Contingency Selection:
The planning studies for the transmission system are performed for normal and
contingency conditions in accordance with NERC Reliability Standards TPL-001 through
004.
The following information was taken from Table I of the NERC Reliability Standards. Notes
have been added (in italics) to demonstrate how Duke Carolinas Transmission Planning
complies with Category A through D of Table 1.
TPL 001– Category A [TPL 1: R 1.3.7]
Category A – No Contingencies, all facilities in service. Base case is screened for thermal
and voltage violations. [TPL 1: R 1.3]
TPL 002 – Category B [TPL 2: R 1.3, R 1.3.1, R 1.3.7, and R 1.5]
Category B – Event resulting in the loss of a single element
Single Line Ground (SLG) or 3-Phase Fault, Normal Clearing:
1. Generator – Duke will evaluate the loss of the largest generating unit at each
transmission voltage level at each significant station.
2. Transmission Circuit - Duke will evaluate the loss of every 100 kV, 115 kV, 138 kV, 161
kV, 230 kV, 500 kV, and network 44 kV transmission circuit on the system.
3. Transformer – Duke will evaluate the loss of every 230-100 kV, 230-100-44 kV, 115100 kV, 138-100 kV, 230-161 kV, 161-66 kV, 500-230 kV, and 100-44 kV transformer
on the system.
4. Single Pole (dc) Line – Not applicable at Duke Energy.
5. Transmission level reactive power sources. (capacitors and reactors)
6. Loss of an Element without a Fault. - Loss of a breaker without a faultThese contingencies will not impact radial lines or clean lines. Therefore, most Duke
230 kV lines, 161 kV, and 44 kV lines will not apply. The loss of a breaker at one end
without a fault could impact 3 terminal lines and lines with delivery taps, therefore
most of these contingencies will be on the 100 kV with some on the 44 kV.
Duke Energy Carolinas Transmission Planning selects all Category B contingencies which,
based on engineering judgment, produce the most severe system results. [TPL 2: R 1.3.1]
Several 230 kV tie stations on the Duke Carolinas system have incomplete double bus or
breaker-and-a-half designs. Thus, abnormal single contingency configurations can
result. To properly screen for violations of the guidelines, the following table indicates
the additional contingencies that should be modeled.
Tie Station
Outaged Facilities for
230 kV line fault
Outaged Facilities
for
230 kV line fault
The tx and a line
Test against Short
term ratings
Test against Long
Term ratings
Bush River
Hodges
Lakewood
McDowell
Morningstar
The line and
transformer
The line
The line
The line
The line
Line and Tx, Line only
Tx only
Line and Tx, Line only
Line and Tx, Line only
Line and Tx, Line only
Line and Tx, Line only
Line and Tx, Tx only
Line and Tx, Tx only
Line and Tx, Tx only
Line and Tx, Tx only
The line
The line
The tx and a line
The tx and a line
The tx and a line *
The tx and possibly
a line*
The tx and line
The tx and tap line
Peacock
Shady Grove
The line
The line and
transformer
The tx and Line
The tx and possibly
a line *
Line and Tx, Line only
Tap Line and Tx, Line
only
Line and Tx, Line only
Line and Tx, Line only
Line and Tx, Tx only
Tap Line and Tx, Tx
only
Line and Tx, Tx only
Line and Tx, Tx only
Tuckaseegee**
Woodlawn
*Depends on which 230/100 kV transformer experiences the fault. ** 230/161 Transformer
Typically Duke Energy Carolinas bases the annual transmission system assessment on
summer peak conditions. Duke does not plan to take out bulk equipment or generation
during summer peak. Duke plans the system to accommodate the maintenance of the
largest generating unit (at each transmission voltage level) at any significant generating
plant on the Duke system. [TPL 2-3: R 1.3.12, TPL 4: R 1.3.9] Duke Carolinas creates one
generator maintenance case for the largest unit at each transmission voltage level at each
significant generating plant. Additional maintenance cases are created by outaging all
units at small hydro plants and combinations of gas/steam units at combined cycle plants.
For TPL-002, the generator maintenance outage is followed by an economic dispatch and
transmission contingencies (lines, transformers, capacitors, and generators). The
generation (MW) deficiency created by a generator contingency is made up by a
combination of internal Duke generation and imports from adjacent VACAR control areas
as defined by the VACAR Reserve Sharing Agreement. Duke typically holds back 8 Lincoln
CTs to supply our VACAR reserve sharing obligation, thus these units are first dispatched
to provide Duke’s approximate 515 MW reserve obligation followed by additional imports
divided among DVP (35%), PEC (31%), SCPSA (17%), and SCEG (17%) to replace any
remaining generation deficiency.
