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Generator Restoration Following a Protection Operation

Steven Turner's picture
Senior Engineer, APS

Steve Turner Arizona Public Service - Generation - System Protection Formerly: Private consultant (2 years) Beckwith Electric (15 years) Duke Energy (5 years) SEL Inc. (5 years) GEC (5 years)...

  • Member since 2021
  • 5 items added with 417 views
  • Jun 23, 2022


The goal of a generating entity is to safely provide generation that maximizes reliability, capacity, and flexibility. Typically, this could be a utility or independent power producer. Loss of a generator can have an adverse impact on the adjacent grid and customers, especially during periods of heavy loads such as the summer months. It is vital to determine the root cause of the event when a generator is tripped offline due to a protective relay operation. The goal is to quickly restore service if there is no damage to the generator or any of the interconnected apparatus. Of course, safety is always the number one priority. This article explores one such recent event, covering the technical analysis in detail.



A large steam turbine generator tripped on 87 phase differential protection while attempting to synch the machine to the grid, however only the main generator protection relay operated and not the backup protection. The goal of the analysis is to determine why only one relay operated and what caused the trip to occur.

FIGURE 1.  Power System Configuration

Figure 1 above shows the system configuration to sync the generator to the grid. The generator is brought online to full speed then ideally the generator breaker is closed when the generator is in sync with the grid. The main generator protection tripped on 87 phase differential when the generator breaker closed but not the backup protection.

Table 1 below shows the sequence of event report (i.e., SER) captured by the main relay for this event.


EVENT #22 05-21-2022 22:11:07.136

|IA| = 1.24 A     |Ia| = 1.13 A     Ia DIFF = 0.26 A

|IB| = 0.98 A     |Ib| = 0.98 A     Ib DIFF = 0.00

|IC| = 1.96 A     |Ic| = 1.19 A     Ic DIFF = 0.96 A

EVENT #26 05-21-2022 22:11:07.161

|IA| = 2.62 A     |Ia| = 3.24 A     Ia DIFF = 1.29 A

|IB| = 3.19 A     |Ib| = 3.17 A     Ib DIFF = 0.02 A

|IC| = 2.62 A     |Ic| = 3.25 A     Ic DIFF = 1.68 A

EVENT #27 05-21-2022 2211:07.199

|IA| = 3.74 A     |Ia| = 4.72 A     Ia DIFF = 2.00 A

|IB| = 0.99 A     |Ib| = 0.99 A     Ib DIFF = 0.00

|IC| = 3.32 A     |Ic| = 4.15 A     Ic DIFF = 1.71 A

EVENT #28 05-21-2022 22:11:07.207

|IA| = 3.15 A     |Ia| = 4.75 A     Ia DIFF = 2.00 A

|IB| = 0.04 A     |Ib| = 0.04 A     Ib DIFF = 0.00

|IC| = 2.70 A     |Ic| = 4.41 A     Ic DIFF = 4.41 A

TABLE 1.  Sequence of Events Report

Review of the SER reveals that the total time of the event following the generator breaker closing and then tripping was approximately 4 cycles, which corresponds to one cycle for the main protection to assert the trip contact output and 3 cycles for the generator breaker to open. Review of the SER also reveals that the 87 phase differential protection repeatedly picked up and dropped out over the course of the event. Note that the trip output contact asserts the first time the protection operated since there is no intentional time delay.

Figure 2 below shows the oscillography captured by a digital fault recorder (that is, DFR) for the event. The currents shown (Ia gen, Ib gen and Ic gen) are measured on the neutral side of the generator stator winding, which corresponds to the current flowing through the generator. Note that these signals are unfiltered and reveals the large dc offset that was present in these currents. The generator currents were fully offset during the entire event.

FIGURE 2.  Generator Currents

At first glance the event appears to be an A-Phase-to-C-Phase fault, however the generator terminal voltages are balanced and nominal magnitude.

Figure 3 below shows the filtered currents flowing through the generator; that is, the 60 Hz fundamental component for each of the phase current waveforms. Review of these waveforms reveal that the current magnitude is close to nominal and the currents are all balanced approximately 120 degrees apart. Thus, there was no phase fault present during the event.

FIGURE 3.  Filtered Generator Phase Currents

Figure 4 below shows the corresponding 87 phase differential operating characteristics for both the main generator (red point) and backup protection (green point). The operating point for the main protection is well within the zone of operation, while for the backup protection it is outside.

FIGURE 4.  87 Phase Differential Operating Characteristics, Main and Backup


The root cause of the unwanted trip was due to a bad sync; that is, the electrical angle across the generator breaker was close to 60 degrees at the time of the closing because of improper timing. 180 degrees is the worst case electrically, while 90 degrees is the worst case mechanically. Improper synchronization can affect the health of the power system and results in electrical and mechanical transients that can damage the prime mover, generator, transformers, and other power system components.

The bad sync was the source of large dc offset present in the generator currents. It is suspected that as a result the internal relay CTs saturated, which accounts for why the main 87 phase differential protection picked up and dropped out four times during the event.



A large steam turbine generator tripped on 87 phase differential protection while attempting to synch the machine to the grid, however only the main generator protection relay operated and not the backup protection. The root cause of the unwanted trip was due to a bad sync. Review of the 87 phase differential characteristics illustrate that the main protection is more sensitive than the backup protection with respect to the operating point for this event. There is no need to change relay settings and the trip alerted the utility that there was a problem with the sync.


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Steven Turner's picture
Thank Steven for the Post!
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