Ride-through LVRT / HVRT

What it is (precise)

When a fault strikes the transmission or distribution network, voltage at the BESS terminals can momentarily collapse (a sag) or, once the fault clears or load sheds, briefly rise above nominal (a swell). Ride-through defines a no-trip envelope in per-unit voltage versus time.

The abbreviations travel under aliases: LVRT is also written UVRT (under-voltage ride-through) and, in European codes, FRT (fault ride-through); HVRT likewise appears as OVRT (over-voltage ride-through). A typical LVRT curve requires surviving near-zero voltage for roughly 150 ms (a normally cleared transmission fault), then a staged recovery plateau around 0.5 to 0.9 pu lasting from hundreds of milliseconds to several seconds.

HVRT curves mirror this above nominal, commonly near 1.2 pu for a second or less, with the continuous ceiling near 1.05–1.1 pu depending on whether the plant sits under IEEE 2800 (~1.05) or IEEE 1547 (~1.10). The swells HVRT guards against come from load rejection after a fault clears, single-phase faults raising the healthy phases, and capacitor-bank or line switching.

They stress the hardware differently from a sag: the DC link needs voltage headroom above the elevated AC peak or the inverter loses current control, sustained overvoltage eats into surge-arrester TOV margin, and the inverter absorbs reactive power to pull the voltage down rather than injecting it. Outside the envelope the plant is permitted to disconnect — and under IEEE 1547's shall-trip regions on distribution, required to.

Ride-through is a PCS-and-controls behavior, not a battery-cell property: the DC side just needs voltage headroom and the contactors must stay closed, so the requirement is met by inverter firmware and the plant controller, whether the plant runs Grid-following or Grid-forming control.

Modern codes pair LVRT and HVRT with dynamic support: during a sag the inverters prioritize injecting reactive current (a capacitive boost drawing on the machine's P-Q capability) to prop up voltage, and during a swell they absorb it. Reference point matters: codes define the envelope at the Point of Interconnection, but the inverter measures at its own terminals behind the Transformer impedance, so the two voltages differ throughout the event.

Why it matters in a real grid-scale project

Ride-through is a mandatory Interconnection requirement, not an optional feature. The interconnection agreement and grid code make it a condition of energization, and the plant must prove compliance through model validation (in the US increasingly via IEEE 2800-2022 and the IEEE 2800.2 conformity-assessment recommended practice) and often a field or hardware-in-the-loop test before the utility grants permission to operate.

Fail it and you block the commercial operation date and the revenue behind it, because retrofitting inverter firmware or protection settings after energization is slow, negotiated work that can reopen the whole study.

Regulators care because the failure mode is systemic: if many inverter-based resources trip on one remote fault, the network loses gigawatts at the worst moment and the disturbance can cascade. The 2016 South Australia blackout and the 2016/2017 California events (the Blue Cut and Canyon 2 fires, where roughly 1,200 MW and 900 MW of solar dropped through inverter tripping and momentary cessation) drove much of the tightening in today's standards.

For the owner the stakes are commercial too: nuisance trips on recoverable sags mean lost dispatch, missed ancillary-service obligations tied to Frequency response, and penalties or curtailment from the system operator for persistent non-compliance.

Typical values and standards

In the United States the governing documents are IEEE 1547-2018 for distribution-connected systems and IEEE 2800-2022 for transmission-connected plants, with NERC PRC-024 barring protection settings that would trip bulk-system generation inside its voltage and frequency boundaries (a settings standard, not a performance one) — though for inverter-based resources PRC-024 is being superseded by PRC-029, the ride-through standard NERC wrote for IBRs under FERC Order 901, so check which one the interconnection agreement actually cites.

IEEE 2800 notably restricts momentary cessation (the inverter briefly ceasing current injection while staying connected), the behavior that made the California solar-loss events so large. In Europe the framework is the ENTSO-E RfG network code (Regulation 2016/631) as implemented nationally, for example Germany's VDE-AR-N 4110 for medium voltage and 4120 for high voltage. Project-specific deviations live in the interconnection facility study, which governs over the generic curve.

