IEEE Power & Energy Magazine - July/August 2020 - 24

Planning criteria have been developed and applied to
power systems around the world to ascertain the need
for new transmission infrastructure.
new transmission infrastructure. This infrastructure provides
a robust grid so that system operators can address various
operating scenarios on any given day. Planners test the system under simulated stressed conditions (extreme weather,
for example) to understand where reinforcements are needed
to make the grid reliable. Reliability criteria are structured
around likely events. NERC planning criteria require that
the bulk power system be tested for contingencies, such as
the loss of a transmission line, under the assumption that
every other transmission facility is in service. Yet in reality, dozens of facilities are out of service on any given day.
More severe, lower-probability events, such as multiple facility outages, are also tested, known as the N−1−1 test. For
example, these could include the loss of two circuits on a
common tower line, a fault on a circuit followed by a breaker
failure, or two unrelated contingencies.
NERC standards do address resilience, to a degree. Planning
standards require the examination of the impact of extreme
events, such as the loss of an entire substation or a whole
right-of-way because of a landslide, tornado, or fire that takes
down multiple transmission lines in one corridor. Although
an assessment of the impact of these events is required, reinforcement for these low-probability events is not mandatory
under current NERC criteria. To achieve grid resilience,
planners must also assess whether the transmission system
is sufficiently reinforced to address extreme events, including physical and cybersecurity attacks and extreme weather
conditions such as hurricanes.

Regional Transmission
Expansion Planning
We have initiated efforts to implement regional transmission
expansion planning (RTEP) process criteria and metrics to
enhance grid resilience beyond what is in place today. NERC
Reliability Standard CIP-014 requires transmission owners
to assess and identify critical facilities that, if rendered inoperable, would result in instability, uncontrolled separation,
or cascading outages. Experience suggests that developing
RTEP projects in response to resilience criteria could be
accomplished through three decision-making approaches:
1) Do no harm: The solution to an identified reliability criteria violation must not introduce other reliability issues.
2) Leverage project opportunities: Use projects that are already identified under reliability, market efficiency needs,
or public policy requirements to solve resilience issues.
3) Respond proactively: Introduce new projects specifically for resilience.
24

ieee power & energy magazine

Under each approach, metrics are required to assign a resilience score to every transmission facility (substation, line,
and transformer) based on its criticality.
System resilience is a key consideration in the evaluation of solution alternatives so that initiatives are selected to
enhance resilience as part of addressing other criteria violations or as stand-alone measures. Resilience vulnerabilities
that are significant enough to warrant a transmission system
enhancement could be integrated into the RTEP, for example, including building redundancy into black-start generation-cranking paths, reducing the criticality of substations
through transmission line siting, and facilitating power flow
diversity for areas with load congestion or high concentrations of critical restoration generating units. While the formal
implementation of these transmission-planning approaches
is pursued, parallel resilience initiatives continue in several
other areas; for example, spare transformers need identification and cascading-event analysis tool development.

Spare Transformers
As the transmission system in the United States ages, mitigating the risk of high-voltage equipment failures becomes
an increasingly important issue for transmission owners and
operators. Transmission owners must anticipate procurement lead times when planning for emergencies and unexpected equipment replacements. Certain equipment, such as
power transformers, can take up to 18 months from the time
it is ordered until it is delivered and installed. This wait time
can limit the speed of system restoration. Mitigating this
requires transmission owners to develop asset management
strategies, including condition assessments and monitoring
equipment closely. The purpose is to maintain reliability and
control costs.
To address these strategic objectives, in 2006, a probabilistic risk assessment (PRA) model was developed for managing the existing 500/230-kV transformer infrastructure.
The model couples transformer conditions and asset-specific
data provided by transmission asset owners with information
from market analyses. This data helps estimate the annual
likelihood of failure as well as the potential replacement
costs and installation time for each transformer. The market
analyses provide the expected congestion costs associated
with the loss of each transformer. The PRA model combines
failure likelihood and congestion information to determine
the annual risk, in U.S. dollars, to the system from the loss
of a transformer. The PRA is performed biennially to minimize transformer fleet risk exposure.
july/august 2020

IEEE Power & Energy Magazine - July/August 2020

Table of Contents for the Digital Edition of IEEE Power & Energy Magazine - July/August 2020