ML18026A967
| ML18026A967 | |
| Person / Time | |
|---|---|
| Site: | Clinton  |
| Issue date: | 01/26/2018 |
| From: | Louden P Division Reactor Projects III |
| To: | Bryan Hanson Exelon Generation Co, Exelon Nuclear |
| References | |
| IR 2017012 | |
| Download: ML18026A967 (27) | |
See also: IR 05000461/2017012
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION III
2443 WARRENVILLE RD. SUITE 210
LISLE, ILLINOIS 60532-4352
January 26, 2018
Mr. Bryan C. Hanson
Senior VP, Exelon Generation Company, LLC
President and CNO, Exelon Nuclear
4300 Winfield Road
Warrenville, IL 60555
SUBJECT: CLINTON POWER STATIONNRC SPECIAL INSPECTION REPORT
Dear Mr. Hanson:
On December 21, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed a special
inspection at your Clinton Power Station. The special inspection evaluated the facts and
circumstances surrounding the unexpected opening of Breaker 0AP07EJ due to the events of
December 9, 2017, and the electrical failure of Step Down Transformer 1AP11E. The breaker
normally powered the 1A and A1 480 volts alternating current (VAC) buses. The associated
loss of power to these Division 1 buses resulted in the closure of the outboard instrument air
containment isolation valve and a loss of instrument air to containment. Operators responded to
the loss of instrument air to the containment air loads by initiating a reactor scram in accordance
with station operating procedures. The enclosed report documents the results of this inspection
which were discussed on December 21, 2017, with Mr. T. Stoner and other members of your
staff.
Based on the results of this inspection, the NRC identified two findings that were evaluated
under the risk significance determination process as having very low safety significance
(Green). The NRC also determined that a violation is associated with one of these findings.
Because your organization initiated a condition report to address this issue, this violation is
being treated as a Non-Cited Violation (NCV), consistent with Section 2.3.2 of the NRC
Enforcement Policy. The NCV is described in the subject inspection report.
If you contest the violation or significance of the NCV, you should provide a response within
30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear
Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with
copies to the Regional Administrator, Region III; the Director, Office of Enforcement; and the
NRC Resident Inspector at the Clinton Power Station.
If you disagree with a cross-cutting aspect assignment or a finding not associated with a
regulatory requirement in this report, you should provide a response within 30 days of the date
of this inspection report, with the basis for your disagreement, to the U.S. Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with copies to the
Regional Administrator, Region III; and the NRC Resident Inspector at the Clinton Power
Station.
B. Hanson -2-
This letter, its enclosure, and your response (if any) will be made available for public inspections
and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document
room in accordance with 10 CFR 2.930, Public Inspections, Exemptions, Requests for
Withholding.
Sincerely,
/RA/
Patrick L. Louden, Director
Division of Reactor Projects
Docket No. 50-461
License No. NPF-62
Enclosure: w/Attachments
Inspection Report 05000461/2017012
cc: Distribution via LISTSERV
B. Hanson 3
Letter to Bryan Hanson from Patrick Louden dated January 26, 2018
SUBJECT: CLINTON POWER STATIONNRC SPECIAL INSPECTION REPORT
DISTRIBUTION:
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ROPreports.Resource@nrc.gov
ADAMS Accession Number: ML18026A967
OFFICE RIII RIII RIII RIII
NAME JHanna:lg KStoedter RSkokowski PLouden
DATE 1/24/2018 1/26/2018 1/25/2018 1/26/2018
OFFICIAL RECORD COPY
U.S. NUCLEAR REGULATORY COMMISSION
REGION III
Docket No: 50-461
License No: NPF-62
Report No: 05000461/2017012
Licensee: Exelon Generation Company, LLC
Facility: Clinton Power Station
Location: Clinton, IL
Dates: December 18 through 21, 2017
Inspectors: J. McGhee, Byron Senior Resident Inspector (Lead)
C. Phillips, Project Engineer
Approved by: P. Louden, Director
Division of Reactor Projects
Enclosure
SUMMARY
Inspection Report 05000461/2017012, Clinton Power Station; Other Activities
This report covers a special inspection performed by two U.S. Nuclear Regulatory
Commission (NRC) Region III inspectors in December 2017. The inspection was conducted in
accordance with Inspection Procedure 93812. Two Green findings were identified by the
inspectors. One of the findings had an associated non-cited violation (NCV) of NRC
regulations. The significance of inspection findings is indicated by their color (i.e., greater than
Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process dated April 29, 2015. Cross-cutting aspects are
determined using IMC 0310, Components Within the Cross Cutting Areas dated December 4,
2014. All violations of NRC requirements are dispositioned in accordance with the NRCs
Enforcement Policy dated November 1, 2016. The NRC's program for overseeing the safe
operation of commercial nuclear power reactors is described in NUREG-1649, Reactor
Oversight Process, dated July 2016.
NRC-Identified and Self-Revealed Findings
Cornerstone: Initiating Events
Green. The inspectors identified a finding of very low safety significance and an associated
NCV of Title 10 of the Code of Federal Regulations (CFR) 50, Appendix B, Criterion XVI,
Corrective Actions, for the licensees failure to take corrective action to preclude
repetition (CAPR) of a significant condition adverse to quality. Specifically, CAPRs developed
following a December 8, 2013, 480 Volt transformer failure were not completed on Division 2
equipment even though the licensee recognized the 2013 transformer failure as a significant
condition adverse to quality. The licensee entered this issue into their corrective action program
(CAP) as action request (AR) 04089480. As corrective actions, the licensee planned to perform
the testing, which made up the corrective action to prevent recurrence, at the next available
opportunity which will be the 2018 refueling outage.
This performance deficiency was determined to be more than minor because it adversely
impacted the Equipment Reliability attribute and the Initiating Events Cornerstone objective to
limit the likelihood of events that upset plant stability and challenge critical safety functions
during shutdown as well as power operations. Failure to perform the CAPR commensurate with
safety reduced the effectiveness of the CAPR and increased the likelihood of a recurring event.
This finding was determined to be of very low safety significance because the finding did not
involve the complete or partial loss of a support system that contributes to the likelihood of, or
cause, an initiating event and did not affect mitigation equipment. This finding affected the
cross-cutting area of human performance, in the aspect of work management where the
organization implements a process of planning, controlling, and executing work activities such
that nuclear safety is the overriding priority. Delaying the performance of the testing because it
extended the outage did not demonstrate that nuclear safety was the overriding priority. [H.5]
(Section 4OA3.3)
Green. The inspectors identified a finding of very low safety significance for the licensees
failure to follow procedure ER-AA-200-1001, Equipment Classification, Revision 3.
