TI 2515/194
See also TI 2515/192 for more OPC
- https://www.nrc.gov/docs/ML2023/ML20230A328.pdf - Rev 2
- https://www.nrc.gov/docs/ML1713/ML17137A416.pdf
Text
Issue Date: 08/18/20 1 2515/194 Rev 2
NRC INSPECTION MANUAL EEOB
TEMPORARY INSTRUCTION 2515/194 REVISION 2
INSPECTION OF THE LICENSEES’ IMPLEMENTATION OF INDUSTRY INITIATIVE
ASSOCIATED WITH THE OPEN PHASE CONDITION DESIGN VULNERABILITIES IN
ELECTRIC POWER SYSTEMS (NRC BULLETIN 2012-01)
Effective Date: 08/18/2020
CORNERSTONE: Initiating Events, Mitigating Systems
APPLICABILITY: This Temporary Instruction (TI) applies to the holders of operating licenses
for operating nuclear power reactors who have implemented actions to
protect against open phase conditions (OPCs). This TI is to be performed
at all current operating plants with the exception of Seabrook Station, Unit
1, plants seeking NRC approval in accordance with 10 CFR 50.90, and
sites that have informed the NRC of their intent to decommission prior to
01/30/2021.
2515/194-01 OBJECTIVE
01.01 To verify that licensees have appropriately implemented the Nuclear Energy Institute
(NEI) voluntary industry initiative (VII), Revision 3, including updating their licensing
basis to reflect the need to protect against OPCs.
2515/194-02 BACKGROUND
Event at Byron Nuclear Plant
On January 30, 2012, Byron Station, Unit 2 experienced an automatic reactor trip from full
power because the reactor protection scheme detected an undervoltage condition on the 6.9
kilovolt (kV) buses that power reactor coolant pumps (RCPs) B and C (undervoltage on two of
four RCPs initiate a reactor trip).
Byron Station is a two-unit pressurized water reactor plant. The electrical distribution system for
each unit consists of four non-safety 6.9-kV buses, two non-safety 4 kV buses, and two
engineered safety features (ESF) 4-kV station buses. During normal plant operation, the safety
(or ESF buses) and non-safety buses (or non-ESF) are powered from the Unit Auxiliary
Transformers (UATs). On the day of the event, two non-ESF 6.9-kV station buses that power
two of the RCPs and the two 4-kV (ESF and non-ESF) buses were supplied by station auxiliary
transformers (SATs) connected to the 345-kV offsite power switchyard (Figure 1 below). The
other two 6.9-kV and 4-kV buses were powered from the UATs. The undervoltage condition on
the SAT powered buses was caused by a broken inverted porcelain insulator stack of the phase
C conductor for the 345-kV power circuit that supplies both SATs. The insulator failure caused
the associated phase C conductor to break off from the power line disconnect switch resulting in
a high impedance ground fault through the fallen phase C conductor and a sustained open
phase condition (OPC) on the high voltage side of the SAT. The open circuit created an
Issue Date: 08/18/20 2 2515/194 Rev 2
unbalanced voltage condition on the two 6.9-kV non-ESF RCP buses and the two 4.16-kV (ESF
and non-ESF) buses. After the reactor trip and subsequent generator trip, the two 6.9 kV
buses, which were aligned to the UATs, automatically transferred to the SATs, as designed. As
a result of the open circuit on C phase, the load current in phases A and B increased and
caused the remaining two operating RCPs to trip on phase overcurrent. In the absence of any
operating RCPs, control room operators performed a natural-circulation cooldown of the plant.
The SATs continued to power the 4.16 kV ESF buses A and B because of a design vulnerability
that did not isolate the safety related buses from the degraded offsite power system. Some ESF
loads that were energized relied on equipment protective devices to prevent damage from an
unbalanced overcurrent condition. The phase overcurrent condition caused by the OPC
actuated relays to trip several ESF loads.
Approximately 8 minutes after the reactor trip, the control room operators diagnosed the loss of
the phase C condition and manually tripped circuit breakers to separate the unit buses from the
offsite power source. When the operators opened the SAT feeder breakers to the redundant
4.16-kV ESF buses, the loss of voltage relays started the emergency diesel generators (EDGs)
and restored power to the ESF buses. If the condition had been allowed to persist for an
additional few minutes, damage to the RCP seals could have occurred through a loss of RCP
seal cooling water. This in turn, could have resulted in a loss of coolant from the RCP seals in
the containment building.
