IEEE Power & Energy Magazine - September/October 2021 - 54

control and inertia, must be sourced from within the island.
These factors collectively increase the minimum required
number of synchronous generators under islanding conditions
compared to those required for system intact conditions.
Relationship Between Physical Inertia
and Fast Frequency Response
In a power system, inertia and frequency control are closely
related. The amount of physical inertia is the key determining
factor in arresting frequency rise or fall. However,
this is not sufficient by itself to ensure frequency recovery
within the necessary frequency range. The provision of
local frequency control is another critical factor in maintaining
system security under islanding conditions. The
two attributes may be provided by the same device (e.g.,
synchronous generators). However, this is not essential as
inertia-less IBRs can provide a faster frequency response
than that of the turbine-governor of a synchronous generator.
For example, a battery energy storage system has a
typical frequency response on the order of a few hundred
milliseconds as opposed to several seconds for a synchronous
generator.
While a minimum level of physical inertia is always
needed to arrest the frequency, this is not sufficient to maintain
all aspects of system security. The additional inertia
required can be sourced from synchronous generators or by
fast frequency response (FFR) from the IBR. For example,
if several synchronous generators are running, they could be
utilized as the primary source of frequency control. However,
operating under low-demand conditions with a lower
number of synchronous generators would mean these generators
likely need to be directed to come online. Maximizing
the use of FFR would reduce the need for these synchronous
generators and associated directions.
Figure 8 shows an example of the relationship between
physical inertia and FFR for the SA power system under
a specific operating condition. The relationship shown in
Figure 8 changes based on the size of the contingency. The
potential for inadvertent disconnection of distributed PVs
would mean the occurrence of a larger credible contingency
Physical Inertia Versus FFR
8,900
8,400
7,900
7,400
6,900
6,400
5,900
5,400
4,900
4,400
Night Time
Day Time
during daylight hours, indicating the need for a higher level
of physical inertia and FFR during the daytime.
Management of the Size
of the Contingency
The largest size of a contingency an islanded power system
can withstand without breaching its frequency operating standards
depends on the frequency control capability of local
generators. AEMO's power system studies for SA islanding
conditions indicated the total frequency control capability
provided by synchronous generators and IBRs would not
always be sufficient to deal with the largest credible contingency
if no preemptive measures were taken.
The maximum size of a contingency can often be controlled
by the central dispatch process, where a constraint can be applied
to the output of IBRs and synchronous generators to manage
their credible disconnection. However, this is not true when a
sympathetic trip of distributed PVs is involved because distributed
generation is not controllable via the dispatch process.
To reduce the size of distributed PV disconnection and
the contingency size, emergency manual intervention in the
form of preemptive disconnection of distributed PVs would be
required. This would also increase the available load required
for the stable operation of large synchronous generators,
allowing them to operate sufficiently far above their minimum
stable load points to facilitate the provision of bidirectional
frequency control. Such an emergency intervention would be
achieved through coordination between transmission and distribution
network service providers and AEMO as the power
system operator.
Commitment Order for Grid-Connected IBRs
During low-demand periods, where there is more generation
than demand, judicious decisions need to be made on the
commitment order of controllable generators. Some IBRs in
SA are enabled with the OFGS. AEMO needs to ensure sufficient
OFGS capacity was available at all times to accommodate
the loss of the largest loads and the dc interconnector
in SA, so AEMO
✔ gives priority to all IBRs enabled with OFGS during
low-demand periods where not IBRs can remain online
✔ applies further delineation in very-low-demand periods
to give dispatch priority to those OFGS-enabled IBRs
with a relatively lower frequency activation threshold.
These actions were implemented during the actual islanding
event and would be implemented should a future islanding
event occur.
We earlier discussed the relationship between physical
020406080 100 120 140 160
FFR (MW)
figure 8. The relationship between physical inertia and FFR.
54
ieee power & energy magazine
inertia and FFR. Currently, a large amount of FFR is available
from a transmission-connected battery energy storage
system in SA. Operating a battery energy storage system
close to zero generation would maximize FFR capability
for any given contingency and either load or generation disconnection
events. This would help operate an islanded SA
power system with much lower physical inertia than would
september/october 2021
Inertia (MWs)
IEEE Power & Energy Magazine - September/October 2021

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