Specifically, three non-safety related 4160 volt to 480 volt transformers were not properly
classified as operationally critical components. The licensee entered this issue into its CAP
as AR 04086449. As corrective actions, the licensee corrected the criticality classifications
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for 0AP44E 480 VAC Auxiliary Transformer D, 0AP92E 480 VAC Auxiliary Transformer P,
and 1AP18E2 480 VAC Auxiliary Transformer 1H. Additionally, the licensee planned to perform
a work group evaluation to document the extent of condition to ensure that all dry type
transformers onsite have the correct criticality classification.
The performance deficiency was determined to be more than minor, because it was associated
with the Initiating Events Cornerstone attribute of Equipment Performance and adversely
affected the cornerstone objective of limiting the likelihood of events that upset plant stability
and challenge critical safety functions during shutdown as well as power operations.
Specifically, the performance of the transformers listed above was not fully evaluated as
required by the preventive maintenance program to ensure the likelihood of failure was limited.
The inspectors determined this finding was of very low safety significance because although the
performance deficiency resulted in a preventive maintenance strategy that may have resulted in
lower reliability of the respective 480 volt auxiliary transformers, it would not have resulted in the
loss of mitigation equipment relied upon to transition the plant from the onset of the scram to a
stable shutdown condition. The inspectors determined this finding affected the cross-cutting
area of Human Performance in the aspect of Consistent Process where individuals use a
consistent systematic approach to make decisions andrisk insights are incorporated as
appropriate. Specifically, the licensee failed to use a consistent classification process to reach
the conclusion that the 480 VAC auxiliary transformers 0AP44E, 0AP92E, 1AP18E2 were
properly classified as operationally critical components. [H.13] (Section 4OA3.4)
Licensee-Identified Violations
No findings were identified.
3
REPORT DETAILS
Summary of Plant Event
On Saturday, December 9, 2017, Clinton Power Station control room operators inserted a
manual reactor scram from 98.2 percent power following an electrical system perturbation.
Multiple alarms were received in the control room upon the unexpected opening of
the 1A1 4160 volts alternating current (VAC) bus breaker 1AP07EJ, which feeds 480 VAC Unit
Substation A (0AP05E) and 480 VAC Unit Substation 1A (1AP11E). Control room operators
noted that the outboard containment isolation valve for instrument air to containment had closed
with the loss of 480 VAC power and entered the abnormal procedure for loss of instrument air to
containment while attempting to identify the cause of the power loss. Four minutes after the
breaker opened, the control room received a low scram pilot air header pressure alarm. Two
minutes later, the control rod drift annunciator alarmed as expected and the control room
operators inserted a manual scram by taking the Mode Switch to Shutdown in accordance with
procedural guidance.
Operators began cooling down the reactor by directing steam to the main condenser using the
main steam bypass valves and auxiliary steam equipment. As reactor pressure lowered
operators removed auxiliary equipment from service to maintain the cooldown rate within
Technical Specification (TS) limits and maintained reactor water level using the condensate and
feedwater pumps which remained available throughout the event. The partial loss of Division 1
480 VAC power de-energized the Division 1 containment isolation solenoid valves and isolated
instrument air to the containment when the outboard containment isolation valve, 1IA005,
closed. In addition to isolating the air supply to the scram air header, closure of 1IA005 resulted
in a loss of air supply to all containment loads including the inboard main steam isolation
valves (MSIVs). Operators lined up the main steam line drains to maintain pressure control and
continue the cooldown in anticipation of MSIV closure as containment air pressure lowered.
The last inboard MSIV indicated full closed about 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> after the instrument air containment
isolation valve closed, but the main steam line drain valves remained available to the operators.
The drains were used in conjunction with the reactor core isolation cooling (RCIC) turbine to
continue to cooldown to Mode 4 within the time limits required by TS.
The partial loss of Division 1 4160/480 VAC power rendered several components inoperable.
Low pressure core spray (LPCS) and the A train of residual heat removal (RHR) were
inoperable and unavailable. The RCIC system was also declared inoperable because the AC
powered RCIC water leg pump could not function. The Division 1 battery charger also lost
power causing operators to reduce loading on the battery while the swing battery charger was
aligned.
Based on the deterministic criteria provided in NRC Management Directive (MD) 8.3, NRC
Incident Investigation Program, this event met MD 8.3 Criterion (d), because there was a loss
of secondary containment when the Fuel Building Ventilation fans lost power and were unable
to maintain the secondary containment differential pressure within the TS limits. This condition
existed for approximately 15 minutes until the standby gas treatment system was manually
aligned to the Fuel building and differential pressure was restored. Also, LPCS, a single train
safety system, and RHR A were considered inoperable due to loss of the water leg fill pumps
and loss of power to motor operated valves. In addition, the event also met MD 8.3 criterion (g),
in that the loss of power to the Division 1 480 VAC bus was very similar to a failure that
occurred in December 2013 when the A1 4160/480 VAC transformer failed. The initial risk
4
assessment resulted in an estimated Conditional Core Damage Probability (CCDP) range
of 4.0E-6 to 9E-6. The Special Inspection Team (SIT) was dispatched to the site and arrived
on December 18, 2017.
The SIT charter is included with this report in the Supplemental Information.
4OA3 Special Inspection (93812)
.1 Establish an Overview of Events Related to the Transformer Failure, Reactor Scram,
and Plant Recovery Actions. Review Related Licensee Actions with Respect to
Monitoring of Plant Conditions, Procedure Usage, and Decision Making.
a. Inspection Scope
The special inspection charter charged the team with establishing an overview of events
related to the December 9, 2017, event including the licensees actions prior to the event
as well as during and recovery from the event. To that end, inspectors reviewed
operating logs, plant parameter recordings, testing and trend information, and other
maintenance records. Inspectors reviewed statements prepared by control room
operators following the event. In addition, the inspectors compared the resulting
sequence of events to the licensee generated sequence of events to ensure
completeness and accuracy of both documents. Pertinent historical information and the
timing of those activities such as previous preventative maintenance dates and
maintenance inspections performed are discussed in the following sections of the report.
The inspectors also reviewed the licensee actions with respect to monitoring of plant
conditions, procedure usage and decision-making. The inspector-generated sequence
of events is included with this report in the Supplemental Information.
Documents reviewed are included in the Supplemental Information.
b. Discussion
The team concluded that the plant responded as designed to the failure and the resulting
transient with a small number of equipment failures. The licensee staff appropriately
identified, evaluated, and corrected the equipment failures prior to restarting the unit
which included installing a modification to replace the failed transformer and the
performance of immediately required extent of condition testing. Additionally, the team
concluded that operator decisions were appropriate and procedures were implemented
correctly in response to the event.
c. Findings
No findings were identified.
