ML21105A543
| ML21105A543 | |
| Person / Time | |
|---|---|
| Site: | FitzPatrick  |
| Issue date: | 04/20/2021 |
| From: | Ray Lorson NRC Region 1 |
| To: | Rhoades D Exelon Generation Co |
| References | |
| EA-20-138, IR 2021090 | |
| Download: ML21105A543 (23) | |
See also: IR 05000333/2021090
Text
UNITED STATES
NUCLEAR REGULATORY COMMISSION
REGION I
2100 RENAISSANCE BOULEVARD, SUITE 100
KING OF PRUSSIA, PA 19406-2713
April 20, 2021
Mr. David P. Rhoades
Senior Vice President
Exelon Generation Company, LLC
President and Chief Nuclear Officer, Exelon Nuclear
4300 Winfield Road
Warrenville, IL 60555
SUBJECT:
JAMES A. FITZPATRICK NUCLEAR POWER PLANT - FINAL SIGNIFICANCE
DETERMINATION OF A WHITE FINDING WITH ASSESSMENT FOLLOW-UP
AND NOTICE OF VIOLATION - NRC INSPECTION REPORT
Dear Mr. Rhoades:
This letter provides you the final significance determination for the preliminary White finding
discussed in the U.S. Nuclear Regulatory Commission (NRC) letter dated January 21, 2021,
which included NRC Inspection Report Number 05000333/2020012 (ML21020A108).1 The
finding, as initially described in the report, involved a failure by Exelon Generation Company,
LLC (ExGen) to control defective parts at the Limerick Generating Station (Limerick) and
prevent their subsequent use at the James A. FitzPatrick Nuclear Power Plant (FitzPatrick). As
described in the subject inspection report, the NRC determined that this finding involved
apparent violations of Title 10 of the Code of Federal Regulations (10 CFR) Part 50,
Appendix B, Criterion XV, Nonconforming Materials, Parts, or Components and Criterion VII,
Control of Purchased Material, Equipment, and Services. The receipt and use of the defective
part at FitzPatrick resulted in a failure of the High Pressure Coolant Injection (HPCI) system on
April 10, 2020. Consequently, ExGen also violated FitzPatrick Technical Specification (TS) 3.5.1, since the HPCI system was determined to be inoperable for greater than the TS
allowed outage time.
In a letter dated February 26, 2021 (ML21057A190), ExGens Mr. Pat Navin, FitzPatrick Site
Vice President, provided a written response that acknowledged the circumstances that led to
the use of the defective part at FitzPatrick. However, in the response, ExGen also:
(1) described Exelons business services group (which handled the part at Limerick and
FitzPatrick) as being a separate corporate entity that works only under the specific facility
license at which the staff are physically located and disagreed the Criterion XV violation
represented a failure that was within FitzPatricks ability to foresee and prevent; (2) maintained
that FitzPatricks receipt inspection of the parts was performed in accordance with Criterion VII
and other regulatory and self-imposed requirements; and (3) provided information and insights
related to the NRCs preliminary characterization of the finding as being of low-to-moderate
1 Designation in parentheses refers to an Agency-wide Documents Access and Management System
(ADAMS) accession number. Documents referenced in this letter are publicly-available using the
accession number in ADAMS.
D. Rhoades
2
(White) safety significance and stated that the significance of this finding could potentially be
below the threshold for a White determination.
In the February 26, 2021, letter, ExGen also indicated that the NRCs description of the
Criterion VII apparent violation should be analyzed as a backfit under 10 CFR Part 50.109,
Backfitting. On March 3, 2021, Mr. Daniel Collins, Director, Division of Reactor Projects and
Mr. Eric D. Miller, Senior Resident Inspector, of my staff participated in a telephone call with
ExGens Mr. Navin and Ms. Adriene Smith, FitzPatrick Director of Organizational Performance
and Regulatory Affairs, to obtain clarification on whether ExGen was requesting to enter the
backfit appeal process described in NRC Management Directive 8.4, Management of
Backfitting, Forward Fitting, Issue Finality, and Information Requests. Mr. Navin and Ms. Smith
clarified during the call that ExGen was not requesting to enter the backfit appeal process at this
time but may choose to formally contest the violations or seek formal review of backfit concerns
after the final significance determination is issued. Therefore, the NRC evaluated the remaining
items in ExGens February 26, 2021, letter. A summary of ExGens positions as provided in its
letter, the NRCs response to the points raised by ExGen, and the details of the NRCs
conclusion on the safety significance of this issue, are provided in Enclosure 1.
After careful consideration of the information developed during the inspection and the additional
information provided in ExGens February 26, 2021, letter, the NRC staff has clarified the finding
and has concluded that the finding is appropriately characterized as White, a finding of low to
moderate safety significance. The NRC staff has also determined that the finding involved
violations of 10 CFR Part 50, Appendix B, Criterion VII, Criterion XV, and TS 3.5.1, and has
revised those violations. Our considerations in reaching these determinations included that:
1) the duration of the finding and violations should be changed from 2010 to 2017 in order to
more clearly focus on the time period in which Fitzpatrick had become part of the ExGen Fleet;
2) the NRCs Enforcement Policy holds licensees accountable for the actions of their
employees, contractors and vendors, and, therefore, the information in ExGens response
regarding ExGens corporate structure and internal work practices (i.e. roles and responsibilities
of buyers and sellers) would not impact the assignment of this regulatory and enforcement
action to Fitzpatrick; and, 3) our review of the additional information provided relative to the risk
for this finding did not materially impact our assessment. In fact, a more comprehensive
analysis of some of the information provided may have actually resulted in an overall increase in
our risk assessment. It should be noted that the violations are strictly focused on compliance
with 10 CFR Part 50, Appendix B, but should not be viewed as limiting or impacting any of your
internal practices as long as the applicable underlying regulatory requirements are satisfied.
