f = v PD 2 t 3 − t 4 + l 2

[0017] Here, t3 corresponds to the third time point, t4 to the fourth time point, VPD to the propagation speed of the partial discharge pulse (i.e., the effects of the partial discharge) along the power transmission cable, and I to the length of the section of the power transmission cable that is bounded by the third and fourth measurement points.

[0018] It should be noted that equation (1) can also be used to determine the fault location as a function of the first and second time points. In this case, t3 corresponds to the first time point, t4 to the second time point, and I is the length of the power transmission cable running from the first measurement point (one end) to the second measurement point (the other end). The distance If defines, in this case, the distance of the fault location from the first measurement point (one end) of the power transmission cable.

[0019] Furthermore, according to the invention, it is possible that at the first, second, third, and fourth time points, the same partial discharge pulse or the effects of the same partial discharge are detected at each of these measuring points, albeit with different attenuation. In this case, the determined partial discharge pulse corresponds to the further determined partial discharge pulse.

[0020] For example, all measuring points can be designed to determine and record the times at which they detect partial discharge pulses. In a subsequent evaluation step, it can then be determined for the same partial discharge pulse when this pulse was detected at the first, second, third, and fourth measuring points, from which the location of the fault can then be determined, as described above.

[0021] According to a further preferred embodiment of the invention, the first, second, third, and fourth time points each correspond to a time at which information about the respective partial discharge pulse is acquired by control means. According to this further embodiment, a time delay is additionally determined, which results from the transmission of the respective information from the corresponding measuring point to the control means. The respective time point is then corrected by the corresponding time delay. The determination of the time delay is carried out by the inventive method for verifying an energy transmission network.

[0022] According to this further embodiment, a first, second, third, and fourth measuring unit, connected to the first, second, third, and fourth measuring points respectively, transmits the corresponding information about the respective partial discharge pulse to the control means as soon as the respective measuring unit has detected the corresponding partial discharge pulse at the associated measuring point. The control means then determine and correct the location of the fault depending on the first, second, third, and fourth time at which the respective information reaches the control means, taking into account the respective time delay resulting from the transmission of the respective information from the corresponding measuring point or from the corresponding measuring unit to the control means.

[0023] The specific method used to determine the respective time delay for the transmission of the respective information from the corresponding measuring unit to the tax authorities will be explained in more detail below.

[0024] The present invention provides a method for verifying an energy transmission network. This method for verifying the energy transmission network comprises the following steps: Detecting an event (e.g., a partial discharge pulse or the effects of a partial discharge) at a measuring point or a measuring unit connected to the measuring point. Transmitting information about the event from the measuring point to the control system. Specifically, as soon as the measuring unit connected to the measuring point detects the event, corresponding information is transmitted to the control system. Determining the time at which the information about the event is detected by the control system. This time defines when the information about the event reaches the control system. Determining a time delay resulting from the transmission of the information from the measuring point or the measuring unit connected to the measuring point to the control system. Correcting the time based on this determined time delay.By correcting the time for the time delay, the time advantageously reflects exactly the time at which the event was recorded at the respective measuring point. This allows for verification of the energy transmission network in relation to the event and the corrected time.

[0025] Since the corrected time corresponds almost exactly to the time at which the event to be recorded was captured at the respective measuring point, the verification of the energy transmission network can advantageously be carried out based on this time. This allows for more precise verification of the energy transmission network, particularly when the precise time at which an event occurs at multiple different measuring points is relevant. Especially when several measuring points are located at varying distances from the control equipment, the transmission time from the respective measuring points or the measuring units connected to them is crucial for determining the time interval between the occurrences of the same event or its effects at the respective measuring points.By taking the time delay into account according to the invention, the times at which the same event or the effects of the same event occurred at the respective measuring points can be determined more precisely compared to the prior art, which also allows the verification of the energy transmission network based on this to be carried out more precisely.

[0026] According to the procedure for verifying the energy transmission network, information about the event is transmitted from the measuring point (or the measuring unit connected to the measuring point) via at least one further measuring point (or at least one further measuring unit connected to a measuring point) to the control equipment. The measuring point (or measuring unit), the at least one further measuring point (or the at least one further measuring unit), and the control equipment are connected to each other via lines through which the information is transmitted. Determining the time delay involves, firstly, determining the transit time of the information across the lines and, secondly, determining the processing time of each measuring point (or the respective measuring unit connected to the measuring point) in order to acquire and forward the information at that particular measuring point (measuring unit).

[0027] In this embodiment, the measuring points or units are interconnected, for example, via a daisy-chain connection. Information is transmitted from the sending measuring unit to the next measuring unit in the direction of the control means, which in turn transmits the information to the next measuring unit in the direction of the control means, and so on, until the information finally reaches the control means.