5
.2 Review the Operation of the Plant equipment in Response to the Transient, Including
Adequacy of Procedures and Whether Equipment Operated in Accordance with its
Design.
a. Inspection Scope
The inspectors reviewed the anticipated plant response to a manual scram, loss of
electrical power, and a loss of instrument air described in the Clinton Power Station
Updated Final Safety Analysis Report (UFSAR) Chapter 15. Additionally, several
procedures were reviewed and compared to the plant response and the actions
taken by the operators during the event. The inspectors reviewed the licensees
operations narrative logs for the time period just prior to the transformer failure on
December 9, 2017, at 1:47 p.m., to the time that the unit reached Mode 4 at 8:00 p.m. on
December 10, 2017. The inspectors also reviewed statements documented by
operators that were on shift at the time of the event. The inspectors also reviewed plant
parameter recordings and the post trip review completed by the licensee. The
inspectors compared the operator and plant response to a similar transformer failure
event that occurred on December 8, 2013. The results of the 2013 transformer failure
are documented in Clinton Power Station NRC Special Inspection Report 05000461/2013009.
The inspectors reviewed the licensees corrective action program (CAP) documentation
to ensure the licensee had identified other non-consequential, non-safety related
equipment failures and degraded conditions that occurred during the event and entered
those failures into the CAP. Documents reviewed are included in the Supplemental
Information.
b. Discussion
The loss of alternating current (AC) power was the direct cause of the loss of instrument
air to containment, loss of secondary containment integrity when dampers closed
tripping ventilation exhaust fans, and inoperability of LPCS and RHR A due to loss of
water leg pumps and motor operated safety-related valves. The inspectors reviewed the
operating procedures and design for the instrument air containment isolation valves. The
instrument air supply to the air operated containment isolation valves was regulated and
aligned to open the valve through AC powered solenoid operated valves. The solenoid
for 1IA005, Containment Outboard Isolation Valve, lost power when the Division 1 480
VAC busses were de-energized and the air operated instrument air containment
isolation valves failed closed as expected. The inspectors determined that the operators
correctly identified the loss of AC power and closure of the containment isolation valves.
The operators implemented the correct station procedures and focused on the
parameters called out in those procedures to identify when the reactor was required to
be shutdown. As stated previously, loss of instrument air to containment subsequently
resulted in a loss of air pressure to the inboard MSIVs, reactor water cleanup system
components and control rod drive system components including the scram air header.
Procedure CPS [Clinton Power Station] EOP-1; RPV [reactor pressure vessel] Control,
lists main turbine bypass valves and main steam line (MSL) drain lines possible means
of pressure control if the MSIVs are open. The MSL drains remained available after the
inboard MSIVs closed. Procedure CPS 4100.01, Reactor Scram, directs the operator
to use an appropriate cooldown method listed in CPS 9000.06, Unit Shutdown.
In CPS 9000.06, Section 8.8, Cooldown With Main Condenser, MSL drain valves were
6
one method listed and included a statement that it is OK to shut MSIVs when using this
method. The control room supervisor stated that he considered using RCIC for pressure
control, but determined that he did not need to immediately because the main condenser
remained available and he was able to control pressure and the cooldown rate using
MSL drains and bypass valves until the last MSIV closed.
The control room supervisor indicated that although the RCIC water leg keep fill pump
had lost power, he determined RCIC was inoperable but available and requested an
engineering review to validate his assessment. During the 2013 special inspection, the
inspectors reviewed RCIC annunciator and system operating procedures to evaluate
RCIC availability under these conditions. At that time, the inspectors also interviewed
the RCIC system manager and two program engineers that perform ultrasonic testing on
piping to look for voids. The inspectors also reviewed computer printouts of RCIC
suction and discharge pressure from the beginning of the 2013 event until the plant
reached Mode 4 and reviewed calculations for net positive suction head for the RCIC
pump from both of its suction sources. The inspectors concluded in 2013 that the RCIC
system, although appropriately declared inoperable due to the power loss to the water
leg pump, was available for operation if necessary for pressure/inventory control and for
decay heat removal. The inspectors reviewing the 2017 event arrived at the same
conclusion. At 6:59 p.m. on December 9, 2017, the operating crew placed RCIC in
service in the pressure control mode operating tank to tank and the system remained in
service until 11:39 a.m. on December 10, 2017, after instrument air had been returned to
containment and the MSIVs were reopened. The RHR B train was started in shutdown
cooling mode at 7:37 p.m. on December 10, 2017, and the plant entered Mode 4
at 8:00 p.m. that same day.
c. Findings
No findings were identified.
.3 Evaluate the Licensee Planned and Completed Corrective Actions Following the 2013
Transformer Failure and to the Extent Possible, Assess if Prior Opportunities (e.g.
Surveillances, Maintenance) Existed to Have Identified Transformer Degradation or
Failure, at an Earlier Point in Time.
a. Inspection Scope
The inspectors reviewed the licensees root cause evaluation (RCE) 01594407,
Automatic Trip of Breaker 1AP07EJ - 0AP05E2 Transformer Failure and associated
CAP documentation. Documents reviewed are included in the Supplemental Information
Section of this report.
b. Discussion
The licensee considered the transformer failure in 2013 to be a low probability event
since a very low percentage of these dry transformers had failed within the nuclear
industry. As part of the extent of condition from the 2013 event the licensee visually
inspected and megger tested the 0AP79E2 transformer and found it in good condition
(IR 01594407 Assignment 34). Based on the result of this single inspection the licensee
assumed the other transformers were also in good condition. The inspectors considered
this to be a weak assumption based on a single observation. The inspectors also noted
that the licensee planned to install infrared windows in the transformer cabinets so that
7
the temperature of the windings could be monitored. The licensee canceled that action
because the transformers had installed thermocouples which would have been a better
method of monitoring temperature. However, the thermocouples were only in one phase
winding of the transformers, which significantly reduced the effectiveness of this type of
monitoring, and the licensee stopped monitoring the temperatures in 2015.
The inspectors determined that there were no prior opportunities to perform the testing
needed to identify the transformer degradation to the Division I 480 VAC substation
transformer that failed on December 8, 2017. However, the inspectors determined that
the licensee had a prior opportunity to perform testing designated as a corrective action
to prevent recurrence on the Division II 480 VAC substation transformers and failed to
do so.
c. Findings
Introduction: The NRC identified a finding of very low safety significance and an
associated non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion XVI, for the
licensees failure to take corrective action to preclude repetition in the case of a
significant condition adverse to quality. Specifically, corrective actions for an event that
the licensee recognized as a significant condition adverse to quality were not completed
commensurate with safety.
Description: The inspectors reviewed the corrective actions associated with
licensee RCE 1594407, Automatic Trip of Breaker 1AP07EJ-0AP05E2 Transformer
Failure. This event occurred on December 8, 2013, when the 480 VAC Unit
Substation 0AP05E2 Transformer failed and caused of a loss of Division I 480 volt loads
and a subsequent reactor scram. On June 6, 2016, the licensee finalized root cause
report (RCR) 01594407, Automatic Trip of Breaker 1AP07EJ0AP05E2 Transformer
Failure, in accordance with station procedure PI-AA-125-1001, Root Cause Analysis
Manual, Revision 2.