The revised finding is provided in Enclosure 2. You have 30 calendar days from the date of this
letter to appeal the NRC staffs determination of significance for the identified White finding.
Such appeals will be considered to have merit only if they meet the criteria given in the NRC
Inspection Manual Chapter 0609, Attachment 2, Process for Appealing NRC Characterization
of Inspection Findings (SDP Appeal Process), effective January 25, 2021. An appeal must be
sent in writing to the Regional Administrator, Region I, 2100 Renaissance Boulevard, Suite 100,
King of Prussia, PA 19406.
The revised violations are cited in the Notice of Violation (Notice), provided as Enclosure 3.
Because the violations are related, they have been categorized collectively as an enforcement
problem, which is a way of documenting violations that share a common factor (i.e., cause and
effect) rather than citing individually. By grouping such violations, the NRC applies appropriate
focus on the underlying factors that caused the concerns, so that licensees can develop
effective and comprehensive corrective actions.
D. Rhoades
3
In accordance with the NRC Enforcement Policy, the Notice is considered an escalated
enforcement action because it is associated with a White finding. You are required to respond
to this letter and should follow the instructions specified in the enclosed Notice when preparing
your response. If you have additional information that you believe the NRC should consider,
you may provide it in your response to the Notice. The NRC review of your response to the
Notice will also determine whether further enforcement action is necessary to ensure
compliance with regulatory requirements.
As a result of this White finding in the Mitigating Systems Cornerstone, the NRC has assessed
FitzPatrick to be in the Regulatory Response column of the NRCs Reactor Oversight Process
Action Matrix described in Inspection Manual Chapter 0305, Operating Reactor Assessment
Program, retroactive to the fourth calendar quarter of 2020. The NRC plans to conduct a
supplemental inspection for this finding in accordance with Inspection Procedure 95001,
Supplemental Inspection Response to Action Matrix Column 2 (Regulatory Response) Inputs,
effective January 1, 2021, following Exelons notification of readiness for this inspection. This
inspection is conducted to provide assurance that the root causes and contributing causes of
any performance issues are understood, the extent of condition is identified, and the corrective
actions are sufficient to prevent recurrence.
In accordance with 10 CFR 2.390 of the NRC's Rules of Practice and Procedure, a copy of this
letter, its enclosure, and your response will be made available electronically for public inspection
in the NRC Public Document Room or from the NRCs document system (ADAMS), accessible
from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html. To the extent possible,
your response should not include any personal privacy, proprietary, or safeguards information
so that it can be made available to the Public without redaction.
Should you have any questions regarding this matter, please contact Ms. Erin E. Carfang, Chief,
Projects Branch 1, Division of Reactor Projects in Region I, at 610-337-5120.
Sincerely,
Raymond K. Lorson
Deputy Regional Administrator
Docket No.
50-333
License No.
Enclosures:
As stated
cc w/encl: Distribution via ListServ
Raymond K.
Lorson
Digitally signed by
Raymond K. Lorson
Date: 2021.04.20
14:07:45 -04'00'
X
SUNSI Review/
X
Non-Sensitive
Sensitive
X
Publicly Available
Non-Publicly Available
OFFICE
RI/ORA
RI/DORS
RI/DORS
RI/DRSS
RI/ORA
RI/ ORA
NAME
M McLaughlin
E Miller via email
D. Collins via
P. Krohn via
B Klukan via email
R McKinley via email
DATE
3/26/21
4/3/21
4/6/21
3/31/21
3/31/21
4/2/21
OFFICE
RI/DORS
RI/DRA
NAME
E Carfang via
R Felts via email
R Fretz via email
R Lorson
DATE
4/7/21
4/7/21
4/7/21
4/20/21
ENCLOSURE 1
NRC RESPONSE TO INFORMATION PROVIDED IN THE
EXGEN LETTER DATED FEBRUARY 26, 2021, REGARDING A
HIGH PRESSURE COOLANT INJECTION FINDING
As discussed below, the NRC staff reviewed the points raised by Exelon Generation Company,
LLC (ExGen) and determined that the proper characterization of the finding remains of
low--to--moderate safety significance (White). The NRC staff has also determined that the
finding involved violations of 10 CFR Part 50 Appendix B, Criterion VII, Criterion XV, and
However, the NRC staff has revised the finding and violations as described in Enclosures 2
and 3. Specifically, the NRC staff determined that: 1) the duration of the finding and violations
should be changed from 2010 to 2017 in order to more clearly focus on the time period in which
Fitzpatrick had become part of the ExGen Fleet; 2) the NRCs Enforcement Policy holds
licensees accountable for the actions of their employees, contractors and vendors , and,
therefore, the information in ExGens response regarding ExGens corporate structure and
internal work practices (i.e. roles and responsibilities of buyers and sellers) would not impact
the assignment of this regulatory and enforcement action to Fitzpatrick; and, 3) our review of the
additional information provided relative to the risk for this finding did not materially impact our
assessment. In fact, a more comprehensive analysis of some of the information provided may
have actually resulted in an overall increase in our risk assessment. It should be noted that the
violations are strictly focused on compliance with 10 CFR Part 50, Appendix B, but should not
be viewed as limiting or impacting any of your internal practices as long as the applicable
underlying regulatory requirements are satisfied.
