IEEE Power & Energy Magazine - November/December 2019 - 31

The key to the reliable and efficient integration of IBRs lies in
adopting best grid operation practices: having the appropriate
grid codes avoids costly reliability problems in real time, accurate forecasting allows the grid operator to efficiently schedule
other resources, and ancillary services can mitigate risks associated with forecast errors. This enables IBRs to provide many
of the services usually provided by synchronous generators.
ERCOT currently has four types of ancillary services:
regulation service up (reg-up), regulation service down
(reg-down), responsive reserve service (RRS), and nonspin
reserve service (NSRS). Prior to the huge growth in IBRs,
ERCOT procured mostly a fixed level of RRS and NSRS
throughout the year. This static approach is no longer appropriate with ERCOT's high IBR penetration levels.
Regulation provides 4-s system balancing so that
ERCOT can maintain grid frequency, per North America
Electric Reliability Standard BAL-001, which uses the
Control Performance Standard 1 (CPS1) metric. Prior to
2010, ERCOT had a zonal market with a 15-min dispatch.
In 2009, ERCOT procured an average of 825 MW of reg-up
and 851 MW of reg-down. In 2010, ERCOT switched to a
nodal market with a 5-min security-constrained economic
dispatch (SCED). Contrary to the conventional wisdom
that VERs increase regulation requirements, ERCOT today
maintains one of the best CPS1 scores in North America
while reducing regulation procurements year over year
(Figure 6). This has been achieved through 5-min dispatch,
refining its SCED algorithm, load frequency control tuning,
requiring VERs to follow ERCOT base points under some
system conditions, and a primary frequency response (PFR)
grid code requirement.
RRS is procured by ERCOT primarily to arrest frequency
declines below 59.40 Hz for the loss of 2,750 MW of generation. Increased VER levels displace synchronous generators
and the inertia they provide. For an island grid, inertia largely
determines the rate of change of frequency (ROCOF) following generator-loss events. If inertia falls below 100 GW/s, the
loss of 2,750 MW would result in the frequency dropping
so quickly that underfrequency load-shedding would occur
before the fastest reserve could respond (0.5 s is the response
time of demand response triggered by underfrequency relays).
RRS in ERCOT primarily comes from generators providing PFR and load resources with underfrequency relays. In
2015, ERCOT started factoring anticipated system inertia
into RRS procurements. The peak RRS requirements generally coincide with the low-demand, high-wind early morning
hours (1-4 a.m.).
The 30-min NSRS provides reserves to address load or VER
forecast errors. Today, NSRS is procured for underforecast
errors of load and overforecast errors of VERs. When the net
load is likely to be ramping up, ERCOT procures NSRS sufficient to cover the 95th percentile of the net forecast errors. When
the net load is not likely to ramp up, ERCOT procures NSRS
that may only be sufficient to cover the 70th percentile of the net
forecast errors.
november/december 2019

ERCOT identifies hourly ancillary service requirements
for the upcoming year during the fall of the previous year,
and historical data play a significant role in determining
these requirements. Since ancillary service quantities are
determined months in advance, cutting-edge tools help control-room operators identify real-time shortages in RRS or
NSRS. ERCOT's ancillary service products, designed more
than two decades ago, were recently revised to include contingency reserve service as a new product and fast frequency
response as a subset of the existing RRS.

New System Services in EirGrid
Similar to ERCOT, Ireland's grid is also islanded with limited dc interconnection to Great Britain. In 2008, EirGrid,
the transmission system operator for Ireland and Northern
Ireland, pioneered the analysis of the impact of high penetrations of IBRs on transient stability. The system operator
faced several daunting challenges to reaching 75% system
nonsynchronous penetration (SNSP differs from the IBR
metric in that net imports are added to the IBR generation and net exports are added to the demand) and 1-Hz/s
ROCOF. These included
✔ managing system stability
✔ controlling system voltage (when more than 25% of
the total transmission-based synchronous generator
reactive power sources would be displaced)
✔ protecting the system from overfrequency events (loss
of export under high wind conditions)
✔ managing the uncertainty of a weather-dependent system.
Today, EirGrid operates the grid up to 65% SNSP with a
0.5-Hz/s ROCOF limit. In November and December 2018,
wind power provided more than 43% of the total energy consumed. Over the entire year, wind served more than 30% of
demand. An additional 1,000 MW of wind power is expected
to be connected in the next 12 months. To successfully integrate this wind power, the company plans to operate the system up to a 75% SNSP ratio and up to 1-Hz/s ROCOF by 2020.
At these high IBR penetration levels, the system stability
issues largely arise due to low synchronizing torque. This
might be partially mitigated by grid-forming inverters. However, currently the grid code does not require grid-forming
inverters, and an understanding of how this new technology
would perform and interact with the rest of the system is
still being developed. To date, EirGrid has fundamentally
revamped its system services to provide incentives for introducing technologies that provide synchronous-like torque
and strong reactive power support when wind output is high.
With these new system services, there is likely to be sufficient capability in the existing portfolio to reach the 2020
targets efficiently and effectively.
Ancillary services had previously been a very small market (€50 million per year or 2% of generator revenues). The
revamped market guarantees incentives are in place for at
least six years, as opposed to one year previously, and has
a value of up to €235 million per year (in 2018, it was €180
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IEEE Power & Energy Magazine - November/December 2019

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