[0028] If one imagines the measuring point (measuring unit) at which the event is recorded, the at least one further measuring point (measuring unit) and the control means each as a unit which are connected via the lines in the daisy-chain technique, the time delay Δt can be calculated by the following equation (2). Δ t = ∑ i = 0 x RXBW i − RXFWi i 2 − TXBW i + 1 − TXFW i + 1 2

[0029] Here, RXBWj corresponds to the time at which a specific data packet is received at the j-th unit in a backward direction. RXFWj corresponds to the time at which the specific data packet is received at the j-th unit in a forward direction. TXBWj corresponds to the time at which the specific data packet is sent from the j-th unit in the backward direction. TXFWj corresponds to the time at which the specific data packet is sent from the j-th unit in the forward direction. x corresponds to the number of additional measurement points (measurement units) located between the control means and the measurement point (measurement unit) where the event was recorded. The control means (E 0 ) correspond to the 0-th unit, and the measurement point corresponds to the 'x+1'-th unit (E 1 - E 6 ).

[0030] By combining the method for locating a fault with the method for checking an energy transmission network, the time delay resulting from the transmission of information about the corresponding partial discharge pulse from the respective measuring point to the control means is taken into account when recording the first, second, third or fourth time point, which makes it possible to record or determine the respective time point at which the partial discharge pulse was recorded at the corresponding measuring point much more accurately.

[0031] According to one embodiment of the invention, a system for locating a fault in a power transmission cable is also provided. This system comprises control means and several measuring units. A first of these measuring units is connected to a first measuring point located at one end of the power transmission cable, while a second of these measuring units is connected to a second measuring point located at the other end of the power transmission cable. Each measuring unit is configured to detect a partial discharge pulse at the measuring point in the power transmission cable connected to the respective measuring unit.The system is designed to use the first measuring unit to record a first time at which a specific partial discharge pulse is detected at the first measuring point by the first measuring unit, and to use the second measuring unit to record a second time at which the same partial discharge pulse is detected at the second measuring point by the second measuring unit. Furthermore, the system is designed to use control means to determine, based on the first and second time points, a fault location along the power transmission cable where the specific partial discharge pulse was generated. Using the control means, the system then determines a third and a fourth measuring point such that these third and fourth measuring points define a section of the power transmission cable containing the fault location and where no other measuring point connected to either measuring unit is located.With a third measuring unit connected to the third measuring point, the system records a third time at which another specific partial discharge pulse is detected at the third measuring point by the third measuring unit. With a fourth measuring unit connected to the fourth measuring point, the system records a fourth time at which another specific partial discharge pulse is detected at the fourth measuring point by the fourth measuring unit. Finally, the system corrects the specific fault location using control means, depending on the third and fourth time points. This system is combined with the inventive system for testing an energy transmission network, which is described below.

[0032] Finally, the present invention provides a system for monitoring an energy transmission network, which also includes control means and several measuring units. Each of these measuring units is connected to a specific measuring point within the energy transmission network. Each measuring unit is configured to detect an event at the respective measuring point and to transmit information about this event to the control means. The control means are configured to receive the information from the measuring units and to record the time at which the information about the event is received by the control means. The system is configured to determine a time delay resulting from the transmission of the information from the measuring unit that detects the event to the control means.The control mechanisms are further designed to correct the time by the time delay, so that the corrected time reflects when the event was recorded at the respective measuring point. Finally, the system is designed to monitor the energy transmission network based on the event and the corrected time.

[0033] The advantages of the system according to the invention for checking the energy transmission network essentially correspond to the advantages of the method according to the invention for checking the energy transmission network, which have already been explained in detail, so that a repetition is omitted here.

[0034] By combining the two systems described, the respective time at which a specific partial discharge pulse is detected by the respective measuring unit at the associated measuring point is determined depending on the time delay resulting from the transmission of the information about the detected partial discharge pulse from the respective measuring unit to the control means.

[0035] The present invention advantageously allows a partial discharge in a high-voltage cable to be located with an accuracy of 2 m.

[0036] The present invention will now be described in detail with reference to the figures and to preferred embodiments according to the invention.

[0037] In Fig. 1 The diagram shows a high-voltage cable with measuring points, each of which is connected to measuring units that are in turn connected to control devices.

[0038] In Fig. 2 The connection of three measuring units with the control means according to the invention is shown in detail.

