Abnormal States in Power Systems and Criteria for Their Recognition - Digital Signal Processing in Power System Protection and Control - page 9

• dependability: the assurance that the protection device will perform its function
and selectively trip the protected item of a primary plant in the event of a fault,
• security: the assurance that the protection device will not trip unless there is a
fault on the protected item,
• availability: the ratio of the time that a protection device is actually serviceable
to the total time it is in operation.
Sensitivity—ability to react even to relatively small deviations of the monitored
variables due to a disturbance in the system.
Operating speed—ability to isolate the faulted element within shortest possible
period of time. The protection trip time is the time between fault inception and trip
command. One should understand that the total fault clearing (TFC) time is a sum of
the protection reaction time and circuit-breaker operating time (including arc
extinguishing). The TFC time amounts: 60-100 ms in EHV/HV networks, up to
200 ms in 110 kV networks, and 0.1-1.0 s in MV networks. With modern protection
devices the operating time is typically one period of the power system frequency.
Most of the commonly applied protective relays perform their job in the
''traditional way'' (relay's modus operandi) that can be summarized as follows:
• collecting the local information (currents, voltages, etc.),
• extracting (measurement) certain features such as magnitude, phase difference,
impedance, etc.
• comparing the measured criteria values with the operating characteristics or
thresholds,
• applying certain delays,
• issuing trip command.
The above algorithm (even though realized in digital technology) reproduces
the well known protection principles and cannot by-pass certain constraints of
those principles. Even though the digital protection devices are better and better,
offering fast and accurate signal processing algorithms, possibilities of almost free
shaping and setting of decision characteristics, as well as number of additional
auxiliary functions, there are situations and plants where classical approach and
methods may not guarantee proper relay operation. A number of difficulties can
still be faced, among which the following seem to be the most significant:
• Limited recognition abilities of the known protection principles, e.g.:
- impedance is not a perfect measure of the distance to a fault on a transmission
line since the same impedance value may be seen by the relay for both
internal and external faults—consequences: faults close to the line remote
terminals (in front of and behind) are difficult to distinguish, thus only
80-90% of the line length is efficiently protected,
- 2nd harmonic ratio is not a perfect indicator of the magnetizing inrush in a
transformer since the 2nd harmonic may occur during internal faults as well—
consequences: either false tripping or delayed operation may occur depending
on the threshold;