IEEE Power & Energy Magazine - November/December 2021 - 47

The control algorithms that dictate the
response of IBRs to grid conditions
vary across inverter designs and manufacturers.
The challenges are compounded as most inverters currently
do not provide certain services like inertia response
and high-fault current, both of which contribute to maintaining
stability. This system/device interaction demands a
co-design approach with a simultaneous focus on both the
system and the inverter to reach a low-cost and effective
overall solution. Finding a solution requires close working
relationships and collaboration with industry solution
providers such as inverter manufacturers. Therefore, the
Inverter Design Research Program focuses on capabilities,
services, design methodologies, and standards for IBRs
(Table 2). It also examines the cost implications of these
designs in terms of additional hardware and tradeoffs with
other performance measures like efficiency or load factor.
Figure 1 highlights the impacts of photovoltaic (PV)
inverter-level voltage control on a test system with no synchronous
generation. The test system is an adapted portion
of the North American Eastern Interconnection, with
165 buses, 112 branches, and 1.1 GW of load represented
as constant-current active power and constant-impedance
reactive power. The loads are supplied by 17 inverter-based
devices, including seven type IV wind plants, eight PV
plants, and two static synchronous compensators. The total
generation capacity is 2.2 GW. The wind plants have local
voltage control on the grid-side converter, and they have
no plant controller or frequency-response capability. There
is a 480-km, 1-GW, uncompensated 345-kV transmission
corridor comprising three parallel conductors to a compact
load center located at the far end of the transmission corridor
with static synchronous compensators at either end. A
solid six-cycle, three-phase fault to ground at the sending
end of the 480-km transmission corridor is simulated for
the following scenarios:
1) Scenario 1: Of the eight PV plants, only one has inverter-level
voltage control. The remaining seven plants are
set to operate on inverter-level reactive power control.
2) Scenario 2: Of the eight PV plants, four (including the
plant from Scenario 1) have inverter-level voltage control.
The remaining four are set to operate on inverterlevel
reactive power control.
3) Scenario 3: All eight PV plants operate on inverter-level
voltage control.
In Scenario 1, with a minimal number of devices on inverterlevel
voltage control, the system is unable to achieve a postdisturbance
steady state and results in a complete system collapse.
However, with the increased number of plants on inverter-level
voltage control, not only does the system stabilize quickly, but
november/december 2021
increasing the number (i.e., Scenario 3 compared with Scenario
2) has a pronounced benefit on voltage recovery.
These simulation results illustrate many aspects of the
Inverter Design Research Program (e.g., research question
table 2. Inverter Design
Research Program questions.
1) What are the needs of a power system (to achieve
security and good regulation) expressed in technologyneutral
form, and how do these needs map to services that
any resource, including an IBR or a synchronous machine,
can provide?
2) For each service defined in question 1, how feasible is
it to provide from IBRs, what " cost " does it add, and what
limitations exist on its magnitude and duration of service?
What implications do these have for system operations?
3) What are the limitations of each IBR technology option to
provide frequency-control services, and how do the various
frequency services overlap and compete?
4) What design standards or dispatch guidance should be
introduced to avoid instability (e.g., caused by phase-locked
loops or other elements) in weak grids? This is a more
widely drawn version of the question on minimum ratios of
grid-forming to grid-following inverters.
5) What are the appropriate inverter capabilities and,
consequently, control design methods for operation in grids
with a high percentage of IBRs? Are standard configurations
and combinations of services helpful in simplifying
operational decision making?
6) Are the black-box models (impedance spectrum and
binary code) favored by manufacturers for disclosure
sufficient for stability assurance and system design across all
problem types?
7) What recommendations should be made for standard
behaviors of IBRs in certain frequency ranges for different
power system conditions to aid system design? For example,
should a contribution to damping be mandatory at certain
frequencies?
8) What impedance requirements should be placed on IBRs
to suppress negative-sequence and low-order harmonic
currents?
9) How will protection systems need to change to
accommodate high penetrations of IBRs, and what possible
actions might an inverter take during a fault that would aid
fault detection and location?
10) What is the future of frequency control as the synchronous
generation fraction reduces? Might tightened or
loosened frequency limits lead to a more reliable, secure,
lower-cost IBR-based power system?
11) At what point is it better to break from trying to replicate
synchronous machine features and exploit the wider flexibility
of inverters?
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IEEE Power & Energy Magazine - November/December 2021

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