SUMMARY OF EXGEN COMMENT - Independence of Licensed Facilities
ExGen stated that the James A. FitzPatrick Nuclear Power Plant (JAF) licensed facility and the
Limerick Generating Station (LIM) licensed facility are legally independent entities with separate
NRC-issued operating licenses that are supported by common resources as part of the
larger ExGen fleet. Support resources provided by the Exelon Business Services Company
(BSC) and which are assigned to individual licensed facilities are subject to the specific
operating license(s) of the facility to which they are assigned. Therefore, the ability to foresee
and prevent the deficiency at LIM (seller) in 2010 should not be a basis for the deficiency being
foreseeable and preventable by JAF (buyer) in 2017.
NRC RESPONSE
Although each facility maintains separate NRC operating licenses, the JAF License No. DPR-59
and the LIM License Nos. NPF-39 and NPF-85 each specify Exelon Generation Company, LLC
as the licensee. However, more salient to this issue is that, upon joining the ExGen fleet in
2017, JAF began to utilize and have access to many of the same processes and programs as
LIM and other ExGen sites, including the corrective action program and component tracking
database. The NRC identified that both of these programs contained information pertaining to
the defective high pressure coolant injection (HPCI) system oil pressure control valve (PCV).
The performance deficiency and apparent violations as originally presented in NRC inspection
report number 05000333/2020012 described in full the circumstances that led to the installation
of the defective PCV at JAF. This included describing the failures that occurred in 2010 at LIM
Enclosure 1
2
in response to a Title 10 of the Code of Federal Regulations (10 CFR) Part 21 notification when
staff at that site did not segregate or place an electronic hold on the PCV, contrary to Exelon
procedures. The NRC staff considered the comments in ExGens February 26, 2021, letter
pertaining to the finding and acknowledges that in 2017, ExGen staff could not have prevented
the process breakdown that occurred at LIM in 2010. However, the NRC staff maintains that it
was reasonable in 2017 for ExGen staff to have identified the information about the defective
component that was readily available in the component tracking database and corrective action
database; common ExGen programs utilized by both sites. For example, when receiving the
part, ExGen staff at JAF accessed the component tracking database and removed a 'hold' due
to a shelf life concern. The NRC staff identified that information about the Part 21 notification
was readily available in the database and could reasonably be identified by a qualified
procurement engineer when performing a review of available information to address the hold'.
Additional detail about the NRC staffs conclusions related to the finding is provided in the NRC
response to ExGens comment below related to the Criterion VII violation.
In light of these considerations, the NRC staff revised the finding and violations to properly focus
on the events that occurred in 2017. The circumstances of the 2010 failures are still included in
the Description Section of the finding as background information. The revised finding and
violations are provided as Enclosures 2 and 3 to this final determination report.
SUMMARY OF EXGEN COMMENT - 10 CFR Part 50, Appendix B, Criterion XV
The 10 CFR Part 50, Appendix B, Criterion XV violation and associated performance deficiency
occurred at the LIM licensed facility in 2010 by support resources working in direct support of
the LIM operating licenses. The Inspection Report identified an apparent violation of 10 CFR
Part 50, Appendix B, Criterion XV, "Nonconforming Materials, Parts, or Components" based on
the failure to properly identify and segregate non-conforming material that was identified and
communicated to LIM by a General Electric-Hitachi (GEH) 10 CFR Part 21 notification. The JAF
Causal Analysis to address the HPCI failure determined that as part of LIMs response to the
2010 GEH 10 CFR Part 21 notification, LIM personnel failed to follow procedure requirements to
place an electronic hold and segregate the defective part. This allowed the defective part to be
sold to JAF in 2017 without being notified of the deficiency.
NRC RESPONSE
As described above, the NRC staff acknowledges that prior to 2017, ExGen staff at JAF could
not have prevented the 2010 failures at LIM related to identifying and segregating the
non-conforming PCV since JAF was not transferred to ExGen until March 2017. Therefore, the
finding and the related Criterion XV violation have been revised accordingly. However, the NRC
staff maintains that the remaining aspect of the finding and Criterion XV violation is attributable
to JAF. Specifically, the regulation requires that licensees establish measures to control
materials, parts, or components which do not conform to requirements in order to prevent their
inadvertent use or installation and to accept, reject, repair, or rework nonconforming items.
Regardless of the past failures to identify and segregate the nonconforming PCV, in 2017
ExGen again did not control and reject the nonconforming component, resulting in its
acceptance and installation at JAF. The NRC staff maintains that JAF is responsible for this
failure.
In particular, the activities performed in 2017 to transfer the part between LIM and JAF and to
accept and use the part at JAF were performed in support of ExGen and the JAF license. As
Enclosure 1
3
noted in Section 1.2 of the NRC Enforcement Policy, it is NRC policy to hold licensees
responsible for the acts of their employees, contractors, or vendors and their employees, and
the NRC may cite the licensee for violations committed by its employees, contractors, or
vendors and their employees. Therefore, regardless of the physical locations of the involved
staff, their reporting authority under the greater Exelon Corporation structure, or the typical
responsibilities of these individuals to support the licensed facilities at which they are located,
when individuals are directed by a licensee to perform activities that affect that NRC licensee,
that licensee assumes the responsibility for violations caused by the individuals actions or
inactions.
Furthermore, the NRC staff maintains that, in consideration of the common procedures and
processes shared between LIM and JAF, it was reasonable for ExGen staff at JAF to have
foreseen and prevented the acceptance and use of the nonconforming PCV and that ExGen
staff at JAF should have identified and rejected the defective item during receipt inspection
activities conducted in December 2017. Additional information about the finding is provided in
the NRC response to ExGens comment below related to the Criterion VII violation.
