IEEE Power & Energy Magazine - May/June 2021 - 52

The combined heat and power-based microgrids
at Princeton University and New York University enabled
the campuses to keep the lights on during Hurricane Sandy.
Microgrids Sourced by Rotating Machines
Some microgrids are energized by diesel- and gas-powered
generators as well as by rotating turbomachines driven
by steam plants. For low-impedance symmetrical faults,
rotating machines typically provide subtransient fault currents ranging from six to 10 times their rated current for
approximately six cycles, assuming that they are effectively grounded. For this reason, microgrids that are served
exclusively or primarily by rotating generators can usually
use standard time-overcurrent protection, although care
must be taken to ensure that such a defense is triggered
quickly enough, preferably within the subtransient period.
Also, it is common, although not universal, that all generators are connected to a microgrid at the same source
bus and not -d istributed across the network. In some such
cases, this centralization further simplifies the system protection by making the coordination of time-overcurrent
protection possible. In addition, centralization can make it
possible to use directional elements to enable the defense
to work both on and off grid. Together, these factors suggest that the protection of microgrids sourced by rotating
machines can, in general, be achieved using existing techniques and devices.

Microgrids Sourced by IBRs
Microgrids sourced entirely or primarily by IBRs pose a different set of protection challenges. These difficulties are covered
in detail in the first part of article, " Influence of Inverter-Based
Resources on Microgrid Protection, " by Reno et al, in this issue.
For the purposes of this article, there are four key challenges that
arise in IBR-sourced microgrids, as described in the following:
1) IBRs generate limited fault current (grid-forming inverters typically produce less than twice their rated
current into a fault, with most supplying only about
1.1-1.5 times their rating). This is an inherent limitation
of IBR hardware since s- emiconductor switches can be
quickly damaged by overcurrent. In some microgrids,
this drawback is mitigated by -providing much more
inverter capacity than required to serve the loads,
thereby increasing the available fault current. This, of
course, comes at a cost.
2) The phase angle between an IBR's fault current and
the voltage at the point of current injection depends on
how the IBR is programmed. IBRs will typically have
a specific LV reactive power response so that they will
adjust the phase angle of their output current, depending on the voltage, meaning that the voltage must be
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known to determine the phase angle. An iterative solution is required to model this mathematically.
3) Many IBRs limit their fault current magnitude by shaving the output current waveform peaks. For these IBRs,
the fault current is highly nonsinusoidal. This may cause
problems, such as errors in root-mean-square measurements and the tripping of ground fault sensors.
4) IBRs can trip during fault events on various internal
triggers, such as frequency measurement errors and
software-applied limits on maximum phase jumps
(phase-locked-loop errors).

Distributed Versus Centralized Microgrids
A centralized microgrid has all its power sources connected
at a single source bus. A distributed microgrid has multiple
source buses. The protection of a distributed microgrid is
more difficult than that of a centralized one because the
safety system must continue to operate properly for all feasible combinations of sources. This is true regardless of whether
the distributed sources are rotating or IBRs. Also, a distributed microgrid has the potential to separate into islands
centered around each source bus, and the protection system
must deal with that situation and with any recombination of
the islands back into the microgrid.

Protection Challenges for Microgrids
in Secondary Networks
Today, microgrids are usually deployed to provide continuity of service in the event of a loss of the main utility
source. It is conceivable that if a facility already served by
a secondary network has an on-site power source, such as
steam and CHP plants, the operator might consider creating
a microgrid based on that resource to provide power during a catastrophic event that knocks out all primary service.
If there is sufficient generation capacity to provide power
to nearby facilities, it is also possible that the boundary of
this microgrid could extend, thus including a portion of the
secondary network. Based on the foregoing, two key challenges must be overcome if a microgrid were to be deployed
on a secondary network. The first arises if the microgrid
DERs cause a reverse power flow through the NUs. Figure 1
details a network without DERs and indicates that the power
flow through the NPs is unidirectional. In Figure 4, DERs
have been added to the same grid, and now the power flow
through the NPs can be in either direction, as shown by the
P, Q arrows in Figure 4. This reverse power flow must be
differentiated from the reverse fault current flows, and there
may/june 2021

IEEE Power & Energy Magazine - May/June 2021

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