IEEE Electrification - September 2022 - 78

which was sufficient to cause all operational wind farms
and Basslink (which was importing at the time) to enter
FRT mode. The peak transient power deficiency caused by
these IBRs entering FRT was 480 MW, contributing to an
energy deficit of 139 MW.s. The minimum frequency was
recorded at 49.43 Hz with an average ROCOF measured
over 500 ms of approximately 1 Hz/s.
While clearance of the fault did not directly disconnect
any generation or load, more than 100 MW of industrial
load did ultimately disconnect in response to the voltage
disturbance. Given the large initial frequency dip that
resulted from the transient power deficiency, despite this
overall net loss of load, it is easy to appreciate the compounding
effect that the loss of a large generating unit
could have for such an event. The overshoot of active
power shown in Figure 6 was due to the controls on
Basslink automatically increasing power transfer into
Tasmania in response to the frequency dip, after it recovered
from the initial fault.
A secondary consideration is the potential impact of a
larger contingency event involving the loss of multiple
generating units. Whereas traditional under-frequency
load-shedding schemes may have been capable of managing
a particular set of events prior to the connection of significant
IBRs, the risk of maloperation due to an increased
ROCOF becomes real when FRT-induced energy deficits
are included. At an excessive ROCOF, discrimination
between load blocks may be lost, resulting in potential
overtripping of load, excessive frequency rebound, and
progressive loss of frequency control.
The approach to address this issue in Tasmania has
two parts.
x The inertia is maintained above a set threshold at all
times, effectively defining a minimum floor condition.
The current Tasmanian inertia floor is 3,800 MW.s, corresponding
to approximately a 4-s H time constant on
a system demand of 950 MW. The requirement to
maintain a minimum inertia level was codified in the
National Electricity Rules in 2017 and fully operationalized
by early 2020.
x The megawatt output of the IBRs is constrained
through the 5-min central dispatch process as a function
of system inertia, such that the peak ROCOF
does not exceed 3 Hz/s averaged over 250 ms or
exceed 1.1 Hz/s (averaged over the same time frame)
as the frequency passes through 49 Hz (noting that
the under-frequency load shedding commences at
48 Hz, and the frequency must be arrested above
47 Hz for all events).
The second criterion is linked to the design of the
Tasmanian under-frequency load-shedding scheme as
well as generator performance standards defined in the
National Electricity Rules. The approach of defining
two distinct ROCOF periods is broadly consistent with
concepts published by the European Network of Transmission
System Operators for Electricity in its
78
IEEE Electrification Magazine / SEPTEMBER 2022
guidance document on ROCOF withstand capability
(January 2018).
With decreasing levels of synchronous generation dispatched
in the market at times of high IBR output, minimum
inertia levels are now actively managed by operating
a number of suitably capable hydrogenerating units in
synchronous condenser mode. This has required new
commercial and operational arrangements to be developed,
including payments to the generator for this service
and real-time mechanisms to commit and withdraw the
services to manage system security as required.
Maintaining Adequate System Strength
The system strength may be thought of as the " stiffness "
of the voltage at any location on the power system. A high
sensitivity of voltage magnitude and/or phase angle to
changes in reactive and active power flows indicates a
" weak " point in the network, usually associated with a
high impedance connection back to controlled voltage
sources in the " core grid. " With the rapid increase in IBR
connections, however, entire areas of network can now at
times be classified as weak. A three-phase fault level has
been the usual proxy metric to characterize the available
system strength, allowing relatively straightforward calculations
to be undertaken as part of planning studies and
during real-time operation.
The system strength is an important factor for secure
operation of a power system. Minimum levels of system
strength must be maintained to ensure stable operation
of conventional " grid-following " IBRs, particularly following
disturbances (including fault events). All IBRs in
Tasmania are currently of the grid-following type, which
rely on the presence of a suitably stable external voltage
waveform against which to synchronize their internal
control systems.
The mechanism to manage system strength in
Tasmania to date has been to define four " fault-level
nodes, " which represent critical points in the transmission
network (Figure 7). Through extensive offline analysis,
it has been possible to define minimum three-phase
fault levels for the intact network, which enable correct
operation of IBR equipment, including when it is subjected
to key fault events. Network outage conditions are
managed as a separate issue, with constraints imposed
on IBRs where it becomes impractical to maintain the levels
of system strength needed to support maximum
power output.
As with inertia, new commercial and operational
arrangements have been necessary to maintain minimum
levels of system strength during real-time operation. The
solution at the present time is largely the same as for inertia,
i.e., managing commitment of hydro units in synchronous
condenser mode, noting that the system strength is
much more dependent on location, requiring available
synchronous condensers to be allocated against each of
the four system strength nodes.
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