SUMMARY OF EXGEN COMMENT - 10 CFR Part 50, Appendix B, Criterion VII
The receipt inspection completed at JAF in 2017 was performed consistent with the
requirements of 10 CFR Part 50, Appendix B, Criterion VII and the JAF Quality Assurance
Program (QAP) requirements and, therefore, does not constitute a failure to follow a regulatory
or self-imposed standard. The Inspection Report identified a Violation of 10 CFR Part 50,
Appendix B, Criterion VII, "Control of Purchased Material, Equipment, and Services based on
the failure to identify, during receipt inspection, that the purchased valve was the subject of a
2010 10 CFR Part 21 notification. ExGen has confirmed that the JAF receipt inspection was
performed consistent with the requirements of 10 CFR Part 50, Appendix B, Criterion VII and
the JAF QAP and, therefore, was not a failure to follow a regulatory or self-imposed standard.
Additionally, without further actions beyond these requirements, the receipt inspector could not
reasonably have been expected to identify that the valve was the subject of the 2010 10 CFR
Part 21 notification based on the documentation provided by the seller (LIM).
NRC RESPONSE
Title 10 CFR Part 50, Appendix B, Criterion VII requires that licensees establish measures to
assure that purchased material, equipment, and services, whether purchased directly or through
contractors and subcontractors, conform to procurement documents. However, the measures
implemented by ExGen in 2017 did not identify the nonconformance of the PCV. A licensees
QAP and the processes developed to implement that program provide the mechanism for the
licensee to comply with 10 CFR Part 50, Appendix B; they do not serve as replacements or
alternatives to these regulatory requirements. Therefore, if a licensees QAP, or implementation
of the QAP, fails to ensure that the licensee meets an Appendix B requirement, the licensee is
in violation of that requirement.
The NRC staff maintains that, in this case, the receipt inspection performed at JAF (the intended
measure to assure purchased material conformed to procurement documents) was not sufficient
to meet this Appendix B requirement. Specifically, as noted in the finding description in
Enclosure 2, the ExGen Quality Assurance Program Manual (QAPM), Revision 0, Section A,
Management, stated, the requirements and commitments contained in the QAPM are
mandatory and must be implemented, enforced, and adhered to by all individuals and
organizations. Section 5, Procurement Verification, required a program to be established and
Enclosure 1
4
implemented to verify the quality of purchased items and services. Section 6, Identification and
Control of Items, required a program to be established and implemented to identify and control
items to prevent the use of incorrect or defective items. The receipt inspection, conducted using
ExGen Procedure SM-AA-102, Revision 23, Warehouse Operations, implemented these
procurement verification requirements. This receipt inspection did not identify that the PCV
contained a defective diaphragm.
The NRC staff maintains that it was reasonably within ExGens ability to foresee and prevent the
use of the nonconforming PCV at JAF. In particular, information about the defective diaphragm
was located in both the ExGen component tracking database and corrective action database.
The inspectors reviewed the component tracking database and determined that the issue report
(IR) associated with the 10 CFR Part 21 report should have been reasonably identified by a
qualified procurement engineer. Notably, when receiving the part, ExGen staff at JAF accessed
the component tracking database and removed a 'hold' due to a shelf life concern. The NRC
staff identified that information about the Part 21 notification was readily available in the
database and could reasonably be identified by a qualified procurement engineer when
performing a review of available information to address the hold.' The staff also noted that the
information was available to staff involved with the transfer of the component to JAF through the
ExGen corrective action program, because the issue report was noted in the component
tracking database and had not been resolved at the time the part was moved to and accepted at
JAF. As such, it was reasonable for ExGen staff responsible for, and in control of, both sides of
the internal transaction that occurred in order to effect the movement of the PCV from LIM to
JAF in 2017 to have identified the Part 21 information related to the PCV.
SUMMARY OF EXGEN COMMENT - Uncertainties Input for Significance Determination
ExGen provided new information and additional insights which the licensee stated reduce some
of the calculational uncertainties that weigh into the Significance Determination (SDP). ExGen
indicated that the uncertainties are smaller than characterized in the NRC inspection report and
could potentially result in a significance below the threshold for a White determination.
1. The JAF Engineering staff has performed additional engineering reviews related to the
maximum oil leak rate from the HPCI system PCV which provide information supporting the
leak rate used in the JAF SDP analysis.
2. JAF Operations staff have gathered and documented additional timeline and performance
data which better characterizes the uncertainty in the analysis of operator credit for
identification and restoration of HPCI oil.
3. JAF Operations and Engineering staff have validated information regarding Main Control
Room (MCR) staff operation of HPCI during transient conditions.
4. JAF Engineering and Probabilistic Risk Assessment (PRA) Staff provided information
regarding incorporation of Electric Power Research Institute (EPRI) fire realisms and the
associated reduction in fire ignition frequencies (FIFs) for areas that are risk important
relative to HPCI operation.
NRC RESPONSE
The NRC staff reviewed the information in ExGens written response and determined that the
proper characterization of this finding overall remains of low-to-moderate safety significance
Enclosure 1
5
(White). The NRC staff agreed that ExGens use of revised fire ignition frequencies from those
used in the NRC risk determination was appropriate. However, the slight reduction in the
calculated increase in core damage frequency (CDF) due to a lower fire risk estimate did not
impact the overall NRC risk assessment and significance determination process conclusion.