The inspectors identified that the RCE neither established a root cause nor were
corrective actions to prevent recurrence created as required by PI-AA-125-1001 after
the RCE was issued. The NRC issued NCV 05000461/2017002-07, Root Cause
Evaluation Failed to Identify Corrective Action to Preclude Repetition, on
August 11, 2017. (The issuance of this violation had been delayed for several months
determining an outcome of an issue regarding the CAP program that impacted all Exelon
sites.) The licensee then determined that the root cause of the transformer failure was
insulation degradation of the phase windings over time. The corrective action to prevent
recurrence (CAPR) included implementation of Doble testing on dry type transformers to
predict and identify indicators of insulation degradation over time. Doble testing includes
a series of individual tests performed with specialized equipment to determine the
amount of internal insulation degradation, if any, that existed on different transformer
components. This testing was intrusive and required the electrical busses associated
with the transformers to be de-energized.
The licensees RCE and CAP documentation stated that the implementation of the Doble
testing was to be performed by updating the model work orders for all safety-related and
non-safety related dry type transformers. The licensee designated the revision of the
model work orders as a CAPR in October 2016, completed revising the model work
orders on November 18, 2016, and closed the CAPR. However, the inspectors
determined that revising the model work orders alone was not a CAPR. In order for the
8
CAPR to be considered implemented, the licensee needed to complete actual Doble
testing of the transformers.
The licensee conducted a refueling outage from May 8, to May 29, 2017. The licensee
stated that Doble testing on the Division 2 4160 to 480 VAC transformers had been
planned for the 2017 refueling outage but not conducted because it would have
extended the length of the outage by three days. The implementation of the Doble
testing on the safety-related Division 2 4160 to 480 VAC transformers was delayed until
the 2018 refueling outage.
The inspectors reviewed NRC guidance related to the timeliness of corrective actions
provided in NRC Inspection Manual Chapter 0326, Operability Determinations &
Functionality Assessments for Conditions Adverse to Quality or Safety, which stated:
In determining whether the licensee is making reasonable efforts to complete
corrective actions promptly, the NRC will consider safety significance, the effects
on operability, the significance of the degradation, and what is necessary to
implement the corrective action. The NRC may also consider the time needed
for design, review, approval, or procurement of the repair or modification; the
availability of specialized equipment to perform the repair or modification; and
whether the plant must be in hot or cold shutdown to implement the actions. If
the licensee does not resolve the degraded or non-conforming condition at the
first available opportunity or does not appropriately justify a longer completion
schedule, the staff would conclude that corrective action has not been timely and
would consider taking enforcement action. Factors that should be considered
are (1) the identified cause, including contributing factors and proposed
corrective actions, (2) existing conditions and compensatory measures, including
the acceptability of the schedule for repair and replacement activities, (3) the
basis for why the repair or replacement activities will not be accomplished prior to
restart after a planned outage (e.g., additional time is needed to prepare a
design/modification package or to procure necessary components), and (4)
review and approval of the schedule by appropriate site management and/or
oversight organizations.
The inspectors determined that the licensees rational for delaying the testing that made
up the CAPR was not due to the extenuating circumstances listed above.
Analysis: The inspectors determined that the failure to implement CAPRs in accordance
with Title 10 of the Code of Federal Regulations (CFR) 50, Appendix B, Criterion XVI,
was a performance deficiency. The performance deficiency was determined to be more
than minor in accordance with IMC 0612, Power Reactor inspection Reports,
Appendix B, Issue Screening, dated September 7, 2012, because it adversely
impacted the Equipment Reliability attribute of the Initiating Events Cornerstone
objective to limit the likelihood of events that upset plant stability and challenge critical
safety functions during shutdown as well as power operations. Specifically, the failure to
perform the CAPR promptly (i.e. at the first outage of sufficient duration or first available
opportunity) reduced the effectiveness of the CAPR and increased the likelihood of a
recurring event. Using IMC 0609, Attachment 4, Initial Characterization of Findings at
Power, and Appendix A, The Significance Determination Process for Findings at
Power, issued June 19, 2012, the finding was screened against the Initiating Events
Cornerstone and determined to be of very low safety significance (Green) because the
9
finding did not involve the complete or partial loss of a support system that contributes to
the likelihood of, or cause an initiating event that affected mitigation equipment.
The inspectors determined this finding affected the cross-cutting area of human
performance, in the aspect of work management where the organization implements a
process of planning, controlling, and executing work activities such that nuclear safety is
the overriding priority. Delaying the performance of the testing because it extended the
outage did not demonstrate that nuclear safety was the overriding priority. [H.5]
Enforcement: Title 10 CFR 50, Appendix B, Criterion XVI, Corrective Actions, required,
in part, that measures shall be established to assure that conditions adverse to quality,
such as failures, malfunctions, deficiencies, deviations, defective material and
equipment, and non-conformances are promptly identified and corrected. In the case of
significant conditions adverse to quality, the measures shall assure that the cause of the
condition is determined and corrective action taken to preclude repetition.
Contrary to the above, from May 8, to May 29, 2017, the licensee failed to establish
measures to assure that corrective actions to preclude repetition were taken for the
Division 2 4160 VAC to 480 VAC transformers following the failure of Division I 480 VAC
Unit Substation Transformer 0AP05E2 on December 8, 2013 (a significant condition
adverse to quality). Specifically, the licensee scheduled and had the opportunity to
perform testing on the Division II 4160 VAC to 480 VAC transformers but failed to
perform the testing. The corrective actions in response to this violation are to perform
the testing at the next available opportunity which is the 2018 refueling outage. Because
this finding was of very low safety significance and was entered in the CAP
as AR 04089480, this violation is being treated as an NCV, in accordance with
Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000461/2017012-01: Failure to
Perform a Corrective Action to Prevent Recurrence)
.4 Review the Licensees Extent of Condition Evaluation Plan and Related Activities to
Evaluate the Licensees Assessment of the Condition of Similar Installed Transformers.
a. Inspection Scope
The inspectors reviewed the licensees extent of condition evaluation and plans to test
and/or replace existing safety-related and non-safety related 4160 VAC to 480 VAC
dry transformers.
b. Discussion
The licensee determined that there were five safety-related and 24 non-safety related
dry 4160 VAC to 480 VAC transformers for a total of 29. The licensee had developed
two separate plans to replace the safety-related and non-safety related transformers.
The plan to replace the safety-related transformers was scheduled to start with the
Division III transformer in 2021. Since the recent failure of the Division I transformer the
licensee has subsequently verbally committed to replacing the Division II transformers in
the next refueling outage in 2018. The inspectors reviewed the paperwork issued to
track that work to completion. Licensee management personnel also stated that they
planned to replace the Division III transformer on line sooner than 2021. The Division I
transformers were replaced due to the failures in 2013 and 2017.
