IEEE Power & Energy Magazine - November/December 2019 - 33

million). This allows owners who provide these services to
recover capital investment in upgrades. Incentives are split
across products and earnings are higher when the system
operates above 55% SNSP because it is at high IBR penetrations when EirGrid most needs these products.
The Synchronous Inertial Response (SIR) product is one
of seven new products implemented last year, in addition
to the seven existing ancillary services. SIR is the ratio of
the kinetic energy divided by the minimum generation of the
plant. EirGrid created a product that paid generators if they
were dispatched and had an SIR of 45, with higher payments
at high IBR penetrations. In addition to SIR, the reduced
minimum generation level allows for the plant to provide
higher ramping and reactive power services. As a result,
five large plants have now lowered their minimum generation, which they were previously unable to do, by a total
of 350 MW. Also in 2018, 39 wind plants and 21 demandside management units were contracted to provide system
services, including more than 99 MW of fast frequency
response and 111 MW of primary operating reserves.
System strength, protection, and frequency regulation
were also explored for 2020 and were not an issue in the
short term. However, EirGrid initiated an exploration of the
2030 system where it will be operating close to 100% SNSP.
It is expected that grid-forming capability from IBRs will be
considered in this study.

Modeling and Synchronous Generation
Management in South Australia
The state of South Australia sits at one end of the eastern
Australian interconnection, also known as the National
Electricity Market (NEM). While not an islanded system,
only one double-circuit ac interconnection spans the
580 mi between synchronous generation centers in South
Australia and the next N E M reg ion. I n 2018, Sout h
Australian wind output exceeded regional demand approximately 5% of the time, and instantaneous output peaked at
144% of regional demand. Additionally, more than 30% of
households i n Sout h Australia have distributed PV
(DPV) systems.
The operator of the NEM, the Australian Electricity
Market Operator (AEMO), has the challenge of operating a system that can transition in 12 h from one with only
synchronous generators online to one in which IBR output
significantly exceeds regional demand. Under these conditions, dynamic performance is dominated by the response
of IBRs. To operate stably, current IBR technology requires
a level of grid strength provided by synchronous machines.
AEMO faces challenges similar to those of ERCOT and
EirGrid. AEMO must now explicitly ensure that sufficient
synchronous generators remain online at all times within
South Australia, specifically to ensure adequate postfault
recovery, during the periods of highest IBR penetration.
The NEM design does not feature centralized real-time
commitment or a binding precommitment of generating
november/december 2019

units. Out-of-merit dispatch is, therefore, used to ensure
sufficient synchronous generation commitment. Much of
the synchronous generation in South Australia is relatively
inflexible, with start times of several hours or more and high
minimum generation levels in some cases. None of the large
synchronous generators is capable of operating in synchronous condenser mode.
Assessing the performance of the South Australian
power system requires accurately modeling the behavior
and interaction of multiple, widely dispersed IBRs, under
low grid strength conditions, in a system where they may
be the dominant generation technology. Traditional dynamic
modeling tools are inadequate. So AEMO developed a large
electromagnetic transient model of the entire South Australian region, which includes all synchronous generation, gridconnected IBRs, the transmission network, and important
network and generation protection systems.
These studies have identified 1) the need for a minimum
of four-to-five synchronous machines (approximately 150-
200 MVA each) to remain online in South Australia at all
times and 2) the maximum wind output under low inertia
conditions. These limits resulted in curtailment of approximately 4% of wind generation in the fourth quarter of 2018.
While the ac interconnection to the rest of the NEM is
vital for short-term balancing and economic interchange, it
does not provide sufficient grid strength for reliable postfault recovery of IBRs in South Australia. So this function
must be provided locally. New rules introduced in 2018
require maintaining both minimum fault levels at selected
transmission nodes and minimum regional levels of inertia under certain operating conditions. These rules support
contracting arrangements with synchronous generators
or the potential construction of synchronous condensers
where this makes economic sense. The regional transmission owner is currently tendering for synchronous condensers, partly to reduce out-of-merit dispatch driven by
reliability concerns.
South Australia also has high levels of DPVs, which continues to grow rapidly. At times, 50% of regional demand
is served by distributed energy resources (DERs), and this
is forecast to reach 100% by 2027 (Figure 7). DERs add
another layer of complexity to the variability and IBR issues.
High DER penetrations require DER control and communication infrastructure, strong ride-through capabilities, grid
support requirements, and suitable DER dynamic simulation
models (see the article "Ensuring Bulk Power System Reliability" in this issue).

A Way Forward
The case studies in this article show how the technical
barriers of renewable integration are being overcome
and redefined across the industry. While each system
is unique, their planners and operators have innovated
to increase system f lexibility, which is essential for
large-scale renewable integration. Flexibility has been
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IEEE Power & Energy Magazine - November/December 2019

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