Figure 1. Simplified Schematic of Electrical busses associated with one train (Unit 2)
Issue Date: 08/18/20 3 2515/194 Rev 2
A second event also occurred at Byron Station Unit 1 on February 28, 2012. This event was
also initiated by a failed inverted porcelain insulator that resulted in an open phase as well as a
phase-to-ground fault on the line side of the circuit. In this event, the fault current was high
enough to actuate protective relaying on the 345-kV system. The 4.16-kV ESFs buses
experienced a loss of voltage (LOV) caused by the opening of 345-kV system breakers, which
resulted in a separation of the SATs from the 4.16-kV buses. The two EDGs started and
energized the 4.16-kV ESF buses, as designed.
Operating Experience
A review of other operating experience identified design vulnerabilities associated with single
phase open circuit conditions at South Texas Project (South Texas), Unit 2 (Licensee Event
Report (LER) 50 499/2001 001, Agencywide Documents Access and Management System
(ADAMS) Accession No. ML011010017); Beaver Valley Power Station, Unit 1 (LER 50
334/2007 002, ADAMS Accession No. ML080280592); and a single event that affected Nine
Mile Point, Unit 1 (LER 50 220/2005 04, ADAMS Accession No. ML060620519) and the
neighboring James A. Fitzpatrick Power Plant (LER 50 333/2005 06, ADAMS Accession
No. ML060610079).
These events involved offsite power circuits that were rendered inoperable because of an open
circuit in one phase. In each instance (except South Texas, Unit 2), the condition went
undetected for several weeks because offsite power was not aligned to the ESF buses and
therefore unloaded during normal operation and the surveillance tests, which recorded
phase-to-phase voltage, did not identify the loss of the single phase. At South Texas, Unit 2,
offsite power was normally aligned to the ESF and non-safety plant buses, and the operator
manually tripped the reactor when the OPC tripped the three circulating water pumps.
Operating experience has identified several international events and the International Atomic
Energy Agency (IAEA) has published a report titled “Impact of Open Phase Conditions on
Electrical Power Systems of Nuclear Power Plants,” detailing the significance and
consequences of such events (Reference: https://www.iaea.org/publications/11026/impact-ofopen-phase-conditions-on-electrical-power-systems-of-nuclear-power-plants.)
Industry Initiative to Resolve OPC Design Vulnerability Issue
In response to the Byron event, the industry’s chief nuclear officers approved a formal initiative
to address OPCs. This initiative was communicated to NRC by the NEI in letter dated
October 9, 2013 (ADAMS Accession No. ML13333A147) and acknowledged in the NRC letter
dated December 19, 2013 (ADAMS Accession No. ML13340329). This letter further indicated
that this approved initiative commits each licensee to develop a proactive plan and schedule for
addressing the potential design vulnerabilities associated with OPCs. Subsequently, on
March 16, 2015, NEI informed the NRC (ADAMS Accession No. ML15075A454) that, to provide
adequate time for OPC implementation, the completion schedule would be revised to
December 31, 2018. The industry’s chief nuclear officers approved this schedule change in
Revision 1 of its document. Subsequently, on September 20, 2018, NEI informed the NRC
(ADAMS Accession No. ML18268A114) that to provide adequate time for implementation of the
necessary modifications to the plants and to accommodate an adequate monitoring time
afterwards, the completion schedule would be revised to December 31, 2019, with a minimum
of 24 months for the completion of the associated monitoring period. The industry’s chief
nuclear officers approved this schedule change in Revision 2 of its document. In letter dated
December 14, 2018, the NRC acknowledged the NEI letter (ADAMS Accession No.
Issue Date: 08/18/20 4 2515/194 Rev 2
On June 6, 2019, NEI submitted Revision 3 to the industry initiative (ADAMS Accession No.
