IEEE Power & Energy Magazine - November/December 2021 - 93

ERCOT has seen an increase in stability constraints in recent years,
particularly in western and southern Texas where much of the
wind and solar growth is concentrated.
where much of the wind and solar growth is concentrated.
These stability constraints can limit power transfers below
the physical thermal ratings of the individual transmission
lines. Stability limits for the GTCs are determined based on
offline studies.
ERCOT is currently in the process of implementing realtime
transient stability assessments to identify and manage
stability constraints more efficiently. This implementation
requires accurate modeling of IBR controls in simulation
applications; the development of these models has delayed
the implementation.
ERCOT defined the critical minimum inertia with existing
frequency control practices to be 100 GWs. Over the past
eight years, the system minimum inertia had been fairly
steady at about 128 GWs despite 20 GW of wind generation
added to the system. This was due to load growth and
the inertial contribution of nuclear units and industrial
generation. However, the recent lowest inertia condition of
109 GWs in March 2021 may indicate a change in commitment
patterns.
For the Australian National Electricity Market, minimum
inertia limits have been established to maintain synchronous
inertia to control the frequency if any region was to become
islanded. In South Australia, energy market intervention is
frequently required to ensure a minimum commitment of
synchronous generating units to maintain adequate system
strength and allow stable system operation. There are currently
no large synchronous condensers available in this system.
However, the installation of four such condensers by the
regional transmission operator during 2021 is expected to
reduce the need for these market interventions.
For smaller island systems, like Ireland and Tasmania,
operation at high levels of IBR penetration requires careful
real-time monitoring and management of inertia, fault levels,
and frequency response reserves. System requirements are
identified through the use of well-validated system models.
Reduction in transient stability margins, controllable reactive
power resources, and voltage-dip-induced frequency
dips add to operational challenges.
The latest additions to wind generation in Tasmania during
2020 mean installed wind plus HVdc import capability
may theoretically meet the entire demand, putting further
downward pressure on the synchronous generation commitment
and system inertia. Tasmania's mitigation for low-inertia
operation includes the following:
✔ There is significant use of contracted switched load
interruption for the provision of primary frequency renovember/december
2021
sponse reserves. A minimum requirement for proportional-type
governor response reserves has also been
established to manage frequency overshoot following
smaller generation-loss events that trigger switched
load interruption.
✔ Many hydropower units are capable of operating in
synchronous condenser mode. One larger hydro unit
is capable of operation in tailwater depression mode,
allowing rapid transition from synchronous condenser
to generation mode to respond to underfrequency
events.
✔ Tasmania allows a 2-Hz fall in frequency before
UFLS commences (compared to 1 Hz on the Australian
mainland). Key protection and control systems
in Tasmania are designed to tolerate a rate of change
of frequency (RoCoF) in excess of 1 Hz/s. If RoCoF
were to exceed this level, early UFLS blocks are designed
to drop off at a higher frequency setting.
In Tasmania, it was found that an even more operationally
onerous requirement than maintaining minimum
levels of system inertia is maintaining minimum fault levels.
Managing fault levels at key transmission busses is a
real-time requirement, with minimum fault levels identified
through system studies considering the stable postfault
response from wind generation and the HVdc link. Hydro
units are committed in synchronous condenser mode, via
commercial arrangements, where required to maintain
these fault levels.
In Ireland and Northern Ireland, operational constraints
due to stability have traditionally meant that a minimum of
eight large synchronous machines needs to be committed at
all times. Now, to accommodate increasing amounts of nonsynchronous
renewable generation, this constraint must be
relaxed. New control center decision-support tools to help
manage this situation include the following:
✔ The online security assessment has been enhanced
with a new look-ahead security assessment tool to
identify potential instabilities. This enables timely
implementation of the required changes to the initial
market schedules to meet the operational security
criteria.
✔ A voltage trajectory tool is being developed to provide
guidance to control center operators on the best methods
of managing system voltage. It will determine
optimal reactive targets for different types of devices
and deliver voltage trajectory plans that are secure
against contingency events for near time horizons
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IEEE Power & Energy Magazine - November/December 2021

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