Fault Ride-Through

The voltage vs. time profile that defines mandatory continuous operation. Grid codes specify a minimum voltage magnitude (often down to 0.0 pu for a defined duration) and a recovery slope. For example, a generator must remain connected for 150 ms at zero voltage during a close-up three-phase fault, then linearly recover to nominal voltage. This prevents cascading disconnections during transient faults cleared by protection systems.

During a voltage sag, the inverter must prioritize dynamic reactive power support to help restore local voltage. Modern grid codes mandate a proportional reactive current injection—typically 2% of rated current for every 1% of voltage deviation from nominal. This fast-acting capacitive boost, often with a response time under 20 ms, provides critical voltage stabilization before slower mechanical devices like tap changers can react.

After fault clearance, the generator must not abruptly surge active power, which could destabilize the recovering grid. The FRT specification defines a controlled active power restoration ramp rate, typically returning to pre-fault output within 1 second. This gradient is crucial for grid-forming inverters in microgrids, where a sudden power spike could trigger a secondary frequency dip or overvoltage condition on a weak feeder.

The Phase-Locked Loop (PLL) is the digital sensor that tracks grid voltage angle. During asymmetrical faults, negative-sequence components can cause PLL instability, leading to erroneous synchronization and tripping. Advanced FRT algorithms employ dual second-order generalized integrators (DSOGI) or moving average filters to extract the positive sequence voltage rapidly, ensuring the inverter maintains synchronism even under severe unbalanced fault conditions.

During unbalanced faults, injecting only positive sequence current can cause excessive voltage rise on non-faulted phases. Sophisticated FRT strategies actively manage negative sequence current injection to balance phase voltages. By controlling the ratio of positive to negative sequence reactive current, the inverter can mitigate voltage swell on healthy phases while still supporting the sagged phase, preventing overvoltage tripping of adjacent equipment.

FRT requirements must be carefully coordinated with anti-islanding detection. A generator must ride through a transmission fault but must still detect and disconnect for an unintentional island within 2 seconds of formation. The FRT logic uses a dead-band timer: if voltage remains outside nominal bounds beyond the ride-through envelope's maximum duration, the system transitions from FRT mode to a definitive trip, ensuring safety without nuisance disconnections.

The specific capability of a generator to remain connected during voltage sags—typically down to 0% of nominal voltage—for a defined duration. LVRT curves specify the exact voltage-vs-time profile that equipment must withstand without tripping. This prevents a cascading loss of generation during transmission faults. Key parameters include:

• Zero-voltage ride-through: Surviving a complete voltage collapse for 150-500ms
• Recovery ramp: The rate at which voltage must return to normal
• Reactive current injection: Providing dynamic reactive power support during the sag to help restore system voltage

The ability of an inverter or generator to tolerate sustained overvoltage conditions—typically up to 120-130% of nominal—without disconnecting. HVRT is increasingly critical in grids with high solar PV penetration, where sudden load rejection or capacitor bank switching can cause voltage swells. Requirements include:

• Continuous operation at 110% voltage for extended periods
• Defined withstand times at higher overvoltage thresholds
• Active power curtailment to help reduce voltage during swell events

The mandatory technical regulations that define fault ride-through requirements for generators connecting to a transmission or distribution network. Grid codes specify:

• Voltage-against-time profiles for fault survival
• Reactive current injection magnitude and response speed
• Frequency ride-through limits during under/over-frequency events
• Rate of change of frequency (RoCoF) withstand capability Key standards include IEEE 1547-2018 for distributed resources and ENTSO-E Network Code for European transmission-connected generation.

A hardware circuit used in doubly-fed induction generators (DFIGs) to protect the rotor-side converter during grid faults. When a voltage dip occurs, the crowbar short-circuits the rotor windings through external resistors, absorbing the surge current and preventing converter damage. The crowbar activation:

• Momentarily converts the DFIG into a squirrel-cage induction machine
• Absorbs reactive power from the grid during the fault
• Must deactivate rapidly after fault clearance to restore converter control Modern designs use active crowbars with IGBT switches for faster response.

A control mode where an inverter prioritizes reactive current injection over active power export during a voltage disturbance. When terminal voltage deviates from nominal, the inverter rapidly injects leading or lagging reactive power to support grid voltage recovery. Key characteristics:

• Response time typically under 40ms per grid code requirements
• Dynamic reactive current proportional to voltage deviation magnitude
• Active power reduction to stay within inverter current limits
• Essential for weak grid stability where voltage support is critical

The critical control mechanism that enables an inverter to synchronize with grid voltage angle during and after faults. A PLL tracks the fundamental frequency component even when voltage waveforms are distorted by harmonics or unbalanced faults. Advanced PLL designs include:

• Dual second-order generalized integrator (DSOGI-PLL) for unbalanced conditions
• Low-bandwidth filtering to reject harmonic distortion
• Fast phase-angle tracking to maintain synchronism through fault transitions PLL instability during fault recovery is a leading cause of inverter tripping despite adequate voltage support.