ML19163A176), and subsequently submitted the accompanying guidance document, NEI 19-02
“Guidance for Assessing Open Phase Condition Implementation Using Risk Insights,” (ADAMS
Accession No. ML19172A086) on June 20, 2019. Revision 3 of the industry initiative includes
an option for not enabling the Open Phase Isolation System (OPIS) automatic functions based
on assessing the change in risk between operating with automatic functions versus reliance on
operator manual action to isolate a power supply affected by an OPC. The industry’s chief
nuclear officers approved the changes in Revision 3 of its NEI document. In a letter dated July
17, 2019, the NRC acknowledged the NEI letter (ADAMS Accession No. ML19193A192). The
industry initiative described in the June 6, 2019 NEI letter is the VII referred elsewhere in this TI.
Failure Modes and Consequences of OPC
An OPC may result in challenging plant safety. Operating experience in different countries has
shown that the currently installed instrumentation and protective schemes have not been
adequate to detect this condition and take appropriate action. An OPC that affects the safety
function, if not detected and disconnected promptly, represents a design vulnerability for many
nuclear power plants (NPPs). It may lead to a condition where neither the offsite power system
nor the onsite power system is able to support the safety functions, and could propagate to
station blackout. The January 2012 operating event at Byron Station, Unit 2, revealed a
significant design vulnerability where an OPC in the plant’s offsite power supply caused a loss
of certain safety functions powered by the site’s alternating current (ac) electric power system.
The loss of these safety functions occurred because the ESF electric power system's protection
scheme was unable to detect and isolate the loss of a single phase between the transmission
network and the onsite power distribution system. The resulting degraded and unbalanced
voltage conditions on redundant ESF buses led to the tripping of equipment required for normal
plant operations and safe shutdown. The inability of the protection scheme to detect an OPC
and automatically transfer power from the affected electric power system allowed the degraded
offsite power system to remain connected to ESF buses, and prevented other onsite ac sources
(e.g., Emergency Diesel Generators (EDGs)) from starting and powering these buses. As a
result, certain important to safety equipment required for safe operations remained powered by
the degraded ac source. The ability of this equipment to perform the required safety functions
was questionable as the internal protective features installed to prevent damage from
overheating would have either actuated and locked-out the vulnerable components or,
depending on the setpoint, allowed continued operation and thereby risk damage from
overheating. Furthermore, equipment required for safe shutdown was also at risk of being
unavailable for an extended period of time even after the restoration of an operable power
source, since operator actions would be required to manually reset tripped protective devices.
In response to the Byron event, the U.S. and international nuclear industry evaluated the
consequences of an OPC and an unbalanced voltage condition in a three-phase power system.
Continued operation for an extended duration with unbalanced voltage conditions can damage
equipment as a result of overheating and vibration, or result in the inadvertent trip of electrical
equipment and cause a plant transient. Redundant equipment important to safety which is
supplied from a common power source may be damaged when exposed to the unbalanced
voltage conditions. The operators may not always be able to respond promptly to prevent
multiple equipment damage due to a lack of information available from existing measurements,
indications, and automatic actions. The type of fault or transformer winding configuration and
grounding techniques can result in low voltage unbalance conditions (e.g., during light load or
Issue Date: 08/18/20 5 2515/194 Rev 2
no-load conditions), and the degraded conditions can go undetected for a long period of time
and may not be revealed until the transformer load is increased.
The effect of OPC on the operating equipment, typically induction motors, depends on a number
of factors. An OPC in fully loaded power supply system can result in high current flow in at least
one of the three phases of rotating motors. This higher than normal current may actuate the
protective scheme, which disconnects the loads from the degraded source. However, the
magnitude of the current is dependent on the type of transformer and system configuration to
the associated feeder circuits and in some cases the current flow may not actuate protective
relaying and result in excessive heating of the motor windings. Unbalanced voltages applied to
a three–phase induction motor result in unbalanced currents in the stator windings and
introduce a negative sequence voltage. The negative sequence voltage produces a flux rotating
in the opposite direction of the rotation of the rotor, producing additional currents and heating.
The unbalanced conditions result in overheating of the motor. If the protective scheme actuates
and disconnects the load important to safety from the degraded power source, the safe
shutdown capability of the plant may be compromised as the affected component may not be
available until manual actions are taken to identify the cause of the trip, reset the protective
relaying and close the appropriate breaker.
If the circuit with an OPC is in standby mode or lightly loaded, then the low magnitude of current
flow in the degraded circuit may not result in sufficient unbalance to actuate any protective
device. The OPC may therefore not get detected until a change in plant state or a bus transfer
to the offsite standby source results in increasing the load current in the circuit. Once the circuit
has increased demand, then the running motors may trip due to overcurrent protection actuation
or sustain winding damage due to heating effects.