[0039] In Fig. 1 Figure 1 shows a high-voltage cable 1, which is terminated at both ends by a cable termination 4. Connecting pieces 2 are arranged at various points along the high-voltage cable 1, dividing it into different sections. Each of these connecting pieces 2 and each of the two cable terminations 4 is connected to a measuring unit E1-E6 via a measuring cable. It should be noted that significantly more than six measuring units can also be used according to the invention.

[0040] The measuring units E 1 to E 6 are in turn connected to each other via fiber optic cables 5 in daisy-chain technology (e.g. up to 20 km), whereby the measuring unit E 1 is itself also connected to a controller E 0 via a fiber optic cable.

[0041] Between the fourth measuring unit E4 and the fifth measuring unit E5, there is a fault location 6 where partial discharge pulses are generated. This means that partial discharges occur at the fault location 6 in the high-voltage cable 1, the effects of which, in the form of partial discharge pulses propagating along the high-voltage cable 1, can be detected at the measuring units E1 to E6. The distance between two adjacent measuring points along the high-voltage cable 1, which are implemented by a connector 2 or a cable termination 4, is known in each case. For example, in Fig. 1 The distance I between the fourth measuring point and the fifth measuring point is shown. The object of the inventive method for locating a fault location 6 is to determine the distance I f between a measuring point 2; 4 and the fault location 6 as accurately as possible.

[0042] To solve this task, or rather to locate the fault location 6, a first step of the first stage involves determining a first time at which a specific partial discharge pulse, generated at the fault location 6, is detected at one end of the high-voltage cable 1 (at the first measuring point 4), which is connected to the first measuring unit E1. In a second step of the first stage, a second time is similarly determined at which the same partial discharge pulse is detected at the other end of the high-voltage cable 1 (at the sixth measuring point 4), which is connected to the sixth measuring unit E6. Knowing the length of the high-voltage cable 1 (i.e.,The distance between the first and sixth measuring points) and the propagation speed of the partial discharge pulse along the high-voltage cable 1 can be used to determine, for example, the distance between the first measuring point and the fault location 6 quite accurately using the equation (1) described above.

[0043] Based on the distance determined in this way, the location of the fault 6 within the high-voltage cable 1 is known. Using this location, the two measuring points along the high-voltage cable 1 that are closest to the fault 6 can now be determined. These two measuring points (fourth and fifth measuring points in) are then used to measure the fault. Fig. 1 ) define a section of the high-voltage cable 1 in which, firstly, the fault location 6 is located and, secondly, in which no other measuring point 2 is located. Using these two measuring points thus determined, the localization of the fault location 6 is repeated in the same manner as described above.

[0044] In the first step of the second stage, a third time point is determined at which a specific partial discharge pulse, originating at fault location 6, is detected at a specific measuring point by the fourth measuring unit E4, which is connected to this specific measuring point. In the second step of the second stage, a fourth time point is determined at which the same partial discharge pulse is detected at a different specific measuring point by the fifth measuring unit E5, which is connected to the other specific measuring point. Using equation (1), the distance If between the fourth measuring point and fault location 6 can now be determined very precisely, given the distance I between the fourth and fifth measuring points.

[0045] According to the invention, several methods exist for determining the time at which a specific partial discharge pulse is detected at a particular measuring point. Firstly, the measuring unit that detects the partial discharge pulse at the connected measuring point can determine the time itself, which would be possible using highly accurate timers within the measuring units. Another possibility is for the measuring unit that detects the partial discharge pulse at the connected measuring point to transmit information indicating that it has detected the partial discharge pulse to the controller E0, which then determines the time. However, with this second method, it is advantageous to consider the time delay required for transmitting the corresponding information from the transmitting measuring unit to the controller E0. This is particularly relevant when the measuring units E1 to E6 are connected using daisy-chain technology, as described in [reference to diagram]. Fig. 1 (and also in Fig. 2 ) shown, this time delay should be taken into account, since this time delay is influenced not only by the propagation time along the fiber optic cable 5, but also by the processing time of the measuring units located between the sending measuring unit and the controller E 0.

[0046] The way in which the controller E 0 and the measuring units are connected in the daisy-chain technique is fundamentally and in more detail than in the Fig. 1 in the Fig. 2 Only three measurement units E1 to E3 are shown for illustrative purposes (instead of the six measurement units E1 to E6 of the Fig. 1 ) shown.

[0047] A data packet sent by controller E0 is sent to the first measuring unit E1 at time TXFW0 and received by the first measuring unit E1 at time RXFW1 and forwarded to the second measuring unit E2 at time TXFW1, and so on. On the return path, the data packet is sent by the third measuring unit E3 to the second measuring unit E2 at time TXBW3, which receives the data packet at time RXBW2 and forwards it to the first measuring unit E1 at time TXBW2, and so on.

