60.05 59.95 59.9 59.85 59.8 59.9 59.85 59.8 59.75 59.75 59.7 59.7 59.65 0 10 20 30 40 Time 50 60 figure 8. VRE with and without synthetic inertia controls. system frequency response using wind synthetic inertia control and/or primary frequency response control. This shows that using these controls can contribute to a faster-acting, more stable system. Solar PV systems need to be leveraged in conjunction with storage or be derated from their maximum available power to provide synthetic inertia response for underfrequency events. An example of solar power providing primary frequency response (droop response) is shown in Figure 10. This response was measured on a real 20-MW PV plant when the plant was operating with 3 and 5% droop setting with a 12-mHz deadband. The scatter around ideal expected response (solid plots) is due to the irradiance variability. The plant droop is determined in the same way as that for conventional generators: Droop = 0 10 20 70 TP Prated . Tf 60 Hz The upper limit of the droop curve was the available plant power, and the lower limit was at a level that was 20% below the then-available peak power. Another example of a PV plant participating in AGC is shown in Figure 11. These data were measured on a 300-MW PV plant that was curtailed to 30 MW lower than its available maximum power. The plant adjusted its active power output following the AGC commands sent by the system operator. This figure shows that the PV plant could easily follow the AGC signals as commanded. Many utility-scale PV power plants are already capable of receiving curtailment signals from grid operators; although each plant is different, it is expected that the transition to operation with ancillary service provision will be relatively simple with modifications made only to a plant's controller and interface software. 30 40 Time 50 60 70 figure 9. VRE with and without both synthetic inertia and primary frequency response. tection systems and coordination. Synchronous generators produce approximately six times rated current during a fault (Figure 12). This large amount of fault current is often used as a signature for certain types of faults and is the basis for timeovercurrent relay protection. A protective relay can sense the large amount of fault current and trip a circuit breaker to protect grid components. Inverter-based power sources do not have the same fault characteristics as synchronous generators. They can typically provide only a small amount above rated output current. In inverter-dominated systems, this may cause the protective relays to lose the ability to sense the fault conditions because the available fault current is drastically reduced. On the other hand, inverters can react extremely quickly to grid disturbances and may be able to disconnect from the grid, thereby not causing thermal overload on grid components. One unique characteristic of inverters is that their fault current can actually be programmed. They can sense a fault extremely quickly and stop producing current within one-fourth of a cycle, or they can 1 3% Droop Change in Power (MW) 59.65 Without Control With Control 60 Frequency 59.95 Frequency 60.05 Without Control With Control 60 0.5 5% Droop ±12.5-MHz Frequency Deadband 0 -0.5 -1 -0.2 -0.1 0 0.1 Change in Frequency (Hz) 0.2 Power System Protection Additional challenges with the removal of a significant number of synchronous generators from the grid are promarch/april 2017 figure 10. A PV plant providing primary frequency response (3% and 5% droop). ieee power & energy magazine 71