Normally, all generators within an interconnected power system operate at like frequency with their magnetic poles coupled through interaction with the network. The interconnecting force is elastic, allowing some angular play between generators in response to system disturbances. A loss of synchronism occurs when the bonding force is insufficient to hold a generator or group of generators in step with the rest of the power system. This can occur when equipment outages or low voltage weaken the system or if the force is inadequate to restrain extreme rotor excursions following a system fault or switching.
Once synchronism is lost, the affected generator or generators operate at slightly different frequencies.
The difference in frequencies is termed the slip frequency. A generator that pulls out of step ahead of the system with a slip frequency of 4 Hz will be operating at a speed of 1+ slip/60 = 1.067 pu. or 6.7% over speed.
The effects of a loss of synchronism can be visualized using the case of a single generator out of step with the system. The system and generator voltage vectors sweep past one another at slip frequency, producing a pulsating current with peak magnitude potentially greater than a three phase fault at the generator terminals. An out-of-step generator must be rapidly isolated from the power system to prevent damage to the generator, turbine and GSU transformer. The isolation of any asynchronous portion of the system is also required to facilitate system restoration, because synchronism cannot be restored without operator intervention.
There are several schemes available for out-of-step protection. Most detect a loss of synchronism by measuring variations in system impedance. Settings applied to these schemes are critical to system reliability. The schemes must be set to quickly isolate an asynchronous machine, not only to prevent damage, but also to prevent instability from spreading to other portions of the system. Yet, setting must be secure against misoperations. The loss of generating capacity during a disturbance can precipitate a major outage.
Distance relays applied at the generator as system backup protection will detect a swing if the swing impedance passes through the trip characteristic. The relay time delay and the speed at which the apparent system impedance crosses the relay characteristic will determine if tripping is initiated.
Normally, the delay required for coordination with network relaying will prevent these schemes from operating during out-of-step events.
Over the years, specialized detection schemes have been developed. Early out-of-step protection schemes counted the current pulsation each time a generator pole slipped (passed through 180˚ separation with system voltage). Tripping was initiated after a preset number of counts. Now it is recognized that the system impedance viewed from the generator terminals provides a method for the rapid detection of a loss of synchronism. Consequently, out-of-step detection schemes employ impedance-sensing elements and specialized logic to distinguish between a fault condition and a loss of synchronism. In order to apply this type of protection, it is necessary to understand how system impedance varies during a loss of synchronism.
Out-of-step protection must be set to initiate tripping only when a loss of stability is imminent. Following a system disturbance, generator rotors experience angular perturbations as they attempt to adjust a new steady-state operating condition. In a stable system, rotor oscillations are damped. The initial angular displacement is the largest, with each subsequent rotor swing diminished in magnitude until a new steady-state rotor angle is found. As the severity of the disturbance increases, so does the initial angular displacement. There exists a maximum swing angle from which the system cannot recover.
Some out-of-step schemes are designed to operate only after synchronism is lost. Other schemes attempt to actuate before the first pole slip (before 180˚ separation) at the maximum stable swing angle. In the latter case, settings are difficult to derive. The critical angle and resulting impedance trajectories are not fixed and vary dramatically with system conditions and fault location.
The best way to determine the critical swing angle is to model the system using a transient stability program. The system representation must include system loads, all generators, their voltage regulators and governor controls in a large area surrounding the machines in question. The system would then be tested by applying faults at critical points using maximum anticipated clearing times. These faults would be applied at various load levels, system configurations and generation mix to determine the most severe survivable swing for the unit in question. The impedance loci generated from these test cases would then be used to set the out-of-step relay. Unfortunately, transient stability modeling tools and the time to use them are not available to all and a less accurate method is often adopted.
In the absence of transient stability data, a general assumption is made that a displacement beyond 120˚ is not recoverable and instability is imminent. Consequently, out-of-step protection is often set to initiate tripping when the impedance loci exceed this value. The graphical construction of the swing loci is then used to determine the location 120˚ and 240˚ on the R–X plane. Both are required because a swing may traverse the relay characteristic in either direction. The minimum system impedance should be used in this calculation, because this will produce the minimum swing diameter. The settings derived should be adequate to accommodate a voltage ratio range n of 0.65 to 1.5. This to cover the decay of internal voltage for machines under manual regulator control and voltage increase for machines under automatic regulator control.
Another factor, which must be considered in any setting derivation, is the variation of generator impedance with slip. Generator impedance, along with the system and GSU (Generator Step Up ) transformer reactance, determines the swing trajectory. At zero slip, the equivalent generator impedance would be Xd.
At 100% slip Xg = X"d . Studies have shown that the slip for a typical loss of synchronism case is between 50% and 0.33%. This corresponds to a generator impedance variation of from Xd to 2X'd . The X'd value is typically used to construct the swing loci because lower impedances produce a smaller swing diameter. Setting must allow sufficient margin to capture loci resulting from slower swings with effective generator impedance near 2X'd.