Short-circuit current contribution of inverter-fed sources (PV, BESS) — why IEC 60909-0 needs a different approach here

The [guide on short-circuit current calculation per IEC 60909-0](/guides/nen-1010/kortsluitstroomberekening-iec-60909-impedantiemethode) and the [guide on generator reactances Xd″, Xd′ and Xd](/guides/nen-3140/generator-reactantie-subtransient-transient-synchroon-xd) both cover a network in which the short-circuit current is determined by the impedance of the source: the lower the reactance, the higher the fault current, decaying according to a physically determined decrement curve. A PV inverter or battery inverter (BESS), however, behaves fundamentally differently during a short circuit — and this has direct consequences for protection design and settings.

Impedance-limited versus current-limited

A synchronous generator delivers its short-circuit current through its own magnetic reactance: the physics of the machine itself determines the current, which during a subtransient fault can rise to a multiple (often 5-10× or more) of rated current. A grid-connected inverter works entirely differently: the power electronics (IGBTs or similar switching elements) physically cannot deliver a current that exceeds the thermal and voltage limits of the semiconductors, and the inverter's control actively limits the output current to a pre-set maximum — regardless of how low the network impedance is at the fault location. For a grid-following inverter, as is typical for most existing PV and BESS installations, that limit is generally around 1.1 to 1.2× the rated current of the inverter, roughly for a few grid cycles until the inverter trips itself off.

Why this matters for protection design

This fundamentally different fault current characteristic has practical consequences:

Overcurrent protection relying solely on the inverter contribution may be insufficiently sensitive: a conventional overcurrent relay (ANSI 50/51) set to a multiple of the rated current of a synchronous source may not detect a fault fed solely by inverters — with a maximum contribution of only ~1.2×In — at all.
Directional and differential protections remain functional, because they do not depend on a high absolute current value but on the phase angle, direction or difference between incoming and outgoing current — see also the guide on directional overcurrent protection (67).
The contribution of an inverter-based plant to a network fault elsewhere (for example a nearby solar park helping to feed a fault on the network) is limited compared to an equal amount of synchronous generation — this affects both the total available fault current for detection and the required breaking capacity of switchgear.

IEC 60909-0:2016: a separate rule for full-size converters

To explicitly account for this difference, IEC 60909-0 added, in the 2016 edition, a separate provision for "power station units with full-size converters" — generating units connected to the network via a full power converter (instead of directly via a synchronous machine), as is the case for most PV parks and battery storage systems. Instead of the usual, reactance-based equivalent voltage source method, the contribution of such a unit is treated as a current-controlled source with a fixed, manufacturer-specified maximum contribution, rather than an impedance-limited source whose contribution follows directly from the network impedance.

Note: this article covers the principle for common grid-following inverters. Newer, grid-forming inverter technology can behave differently during a fault and is subject to ongoing standards development (including within IEEE 2800); this article does not give an exhaustive overview of every inverter control strategy.

Practical relevance

When performing a short-circuit current calculation for a network with a significant share of PV or battery generation, it is important not to model the contribution of those inverter-fed sources in the same way as a synchronous generator with a reactance value — the actual contribution is generally significantly lower, which has consequences both for the required breaking capacity (which may turn out lower than with an equal amount of synchronous generation) and for the sensitivity of overcurrent protections (which must be higher to still detect a fault with a limited inverter contribution).

Common mistakes

Estimating the short-circuit current contribution of a PV or BESS inverter using the same reactance approach as a synchronous generator — this significantly overestimates the actual contribution.
Sizing overcurrent protection without accounting for the limited, ~1.1-1.2×In-limited contribution of inverter-fed sources to a fault fed solely by those sources — this can lead to protection that does not trip.
Assuming that a large installed PV or BESS capacity automatically requires a large breaking capacity of switchgear — the actual fault current contribution of inverter-fed sources is generally much lower than the rated power would suggest.
Not distinguishing between grid-following and grid-forming inverter control when assessing the fault current characteristic — both can behave differently during a fault, and the manufacturer specification of the specific inverter remains authoritative.