## 8 Sequence of Actions after an Abrupt and Unexpected EPS Disconnection  
Abrupt, non-planned EPS desynchronization from a synchronous area is relatively rare, and requires proper situation handling. A small, desynchronized, isolated power system is much more prone to suffer stability issues or even blackout. Mitigation of the risks related to the desynchronization of EPSs could be accomplished two ways: by proper preconceived analysis and planning and by proper real-time control. The primary task for the EPS operator during such events is to ensure stable EPS operation and prevent damage to its equipment, putting power-quality and efficiency-optimization requirements in the background. A clear plan of action and clarity on the aspects which must be considered in such situations could be the key to successful situation management. The sequence of actions presented below will help to quickly and properly control the EPS after an unexpected and rapid reorientation from normal work mode to island mode. The sequence of actions is:  
1. Assess the situation and the state of EPS;
2. Is power flow between different (neighboring) EPS equal to 0 MW? 3. Are all inter-system lines switched off? 4. Is sharing of SCADA data between different (neighboring) EPS disabled? 5. Are frequency deviations greater than \(\pm\)0.2 Hz in the isolated part of the EPS? 6. Are sudden and significant deviations of the voltage level observed? 7. Are effects of UFLS on disconnected/isolated EPS noticed? 8. Is the EPS in a stable islanding mode after a sudden disconnection/isolation? (Yes/No);
9. Maintain the currently active power flow through the HVDC. The flow cannot be changed even if the results of the intraday electricity exchange are different. Figure 17: Isolated EPS synchronization with synchronous area. * 9.1. Set the intraday trading capacity for all EPS internal and external inter-system lines to 0 MW;
* 9.2. Deactivate (if enabled) the FC function on the HVDC converter side of the neighboring EPS;
* 9.3. Deactivate (if enabled) the aFRR function on the HVDC converter side of the neighboring EPS;
* 10. Assess/calculate the available primary active power reserve;
* 11. Bring into operation the power plants that can provide sufficient primary active power reserve (must not exceed 300 MW);
* 12. Check the active power regulation FCR and aFRR for the power plants and/or enable the active power regulation;
* 13. Check whether criterion n-1 is met in the EPS (Yes/No);
* 13.1. Switch on the 330 kV lines undergoing repair work and the reserve lines;
* 14. Check whether the maximum generation source exceeds the specified value of 300 MW (also HVDC) (Yes/No);
* 14.1. In existing power plants, increase active power generation up to the technical maximum (must not exceed 300 MW) by an amount that is compensated to reduce the source of generation;
* 14.2. Switch on the generators of the power plants (must not exceed 300 MW) at the correct level to compensate for the reduction in the generation source;
* 14.3. Reduce the capacity of the generation source up to 300 MW, if it exceeds this value;
* 15. Check whether the inertia of the EPS is sufficient (Yes/No);
* 15.1. Switch on power generators or synchronous compensators to increase inertia;
* 16. Check whether the voltage in the EPS is within the permissible limits (Yes/No);
* 16.1. Switch on shunt reactors to control the voltage;
* 16.2. Switch on the synchronous compensators of the power plants;
* 17. Maintain the frequency of the EPS higher than the critical value of 49.20 Hz;
* 18. Redistribute active power flows;
* 18.1. Arrange for the operation of HVDC interconnectors, with the active power flow to be redirected to the isolated EPS (must not exceed 300 MW);
* 19. Enable FC in HVDC interconnection;
* 20. Activate active power reserves from the cold reserve with a start-up time of about 12 h;
* 21. Increase active power generation to the technical maximum (must not exceed 300 MW) in the operating power plants;
* 22.