IEEE Power & Energy Magazine - May/June 2021 - 22

characteristic refers to symmetrical faults only. Hence, the
required response of PE-interfaced units to unbalanced
faults is not defined in the majority of grid codes, and, thus,
the determination of the expected short circuit currents
under unbalanced fault conditions is ambiguous. In this case,
PE-interfaced units contribute to faults based on vendor-specific control algorithms, which are rarely disclosed.
Another source of uncertainty is the power factor of the
short circuit current provided by PE-interfaced generators.
During the fault, the active power is fixed at a prefault level,
while the reactive power should follow the requirements of
Figure 2(b). Therefore, the prefault conditions, voltage sag
due to the fault, and nominal current of the PEs can result
in short circuit currents of similar magnitudes (close to the
nominal current) but different power factors.
Figure 3 presents the case of a fault between buses 5
and 6 that causes a voltage sag below 50%. In this event, a
reactive current contribution equal to 100% of the nominal
current is added to the prefault active current. To maintain
the current of the converter below its thermal limit, a current limitation strategy has to be implemented in the DER
controller, giving priority either to the active or reactive
component. The different power factors considered in this
case represent the various prefault conditions and current

1-1.5 times their nominal current during short circuits
for a limited time. This leads to major differences in the
expected fault current levels when the microgrid is grid
connected or islanded.
The fourth challenge is the ambiguity in the short circuit
current contributed to by PE-interfaced units. During short
circuits, the behavior of these units is dictated by the implemented control algorithms that limit their current during
faults to protect their switching elements. This is different
than synchronous generators, whose fault current contribution is caused directly by the electromagnetic fluxes trapped
in their windings. Several standards and grid codes have
included functionalities that address the operation of PEinterfaced DERs during faults, especially those connected
to transmission systems. The most common and widely
applicable requirement is the fault ride-through capability,
which is expressed as a voltage to the time-after-fault curve,
depicted in Figure 2(a). As long as the operating point at the
connection of a DER unit is above this curve, the unit should
remain connected.
Many grid codes require a reactive current injection for
voltage support during a fault, as illustrated in Figure 2(b),
which depicts the requirements of the Greek operating
code for noninterconnected islanded power systems. This

Circuit
Breaker Closed
L
WT
B

Circuit
Breaker Open
PV

Load

Bus 5

Photovoltaic

Wind Turbine

Utility Grid

Batteries Energy
Storage

PEs

Grounding
Transformer

Fault

Bus 6
ICB7

ICB4
CB4

CB5

CB7

CB9 CB10

CB6

CB8

CB11

ICB6

Fault Current

L
ICB2
CB1

PV
CB2

Bus 3
CB12

ICB12

CB13

Bus 4

CB15

CB17 CB18

Utility Grid
ICB14

Bus 1

Grounding
Transformer

CB14 CB16

CB20
ICB3

Distribution Grid

WT
Microgrid

CB3
Bus 2

CB19

figure 1. The impact of a DER presence in microgrid protection.
22

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IEEE Power & Energy Magazine - May/June 2021

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