[0048] According to the previously described equation (2), the delay times Δt VZi,i+1 on the path from the measuring unit, which detected the partial discharge pulse at its measuring point, to the controller E 0 are summed. Each delay time Δt VZ i, i+1 describes the time required to transmit the information from measuring unit i to the neighboring measuring unit i+1 (or vice versa, from measuring unit i+1 to the neighboring measuring unit i). The delay time Δt VZ i, i+1 can be determined according to the following equation (3). Δ t VZ i , i + 1 = RXBW i − RXFW i 2 − TXBW i + 1 − TXFW i + 1 2

[0049] The time at which the controller E0 receives the information that the partial discharge pulse has been detected by the respective measuring unit is then corrected based on the time delay Δt calculated by equation (2). That is, the corrected time is calculated based on the difference between the time detected by the controller E0 and the time delay Δt. By taking the respective time delay into account, the times at which the respective partial discharge pulse is detected at the first measuring point (measuring unit E1) and at the sixth measuring point (measuring unit E6), as well as at the fourth measuring point (measuring unit E4) and the fifth measuring point (measuring unit E5) (see Fig. 1 ) can be determined very precisely, which ultimately allows the distance I f of the fault location from the fourth measuring point (measuring unit E 4 ) to be determined with very high accuracy. REFERENCE MARK LIST

[0050] 1 High-voltage cable 2 Connector 3 Measuring cable 4 Cable termination 5 Fiber optic cable 6 Fault location E 0 Unit or control E 1 - E 6 Unit or measuring unit L Length of a section of the high-voltage cable I f Distance between measuring point and fault location RXBWy Receiver in reverse direction ("Receiver Backward") at unit y RXFWy Receiver in forward direction ("Receiver Forward") at unit y TXBWy Transmitter in reverse direction ("Transmitter Backward") at unit y TXFWy Transmitter in forward direction ("Transmitter Forward") at unit y

Claims

1. A method for testing a power transmission network (1), comprising the following steps: detecting an event at a measurement point (E1-E6), transmitting an item of information about the event from the measurement point (E1-E6) to control means (E0), and detecting a time at which the item of information about the event is detected by the control means (E0), determining a time delay which is produced by a transmission of the item of information from the measurement point (E1-E6) to the control means (E0), correcting the time by the time delay, and testing the power transmission network (1) depending on the event and the corrected time, wherein the item of information about the event is transmitted from the measurement point, via at least one further measurement point, to the control means (E0), characterized in that the measurement point, the at least one further measurement point and the control means (E0) are connected to one another via lines (5) via which the item of information is transmitted, and wherein determining the time delay comprises determining a run time of the lines (5) and a processing time of the at least one further measurement point in order to detect and to pass on the item of information at the respective measurement point.

2. The method as claimed in claim 1, characterized in that the measurement point, the at least one further measurement point and the control means (E0) correspond to units which are connected in a daisy chain technique by means of the lines (5), in that the time delay Δt is calculated by the following equation Δ t = ∑ i = 0 x RXBW i − RXFW i 2 − TXBW i + 1 − TXFW i + 1 2 , where RXBWj corresponds to the time at which a specific data packet is received at the j-th unit in a backward direction, where RXFWj corresponds to the time at which the specific data packet is received at the j-th unit in a forward direction, where TXBWj corresponds to the time at which the specific data packet is sent to the j-th unit in the backward direction, where TXFWj corresponds to the time at which the specific data packet is sent to the j-th unit in the forward direction, where x corresponds to the number of the at least one further measurement point, and where the control means (E0) correspond to the 0-th unit and the measurement point corresponds to the 'x+1'-th unit (E1-E6).

3. A method for localizing a fault location (6) in a power transmission cable (1), comprising the following steps: detecting a first time at which a specific partial discharge pulse is detected in the power transmission cable (1) at a first measurement point (E1) which is arranged at one end of the power transmission cable (1), detecting a second time at which the specific partial discharge pulse is detected in the power transmission cable (1) at a second measurement point (E6) which is arranged at the other end of the power transmission cable (1), determining a fault location (6) along the power transmission cable (1), at which the specific partial discharge pulse was generated, depending on the first and the second time, determining a third and a fourth measurement point from a quantity of measurement points (E1-E6), which are arranged in the power transmission cable, in such a way that the third and the fourth measurement point delimit a section of the power transmission cable (1) in which the fault location (6) is situated and no further measurement points are located, detecting a third time at which a further specific partial discharge pulse is detected in the power transmission cable (1) at the third measurement point, detecting a fourth time at which the further specific partial discharge pulse is detected at the fourth measurement point, and correcting the determined fault location (6) depending on the third and the fourth time, wherein the first time, the second time, the third time and the fourth time each correspond to a corresponding time at which an item of information about the corresponding partial discharge pulse is detected by control means (E0), and wherein the method additionally comprises: determining a respective time delay which is produced by a transmission of the respective item of information from the corresponding measurement point (E1-E6) to the control means (E0), and correcting the respective time by the corresponding time delay, wherein the time delay is determined according to the method as claimed in one of the preceding claims.