The following details the NRCs assessment regarding the four areas of input provided by
ExGen for consideration in the SDP:
1. Calculated Maximum Oil Leak
NRC Response
ExGen utilized a slightly lower minimum leak rate of 0.19 gallons per minute (gpm) with a
maximum leak rate of 2.8 gpm, which considered higher operating oil temperatures when the
system would be in service. The NRC SDP analysis utilized a minimum leak rate of 0.28 gpm
with a maximum leak rate of 3.65 gpm to arrive at a weighted leak rate estimate which would
account for the probability of an early re-positioning of the degraded, nonconforming Part 21
pressure control valve (PCV). As stated in the detailed risk evaluation (DRE), the NRC used
industry data to estimate a probability that an early HPCI system trip would lead to a large leak
from the PCV. The early probabilistic trip of the HPCI system was determined to be 0.15
through several different methodologies as described within the DRE. However, the DRE
described how this number may be an underestimation of the actual data, even though used in
the development of the weighted leak rate estimation. It is not uncommon for the HPCI system
to be tripped early for level control during postulated events and a sample of industry data
reviewed, reflected that an early HPCI trip could occur up to 50 percent of the time based on a
review of a sample of Licensee Event Reports. This illustrates in part, the uncertainty with
evaluating what leak rate would have existed within this degraded part during a postulated event
where HPCI would have responded. The NRC noted in the DRE that the initial leak rate
subsequently identified by ExGen was reported as one pint in two minutes, although computer
information provided to the analysts indicated the pump was run with the PCV at normal
pressure for only one minute. Of further concern related to the accuracy of ExGens estimated
leak rate was the inconsistency between the leak rate assumed in the analysis and the initial
leak of 0.25 gpm leak rate that was verbally reported to the resident inspector staff. As a result,
the analyst determined that the leak rate values provided in the ExGen analysis and follow-up
letter were uncertain, underestimated the actual leak rate, and are not viewed as credible.
When ExGen attempted to quantify the leak rate through a second start of the auxiliary oil
pump, the pump was secured after 30 seconds based on a much larger leak rate that
overwhelmed the collection apparatus used to measure the oil quantity. The 1.3 gpm was
based on the captured oil for the 30 second run. The analysts noted that the second run was
once again performed with the auxiliary oil pump (AOP), which develops a lower pressure
(85-95 psig) than if the shaft driven oil pump (SDOP) was started (105-110 psig) during an
actual run. The output of the controlling pump pressure is controlled by a main oil system PCV,
which will control downstream pressure to 38 psig. However, there is some response time by
the main PCV resulting in a slightly higher pressure pulse (i.e. stress) that was expected to have
been absorbed by the downstream nonconforming PCV diaphragm. This further adds to the
uncertainty, and validity of any measured oil leak when it was performed under non-operating
conditions. Actual turbine operating conditions result in different dynamics relative to the oil
system, with the potential for an even larger tear on the weakened nonconforming pressure
control valve diaphragm.
Enclosure 1
6
Notwithstanding the multitude of uncertainties mentioned above, if the NRC were to adjust their
weighted leak rate estimate by using a maximum leakage capped at 2.8 gpm or even slightly
lower as suggested by ExGen, this would have an inconsequential effect on the amount of time
assumed and calculated within the NRC DRE before the SDOP and AOP would lose suction
due to the loss of oil inventory. The NRC determined the information provided by ExGen would
have no substantive impact in this area, as the uncertainties overwhelm the ExGens
engineering analysis, including the inputs used in that analysis, for the calculated maximum oil
leak rate.
2. Oil Leak Mitigation/Credited Operator Actions
ExGens position is that giving no credit for operators to recover the HPCI system in the event of
an oil leak does not recognize proceduralized actions that the operators would take and be
capable of executing. ExGen contends that operating procedure, OP-15, Revision 68,
Section G.10, Adding Oil to HPCI Sump with HPCI in Service, provides explicit guidance to
maintain oil in the running level band. ExGen states that operators performed a timed
walkdown for recovery actions to maintain adequate oil level in the HPCI sump in the event the
HPCI PCV diaphragm had a tear. The walkdown was reported to result in operators
successfully restoring oil in approximately 27.5 minutes. ExGen stated that with regards to the
time until the leak is located, there are several considerations. OP-AA-103-102, Watch-
Standing Practices outlines expectations for non-licensed operators to monitor all equipment
they are responsible for. This procedure also establishes post-start and post-shutdown system
walk down requirements to ensure expected system and components response. Lastly, ExGen
stated that if the control room received the HPCI Turbine Bearing Oil Pressure Low annunciator
and HPCI operation is required, the main control room (MCR) operators would respond as
follows:
1. If the HPCI Auxiliary Oil Pump did not auto-start, then attempt to manually start the
pump from the control room.
2. If the annunciator does not clear, then send an operator locally to investigate the reason
for the loss of oil pressure.
3. The field operator would observe a large amount of oil at the HPCI skid and check HPCI
oil sump level.
4. Operations would perform actions per OP-15, Section F Shutdown to secure the AOP
when the HPCI turbine is not rotating.
5. The control room would direct the field operator to add oil to the HPCI sump.
ExGens position is that the oil leak can be effectively managed with readily available equipment
and procedurally directed operator actions.
NRC Response
ExGen procured a Vendor Report, EC-631895, Technical Evaluation to Support Availability of
HPCI System Due to Oil Leak in PCV-12, dated June 18, 2020, which was developed
regarding the oil leak and determined that there is a nominal 1-inch drop in the oil sump for
every 13 gallons of oil. During the postulated events evaluated in an SDP such as this, there
are multiple assumed failures of various equipment that lead to a path of core damage. For
Enclosure 1
7
these events, various equipment may be automatically started from emergency diesel
generators to the reactor core isolation cooling system (RCIC), HPCI, and a multitude of other
equipment. Thus, there can be a multitude of potential response areas required for plant
operators, which directly affects their response time. As noted in the calculation of the
maximum oil leak section above, a probabilistic leak rate could be in the area of 0.7 gpm to an
assumed maximum leakrate in the area of 2.8 gpm or higher, depending on the heatup rate of
the oil and any other factors which would have contributed to the PCV diaphragm tear. As
noted above, a plant operator may enter the HPCI cubicle and check the oil standpipe and with
various potential oil leak rates possible, the indicated level would likely be well within the sight
glass, with zero other operational abnormalities occurring or noticeable, including HPCI turbine
and pump bearing temperatures. This PCV is not located in the front of the machine and
depending on when an operator would check the machine, this leak may not be identified.