The operating experience as well as results from analytical studies has confirmed that voltages
can be present on all three phases downstream of the OPC due to the interaction of magnetic
fields in transformers and three phase loads. In some cases, all three phases on the low
voltage winding may have balanced voltages in all phases under no load or lightly loaded
conditions. With this regard, the voltage can be regenerated through the systems, but depends
upon:
• Transformer winding, core configuration, and rated power
• System grounding arrangements
• Transformer loading, size and type of loads (e.g. motor or static)
• Properties of cables and overhead lines (capacitance, inductance)
• Location of the open phase.
NRC Actions
Based on the Byron Station operating event, the Nuclear Regulatory Commission (NRC) staff
issued Information Notice 2012-03, “Design Vulnerability in Electric Power System,” dated
March 1, 2012 (ADAMS Accession No. ML120480170). On July 27, 2012, the staff issued
Bulletin (BL) 2012-01, “Design Vulnerability in Electric Power System” (ADAMS Accession
No. ML12074A115). Specifically, the NRC asked licensees to provide information by
October 25, 2012, on (1) the protection scheme to detect and automatically respond to a
single-phase open circuit condition or high impedance ground fault condition on GDC 17 power
circuits, and (2) the operating configuration of ESF buses at power.
Issue Date: 08/18/20 6 2515/194 Rev 2
The Electrical Engineering Branch staff reviewed the information that NRC licensees provided
and documented the details of this review in NRC BL 2012-01, in the summary report dated
February 26, 2013 (ADAMS Accession No. ML13052A711).
In SECY-16-0068, dated May 31, 2016 (ADAMS Accession No. ML15219A327), the staff
requested Commission approval of an Interim Enforcement Policy (IEP), applicable to all
operating reactors, to allow the NRC to exercise enforcement discretion for certain instances of
noncompliance with the requirements specified in the technical specifications (TS) for electrical
power systems (typically TS Section 3.8) and action statement(s) associated with “AC
Sources—Operating” and “AC Sources—Shutdown,” and with GDC 17. This IEP could be
applicable to certain instances of nonconformance with the principal design criteria specified in
the UFSAR.
On March 9, 2017, the Commission issued (ADAMS Accession No. ML17068A297) Staff
Requirements Memorandum (SRM) SECY 16-0068, “Interim Enforcement Policy for
Open-Phase Conditions in Electric Power Systems for Operating Reactors.” The Commission
disapproved the staff’s request to establish an IEP for the purpose of exercising enforcement
discretion for purported noncompliance with NRC requirements and nonconformance with
design criteria during the pendency of licensee implementation of actions to address an OPC.
The SRM stated the following:
“Going forward, the staff should verify that licensees have appropriately implemented the
voluntary industry initiative. If the staff determines that a licensee does not adequately
address potential OPCs, including updating the licensing basis to reflect the need to protect
against OPCs, the staff should consider the appropriate regulatory mechanism to impose the
necessary requirements to protect against OPCs using the current guidance on such matters
from the Office of the General Counsel.
The staff should provide the Commission with a notation vote paper if this situation arises for
any licensee or licensees, with options, including the staff's recommended path forward. In
addition, if disagreements arise between the staff and the industry during implementation of
the voluntary industry initiative, and the related issues have policy implications, the staff
should promptly raise such issues to the Commission for resolution.
Once satisfactory implementation of the technical resolution has been verified for each
licensee, the associated NRC Bulletin should be closed. The staff should update the Reactor
Oversight Process to provide periodic oversight of industry's implementation of the OPC
initiative.”
The staff has written this TI for inspectors to verify whether licensees have appropriately
implemented the technical resolution of OPC design vulnerability as discussed in their industry
initiative document at each operating reactor unit. A TI inspection was chosen as verification of
implementation would closely resemble a plant modification inspection.
Four nuclear power plants (River Bend, Palo Verde, Byron, and St. Lucie) were selected as an
initial set of plants with four distinct designs (OPC detection and protection schemes) to assess
the adequacy of the designs using TI 2515/194, Revision 0. The results of the inspections are
documented in inspection reports 05000458/2018010 (ADAMS Accession No. ML18085B197);
05000528/2018010, 05000529/2018010, and 05000530/2018010 (ADAMS Accession No.
