IEEE Power & Energy Magazine - November/December 2020 - 28

require manual adjustments by field personnel. As a result,
while offload tap chargers can permanently alter the maximum and minimum voltages on a supplied LV network, they
provide no reduction of the voltage spread.
Tap reductions and the phase balancing of loads and
PV systems are the first and least-cost options for managing voltage where feasible. Otherwise, excessive voltage
spreading (whether the result of maximum demand growth
or minimum demand reduction) can be reduced in four distinct ways:
1)	 reducing the network impedance, by using either lower-impedance (generally bigger) conductors or higherrating transformers
2)	 reducing the magnitude of real power flows, either traditionally by splitting feeders, with demand response
to shift demand, or with energy storage technologies,
such as BESSs
3)	 adjusting reactive power flows, either traditionally
with capacitor banks and behind-the-meter power factor correction or with modern devices, such as static
synchronous compensators (STATCOMs) and behindthe-meter smart inverter reactive power compensation
4)	 using a regulating technology, such as an MV regulator, an LV regulator, and a voltage-regulating distribution transformer.
A summary of current and potential voltage management
measures is provided in Figure 12. As the DER uptake continues and visibility in the distribution network improves, it
is possible that voltage management challenges may be most
economically addressed through MV solutions, that is, initiatives that impact large regions of the network, rather than
localized and largely reactionary measures in the LV network.

Reverse Flows
Challenges
When considered collectively, D-PV sources are, by far, the
largest generator in NEM. The next-largest plant is the Bayswater black-coal plant, at 2.6 GW. Substantial reverse power
flows are already being observed in the distribution system
across South Australia and metropolitan Queensland. In
the SAPN region, 42% of the zone substations have already
been observed in reverse flow conditions, with a further
32% nearing reverse flows. In some cases, reverse flows
are sufficiently large to exceed subtransmission substation
reverse power limits (which are often constrained by legacy
tap changer designs). While reverse flows are being felt
most acutely in the LV network, their impacts are rapidly
extending to the subtransmission and transmission systems
as well as raising system security concerns for AEMO. The
reduced efficacy of underfrequency load-shedding schemes
is a major concern, along with reactive power management,
which are both exacerbated by the low levels of visibility and
control. It is therefore critical that adopted strategies consider impacts across the entire power system.
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ieee power & energy magazine	

Solutions
Incentivizing Load

Moving hot water demand to coincide with peak solar generation times presents one option, but there are challenges
to this approach; in South Australia, this usually requires
a site visit to manually reprogram the time clock or meter
in each customer's meter box. In addition, the amount of
available load is likely to be sufficient only to defer, rather
than resolve, the minimum demand issue. Another approach
being pursued in South Australia is the introduction of a new
time-of-use "solar soak" network tariff from July 2020 that
includes a low-cost, off-peak rate during the middle of the
day to encourage customers to shift their load into the solar
trough. The effectiveness of this will depend, in part, on the
extent to which energy providers choose to pass on this price
signal in their retail tariffs.
Flexible Export Limits

Currently, all embedded generating units with an export
limit at or below 5 kW are automatically approved for connection in the SAPN network. An analysis by SAPN and EA
Technology indicates that this approach is unsustainable,
even with a volt-var mode mandated for all new installations. Figure 13 shows the approximate amount of D-PV
generation in terms of kilowatts per consumer that can be
accommodated in the SAPN network before voltage and
thermal limits are exceeded across different network types,
and it includes the present and forecast levels of D-PV penetration. The modeling shows that voltage limits are typically
breached ahead of thermal limits across all network types,
and, indeed, voltages are already exceeding allowable levels
in some cases.
Due to the increasing volume of large generator connections of more than 30 kW and the subsequent effect of breaching connecting substation reverse N−1 limits, SAPN generator interconnection standards require a supervisory control
and data acquisition (SCADA) runback scheme carried out
by generators at the constrained substation to prevent any
distribution and transmission asset overload and damage to
equipment. Here, N−1 refers to the total capacity of the connecting substation with one major item of plant out of service
(a "single contingent event"). In this case, it is the resultant
capacity due to a single transformer outage from either a zone
substation or the transmission connection point substation.
Without remedial action, the projected 2025 uptake of
D-PV generation is expected to result in widespread voltage
breaches, and the distribution network may become a bottleneck, limiting the benefits that can be captured from DERs.
Additionally, VPPs present a concern where simultaneous
charging and discharging, even at low battery penetrations,
could exceed thermal limits. In response, SAPN has considered three options:
1)	 It could continue to apply a static connection limit
of 5 kW and increase the network hosting capacity
november/december 2020
IEEE Power & Energy Magazine - November/December 2020

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