The NRC noted that the design of the HPCI control oil system at FitzPatrick does not have a
sump low-level alarm. Additionally, during a leak, it is apparent that other critical early cues of
higher bearing temperatures, low oil pressures, and low sump level would not be available
through instrumentation and would not provide ensured identification of a notable leak prior to
complete failure of the system to operate. Additionally, the assumed leak rate in this SDP
evaluation has unquantifiable uncertainties as mentioned above, with the potential to have been
larger than measured in the relatively colder non-turbine operating condition when the tear was
initially generated. The sequence of events per this design and nonconforming PCV, would be
a continued leak at an uncertain rate, with a silent effect on the system, the controls, and the
annunciators, as there would be no abnormalities until the system would terminate operation
due to complete suction loss of the shaft-driven oil pump (SDOP). As noted above, the only
alarm or cue would be the turbine bearing oil pressure, which would likely not annunciate even
with a large leak, due to a controlling PCV maintaining 38 psig upstream, which would serve to
compensate for the degraded PCV diaphragm leak, and continue to provide downstream flow
and pressure to the bearings.
The first absolute automatic cue for the operators would be this alarm, but it appears, per the
design, that it would come in after the SDOP would lose its suction prime due to low oil level,
resulting in a loss of discharge pressure. This would drop pressure to the control valve actuator
rotating gear pump and result in closure of the control steam valves as well as the turbine stop
valve. The SDOP will then spin down, with the main auxiliary oil pump (AOP) starting on low oil
pressure at around 35 psig. A further uncertainty is the AOP will start and run with no suction
head, likely cavitating as it continues to run without an adequate oil supply. As noted above, the
operators would actually be instructed to start the AOP if it didnt auto start even with an
inadequate suction pressure. When an operator would arrive in the area, there would be 60 to
65 gallons or more of hot oil within the skid area. There would be no leak visible or identifiable,
because the nonconforming PCV would have closed on loss of pressure and there would be no
pressure to drive any further leakage.
In this condition, it would not be obvious if there had been a pipe crack, a severe crack in the
various control oil piping and fittings, or complete failure of the oil system, and its likely
operators would be challenged to identify where the oil came from with 120 degree oil
potentially scattered within the skid area. Furthermore, there is another uncertainty with how
long the AOP would have been running, as it does not automatically receive a trip signal,
resulting in cavitation without any oil supply and/or if it would have damaged itself. ExGen
states they would enter section G.10, Adding Oil to HPCI Oil Sump with HPCI in Service. With
this scenario, however, HPCI would not be in-service as it would be secured automatically
(steam valves closed) due to the failure, contrary to the procedure entry definition/description.
Enclosure 1
8
OP-15, G.10, as written is intended to gather pre-filtered oil and if not prefiltered, to obtain an oil
filtration device and extension cord and fill an oil transfer container from labeled oil barrels in the
lube oil storage room per engineering direction. Again, it should be noted, it is very likely the
leak source would be difficult to determine at this point. Additionally, hooking up a funnel to a
leak source appears to not be proceduralized and the placement would not even be recognized
in this scenario, not to mention the effects of running the oil system below the AOP suction
capability, with air entrainment or other kinds of potential adverse effects on the AOP and motor.
Lastly, if recovery of HPCI in this situation became a priority as suggested in ExGens response,
an operator would have to fill the sump by finding a portable pump along with electricity for
said pump (i.e. for LOOP scenarios there likely isnt normal outlet power), then keep-up with
the potential large leak rate while looking for the leak point. Then, once the leak point is
identified, the operator needs to build the apparatus to route the leak to the sump. Additionally,
a recovery event such as this includes a human error probability (HEP) assessment which
would need to be analyzed on how it may affect the most dominating basic event in this risk
analysis (failure to depressurize event). This scenario will take cognitive ability to detect what
happened, make decisions and to understand the success path to restore the high pressure
system, including its recovery feasibility. In core damage scenarios or cutsets, this HPCI
recovery event would be accompanied by the SPAR model depressurization basic event
(ADS-XHE-XM-MDEPR). This event would now likely justify including a diagnosis as well as an
action assessment due to the cognitive nature of understanding and deciding if the operator
could restore a high pressure injection source in time while reactor vessel level is lowering,
while waiting until EOPs direct depressurization with the potential thought that HPCI is close to
being brought back to service. Adding this diagnostic piece to the normal depressurization
event in the SPAR model raises the potential for a higher failure probability by almost an order
of magnitude even considering extra time for diagnosis and action to depressurize in the
SPAR-H calculation. Therefore, by including a HPCI recovery event, the failure to depressurize
event could now be considered for increased failure probability due to the diagnosis needed in
this situation. A rough calculation has shown that this can increase one of the dominating
postulated core damage event scenarios such as a loss-of-condenser-heat sink for a 38-day
exposure (DRE risk of 4E-7/yr) to an increased risk of 2E-6/yr for this one event.
In summary, recovery credit including the challenges accompanying this condition, should likely
be considered for an increased failure in the ADS-XHE-XM-MDEPR basic event, which may
have a significant increase in the end result of the previous risk determination and make the
effects of recovery credit a non-substantive issue relative to lowering the calculated increase in
CDF/yr for this event.