10
The plan to replace the non-safety related transformers was delayed until it was
determined whether or not the station planned to apply for a license renewal. However,
the inspectors identified an issue with the equipment classification of three non-safety
related transformers.
c. Findings
Introduction: The NRC identified a finding of very low safety significance for the
licensees failure to follow procedure ER-AA-200-1001, Equipment Classification,
Revision 3. Specifically, three non-safety related 4160 VAC to 480 VAC transformers
were not properly classified as operational critical components.
Description: As part of the special inspection conducted from December 18 to
December 21, 2017, the inspectors were given a list of the 4160 VAC to 480 VAC dry
transformers on site. There were five safety-related and 24 non-safety related
transformers. The inspectors questioned if any of the non-safety related 4160 VAC
to 480 VAC dry transformers would cause a significant plant transient if it failed. The
licensee identified three transformers that would cause a reactor scram upon failure:
- 0AP44E 480 VAC Auxiliary Transformer D;
- 0AP92E 480 VAC Auxiliary Transformer P; and
- 1AP18E2 480 VAC Auxiliary Transformer 1H.
All three of these transformers were classified as non-critical components in the
licensees preventive maintenance program. Per licensee procedure ER-AA-200-1001,
Equipment Classification, Revision 3, Step 4.1, Component classification provides the
key input or basis for the Maintenance Strategy as well as work execution controls as
such it is important that the component classification is maintained accurate and the
basis for any changes is appropriately documented and approved. Licensee procedure
ER-AA-200-1001, Equipment Classification, Revision 3, Attachment 1, Steps 1.4
and 2.1, stated, in part, that if a component failure resulted in a reactor scram it was to
be classified as an operationally critical component.
Analysis: The inspectors determined the failure to properly classify 480 VAC auxiliary
transformers 0AP44E, 0AP92E, 1AP18E2 as operationally critical components, in
accordance with licensee procedure ER-AA-200-1001 was a performance deficiency.
Using guidance in IMC 0612, Power Reactor Inspection Reports, Appendix B, Issue
Screening, dated September 7, 2012, the inspectors determined that the performance
deficiency was more than minor because it was associated with the Initiating Events
Cornerstone attribute of equipment performance and adversely affected the cornerstone
objective of limiting the likelihood of events that upset plant stability and challenge critical
safety functions during shutdown as well as power operations. Specifically, the
performance of the transformers listed above was not fully evaluated as required by the
preventive maintenance program to ensure the likelihood of failure was limited.
In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of
IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power,
issued June 19, 2012, the inspectors determined that this finding was of very low safety
significance (Green) because, although the performance deficiency resulted in a
preventive maintenance strategy that may have resulted in lower reliability of
the 480 volt auxiliary transformers that would have caused a reactor scram, it would not
11
have resulted in the loss of mitigation equipment relied upon to transition the plant from
the onset of the scram to a stable shutdown condition.
The inspectors determined this finding affected the cross-cutting area of Human
Performance in the aspect of Consistent Process where individuals use a consistent
systematic approach to make decisions and risk insights are incorporated as
appropriate. Specifically, the licensee failed to use a consistent classification process to
reach the conclusion that the 480 VAC auxiliary transformers 0AP44E, 0AP92E,
1AP18E2 were properly classified as operationally critical components. [H.13]
Enforcement: The inspectors did not identify a violation of a regulatory requirement
associated with this finding due to the 480 VAC auxiliary transformers 0AP44E, 0AP92E,
1AP18E2 being classified as a non-safety related components. The licensee entered
this issue into its CAP as IR 04086449. As corrective actions, the licensee corrected
the criticality classifications for 0AP44E 480 VAC Auxiliary Transformer D, 0AP92E
480V Auxiliary Transformer P, and 1AP18E 480 VAC Auxiliary Transformer 1H.
Additionally, the licensee planned to perform a work group evaluation to document the
extent of condition to ensure that all dry type transformers onsite have the correct
criticality classification. (FIN 05000461/2017012-02: Failure to Properly Classify
Non-Safety Related Auxiliary Transformers as Operationally Critical Components)
.5 Continually Evaluate the Complexity and Significance of the Event to Determine if the
Circumstances Warrant Escalation of the Inspection to an Augmented Inspection Team.
Consider Any New Insights or Issues that Indicate Generic Implications, Increase in the
Risk Evaluation, or Design Vulnerabilities.
a. Inspection Scope
The inspectors held discussions with licensee personnel, reviewed the response of
equipment and operations personnel, and reviewed historical corrective action program
and maintenance related documents to evaluate whether a higher level of NRC
response was needed to review this event.
b. Discussion
The inspectors did not identify any circumstances of the event that warranted escalation
of the inspection to an Augmented Inspection Team. The event itself followed the
anticipated sequence according to accident analysis and with a few non-consequential
exceptions, plant equipment functioned as designed. While performing the preliminary
risk analysis for the MD 8.3 Evaluation to determine the risk criteria, the Senior Reactor
Analyst modeled the transient as a Loss of Condenser Heat Sink initiating event due to
the manual reactor scram and closure of the inboard MSIVs. Direction to use the steam
line drains to maintain the condenser as a heat sink when the MSIVs are closed was
contained in site procedures. Procedure CPS [Clinton Power Station] EOP-1; RPV
Control, listed MSL drains as one of the systems to be used to control RPV pressure
and cooldown rate. Procedure CPS 4100.01; Reactor Scram, directed the operator to
use an appropriate cooldown method listed in CPS 9000.06, Unit Shutdown. In
CPS 9000.06 Section 8.8, Cooldown With Main Condenser, MSL drain valves were
one method listed and included a statement that it was OK to shut MSIVs when using
this method. In this scenario, the control room supervisor stated that he considered
using RCIC for pressure control, but determined that he did not need to because the
12
main condenser remained available and he was able to control the pressure/cooldown
rate using the MSL drains to the main condenser. When the final MSIV closed and
pressure started to rise, the crew started RCIC in the pressure control mode. The
operating crew then continued to cooldown the reactor to Mode 4.