ML18103A157); 05000454/2018011 and 05000455/2018011 (ADAMS Accession No.
ML18138A136); and 05000335/2018002) and 05000389/2018002 (ADAMS Accession No.
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ML18208A328). The inspection team consisted of inspectors from each region and a member
of the Electrical Engineering Operating Reactors Branch (EEOB) staff from headquarters. The
regional inspectors completed Section 03.01 of TI 2515/194, Rev. 0 and the EEOB staff
gathered information in accordance with Section 03.02 of TI 2515/194, Rev. 0. The EEOB staff
generated an assessment of the inspection results from implementation of the TI dated October
31, 2017 (Rev. 0) to document whether licensees identified OPC vulnerabilities using one of the
four OPC designs and implemented the OPIS consistent with the NEI OPC VII. A summary of
the staff’s preliminary assessments and the areas needing additional clarity were discussed with
the industry representatives in two public meetings conducted on September 19, 2018, and
October 17, 2018 (ADAMS Accession Nos.: ML18268A342 and ML18309A227, respectively).
The NRC staff informed the industry that it would use inspection results, the information
discussed in the public meetings, information provided by industry as part of its efforts to
address OPC vulnerabilities, the staff’s preliminary risk assessment on the impact of OPC
(ADAMS Accession No. ML17234A631), and the functional criteria described in the November
25, 2014, NRC letter to NEI (ADAMS Accession No. ML15075A454) to determine whether the
licensees are adequately addressing potential OPC vulnerabilities consistent with Commission
direction in SRM- SECY 16-0068.
The staff is issuing this revision (Rev. 1) to the TI for NRC inspectors to verify that the plants
that choose operator manual action in lieu of automatic protective action are appropriately
implementing the VII and adequately addressing the OPC design vulnerability issue. The staff
is also deleting Section 03.02, “Information Gathering for VII Assessment (Part 2),” guidance
from the TI since the information was obtained during the initial inspections and no longer
required to be performed by this TI.
2515/194-03 INSPECTION REQUIREMENTS AND INSPECTION GUIDANCE
General Guidance.
Preparation: Prior to arrival on site, request that key documents be available for on-site
inspection (e.g., NEI 19-02 evaluation, calculations, analyses, drawings, procurement
specifications, test reports, modification packages including 10 CFR 50.59 evaluations,
maintenance, surveillance, test, and alarm response procedures). Arrange with the licensee to
have appropriate design, maintenance, probabilistic risk assessment (PRA), and operations
staff on-site to support the inspection. Request a brief licensee presentation after entrance
meeting describing their electric power system design; normal plant operating alignments; OPC
design schemes installed to detect, alarm and actuate (if applicable); bus transfer schemes;
maintenance and surveillance requirements; operator walkthrough verifications of the OPC
alarm response procedure(s); consequences of extended duration of unbalanced voltage
conditions affecting electric equipment if OPC is not automatically isolated; and any licensing
basis changes to Updated Final Safety Analysis Report (UFSAR) and Technical Specifications
(TS).
Conduct: It is expected that this TI will be performed to verify that licensees have appropriately
implemented the VII and adequately addressed potential OPCs. Deviations and exceptions to
the VII implementation should be documented in the inspection report with enough details for
EEOB staff to review and closeout Bulletin 2012-01. For sites that are implementing the riskinformed evaluation method to demonstrate that operator manual actions will be sufficient to
mitigate the impact of an OPC, in lieu of TI Section 03.01.b (automatic protective actions), TI
Section 03.01.c will be performed. This inspection activity will be performed after the licensees
Issue Date: 08/18/20 8 2515/194 Rev 2
have completed their evaluations and analyses, issued plant procedure(s), and completed
training for taking manual actions consistent with plant’s design and licensing bases. Any
identified deviations from the VII and TI guidance will be documented in the inspection report as
exceptions. These exceptions will be considered by EEOB staff during the final review and
closeout of the Bulletin. Any performance issues identified during the inspection of the VII that
are considered to be more than minor in accordance with Inspection Manual Chapter (IMC) 0612 will be reviewed by a panel to determine whether they represent a finding to be
documented. These issues may be initially treated as unresolved items (URIs), prior to final
disposition.