Notwithstanding this, based on the above uncertainties, the lack of cues within the system
design, the uncertainties with the leak rate, the uncertainty with the timing and ability to detect
the leak through a walkdown post event for many systems, operator recovery was determined
not to be a feasible action in the primary base case evaluation of the condition, and the
information provided has no substantive effect on that conclusion. However, as is always
prudent, the NRC analysts performed a sensitivity study using appropriate considerations of
recovery difficulty in the DRE (Cases 3 and 4, used 1 out of 5 recovery) within the report giving
some credit for recovery. This sensitivity did not account for an evaluation of increasing the
failure to depressurize (basic event) through the model. If this became a base assumption the
SRA believes it would be appropriate to re-analyze for the above consideration which would
likely result in a notable overall increase of the calculated CDF for the HPCI PCV failure.
Enclosure 1
9
3. HPCI Operations During Transient Conditions
ExGen has stated that while operating HPCI with drywell pressure greater than 2.7 psig, the full
flow path test return valves close to divert all flow to the Reactor Pressure Vessel (RPV). To
control RPV water level, the main control room (MCR) operators would dial the flow controller
back as needed to control the injection rate and maintain level within the required bands
established in the station Emergency Operating Procedures (EOPs).
ExGen also acknowledged that running the HPCI pump on minimum flow with the full-flow test
return valves closed, is not preferred for long term reliability. However, in response to transient
and accident conditions, operations in this manner is consistent with guidance in station EOPs
by ensuring the HPCI system remains available as a high-pressure water source. As such,
MCR operators would not secure HPCI if it was running on minimum flow nor would the pump
be damaged during a transient or accident response to the point that sufficient flow could not be
developed.
NRC response
The NRC acknowledges that the station EOPs direct level control within the proper bands, using
any systems that may be available. The NRC also recognizes the difficulty with controlling level
using HPCI for various events. This is illustrated in the Fitzpatrick RCIC System, B 3.5.3,
technical specification basis document referring to Actions A.1 and A.2. The Bases states for
transients and certain abnormal events (i.e. which drive the NRCs risk SDP evaluation), with no
loss-of-coolant-accident, RCIC (as opposed to HPCI) is the preferred source of makeup coolant
because of its relatively small capacity, which allows easier control of the RPV water level.
Thus, there is a limited time allowed to restore RCIC to an operable status. This simply
confirms the challenge of operating HPCI under conditions where there may be lower makeup
requirements.
OP-15, Revision 68, High Pressure Coolant Injection, System Description, describes the
design operating conditions for when pump discharge water flows through the feedwater line
into the RPV, that HPCI will continue to inject 4250 gpm until RPV water level reaches
222.5 inches, then HPCI will trip on high RPV water level. If RPV water level lowers to
126.5 inches, HPCI will auto-initiate following a high RPV water level trip. This simply explains
the automatic design of the system where it is designed to continually, with no operator action,
inject, trip and reset as required. However, the NRC understands that this is not the preferred
operation or response as operators are trained and instructed to control RPV level within the
proper station EOP designated band without allowing HPCI trips; this description from OP-15
simply illustrates the design of the system.
As documented in the NRC SDP evaluation, while we have found no restriction within the
Fitzpatrick operating procedures specific to HPCI operating in the minimum flow mode taking
water from the condensate storage tank and depleting it to the torus, there are some
uncertainties with this operating mode (i.e., low flow only available). Specifically, there are Terry
Turbine Maintenance guides and technical reports/industry guidance applicable to HPCI, which
recognize that the design basis is to deliver constant flowrate to the RPV over a wide range of
reactor pressures. If reduced vessel injection flowrate (i.e., match decay heat for non-LOCA
transients), is required to control level, this is an off-design operation and is time-consuming and
requires operator attention to control. The pump head versus flow characteristics are relatively
flat as flowrate decreases below rated volume and it is recognized that reduced flowrates below
a nominal 75 percent below design, will likely cause system instability within the control system.
Enclosure 1
10
Additionally, typical Terry turbine guidance cautions that the pump/turbine controls should not
be operated less than 50 percent of rated flow for a sustained period of time. Further guidance
states that operating at 10 to 20 percent minimum flow is intended for startup and shutdown
only and severe internal cavitation at high head conditions can result in pump damage.
According to ExGens above statement, operators would not secure HPCI in the minimum flow
mode and therefore may have run the pump in this off-normal condition for long periods of time
in postulated events. There are several uncertainties with the definitive nature of this statement.
First, OP-15, Attachment 4, HPCI AUTO INITIATION VERIFICATION and SUBSEQUENT
ACTIONS, recognizes appropriately, that when operation of HPCI below 3000 gpm is required,
monitoring of the system operation frequently is required to ensure proper operation and if
oscillations occur then the system is to be operated with the controller in manual. The NRC
recognizes that if oscillations occur, the flow controller will result in increasing and decreasing
speed changes. This by itself would create the need for the main PCV within the oil system to
respond to control to 38 psig with changes in the SDOP speed. Any small delays in PCV
response could result in pressure changes and or small stress changes to the downstream
degraded PCV diaphragm. Additionally, OP-15, Attachment 6, HPCI Operation Flowchart,
requires verifying HPCI parameters per Section D of OP-15. These parameters include
monitoring outboard-end and pump-end vibration levels to ensure less than 0.385 inches per
second.
