IEEE Power & Energy Magazine - September/October 2021 - 24

A multifaceted approach is needed to manage the impacts
of system strength with the needs of the power system likely
to change as the generation mix changes.
The largest net demand ramps are expected to occur on
winter evenings when solar PVs ramp down during sunset
coinciding with evening gross demand requirements ramping
up. The average daily winter net demand profile shown
in Figure 7 compares the projected " duck curve " to historical
levels under the medium scenario build from the 2020 ISP.
AEMO reports that changes in wind or solar output (outside
of sunrise and sunset) are challenging to forecast accurately
over both short and longer forecasting horizons. Technological
development and innovation have resulted in significant
improvements in weather forecasting accuracy. However, the
level of accuracy that is achievable even with best-practice
weather forecasts can still lead to significant challenges in predicting
wind and solar output and hence net demand variability
in the power system. Consequently, ramps in the future are
likely to be subject to more uncertainty. An accuracy analysis
conducted on operational forecasts of wind and solar generation
for 2018 found that recent wind and solar output gives a
good indication of the level of future output (close to real time)
but does not give a good indication of future variability.
Appropriate mechanisms must be in place to ensure that
sufficient flexible resources are available to meet increasingly
variable and uncertain system conditions. These resources can
be sourced through grid augmentation and interconnection,
new fast-start units with high ramping capabilities, demand
response and energy storage, and retrofitted generators to
improve characteristics such as minimum stable load, ramp
rates, and the ability to cycle. A greater utilization of wind
and solar resource flexibility should also be explored given
their high ramp rates, short start-up times, and low minimum
generating levels, subject to resource availability.
To manage the additional uncertainty associated with the
emerging operating conditions in 2025, a suite of improvements
is being investigated. These include operational improvements
such as using a probabilistic forecast as input to the
dispatch, which could help account for ramping uncertainty,
and an improved weather observation infrastructure, which
could enable weather forecasters to predict ramping events
more accurately. Additional mechanisms to enable appropriate
volumes of reserve in the market are also being explored, such
as different approaches to an operating reserve market.
Managing Increasing Volumes of DPVs
AEMO outlines that parts of the NEM that have among the
world's highest levels of DPVs, including one of the highest
levels of residential solar PVs, a subset of DPVs. The majority
of the DPV fleet is currently passive, meaning it is uncontrollable
and invisible to the system operator (behind the meter
and unmonitored in real time). The passivity is beginning to
pose challenges to both the distribution network and bulk
power system operation, especially in regions with higher
DPV uptake relative to the local load.
AEMO's RIS international review identified a typical trajectory
of system limits as the share of passive DPV increases.
Limitations first arise within the distribution network as a result
of concentration in localized areas. This eventually impacts the
operation of the transmission system as the penetrations grow. As
this growth continues, the inability to see and actively manage
the distributed solar fleet affects almost all core duties of the bulk
system operator in some way, including system balancing, system
stability, recovery, and restoration following major events.
NEM regions are at different points along this growth trajectory
and will continue progressing along this path as penetrations
increase. Table 1 compares the maximum half-hourly penetrations
of DPV generation by NEM region in 2019 against 2025
projections, showing projected regional levels as high as 85%.
table 1. The maximum DPV penetration as a
percentage of demand.
NEM Queensland
2019 (actuals) 25% 30%
2025 Central
scenario
2025 Step
Change
scenario
24
41% 45%
50% 57%
New
South
Wales Victoria
21% 31%
33% 45%
48%
66%
South
Australia Tasmania
64%
68%
85%
12%
14%
21%
Impacts on the Bulk
Power System
DPV are already impacting the ability
to securely operate the South Australia
region, and are beginning to affect
operations in other NEM regions.
The RIS investigated challenges for
both distribution system and bulk
power system operation. We present
here the analysis of bulk power system
challenges due to increased levels
of DPVs.
ieee power & energy magazine
september/october 2021
IEEE Power & Energy Magazine - September/October 2021

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