In support of Duke’s responsibilities under the VACAR Reserve Sharing Agreement, Duke
creates VACAR Reserve Sharing (VRS) cases to analyze Duke’s ability to export its reserve
sharing requirement when called upon to respond to the loss of a VACAR generating unit,
a DCS event, which requires recovery within 15 minutes by replacing the generation.
These VRS cases dispatch Duke’s fast-response Lincoln units to meet Duke’s obligation of
providing approximately 515 MW to the generation deficient VACAR control area. Duke
creates VRS cases for the loss of the largest units in VACAR. Transmission and generator
contingencies are run against the VRS cases. The impact of the inrush associated with
Duke’s VRS imports is studied in Duke’s generator contingency analysis.
TPL 003 – Category C: - [TPL 3: R 1.3, R 1.3.1, R 1.3.7, and R 1.5]
Category C - Event(s) resulting in the loss of two or more (multiple) elements.
Single Line Ground (SLG) Fault, with normal clearing:
1. Bus Section – Duke will evaluate the loss of every bus between 100 and 500 kV.
2. Breaker - Duke will evaluate the loss of every 100 kV to 500 kV breaker at a station
which results in a scenario that is not otherwise covered under Category B or C.
SLG or 3 ph Fault, with normal clearing; Manual System Adjustments, followed by
another SLG or 3 ph Fault with normal clearing.
3. Category B (B1, B2, B3 or B4) contingency, manual system adjustments, followed by
another Category B (B1, B2, B3 or B4) contingency – Duke will evaluate double
contingencies that do not result as a function of Category C events #1 or #2. Studies
will encompass lines rated between 100 kV and 500 kV, and transformers with both
voltages between 100 and 500 kV, generators and tie lines.
4. Bipolar (dc) line fault (non 3-ph) with normal clearing – Not applicable at Duke Energy.
5. Any two circuits of a multiple circuit tower line- Covered in # 3.
SLG Fault, with delayed clearing (stuck breaker or protection system failure):
6. Generator – All generators connected to the Duke transmission system have delta – wye
grounded step-up transformers, which eliminates all zero sequence fault current contributions
from the generator to the transmission system. Additionally, each generator has a current
limiting resistor on the neutral, which significantly reduces the available zero sequence fault
current contribution for a fault on the low side of the generator step-up transformer(s).
Because C6 only considers a SLG fault, all C6 contingencies are encompassed by B1 and C2
contingencies for steady-state analysis. The fault in conjunction with a stuck breaker will be
identical to a fault occurring on the stuck breaker and therefore be encompassed by a C2
contingency.
7. Transformer – In steady-state analysis, the loss of any 230-100 kV, 230-100-44 kV, 115-100 kV,
138-100 kV, 230-161 kV, and 500-230 kV transformer on the system in conjunction with a
protection system failure will be encompassed by other category B or C contingencies. When
redundant transformer differential relaying is present, the failure of one does not result in
more elements being removed from service than a B3 contingency. When redundant
transformer differential relaying is not present, remote backup relaying removes the same
elements from service as in the case of a bus differential relay failure, therefore the result is
the same as a C9 contingency. The fault in conjunction with a stuck breaker will be identical to
a fault occurring on the stuck breaker and therefore be encompassed by a C2 contingency.
8. Transmission Circuit – In steady-state analysis, the loss of any 100 kV or greater transmission
circuit with delayed clearing will be encompassed by other category B or C contingencies. In
the case of a relay failure, local backup or redundant relaying will remove the same elements
from service as a B2 fault. The fault in conjunction with a stuck breaker will be identical to a
fault occurring on the stuck breaker and therefore be encompassed by a C2 contingency.
9. Bus Section – Duke Energy Carolinas will evaluate the loss of every 100 kV or greater bus
section on the system where the loss of that bus section with a stuck breaker or protection
system failure results in more elements being removed from service than a C1, C2, C3 or C5
contingency.
Duke Energy Carolinas Transmission Planning selects all Category C contingencies which,
based on engineering judgment, produce the most severe system results. [TPL 3: R 1.3.1]
Because the probability of Category C events is much lower than Category B, these
contingencies will be run only against the base case. Typically Duke Energy Carolinas bases
the annual transmission system assessment on summer peak conditions. Duke does not
plan to take out bulk equipment or generation during summer peak.
TPL-004 Category D: [TPL 4: R 1.3, R 1.3.1, and R 1.4]
Category D-: Extreme event resulting in two or more (multiple) components removed or
cascading out of service. Evaluate for risks and consequences.
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May involve substantial loss of customer demand and generation in a widespread area or
areas.
Portions or all of the interconnected systems may or may not achieve a new, stable operating
point.
Evaluation of these events may require joint studies with neighboring systems.
Document measures or procedures to mitigate the extent and effects of such events.