The inspectors identified a concern that evaluation of the generic implications of the
transformer failure could only be completed when the root cause of the transformer
failure was known. Determination of the actual cause of the transformer failure to
ground required an inspection of the damaged transformer at the ABB facility. The dry
type transformer was built in 1980 and the design worst-case loading was 40 percent of
the transformer rating. This type transformer was used in 29 480 VAC substations in the
plant (only 5 of the 29 are safety-related). The safety-related transformers are inspected
and megger tested at an 8 year frequency aligned with the safety-related bus outage
schedule. The non-safety dry type transformers are inspected and megger tested at an
8 year frequency (some have been extended to 16 years based on performance). No
degraded condition was found during the past preventative maintenance activities on the
dry type transformers. However, operators at Clinton identified noises coming from one
of the non-safety related dry type transformers in 2015. The transformer was removed
from service and replaced. The transformer vendors evaluation identified degraded
insulating material as the cause for the noise. Pending additional information from the
inspection of the December 2017 transformer failure and the associated root cause
investigation, the extent of condition and related activities were determined to be
acceptable.
c. Findings
No findings were identified. During the review of the reactor scram and transformer
failure that occurred on December 9, 2017, inspectors concluded that sufficient
information was not available to identify generic implications or potential performance
deficiencies with the design, manufacture or maintenance of the dry-type transformers
pending completion of the licensees root cause analysis to be documented in
RCE 04082490, Reactor Scram from Trip of 1AP07EJ.
This issue is an unresolved item (URI) pending NRC evaluation of the additional
information being developed by the licensee. (URI 05000461/2017012-03: Evaluation
of RCE 04082490, Reactor Scram from Trip of 1AP07EJ)
4OA6 Management Meetings
.1 Exit Meeting
On December 21, 2017, the inspectors presented the inspection results to Mr. T. Stoner
and other members of the licensee staff. The licensee acknowledged the issues
presented. Proprietary information was examined during this inspection and was
returned to the licensees representatives or destroyed. Specifics of proprietary
information are not detailed in this report.
ATTACHMENT: SUPPLEMENTAL INFORMATION
13
SUPPLEMENTAL INFORMATION
KEY POINTS OF CONTACT
Licensee
T. Stoner, Site Vice President
J. Cunningham, Maintenance Director (Acting Plant Manager)
T. Krawcyk, Site Engineering Director
M. Prospero, Manager Special Projects
T. Dean, Training Director
A. Siegmund, Security Manager
G. Engelhardt, Deputy Maintenance Director
R. Champley, Shift Operations Superintendent
M. Mayer, Security Operations Manager
D. Shelton, Regulatory Assurance Manager
K. Nicely, Principle Regulatory Engineer
B. Rush, Operations Support Manager
G. Sanders, Regulatory Assurance Engineer
N. Santos, Regulatory Assurance Engineer
K. Pointer, Senior Regulatory Assurance Engineer
J. Edom, Senior Risk Management Engineer
D. Reoch, Radiation Protection Technical Manager
J. Kimler, Acting Online Work Control Manager
G. Lux, Senior Staff Engineering Analyst
M. Heger, Senior Manager Design Engineering
J. Madappat, Engineer
J. Robinson, Senior Site Assessor
U.S. Nuclear Regulatory Commission
L. Kozak, Acting Chief, Reactor Projects Branch 1
J. Hanna, Senior Reactor Analyst
W. Schaup, Clinton Senior Resident Inspector
E. Sanchez-Santiago, Clinton Resident Inspector
Illinois Emergency Management Agency
S. Miscke, IEMA Resident Inspector
Attachment 1
LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED
Opened
05000461/2017012-01 NCV Failure to Perform a Corrective Action to Prevent
Recurrence [Section 4OA3.3]
05000461/2017012-02 FIN Failure to Properly Classify Non-Safety Related
Auxiliary Transformers as Operationally Critical
Components [Section 4OA3.4]
05000461/2017012-03 URI Evaluation of RCE 04082490, Reactor Scram
from Trip of 1AP07EJ) [Section 4OA3.5]
Closed
05000461/2013009-01 NCV Failure to Perform a Corrective Action to Prevent
Recurrence [Section 4OA3.3]
05000461/2013009-02 FIN Failure to Properly Classify Non-Safety Related
Auxiliary Transformers as Operationally Critical
Components [Section 4OA3.4]
2
LIST OF DOCUMENTS REVIEWED
The following is a partial list of documents reviewed during the inspection. Inclusion on this
list does not imply that the NRC inspector reviewed the documents in their entirety, but rather
that selected sections or portions of the documents were evaluated as part of the overall
inspection effort. Inclusion of a document on this list does not imply NRC acceptance of the
document or any part of it, unless this is stated in the body of the inspection report.
Work Orders
- WO 01534764-01, Clean and Inspect Unit Sub 1A (1AP11E)
- WO 04722432-05. Electrical Maintenance (EM) Perform Testing and Inspections and
Support Vendor in Performance of Specialized Testing (Doble) on Unit Sub 1A (1AP11E)
New Transformer.
- WO 01534764, Unit Sub Cleaning Substation 1A 1AP11E, October, 15, 2013
Corrective Actions
- IR 04082490, Reactor Scram from Trip of 1AP07EJ; December 9, 2017
- IR 01594407, Automatic Trip of Breaker 1AP07EJ, December 9, 2013
- RCE 01594407, Automatic Trip of Breaker 1AP07EJ - 0AP05E2 Transformer Failure
- IR 04082500; TDRFP Failed to Trip; December 9, 2017
- IR 04086449, NRCID: Incorrect Criticality Classification On Transformers, December 21,
2017
- IR 02699149, Old Unit Sub K Xmfr Inappropriately Stored Outside, August 31, 2016
- IR 01506730, Transformer Insulation Resistance did not Meet Minimum Value,
December 13, 2013
- IR 01624258, Action Plan to Address Aging Dry Type Transformers, February 21, 2014
- IR 01686987, Divisional Bus Outage Realignment from 6YR to 8YR Plan, July 30, 2014
- IR 04084743, Replace 480 Volt Unit Substation 1B, 1AP12E, December 16, 2017
- IR 04084748, Replace 480 Volt Unit Substation B, 0AP06E, December 16, 2017
- IR 04082501; Unable to Engage Main Turbine Turning Gear; December 9, 2017
- IR 04082623; Loss of AC Power to Fire Protection Detection Panel; December 10, 2017
- IR 04082631; Turbine Generator Did Not Trip after Scram; December 10, 2017
- IR 04082632; 1FW004 Leaks By Complicating Level Control; December 10, 2017
- IR 04082715; Primary to Secondary CTMT D/P OOS; December 11, 2017
- IR 04083264; Suppression Pool Level ITS During EOP-6
- IR 04082533; 1MC048C: Small Packing Leak; December 10, 2017
- IR 04082499; 1CB009A RFP Suction Valve Packing Leak; December 9, 2017
- IR 04082532; Manual Valve Handwheel Fell Off; December 10, 2017
- IR 04082978; Crew C 4.0 Crew Critique for CPS Scram December 9, 2017
- IR 04083060; Crew E 4.0 Critique of 1CF61 S/D
Procedures
- CPS 3002.01C003, Mode 3 Checklist
- CPS 3006.01, Unit Shutdown
- CPS 4100.01, Revision 23c; Reactor Scram
- CPS 4100.02, Revision 17f; Automatic Isolation
- CPS 4200.01, Revision 24d; Loss of AC Power
- CPS 4201.01, Loss of DC Power
- CPS 4004.01, Revision 10; Loss of Instrument Air
3
- CPS 4411.09, RPV Pressure Control Sources
- CPS 3310.01, Reactor Core Isolation Cooling (RI), Revision 29
- CPS 5063.07, Reactor Core Isolation Cooling Water Leg Pump Discharge Pressure Low,
Revision 30c
- ER-AA-200-1001, Equipment Classification, Revision 3
- ER-AA-200, Preventive Maintenance Program, Revision 3
- PI-AA-125, Corrective Action Program, Revision 6
- PI-AA-125-1001, Root Cause Analysis Manual, Revision 3
- CPS 8440.01, Insulation Testing, Revision 14
Miscellaneous
- Drawing AP-01, Auxiliary Power, Revision 010
- List of Clinton Station 4160V-480V Dry Transformers, Revision 2
- CPS-14-0014, Plan to Replace Safety-Related Aging Dry Type Transformers
- CPS-17-0092, Plan to Replace Non-Safety Related Aging Dry Type Transformers
- EC 622359, Replacement of Dry Type Transformer 1AP11E2
- Transformer Analysis Report - Unit Sub K Failure Analysis, October 6, 2016
- CPS/UFSAR Section 1.8, Conformance to NRC Regulatory Guides
- CPS/UFSAR Section 7.2.2.1.3.2, Loss of Instrument Air
- CPS/UFSAR Section 7.3, Engineered Safety Features
- CPS/UFSAR Chapter 8, Electric Power
- CPS/UFSAR Section 15A.6.3.2, Required Safety Action/Related Unacceptable Consequences
- CPS/UFSAR Section 15.2.10, Loss of Instrument Air System
- EC 396373, Start RCIC System for Pressure Control Without RCIC Water Leg Pump, Rev.
