IEEE Power & Energy Magazine - September/October 2021 - 71

These arrangements were implemented when the generating
mix was dominated by a limited number of large generation
units. Most were located at generation hubs that were, in turn,
often in highly meshed parts of the grid. Given this mix, dominant
events causing risks to power system security typically
involved the sudden failure or service removal of specific generating
units or network elements. Such events are distinct and
definable with the size of their impact being deterministic.
Australia's NEM generation mix has changed in recent
years with the reduced operation, mothballing, or retirement
of many large synchronous generating units. That is
coupled with the rapid deployment of DERs, inverter-based
resources, and intermittent generation at both the transmission
and distribution levels.
Along with an increase in severe weather events, the changing
generation mix has introduced a new class of risks to power
system security. Risks are increasing due to the so-called indistinct
events that can act on multiple generation and network
assets in an affected area within minutes. The specific assets
involved in the contingency event, and hence the size of the
impact on the system, are not known before the event.
Figure 2 summarizes some examples of these emerging
" indistinct " events. Further considerations and context about
operational uncertainty and risk associated with different
types of indistinct events and underlying issues and drivers
are provided in " Three Types of Indistinct Events Affect
Operational Uncertainty. "
The NEM regulatory frameworks, which are set out in the
national electricity rules, define how the system must be managed
by the AEMO. These frameworks were designed around
the management of traditional " discrete " risks, whereby the
system operator should be able to describe the expected contingency,
indicate which component may be at risk, and quantify
the potential contingency size. As power system risk profiles
changes, and with more and more emerging " indistinct "
events that are difficult to characterize (in probabilistic terms,
not to even mention deterministically), national electricity
rules are being revised to ensure that AEMO has the correct
tools at its disposal to manage these new risks.
Developing a Portfolio
Approach to Resilience
As the power system changes and becomes more " fragile, "
policy makers and system operators are rethinking HILP
event management. A wider range of coordinated resilience
solutions is required to manage increasingly indistinct, and
extreme, HILP events. The need for new resilience solutions
is increased by the decline of innate resilience buffers that
has occurred in many power systems, including the reduction
of latent system inertia and system strength, as discussed
Three Types of Indistinct Events Affect Operational Uncertainty
Weather
There is increasing generation risk associated with weather
changes, such as sunlight intensity or wind speeds, which
are generally distributed and affect a significant number
of units. While the associated generation changes can be
forecast and assessed probabilistically, there is also associated
uncertainty, particularly under abnormal weather
conditions, such as high winds and storms. In parts of the
NEM, the largest credible contingency could be an output
change from a group of variable-generating units in an affected
geographic area.
System Response
With more and more synchronous units retiring, the resulting
lower levels of fault current and inertia are increasing
significantly the uncertainty of a system's dynamic response
to disturbances. This uncertain response is further compounded
by the more complex response behavior of DERs.
In particular, the size of a contingency, such as a single network
fault or generator trip, can be significantly increased
by an unexpected loss of generation. For example, this
could be due to a portion of the nearby inverter-connected
VRE generation (such as in the 2016 South Australia black
september/october 2021
system event) or distribution-connected DERs (such as in
the August 2019 Great Britain load disconnection event)
failing to ride-through the associated disturbance, including
due to protection settings issues.
Emergency Control Schemes
There are emerging issues associated with the effectiveness
of emergency control schemes and the associated
uncertainty in the resulting system response. An important
instance is UFLS schemes in the presence of large DER
quantities. While the scheme is designed to shed load by
disconnecting distribution feeders at predefined substations,
this may also disconnect areas of net embedded generation,
increasing the overall net loss of supply and therefore
risk to the power system.
Again, there have been a few situations of this kind, including
again in the August 2019 event in Great Britain. Other important
considerations on operational uncertainty and risk that
can be brought by emergency control schemes regard the interactions
between different types of special protection schemes
as generation mix and power system conditions change. This
may require revising control algorithms and settings to prevent
unintended interactions and cascading outages.
ieee power & energy magazine
71
IEEE Power & Energy Magazine - September/October 2021

Table of Contents for the Digital Edition of IEEE Power & Energy Magazine - September/October 2021