Representative envelope values for utility-scale plants: ride through roughly 0 to 0.05 pu retained voltage for about 150 ms, a recovery ramp or plateau back to near 0.9 pu within roughly 1.5 to 3 seconds, HVRT tolerance near 1.2 pu for around 1 second or less, and continuous operation typically between about 0.9 and 1.1 pu. Many codes also require riding through multiple successive faults (auto-reclose sequences), which stresses control recovery, not just survival of one dip. Frequency ride-through is specified in the same documents, typically covering excursions of a few Hz around nominal.

Dynamic reactive-current injection usually begins once voltage deviates more than about 5 to 10 percent from nominal, with a proportional gain (the k-factor, commonly set around 2 and adjustable from 0 up to roughly 10 in European practice) and a required response within a few tens of milliseconds.

In a deep sag the inverter hits its current limit, briefly around 1.1 to 1.2 times rated current (some units ~1.5× for a few cycles), so reactive current is prioritized and real power is cut back; this current saturation is a defining constraint for Grid-forming controls. Always read the exact curve, gain and priority rules from the applicable code; these ranges only orient the design.

How it shows up in specs, studies and contracts

On a PCS datasheet, find the LVRT/HVRT curve itself (voltage versus time), the reactive-current gain and its settable range, the fault-current contribution (a multiple of rated current), momentary-cessation behavior, and the certification basis: UL 1741 with the SB supplement demonstrates IEEE 1547-2018 conformance, while European units carry unit certificates to FGW TR3 test procedures under national RfG rules.

A curve on a brochure is not compliance. The question to put to a vendor is direct: send the type-test report and the exact parameter set loaded in firmware, and confirm the k-factor and current-priority values match what the study will freeze.

In interconnection studies, ride-through is where model quality gets exposed. Transmission providers in inverter-heavy regions increasingly demand EMT (electromagnetic-transient) models, usually in PSCAD, alongside positive-sequence RMS models, because ride-through and weak-grid behavior do not appear correctly in RMS.

The study benchmarks the two models, sweeps fault types and grid strengths, and freezes the resulting settings (k-factor, current priority, trip thresholds) into the interconnection agreement. Those frozen settings are the binding constraint on the plant: changing them later usually reopens the study and can slip the schedule, so treat the study-approved parameter set as contractual, not tunable.

Practical checks for a working engineer: confirm which bus the envelope references (POI or inverter terminals) and translate through the Transformer impedance; verify plant protection relays and the ride-through curve do not overlap, so protection cannot trip inside the no-trip zone; confirm auxiliary power for cooling, controls and the BMS rides through the same sag, since a control system that browns out defeats a fully compliant inverter; and check that commissioning includes the utility's ride-through parameter verification, commonly a hold point before permission to operate.

Each is a routine, avoidable cause of a failed test.

Common pitfalls

The classic trip-wires sit at the edges of the inverter, not inside it. Grid-following controls that lean on a phase-locked loop can lose synchronism during deep sags on weak grids even when the hardware could ride through, which is why weak-grid screening (short-circuit ratio at the POI) belongs in the same conversation.

Auxiliary systems are the other silent failure: HVAC contactors and 24 V control supplies fed from station service can drop on a 150 ms sag unless buffered, taking the plant offline seconds after a textbook ride-through. Successive-fault requirements catch designs tuned for a single dip.

Finally, do not treat ride-through as a pure voltage topic. The same standards bundle frequency ride-through, rate-of-change-of-frequency withstand, and post-event active-power recovery ramps (many codes require returning to pre-fault power within a defined time after voltage recovers).

A BESS that survives the dip but restores real power too slowly, or oscillates against nearby plants while doing so, still fails the study. Treat the whole disturbance sequence, from fault inception to full power recovery, as the requirement, and budget commissioning time to prove it rather than discovering the gap on site.