- Operating Crew Written Statements of Events for December 9, 2017
- Post Transient Review (OP-AA-108-114, Revision 13) Completed by the Licensee in
Response to December 9, 2017 Trip
- Scope Change Review Form 10138 for C1R18, dated December 16, 2017; WO 04726293
Replace Substation B1 Transformer
- Scope Change Review Form 10139 for C1R18, dated December 16, 2017; WO 04726315
Replace Substation 1B Transformer
4
LIST OF ACRONYMS USED
AC Alternating Current
ADAMS Agencywide Document Access Management System
ADS Automatic Depressurization System
CAP Corrective Action Program
CAPR Corrective Action to Prevent Recurrence
CCDP Conditional Core Damage Probability
CFR Code of Federal Regulations
CPS Clinton Power Station
EOP Emergency Operating Procedure
IA Instrument Air
IMC Inspection Manual Chapter
IR Inspection Report
IR Issue Report
LPCS Low Pressure Core Spray
MD Management Directive
MSIV Main Steam Isolation Valve
NCV Non-Cited Violation
NRC U.S. Nuclear Regulatory Commission
RCE Root Cause Evaluation
RCR Root Cause Report
RCIC Reactor Core Isolation Cooling
SIT Special Inspection Team
TS Technical Specification
UFSAR Updated Final Safety Analysis Report
URI Unresolved Item
VAC Volts Alternating Current
VG Standby Gas Treatment
5
EVENT TIMELINE [December 9, and 10, 2017]
December 9, 2017
13:47 Initiating Event: Trip of 4160 V 1A1 breaker 1AP07EJ, 480V Transformers 1A
and A1 Supply Breaker, due to failed unit substation 1AP11E 4160V/480V
transformer. Numerous Division 1 loads including Low Pressure Core Spray
(LPCS) system components (water leg keep fill pump and motor operated valves),
Residual Heat Removal (RHR) A system components (water leg keep fill pump
and motor operated valves), and the Reactor Core Isolation Cooling (RCIC) water
leg pump lost power. Loss of electrical power to Containment Instrument Air
isolation valve 1IA012A caused the 1IA005 Outboard Containment Isolation Valve
to close. Control room operators entered the abnormal procedure for loss of
instrument air and dispatched an equipment operator to check the 4160V breaker.
13:48 Secondary Containment differential pressure high alarm due to Fuel Building
Ventilation fans tripping due to dampers failing closed on the loss of AC power.
13:50 Operators placed the Standby Gas Treatment (VG) system in service due to Fuel
Building ventilation tripping off due to loss of power and secondary containment
differential pressure exceeding the Technical Specification limits. After starting the
VG system, secondary containment differential pressure was restored to within
limits in approximately 15 minutes.
13:53 Control rods started to drift in due to instrument air isolation. Operators manually
scrammed the reactor by placing the Mode Switch in Shutdown. The operations
crew entered Emergency Operating Procedure (EOP) 1, Reactor Pressure Vessel
(RPV) Control (4401.01), due to low RPV water level (expected condition with
scram) and entered Reactor Scram Procedure 4100.01. Reactor water level was
initially maintained by the condensate and feedwater systems. Reactor pressure
control was maintained using the turbine bypass valves. Operators also began
reducing auxiliary steam loads to control the cooldown rate.
14:00 An equipment operator reported from the field that a relay flag on breaker
1AP07EJ had dropped indicating a phase to ground overcurrent trip.
14:20 Operators started the A Condenser Air Removal Pump and shutdown the 1B
15:18 Operators removed the trip and control power fuses for the LPCS and RHR A
pumps due to loss of water leg keep fill pumps.
15:55 1AP07EJ breaker door was opened for inspection.
16:12 Operators manually shut control rod drive flow control valve 1C11-F034 to reduce
water input to reactor through the scram header (scram could not be reset due to
loss of air pressure).
Attachment 2
16:35 Operators completed the Division 1 DC load shed procedure to reduce load on
Division 1 batteries.
16:48 Control room operators operated main steam line (MSL) drains to augment bypass
valve pressure control (anticipating MSIV closure).
17:42 The licensee completed their Emergency Notification System notification
(EN 5311). The event notification worksheet (NRC Form 361) included the loss of
Division 1 AC power; a manual scram due to loss of instrument air pressure to
containment, and a loss of scram air header pressure. Division 1 emergency core
cooling (ECCS) systems (including LPCS) were de-energized due to the loss of
electrical power. The plant was in Mode 3 and continuing to cool down.
17:50 Last inboard MSIV shut. Pressure control on MSL drains.
18:59 The reactor core isolation cooling system (RCIC) was started in tank-to-tank mode
for reactor pressure control.
19:32 Operators placed RHR B in suppression pool cooling to support using RCIC for
reactor pressure control.
December 10, 2017
06:44 Operators manually opened 1IA012A per loss of AC procedure to line up backup
air bottles to Automatic Depressurization System (ADS) valves to maintain ADS
07:08 1IA005 and 1IA008 gagged open to restore instrument air pressure to containment
during loss of Division 1 AC power.