As directed by the Commission in SRM SECY-16-0068, should disagreements arise between
the NRC staff and the industry during implementation of the voluntary initiative, and the related
issues have policy implications, the NRC staff will promptly raise such issues to the Commission
for resolution.
03.01 Voluntary Industry Initiative.
Determine whether the licensee appropriately implemented the VII dated June 6, 2019 (ADAMS
Accession No. ML19163A176), by verifying the following:
a. Detection, Alarms and General Criteria.
1. Either:
OPCs are detected and alarmed in the control room.
(a) The licensee has demonstrated that OPCs do not prevent the functioning of
important-to-safety SSCs
AND
(b) OPC detection will occur within a reasonably short period of time (e.g., 24
hours)
AND
(c) The licensee has established appropriate documentation regarding OPC
detection and correction.
2. Either:
Detection circuits are sensitive enough to identify an OPC for credited loading
conditions (i.e., high and low loading).
If automatic detection may not be possible in very low or no loading conditions
when offsite power transformers are in standby mode; automatic detection must
happen as soon as loads are transferred to this standby source. Additionally, if
automatic detection is not reliable, monitoring requirements should be
established on a per shift basis to look for evidence of an OPC.
3. OPC design/protective schemes minimize misoperation or spurious action in the
range of voltage unbalance normally expected in the transmission system that
could cause separation from an operable off-site power source. Licensees have
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demonstrated that the actuation circuit design does not result in lower overall
plant operation reliability.
4. New non-Class-1E circuits are not used to replace existing Class-1E circuits.
5. The UFSAR has been updated to discuss the design features and analyses
related to the effects of any OPC design vulnerability.
6. Identify whether OPIS detection and alarm components are maintained in
accordance with station procedures or maintenance program and that periodic
tests, calibrations, setpoint verifications or inspections (as applicable) have been
established.
b. Protective Actions.
1. If the licensee determines there is no single credible failure that could cause an
OPC, then verify that the licensee has developed and issued a full engineering
evaluation to document the basis for OPC as a non-credited event. The Bruce
Power and Forsmark operating experience must be considered as part of this
analysis.
2. With OPC occurrence and no accident condition signal present, either:
An OPC1 does not adversely affect the function of important-to-safety SSCs
(a) TS LCOs are maintained or the TS actions are met without entry into TS LCO 3.0.3 (or equivalent).1&2
AND
(b) Important-to-safety equipment is not damaged by the OPC1&3
.
AND
(c) Shutdown safety is not compromised3&4
3. With OPC occurrence and an accident condition signal present:
Automatic detection and actuation will transfer loads required to mitigate
postulated accidents to an alternate source and ensure that safety functions are
preserved, as required by the current licensing bases.
1 For operating modes where power is supplied from the main generator through unit auxiliary
transformers, the evaluation must assume that the main generator is lost and loads must be transferred to
the alternate source(s).
2 Applies to TS equipment affected by the OPC and not just the TS related to off-site power system.
Situations where alternate sources are removed from service if allowed by the TS must be considered.
3 Operator action may be credited in the evaluation if existing regulations and guidelines are met for the
use of manual actions in the place of automatic actions.
4 Power supplied to spent fuel pool cooling systems must also be considered. The limiting conditions will
be those where power is supplied from a single source or an alternate source is used that does not have
open phase protection (like a main power transformer back-feed source).
Issue Date: 08/18/20 10 2515/194 Rev 2
The licensee has shown that all design basis accident acceptance criteria are
met with the OPC, given other plant design features. Accident assumptions must
include licensing provisions associated with single failures. Typically, licensing
bases will not permit consideration of the OPC as the single failure since this
failure is in a non-safety system.
4. Periodic tests, calibrations, setpoint verifications or inspections (as applicable)
have been established for any new protective features. The surveillance
requirements have been added to the plant TSs if necessary, to meet the
provisions of 10 CFR 50.36.
5. The UFSAR has been updated to discuss the design features and analyses
related to the effects of, and protection for, any OPC design vulnerability.
