IEEE Power & Energy Magazine - May/June 2021 - 43

Importantly, grid-forming inverters used
for microgrid or off-grid applications may be designed
to produce negative- and zero-sequence currents.

Exploring Traditional Protection Options
for IBR-Fed Microgrids
There are three objectives to protecting any power system:
1) detecting a fault, 2) determining the location of the fault on
the feeder, and 3) de-energizing the fault before equipment
is damaged while interrupting the smallest possible number
of loads. Traditional distribution system protection schemes
achieve all three objectives using coordinated overcurrent
protection, the design of which relies on the assumption that
the system is radial and fed only from an infinite bus.
An IBR-fed microgrid may have multiple sources, having bidirectional fault currents that are severely limited in
magnitude. Therefore, the traditional distribution protection
schemes that heavily depend on fuses and reclosers are not
expected to work well in IBR-sourced microgrids. For this
reason, more sophisticated protection schemes have been
explored regarding their suitability for the protection of distribution system microgrids. The suitability of such protection schemes is discussed in the following subsections.
Increasing the Available Fault Current

One of the most straightforward options that can be considered is to increase the microgrid fault current to the
point at which coordinated overcurrent protection becomes
effective. This solution is most viable in cases in which the
microgrid sources are located at one source bus and not distributed throughout the microgrid. One way to increase the
fault current frequently used in microgrids today is to install
excess inverter capacity (usually twice the expected peak
load requirement or more) so that the IBR plant provides
substantially higher fault currents. This option can work,
but it significantly increases the cost of the IBR plant and
microgrid. Another method being actively explored is the
use of synchronous condensers as fault-current sources in
microgrids. While this approach shows high promise, it also
significantly increases costs, and it can have some detrimental effects on microgrid dynamics.

However, while undervoltage relaying readily indicates
the existence of a fault, it does not work well in identifying the fault's location. Figure 6 shows the pu voltages at all buses for phase A-to-ground fault in the IEEE
13-node system.
The change in the voltages at all nodes is large enough
to detect a fault in the system, both at the IBR terminal or at
any bus in the system. However, the values of the voltages
at all buses are very similar. The differences in the highest
and lowest voltage magnitudes are about 2% for the A-G
fault, 2.3% for the three-phase fault, and 3.1% for the
A-B fault. This difference is too small to provide a reliable means of discerning the fault location. Voltages are
so close because physics dictates the voltage at the fault
point be drawn to a low value, and the system currents are
quite small, so the voltage drops across feeders are quite
small. This creates a situation where a fault anywhere in
the system will be certainly sensed through undervoltage
at every bus, but no discrimination is available to identify
the faulted section.
Distance Protection

Distance protection works well in transmission and is
attractive because it can be implemented without communications, but it is generally difficult to apply in distribution even when there is no microgrid. For example, it is
usually challenging to use distance protection for feeders
with laterals due to problems of overreach into protective
zones at different impedances. In a branching radial distribution system, the recloser protection zone may extend
only a short distance to a fuse on one lateral but much
farther down a different lateral before the next protective device. Since the boundaries of all taps inside the
protective zone are not equal distances or impedances,

transformer, so the ground fault on phase A results in higher
voltages on phase C on the delta inverter side of the transformer. Simulating this fault behavior for the dynamics,
sequence currents, and transient voltages is crucial to analyze the protection of microgrids.

0.155
0.15
0.145
0.14
0.135
0.13
0.125
0.12

1 2 3 4 5 6 7 8 9 10 11 12 13
Bus Numbers

Undervoltage Protection

Under voltage relaying has attracted some attention
because it can be implemented without communications.
may/june 2021

figure 6. The phase A voltages throughout the IEEE 13-node
system for a phase A-to-ground fault.
ieee power & energy magazine

IEEE Power & Energy Magazine - May/June 2021

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