Mitigation or elimination of the risks and consequences of these events is at the discretion of
the entities responsible for the reliability of the interconnected transmission systems.
3Ø Fault, with Delayed Clearing (stuck breaker or protection system failure):
1. Generator – Duke Energy Carolinas has determined that most delayed clearing 3Ø generator (D1)
contingencies are encompassed by B1 and C2 contingencies, because local backup relaying will not
remove any additional elements from service (with the possible exception of the GSU, which would
be encompassed by a B3 or C2 contingency). For those contingencies that are not encompassed by
other category B or C contingencies, they are generally encompassed by D8 and D10 contingencies.
Additional D1 contingencies will only be evaluated on an as-needed basis if additional elements are
removed from service.
2. Transmission Circuit1 – Duke Energy Carolinas has determined that all delayed clearing 3Ø
transmission circuit (D2) contingencies are encompassed by C8 contingencies, therefore no
additional delayed clearing 3Ø transmission circuit contingencies are performed.
3. Transformer1 – Duke Energy Carolinas has determined that all delayed clearing 3Ø
transformer (D3) contingencies are encompassed by C7 contingencies, therefore no
additional delayed clearing 3Ø transformer contingencies are performed.
4. Bus Section1 – Duke Energy Carolinas has determined that all delayed clearing 3Ø bus
section (D4) contingencies are encompassed by C9 contingencies, therefore no additional
delayed clearing 3Ø bus section contingencies are performed.
1
Review of Duke Energy Carolinas’ protection system schemes and failure modes has determined that
delayed clearing SLG contingencies and delayed clearing 3Ø contingencies can be treated the same in
steady state analysis. The only exception to this is in the event when there is a protection system failure
in the SLG case. These SLG contingencies can result in more elements being removed from service and
take longer to clear than the equivalent 3Ø contingency and are therefore more severe. There are no
3Ø contingencies that result in more elements being removed from service or that are more severe than
the equivalent SLG contingency.
3Ø Fault, with Normal Clearing:
5. Breaker (failure or internal fault) – Duke Energy Carolinas has determined that all breaker
failure relaying removes the same elements from service for a 3Ø breaker contingency and
a SLG breaker contingency for all normally cleared 3Ø breaker contingencies (failure or
internal fault). Therefore all normally cleared 3Ø breaker contingencies are encompassed
by C2 contingencies and no additional 3Ø breaker contingencies are performed.
Other:
6. Loss of tower line with three or more circuits – None exist on the Duke Electric
Transmission System.
7. All transmission lines on a common right-of way- Duke will evaluate the loss of the
following:

Any 500 kV Line that shares a common r/w with a line(s) rated 100 kV or higher for more than
one mile,
Any 230 kV Line that shares a common r/w with a line(s) rated 100 kV or higher for more than
one mile, and
Any 161 kV Line that shares a common r/w with a line(s) rated 100 kV or higher for more than
one mile.
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8. Loss of a substation (one voltage level plus transformers) – Duke will evaluate the loss of
the following:
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500 kV busses and 500-230 kV txs at 500-230 kV stations,
230 kV busses and 500-230 kV txs at 500-230 kV stations,
230 kV busses and 230-100-(44) kV txs at a 230-100-(44) kV station,
100 kV busses and 230-100-(44) kV txs at a 230-100-(44) kV station,
230 kV busses and 230-161 kV txs at 230-161 kV stations,
161 kV busses and 230-161 kV txs at 230-161 kV stations,
100 kV busses and 138-100 kV txs at 138-100 kV stations,
138 kV busses and 138-100 kV txs at 138-100 kV stations,
100 kV busses and 115-100 kV txs at 115-100 kV stations, and
115 kV busses and 115-100 kV txs at 115-100 kV stations.
9. Loss of a switching station (one voltage level plus transformers) – Captured in #8.
10. Loss of all generating units at a station – The stations where all units connect to the same
voltage level are covered by #8. Duke will evaluate the loss of the following:
All generating units (trip only the breakers protecting each generator) that connect to 100
kV or higher via a generator step-up transformer and the loss of all units where units are
connected at different voltage levels in the switchyard.
11. Loss of a large load or major load center - Large loads are interrupted in completing D8.
Category D11 is not selected for evaluation because the contingencies evaluated in D8
produce more severe system impacts.
12. Failure of a fully redundant special protection system (or remedial action scheme) to
operate when required. None exist on the Duke Electric Transmission System.
13. Operation, partial operation, or mis-operation of a fully redundant special protection
system (or remedial action scheme) for an event or condition for which it was not
intended to operate. None exist on the Duke Electric Transmission System.
14. Impact of severe power swings or oscillations from disturbances in another Regional
Council. Not applicable to the thermal portion of the Severe Contingency Analysis.