6. Identify whether OPIS protection components are maintained in accordance with
station procedures or maintenance program.
c. Use of Risk-Informed Evaluation Method
For those licensees that opted “to demonstrate that operator manual actions will be
sufficient to mitigate the impact of an OPC,” in accordance with VII, Revision 3,
Attachment 1 and NEI 19-02, “Guidance for Assessing Open Phase Condition
Implementation Using Risk Insights,” instead of automatic protective actions discussed
in Section b above, the inspectors should review, verify, and document, as appropriate,
the following:
1. Review licensee’s evaluation of NEI 19-02 and Attachment 1 of VII, Revision 3
stated above. Verify that the plant configuration matches the changes made to
the PRA model used to evaluate an OPC, and that the logic of the PRA model
changes is sound. Consult with regional Senior Reactor Analyst (SRA) if
inspectors have any questions or concerns regarding the PRA model.
2. Review the procedure(s) and operator actions required to respond to an OPC
alarm and potential equipment trip, with an operator walkthrough and simulator
demonstration if possible (during the walkthrough, verify that the procedure which
validates that the OPC alarm is legitimate would identify the proper indication to
validate the OPCs at all possible locations).
3. Verify that the observations made while carrying out step 2 above match the
Human Reliability Analysis (HRA). Consult with regional SRAs as necessary. To
achieve this objective:
a. Verify that the execution time for each human action as described in the
alarm response procedure(s) and the time available to complete each action
are reasonable.
b. Verify that the environmental and plant operating conditions allow access
where needed, procedures have been revised to account for identifying and
Issue Date: 08/18/20 11 2515/194 Rev 2
isolating an OPC, training has been conducted on these revised procedures,
and any equipment needed to complete these actions is available and ready
for use.
4. Review the assumptions listed in the NEI 19-02 (Appendix A) evaluation and the
sensitivity analyses listed in Section 5 of the evaluation. Verify the assumptions,
focusing additional attention on any assumption that causes the sensitivity
analysis to exceed the risk threshold defined in the NEI 19-02 evaluation.
5. Review the following to ensure the assumptions, procedures, operator actions,
and licensee’s analyses specified above are consistent with the plant-specific
design and licensing bases and/or the as-built, as-operated plant as appropriate:
a. Review the initiating events considered in the analysis.
b. Review and verify the boundary conditions specified in VII, Rev.3, Att. 1.
c. If certain loads are assumed to be impacted by an OPC (i.e.,
tripped/locked out or damaged) review the operating procedure(s) for any
steps taken to recover the affected equipment (or use of alternate
equipment).
d. If recovery is assumed as part of the basis in the PRA analysis for
impacted electric equipment, verify that the restoration of equipment is
based on analyses that demonstrate that automatic trips for isolating any
operating equipment during an OPC event did not result in equipment
damage. The review of the analyses supporting recovery may include,
but not be limited to:
1) System load flow calculations, protective coordination, and failure
mode and consequence analyses.
2) Verifying that the licensee appropriately analyzed the capability of
safe shutdown equipment to perform the required functions.
3) Review of the licensee’s evaluations to verify that ESF/PRAcredited loads (such as large motors, motor-operated valves,
inverters, etc.) would not be damaged during the time delay
between detection of an OPC by the control room operators and
completion of the operator actions.
4) Review of the maximum unbalance seen on ESF buses
(considering ESF/PRA-credited loads during normal, anticipated
operational occurrences, and design basis accidents) at all
voltage levels and verifying how the existing relays are used to
protect the equipment from unbalanced power quality issues and
potential consequences.
5) Review of the time to recover the tripped equipment and/or
replace fuses and damaged equipment given an OPC.
Issue Date: 08/18/20 12 2515/194 Rev 2
6) Review of the time for restoring large motors while factoring the
manufacturer recommendations or site/industry guidance for
restarting stalled or degraded electric equipment.
2515/194-04 REPORTING AND DOCUMENTATION REQUIREMENTS
Document the completion of this TI in the integrated quarterly report or in a standalone
inspection report. Document the VII inspection results and any deviations from the VII in
sufficient details to facilitate NRR staff ‘s final review and closeout of the Bulletin.
2515/194-05 COMPLETION SCHEDULE
This TI is to be completed by July 29, 2022.
2515/194-06 EXPIRATION
The TI will expire on December 30, 2023.
2515/194-07 CONTACT
Any technical questions regarding this TI shall be directed to the Branch Chief of
NRR/DEX/EEOB. Any Reactor Oversight Process-related questions shall be addressed to
Christopher Cauffman, at (301) 415-8416. Questions can also be sent electronically to
Christopher.Cauffman@nrc.gov.
