IEEE Power & Energy Magazine - September/October 2021 - 49

predispatch mechanism has not forecast at least the required
minimum synchronous unit commitment, AEMO has intervened
in the market via directing synchronous generators
online that would not otherwise be dispatched. As shown
in Figure 3, AEMO has increasingly directed synchronous
generators over the past three years, and up to more than 250
times in 2020, to maintain sufficient system strength in SA.
Intervention in the electricity market is not a cost-effective
measure, and it is not in the long-term interest of consumers.
To reduce and ideally eliminate the need for market
interventions, AEMO required SA's transmission network
service provider, ElectraNet, to consider other options.
The process to identify alternate solutions started when
AEMO declared a fault-level shortfall (proxy for system
strength) in SA in October 2017 as required by the recently
introduced fault-level rules in the Australian NEM grid code
(National Electricity Rules). ElectraNet, as the SA system
strength service provider, was then required to develop costeffective
options and timeframes for meeting the declared
shortfall. ElectraNet's economic analysis of viable options determined
that the installation of synchronous condensers would
be the most cost-effective solution. Installation was compared
to AEMO's ongoing directions under the system security constraints
and ElectraNet's contracting directly with synchronous
generators capable of providing the required system strength.
Detailed power system studies confirmed that installing
four large synchronous condensers on the transmission network
would address the system strength shortfall declared by
AEMO. These synchronous condensers are being installed
progressively, and all will be operational by late 2021. Further
studies will be required after the synchronous condensers are
operational to determine whether the SA power system can
be operated without any synchronous generators and, if not,
the exact characteristic and services that must be provided
by synchronous generators.
Synchronous Generators Unit
Commitment for Other NEM Regions
Lessons learned from operating SA with a low number of
synchronous generators prompted AEMO to determine predefined
quantities and combinations for maintaining system
strength in other NEM regions. In the Victoria region, unlike
in SA, AEMO did not identify the need to constrain the
aggregate IBR output at all times under system intact conditions,
but it found critical prior outages could still result in
severe constraints in IBR output. These predetermined combinations
of synchronous generators are available to real time
operational personnel to ensure at least one of the acceptable
combinations of generator dispatch is available at any given
time. Occasional periods where this could not be met have
been experienced. However, the frequency and duration of
directions have been far less than has been required in SA.
AEMO then determined all regional combinations based
on detailed EMT studies as it did for SA. Any new combination
of generation dispatch would need to undergo the same
september/october 2021
assessment before it can be used operationally. The only exception
is the Tasmania region, the smallest in the NEM, and
includes numerous hydro units of comparable sizes. Hundreds
of valid synchronous generator combinations exist in Tasmania,
so AEMO instead developed an automated fault-level
calculation tool that is integrated into the suite of overall control
room tools. This allows a real-time calculation of expected
fault levels.
Results from these simple fault-level analyses have been
benchmarked against a detailed EMT analysis, showing a
good correlation. This approach will not work, however, in
other NEM regions with larger (often much larger) area sizes,
large distances between areas of concentration of IBRs and
synchronous generators, and a variety of synchronous generator
types, sizes, and owners. AEMO-fed lessons learned
from these operational analyses into regulatory changes that
went into effect in 2018. System strength and inertia requirements
focus on a planning horizon of up to five years to assess
and arrest any potential shortfall in the natural availability of
sources of system strength and inertia support.
High Concentration of IBRs
in Remote Areas
Background
Several areas in the NEM have seen an exponential uptake
of IBRs over the past few years with the majority of IBRs
being connected in remote and sparse areas. We earlier
highlighted the need to maintain a sufficient number of
online synchronous generators to maintain system strength.
In remote areas with a high concentration of IBRs, however,
the marginal impact of additional synchronous units is very
limited. This results in limited system strength support from
the wider power system, even when many synchronous generators
are online, creating the potential for adverse IBR
interactions and instabilities as IBR uptake increases.
One of the key manifestations of such instabilities in several
NEM regions is the creation of sustained postdisturbance
oscillations. These oscillations have a dominant frequency of
5-10 Hz and have historically occurred once in practice due
to forced outage of a transmission line. Detailed simulation
Number of Directions in South Australia
300
250
200
150
100
50
2016 2017 2018 2019 2020*
*Up to 26 Nov. 2020
System Strength
Energy (Reliability)
figure 3. The number of directions in SA.
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IEEE Power & Energy Magazine - September/October 2021

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