IEEE Electrification - March 2021 - 8

TECHNOLOGY LEADERS

but it also limits the ability of transmission owners (TOs) and operators
to improve their fleet's performance.
The NERC published " Reliability
Guideline: Improvements to Interconnection Requirements for BPS-Connected Inverter-Based Resources " in
September 2019, which included a
major section on data recording and
real-time monitoring requirements
for BPS-connected inverter-based
resources. TOs are strongly encouraged to ensure that their interconnection requirements explicitly cover
monitoring equipment and can adequately capture the following:
1) high-resolution, point-on-wave
data at the point of interconnection, capturing the overall plant
performance related to BPS disturbances; commonly captured
via the plant-level controller or a
digital fault recorder
2) continuously recorded synchronized phasor measurement data
capturing active and reactive current (and power), phase and positive sequence voltages, and bus
frequencies; commonly captured
via the plant-level controller or
a PMU
3) high-resolution, point-on-wave
oscillography data on the ac and
dc sides of some individual
inverters to better understand
the behavior of inverters during
large disturbances
4) sequence-of-events data from all
elements within a plant, including inverter fault codes and
changes in status, time-synchronized with a resolution of 1 ms.
The ability to perform postmortem
forensic analysis on the performance
of inverter-based resources hinges on
the ability to have the data described
previously. Without this information,
we as an industry continue to struggle
to fully and comprehensively understand the interactions of power
electronics with the bulk grid. No
simulation can truly replace realworld experience with actual equipment installed in the field.

8

I E E E E l e c t r i f i cati o n M agaz ine / MARCH 2021

Data Transfer Across
a Transmission-Distribution
Interface With Increasing
DERs
With the rapid pace of DER interconnection in many parts of North
America, information exchanges
across the transmission-distribution
(T-D) interface are more important
now than they ever have been before.
Grid operators are faced with ensuring BPS reliability and resilience
while a growing percentage of
resources is located on the distribution system and, in many cases,
behind the meter, with little to no
visibility to the transmission-side
entities. These issues are faced by
grid planners and operators from
California to North Carolina and even
in the New England region.
As the generation mix moves
toward more distribution-centric
resources, BPS grid operators are challenged with using the resources and
services they have available to balance generation and demand, manage BPS voltage profiles, and ensure
BPS stability and security. While net
loading quantities may be sufficient
at very low DER penetration levels, the
lack of information exchanged across
the T-D interface poses significant
challenges to future BPS grid operators and planners. DERs behave with a
different steady-state profile and
dynamic response characteristic than
end-use loads. Resource adequacy
analyses need to account for the variability and uncertainty of renewable
energy so that planners can ensure
the adequate availability of capacity
and energy to meet demand during
all 8,760 h of the year. Grid stability
planners must address the possible
abnormal behavior and tripping of
DERs during BPS fault events, which
have been observed in multiple
instances in southern California.
Transmission-level energy management systems may need access to
information beyond net quantities at
the T-D interface for SCADA and
advanced applications.

The NERC System Planning
Impacts from Distributed Energy
Resources Working Group recently
published " Reliability Guideline: DER
Data Collection for Modeling in Transmission Planning Studies, " providing
the industry with recommended practices for gathering data used for developing planning models that include a
representation of DERs such that planning assessments can be performed
adequately. The guideline is intended
to bridge the language barrier between
distribution entities that have limited
data from DER interconnections and
the transmission planners who need
suitable information to populate
aggregate DER representations in
power flow and dynamic simulations.
With limited information about the
forecast capacity level of DERs, the
expected vintage (and, therefore, the
default settings) of DERs, and any relevant interconnection requirements
that may be in place, transmission
planners can make reasonable engineering judgments to develop DER
models in planning assessments.
However, information regarding currently installed DERs and projected
future installations is critical to develop a baseline understanding from
which sensitivity studies can performed. Without data to populate
models for performing simulations,
entities are unable to determine the
level of impact that DERs may be having on their systems. Entities cannot,
and should not, presuppose impacts
to drive the need for data collection;
rather, the data should be available to
drive the identification of potential
impacts and appropriate solutions
to mitigate any potential reliability issues.
Innovative solutions are being
developed to address many of the
impending issues associated with
high penetrations of DERs and their
impact on the traditional BPS and
distribution systems in the planning
and operations horizons. Table 1
presents examples of potential issues
and possible solutions that may be
IEEE Electrification - March 2021

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