IEEE Power & Energy Magazine - September/October 2021 - 53

For a few outages in various parts of the NEM, a combination
of reduction in the IBR output and the number of online
inverters has been applied. The level of constraint required is
often more restrictive than typical constraints experienced in
the system without outages. Outages of critical transmission
lines could require a complete disconnection of some IBRs for
the duration of the outage, typically ranging from a few hours
to a few days.
There have also been examples where outages of critical
dynamic reactive power support sources, such as static
compensators, would require a constraint to the output power or
the number of operating IBRs. The NEM has also seen increasing
instances of multiple concurrent outages, most commonly
involving concurrent outages of network and generation in the
same part of the network. More complex recent outages have
involved multiple network and generation owners. In one of
the most complex experiences to date, an outage necessitated
combinations of synchronous generators in two NEM regions
concurrently to ensure a stable postcontingency overall system
performance.
Increased Uptake of
Distributed PVs
Distributed resources currently represent 20% of the NEM's
installed generation capacity with most of this capacity being
distributed PVs. The SA region has recently experienced
times when 100% of demand was supplied by solar power, of
which 80% came from distributed PVs. Distributed PV systems
have been installed in the NEM for over a decade with
very different standards and requirements, particularly from
the standpoint of fault ride-through capability. A sizable proportion
of distributed PVs have no ride-through standards at
all, yet systems connected more recently have varied levels of
fault ride-through capabilities. Inadvertent disconnection of
distributed PVs during network fault events has been experienced
several times in the course of power system operations.
This behavior has meant that in some NEM regions, particularly
in SA, the size of the largest credible contingency
for which the power system is planned and operated is determined
by distributed PV responses during a fault rather than
the loss of the largest synchronous generator. The largest
credible contingency is often a loss of a large metropolitan
synchronous generator resulting in the sympathetic disconnection
of distributed PVs, also concentrated in metropolitan
areas. In Australia's NEM, this is considered as a single
credible contingency.
Another consequence of increased uptake of distributed PVs
is a reduction in the system's total operational demand to be
met by transmission-connected generators. Key concerns with
low operational demand include the potential for high steadystate
network voltages and ensuring that all minimum must-run
synchronous generators are supplied with their minimum stabilizing
load. Many of these units are large thermal plants with
relatively high minimum loading requirements for their stable
operation compared to other generation technologies.
september/october 2021
Both of these challenges-the inadvertent disconnection of
distributed PVs during faults and a reduction in the minimum
load available for stable operation of synchronous generators
collectively-will be exacerbated when a normally interconnected
system operates as an island. Interconnections to other
regions would not be available as an extra load for a stable
operation of synchronous generators or capable of providing
a range of desired system security attributes. Of these, the
absence of frequency control support from other NEM regions
would have the highest impact during islanding conditions.
Determining Secure Operating Envelope
of a Normally Interconnected System
When Operating as an Island
Background
On 31 January 2020, a multiple contingency event resulted
in the formation of an electrical island comprising the whole
SA power system and a small part of the network in the adjacent
Victoria region. Islanding conditions lasted for 18 days.
AEMO had to develop novel solutions for the secure
operation of this islanded system, which had a high share of
IBRs. An islanded power system must source all essential
system services such as frequency control, voltage control,
inertia, and system strength from within the island without
any support from the neighboring system(s). When the availability
of these services is limited, it is important to effectively
utilize them for the overall power system security of
the islanded network.
System emergency frequency control schemes, such as
the underfrequency load shedding scheme and overfrequency
generation-shedding (OFGS) scheme, are the
last line of defense against large frequency excursions and
play a vital role in maintaining system security. The effective
operation of underfrequency load shedding and OFGS
requires a certain available amount of load and generation
respectively to control large frequency excursions. It
is also important to maintain sufficient inertia to reduce
the rate of frequency changes following a disturbance and
to allow the effective operation of these emergency frequency
control schemes.
While this section focuses on one actual islanding experience,
many of the lessons learned and actions taken would
apply to any normally interconnected power system if it
operated as an island with a high share of IBRs.
Minimum Unit Commitment
Under Islanding Conditions
As discussed earlier in this article, minimum synchronous
unit commitment is maintained in all five NEM regions.
Under system intact conditions, the key factor determining
the required number of synchronous generators is the need to
maintain sufficient system strength. Operating a system as an
island results in reduced available system strength, and it also
means frequency-related characteristics, including frequency
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IEEE Power & Energy Magazine - September/October 2021

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