4. The method as claimed in claim 3, characterized in that the fault location (6) is determined as a distance If from the third measurement point using the following equation l f = v PD 2 t 3 − t 4 + l 2 , where t3 corresponds to the third time, t4 corresponds to the fourth time, vPD corresponds to the propagation speed of the partial discharge pulse on the power transmission cable (1) and I corresponds to the length of the section.

5. The method as claimed in claim 3 or 4, characterized in that the further specific partial discharge pulse corresponds to the specific partial discharge pulse, so that in each case the same partial discharge pulse is detected at the respective measurement point at the first, second, third and fourth time.

6. A system for testing a power transmission network (1), wherein the system comprises control means (E0) and a plurality of measurement units (E1-E6), wherein each measurement unit (E1-E6), which is connected to a respective measurement point (2; 4) in the power transmission network (1), is configured in order to detect an event at the respective measurement point (2; 4) and in order to transmit an item of information about the event to the control means (E0), wherein the control means (E0) are configured in order to detect a time at which the item of information about the event is detected by the control means (E0), wherein the system is configured in order to determine a time delay which is produced by a transmission of the item of information from the measurement unit, which detects the event, to the control means (E0), and wherein the control means (E0) are configured in order to correct the time by the time delay and in order to test the power transmission network (1) depending on the event and the corrected time, wherein the item of information about the event is transmitted from the measurement point, via at least one further measurement point, to the control means (E0), characterized in that the measurement point, the at least one further measurement point and the control means (E0) are connected to one another via lines (5) via which the item of information is transmitted, and the system is configured such that determining the time delay comprises determining a run time of the lines (5) and a processing time of the at least one further measurement point in order to detect and to pass on the item of information at the respective measurement point.

7. The system as claimed in claim 6, characterized in that the system is configured for carrying out the method as claimed in one of claims 1-2.

8. A system for localizing a fault location (6) in a power transmission cable (1), wherein the system comprises control means (E0) and a plurality of measurement units (E1-E6), wherein a first of the measurement units (E1) is connected to a first measurement point (4) at one end of the power transmission cable (1) and a second of the measurement units (E6) is connected to a second measurement point (4) at the other end of the power transmission cable (1), wherein the measurement units (E1-E6) are configured in order to detect in each case one partial discharge pulse at that measurement point (2; 4) which is connected to the respective measurement unit in the power transmission cable (1), wherein the system is configured in order to detect a first time at which the specific partial discharge pulse is detected at the first measurement point (4) by the first measurement unit (E1) by means of the first measurement unit (E1), in order to detect a second time at which the specific partial discharge pulse is detected at the second measurement point (4) by the second measurement unit (E6) by means of the second measurement unit (E6), in order to determine a fault location (6) along the power transmission cable (1), at which fault location the specific partial discharge pulse was produced, by means of the control means (E0) depending on the first and the second time, in order to determine a third measurement point and a fourth measurement point, by means of the control means (E0), in such a way that the third and the fourth measurement point delimit a section of the power transmission cable (1) in which the fault location (6) is situated and no further measurement point (2) which can be connected to one of the measurement units (E1-E6) is located, in order to detect a third time at which a further specific partial discharge pulse is detected at the third measurement point by the third measurement unit by means of a third of the measurement units which is connected to the third measurement point, in order to detect a fourth time at which the further specific partial discharge pulse is detected at the fourth measurement point by the fourth measurement unit by means of a fourth of the measurement units which is connected to the fourth measurement point, and in order to correct the determined fault location (6) by means of the control means (E0) depending on the third and the fourth time, wherein the first time, the second time, the third time and the fourth time each correspond to a corresponding time at which an item of information about the corresponding partial discharge pulse is detected by control means (E0), and wherein the system is additionally configured in order to determine a respective time delay which is produced by a transmission of the respective item of information from the corresponding measurement point (E1-E6) to the control means (E0), and in order to correct the respective time by the corresponding time delay, wherein the time delay is determined with the system as claimed in one of the preceding claims, which is combined with the system for localizing a fault location.

9. The system as claimed in claim 8, characterized in that the system is configured for carrying out the method as claimed in one of claims 3-5.