11:34 Control room operators reopened the MSIVs.
11:39 Control room operators shutdown RCIC.
11:46 Control room personnel reset the reactor scram signal.
11:47 RHR B shutdown from Suppression Pool Cooling Mode of operation.
12:21 Restored 1C11-F034 to normal lineup.
20:14 Entered Mode 4.
22:05 EOP entry conditions were cleared and the plant was stable in accordance with
CPS 3006.01, Unit Shutdown. Operations pesonnel exited EOP-1.
2
December 15, 2017
MEMORANDUM TO: James McGhee, Senior Resident Inspector
Byron Station
Division of Reactor Projects, Branch 3
FROM: Patrick L. Louden, Director /RA/
Division of Reactor Projects
SUBJECT: SPECIAL INSPECTION TEAM CHARTER FOR CLINTON
POWER STATION MANUAL SCRAM FOLLOWING LOSS
OF DIVISION 1 480 VAC POWER, DECEMBER 9, 2017
On Saturday, December 9, 2017, control room operators manually scrammed the reactor from
98 percent power following an electrical system perturbation. The operators had received
multiple alarms in the control room upon the unexpected opening of the 1A1 4160 VAC bus
breaker 1AP07EJ, which powers the 1A and A1 480 VAC substation buses. The licensee
determined that the breaker opened by design due to a fault on a 4160/480V step-down
transformer that feeds the 1A 480 VAC substation bus. Several minutes after the breaker
opened, the alarm came in for low scram pilot air header pressure. In response to two control
rods drifting into the reactor, control room operators initiated a manual scram (mode switch to
shutdown).
The loss of Division 1 480 VAC caused a loss of power to the Division 1 containment isolation
solenoid valves and isolated instrument air (IA) to the containment and the drywell. This also
resulted in a loss of air pressure to the inboard main steam isolation valves (MSIVs) and caused
the inboard MSIVs to start closing sometime after the transformer fault.
The loss of Division 1 480 VAC also caused low pressure core spray (LPCS), a single-train
system, and A train of residual heat removal system to be rendered inoperable because of the
loss of power to the keep fill pumps and AC powered motor operated valves. Reactor Core
Isolation Cooling (RCIC) was later declared inoperable because the RCIC water leg pump could
not function. The licensee could not be assured that these systems were free of voids.
Based on the deterministic criteria provided in Management Directive (MD) 8.3, NRC Incident
Investigation Program, the event met MD 8.3 criterion (d), in that there was a loss of RCIC and
LPCS, both single-train safety systems, and there was a loss of the secondary containment for
3 minutes. The event also met MD 8.3 criterion (g), in that the loss of power to the Division 1
480V substation bus was very similar to a failure that occurred in December 2013. The risk
assessment resulted in an estimated Conditional Core Damage Probability (CCDP) range of
4E-6 to 9E-6 and put the event in the SIT region. The decision is to dispatch a special
inspection team to the site beginning December 18, 2017. Although all plant systems appear to
have operated per design and there were no operator performance issues, the CCDP for this
event warrants a reactive inspection. The focus of the inspection is to gather initial information
relative to licensee actions taken following the similar event that occurred in 2013 and to
ascertain what the licensees plans are to evaluate the circumstances that led to the transformer
failure on December 9, 2017. Pending further risk or operational insights that may be
CONTACT: Ken Riemer, DRP Attachment 3
630-829-9628
developed as the team gathers and evaluates the facts, an SIT was considered appropriate. On
a daily basis, the team should evaluate the need for increasing the scope of the inspection if
conditions warrant.
Accordingly, based on the deterministic and risk criteria in MD 8.3, and after consultation with
NRR, a Special Inspection Team (SIT) will commence an inspection on December 18, 2017.
The SIT will be led by you and will include Charles Phillips. In addition, John Hanna, the Senior
Reactor Analyst, and John Robbins in DRS Engineering Branch 3 will be available to assist as
needed.
The SIT will establish an overview of the December 9, 2017, event and evaluate the facts,
circumstances, and the licensees actions (taken and planned) surrounding the event. The
specific charter for the Team is enclosed.
Docket No. 50-461
License No. NPF-62
Enclosure: Clinton Special Inspection Team Charter
CONTACT: Ken Riemer, DRP
630-829-9628
CLINTON SPECIAL INSPECTION TEAM CHARTER
This special inspection team is chartered to assess the circumstances surrounding the failure of
the 4160 to 480 VAC 1A transformer and subsequent manual reactor scram on
December 9, 2017. The decision to charter this Special Inspection Team is due to the loss of
safety function of multiple safety systems and the failure of the 4160 to 480 VAC transformer
and loss of the associated 480 substation buses, as well as the elevated risk resulting from the
event and unavailability of these systems (Low pressure core spray, reactor core isolation
cooling and secondary containment). The special inspection will be conducted in accordance
with Inspection Procedure 93812, Special Inspection. The special inspection will include, but
is not limited to, the items listed below. This charter may be revised based on the results and
findings of the inspection and the inspection results will be documented in NRC Inspection
Report 05000461/2017012.
1. Establish an overview of events related to the transformer failure, reactor scram, and
plant recovery actions. Review related licensee actions with respect to monitoring of
plant conditions, procedure usage, and decision making.
2. Review the operation of the plant equipment in response to the transient, including
adequacy of procedures and whether equipment operated in accordance with its design.
3. Evaluate licensee planned and completed corrective actions following the 2013
transformer failure and to the extent possible, assess if prior opportunities (e.g.,
surveillances, maintenance) existed to have identified transformer degradation or failure,
at an earlier point in time
4. Review the licensees extent of condition evaluation plan and related activities to evaluate
the licensees assessment of the condition of similar installed transformers.
5. Continually evaluate the complexity and significance of the event to determine if the
circumstances warrant escalation of the inspection to an augmented inspection team
(AIT). Consider any new insights or issues that indicate generic implications, increase in
the risk evaluation, or design vulnerabilities.
6. Identify any lessons learned from the Special Inspection, and, as appropriate, prepare a
feedback form on recommendations for improving reactor oversight process (ROP)
baseline inspection procedures.
Special Inspection Team
James McGhee, Byron Senior Resident Inspector, SIT Team Leader
Charles Phillips, Project Engineer, DRP
Charter Approval
/RA Kenneth Riemer Acting for/ 12/15/17 L. Kozak, Acting Chief, Branch 1, Division of
Reactor Projects
_/RA/_________12/15/17_____________ P. Louden, Director, Division of Reactor Projects
_/RA Karla Stoedter Acting for/ 12/15/17 M. Shuaibi, Acting Director, Division of
Reactor Safety
ADAMS Accession Number: ML17349A974