2515/194-08 STATISTICAL DATA REPORTING
Charge all direct inspection and information collection efforts to TI 2515/194 using IPE code TI.
Charge all preparation and documentation time to activity code TPD (CAC 000989).
2515/194-09 RESOURCE ESTIMATE
Estimated time to complete TI (Rev.0) is 50-60 hours per site for direct inspection and 24-32
hours for preparation and documentation. In addition, estimated time to complete risk-informed
evaluation method of this revised TI is 40-60 hours per site for direct inspection and 24-36 hours
for preparation and documentation.
2515/194-10 TRAINING
It is expected that this inspection will be performed by the regional electrical engineering
specialist or contractors who are knowledgeable in electrical power system design and analyses
for nuclear power reactors. However, a brief training session on the risk-informed evaluation
method outlined in NEI-19-02 and VII, Rev.3, Attachment 1, was provided by NRR/DRA/APOB
and NRR/DEX/EEOB staff on March 6, 2020.
Issue Date: 08/18/20 13 2515/194 Rev 2
2515/194-11 REFERENCES
IP 71152, “Problem Identification and Resolution”
IP 71111.17T, “Evaluations of Changes, Tests and Experiments”
IP 71111.18, “Plant Modifications”
IP 71111.21M, “Design Bases Assurance Inspection (Teams)”
END
Issue Date: 04/15/20 Att1-1 2515/194, Rev 1
Attachment 1 – Revision History for TI 2515/194
Commitment
Tracking
Number
Accession
Number
Issue Date
Change Notice
Description of Change Description of Training
Required and Completion
Date
Comment Resolution and
Closed Feedback Form
Accession Number
(Pre-Decisional,
Non-Public Information)
DRAFT
CN 17-XXX
Draft version of the TI was made public to
share with industry during a public meeting
held on August 15, 2017.
N/A ML17158B437
ML17137A416
10/31/2017
CN 17-024
Initial issuance. Researched commitments for
the last four years and found none. This
Temporary Instruction (TI) applies to the
holders of operating licenses for operating
nuclear power reactors who have
implemented actions to protect against open
phase conditions (OPCs). This TI is to be
performed at all current operating plants with
the exception of Seabrook Station, Unit 1,
plants seeking NRC approval in accordance
with 10 CFR 50.90, and sites that have
informed the NRC of their intent to
decommission prior to 01/30/2020.
CA Note: Initiation of Temporary Instruction
2515/194 To Inspect Implementation of
Industry Initiative Associated with Open
Phase Condition Design Vulnerabilities in
Electric Power Systems ML17240A034
It is expected that this
inspection will be
performed by the regional
electrical engineering
specialist or contractors
who are knowledgeable
in electrical power system
design and analyses for
nuclear power reactors.
However, a specialized
brief training on the OPCs
will be provided by
NRR/DE/EEOB staff prior
to 10/31/17.
Issue Date: 04/15/20 Att1-2 2515/194, Rev 1
Commitment
Tracking
Number
Accession
Number
Issue Date
Change Notice
Description of Change Description of Training
Required and Completion
Date
Comment Resolution and
Closed Feedback Form
Accession Number
(Pre-Decisional,
Non-Public Information)
ML20085H763 Draft version of the TI was made public to
share with industry during a public meeting
held on April 6, 2020
N/A N/A
04/15/20
CN 20-021
Revision 1 - Expanded scope to include all
plants. Incorporated guidance for inspecting
manual action (i.e. risk-informed) approach
consistent with VII, Revision 3.
Removed data-gathering instructions (section
03.02) and Table 1 since the HQ staff
completed this one-time activity for VII
verification effort.
Initial training for this TI was
conducted on September
and October 2017.
It is expected that this
inspection activity will be
performed by the regional
electrical engineering
specialist or contractors
who are knowledgeable in
electrical power system
design and analyses for
nuclear power reactors with
assistance from SRA, if
required to perform risk
evaluations. However, a
brief training session on the
risk-informed evaluation
method outlined in NEI-19-
02 and VII, Rev.3,
Attachment 1, was provided
by NRR/DRA/APOB and
NRR/DEX/EEOB staff on
3/6/20.