With numerical protection relays commissioning and maintenance has become far less complicated as a result of the information provided by the devices as well as the integrated self-monitoring.
The information provided here is restricted to general notes regarding the procedures. Specific instructions for the individual devices are provided in the device manuals.
- Commissioning of protection relays
- Maintenance of protection relays
Pre-testing of the instrument transformers and their connections must be carried out in the same manner as with conventional protection. The measuring functions of the protection devices may already be utilised for this purpose.
The binary device outputs can be activated individually by means of the Siemens software DIGSI. This largely simplifies the pre-testing of the signalling and tripping circuits, as the internal protection functions do not have to be activated for this purpose. The testing of serial interfaces which are new to the numerical devices can also be carried out in this manner.
Settings are usually applied with the setting program in the office of the protection department, off-line (without protection device) and saved onto a mass storage. In the substation the settings must then only be transferred by PC (Laptop) from the mass storage to the protection device.
To test the protection function with injected signals (current and voltage) PC controlled electronic test equipment is available nowadays which provides almost fully automated test sequences. A three-phase test equipment is recommended as the modern devices monitor symmetry of the three-phase system which may pick up when single-phase tests are carried out.
Primary injection testing is only seldom applied due to cost constraints. With the feeder differential protection, testing is somewhat more complicated as the currents must be injected at geographically separated locations.
In the past, single ended injection was therefore applied for pre-testing by phase synchronous connection of the secondary injection equipment to voltage transformers of an unused feeder in both substations. The test sequence was then simultaneously initiated at both ends when the feeder was energised.
With the electronic test equipment this difficulty no longer exists as the test equipment at both line ends can be synchronised via GPS signals.
The final test, whenever possible, is done with load current or a deliberately created short circuit current. The integrated overcurrent protection in the differential protection and the separate back-up protection, if available, are set to trip without delay for this test, so that the feeder is immediately cleared if a short-circuit is present.
For this purpose, the generator is started with a deliberate short-circuit while the system CB is open. The excitation of the generator is then increased. The generator current increases but may not exceed nominal current. In this way stability and tripping of the differential protection can be checked as close to reality as possible.
A similar test with short circuit cycle could also be done on a transformer feeder and busbar protection, if a system connection to an available generator can be established.
Generally, testing can however only be done with load current. To get a definite indication of the current values and therefore the connection and polarity of the CT circuits, a test current of at least 10% of the nominal device current should be obtained by means of appropriate system switching.
To measure the feeder currents as well as the operating/restraint currents, a large number of measuring instruments had to be connected with conventional protection (12 for a transformer differential protection).
When load current is flowing through the system, the operating current (tripping current) should apart from charging currents, be negligibly small and the restraint current should correspond to the sum total of all feeder currents. By reversing the polarity of one current measuring input by means of the corresponding setting parameter, an internal fault can be simulated. Restraint and operating current should in this case have approximately the same magnitude.
An oscillographic record can also be initiated via DIGSI and can then be viewed using SIGRA to calculate the phasors of the current for graphic representation.
In this manner, an error in the current comparison can immediately be detected.
SIPROTEC 4 devices provide for a web monitor (web browser). Thereby the phasor diagrams can be called up and visualised online using a common internet browser tool. See Figure 1 below.
The new SIPROTEC 5 line relays 7SD8 and 7SL8 now allow also DIGSI to communicate not only with the local relay but also with the relay at the remote line end(s) through the communication link of the differential protection.
Following the function tests, the final settings should be applied and tripping of the CB must be tested by simulation of an internal fault. The final settings of the protection for documentation and archiving are extracted locally or from remote via PC.
DIGSI 5 is the SIEMENS engineering tool for parameterization, commissioning and operating all SIPROTEC 5 protection relays. The full capabilities of DIGSI 5 are revealed when you connect it to a network of protection devices. Then you can work with all of the devices in a substation in one project.
Part 1 of 11: Introduction
Part 2 of 11: Creation of a project, adding a device
Part 3 of 11: Device information
Part 4 of 11: Communication and hardware modification
Part 5 of 11: Routing of information in the matrix
Part 6 of 11: Device settings
Part 7 of 11: Display editor
Part 8 of 11: The logic editor
Part 9 of 11: Creating of a OHL (over headline feeder)
Part 10 of 11: Adding the transformer infeed configuration
Part 11 of 11: Adding of a transformer feeder
The self-monitoring contained in the numerical devices covers 80-90% of the protection equipment. CT circuits are included as long as load current is flowing and the signal communication is also continuously monitored to detect errors. The numerical protection therefore only has to be maintained with fairly long maintenance cycles.
At present intervals of between 5 and 6 years are however common and the tendency is towards even larger time intervals. In the periods between the tests plausibility checks with the indicated load values and the stored fault record data are however recommended.
Reference // Numerical Differential Protection by Gerhard Ziegler (Purchase hardcover from Amazon)