IEEE Power & Energy Magazine - May/June 2021 - 63

The industry is strongly advised to move all inverters
to a grid-forming-with-droop mode of operation
with limited or no frequency-tracking dependence.
contactor) to the motor or transformer was last opened. This
phenomenon becomes more pronounced in larger transformers closed onto an energized bus than in DOL motors, but the
physics are the same. The dc offset decays at a rate described
by the X/R ratio of a power system. Larger X/R ratios make the
dc component last longer; for example, high-efficiency transformers with small R and large X are the most prolonged and
difficult for inverters. X/R ratios range from 4 to 50 for power
systems, with typical microgrids having roughly 15. This dc
component can cause momentary current requirements of two
times or greater the nominal transformer current. Ironically, a
less efficient power transport system (greater resistance and
lower X/R ratios) has fewer dc offset problems. Resistance can
be added or inverters can be programmed to emulate this resistance. As discussed later in this article, islanded inverters can
ramp and avoid magnetic inrush altogether.

Frequency-Tracking Failures
Frequency-tracking failures in grid-following inverters have a
history of causing instability and lost revenue for power systems. As shown in Figure 6, some types of inverters track the
power system's frequency; however, during ac faulted-circuit
conditions, the ac voltage waveform is suppressed and the
inverter cannot accurately track the frequency. This puts the
inverter into the position of having to " guess " the power system. Note that inverters with no dependence on " tracking " the
power system's frequency offer a more resilient response.
When inverters fail to accurately track the power system's
frequency, they will phase shift away from the power system
and then trip offline (stop commutating). This may happen during power system transients, switching operations, or faultedcircuit events. Thus, even the best protection system cannot stop
some inverters from demonstrating unreliable behavior. For this
reason, the industry is strongly advised to move all inverters to a
grid-forming-with-droop mode of operation with limited or no
frequency-tracking dependence. This necessitates moving the
industry away from grid-following standards.
Further IBR challenges not addressed in this article
include human error and preferences, Park and Clarke transforms, excessive control complexity, a lack of transparency
regarding intended firmware behavior, and disparate (and
contradictory) industry inverter standards.

Adapting Protection
Without Communication
In this example, a battery and a PV IBR on a distribution feeder
are islanded by an upstream protection event; this forms an
may/june 2021

islanded microgrid, and several challenges arise. In overload or
faults, this particular battery IBR produces a 120% surge current for 10 s and then a 100% current indefinitely; during this
overload, the inverter voltage is held at a low level, and after
5 s (configurable), the inverter stops commutating. The PV IBR
is continuously limited to a 100% current at a lower than 0.8
power factor. When grid connected, the utility grid is capable
of producing fault currents at approximately eight times the
nominal current rating of interconnection. Because normal
feeder loading so closely resembles the fault current capability
of the islanded IBR, the reclosers downstream of the IBR must
be prompted to dynamically switch to more sensitive (different)
protection when islanded; however, there is no communications
infrastructure connecting the downstream reclosers.
One solution to this problem is for the PPR at the utility
disconnection point to communicate a frequency reference
shift to a battery energy storage system inverter. This higher
frequency prompts the downstream recloser relays to shift
to more sensitive and different protection settings, all without the cost or complexity of a communications system. This
ability of inverters to quickly shift system frequency is one
advantage of a low-inertia power system. Note that this same
technique is possible with lower-inertia-distributed gensets
but can take -roughly 0.5-s longer than inverters. A similar
frequency-shifting technique is used in Germany to force
IBRs offline without communication.

+
dc

-
Park
Transformation
A
DQ
B

ABC C
δ

PWM
Modulator

~60 Hz
dt

4 kHz

Best-Guess
Frequency
Frequency
Tracking

figure 6. The inverter frequency tracking " guessing " the
power system's frequency and phase angle. PWM: pulsewidth modulated; DQ: direct and quadrature.
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IEEE Power & Energy Magazine - May/June 2021

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