Because this operation may occur for extensive time periods through a mission time up to
15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br />, long periods of HPCI operation can be expected in this condition. The HPCI system
is not normally run for long periods on minimum flow and hence there likely is no data available
on system effects. Therefore, an additional uncertainty would be if this mode of operation (long
term minimum flow operation) would challenge the procedures acceptable pump vibration
levels with the expected cavitation with the pump internals. If vibration levels would be
exceeded, this would be a decision point with regard to operation of the system (i.e. should the
system be used to fill to the EOP level zone at higher rates, then secured and restarted when
boil-off reduced level back to the lower end of the control zone). It is also unknown how internal
pump cavitation may affect the HPCI skid itself and if there could be any adverse effects on
resonance vibration on the nonconforming degraded PCV diaphragm condition through the
mission time, while running in this off-normal condition. It should be noted if there would be an
adverse effect on the nonconforming PCV; this could extend the exposure time going
backwards, factoring in all of the uncertainties mentioned above.
In addition, the DRE documented the basis for the 0.15 trip rate of the turbine based on industry
operating data, which is relevant to the expected operator responses for operation of the HPCI
turbine.
In summary, the statement concluding the operators would stay on minimum flow has
uncertainty with the ability to do that, considering the system is designed for much higher
flowrates per its design. Lastly, extended operation on minimum flow will deplete the preferred
condensate storage tank (CST) suction source to the torus, resulting in additional challenges of
CST source availability for the longer- term mission and also on control rod drive pump
capability as the CST is depleted for certain events. Because of the above uncertainties, the
NRC SDP used an exposure time above 38 days (i.e., 59 days) for only a very few applicable
events.
Notwithstanding the many uncertainties identified above with the definitive statements of not
securing HPCI if operating on extended minimum flow conditions, the NRC in response to this
Enclosure 1
11
letter and statement of expected operations, revised the 59-day exposure times for the
events to 38 days to determine its impact on the SDP. The result was there was an
inconsequential difference for the few events where the longer exposure time was used and
the final determination of a low to moderate risk significant issue remained unchanged.
4. Fire Analysis
The JAF PRA staff developed and used updated fire modeling ignition frequencies for the fire
areas reviewed in the NRC SDP analysis. The NRC analysis had used fire scenario
frequencies listed in the Fitzpatrick Fire PRA notebook at the time of the evaluation
(JF-PRA-021.11 James A. FitzPatrick - Fire Probabilistic Risk Analysis Summary &
Quantitative Notebook, Revision 2). ExGens position is that the fire ignition frequencies in the
JAF analysis should be used because they are based on more realistic fire modeling
frequencies.
NRC response
The NRC concurs that the JAF updated fire frequencies would result in smaller frequencies and
reduction in the NRC fire model risk assessment. The SPAR Delta CDF increase was
calculated to be 9.9E-7/yr. Using the revised frequencies, the Delta CDF in Table 2 of ExGens
letter resulted in a total of 5.6E-7/yr risk increase. It should be noted fire risk was not a
dominant contributor to this risk assessment.
NRC Overall Risk Determination Conclusion
The NRC does not believe the information and analysis presented by ExGen is substantive in its
nature in reducing the uncertainties and/or influencing a change in the final determination of
significance below the threshold for a White determination, in part, for the various reasons
mentioned above.
However, the NRC analysts reviewed all the information presented by ExGen in their
February 26, 2021 letter and performed a final sensitivity using all the suggested considerations
provided by ExGens supporting information.
The NRC analysts final sensitivity revised the exposure times from 59 days to 38 days based
on the potential for survival of HPCI remaining on minimum flow and never being tripped or
secured during the course of mission times up to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The NRC analysts used the HPCI
recovery credit (0.8) as documented in the original DRE, however it should be noted this was
not the base case and they did not evaluate the effect this could have or potential increase on
the dominant basic event, (failure to depressurize), as mentioned above in the recovery section.
Finally, the analysts used the lower fire risk increase presented by ExGen. With all these
sensitivity changes, the increase in risk for internal events, flooding, fire and seismic resulted in
a revised conditional increase in CDF/yr of a nominal 2E-6/yr. It should be noted these changes
were only performed as a sensitivity as the NRC determined the information presented had no
substantive effect on the risk outcome (i.e., 3E-6/yr) and did not change the original SRA PRA
modeling assumptions, except for the fire ignition frequencies used. All other PRA modeling
assumptions have been documented and justified within the existing DRE.
Although some of the information provided within this letter may suggest there could be a
potential for an increase in risk over that which was originally calculated, the analysts believed
Enclosure 1
12
the original estimate remains a valid best-estimate given the information and uncertainties
relevant to this issue.
RISK SUMMARY
In summary, the NRC staff carefully reviewed the responses provided by ExGen. The NRC
staff acknowledges and considered ExGens viewpoint, but ultimately determined that the new
information did not alter the NRCs original risk assessment outcome or methodology as
described in Inspection Report 05000333/2020012, dated January 21, 2021 (ADAMS Accession
Number: ML21020A108). Based upon the additional information provided, the NRC staff
concluded that the finding remains appropriately characterized as White.
ENCLOSURE 2
REVISED FINDING
Defective Part Results in High Pressure Coolant Injection System Pressure Control Valve
Failure
Cornerstone
Significance
Cross-Cutting Aspect
Report Section
White NOV
05000333/
2020012-01
Open
[H.1] - Resources
The inspectors documented a self-revealed White finding and related violations of Title 10 of
the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion VII, Control of
Purchased Material, Equipment, and Services, and Criterion XV, Nonconforming Materials,
Parts, or Components, because Exelon Generation, LLC (ExGen) did not adhere to
requirements to ensure that a high pressure coolant injection (HPCI) system oil pressure
control valve (PCV) conformed to all procurement requirements. Consequently, ExGen did
not reject the defective PCV, as identified in a 10 CFR Part 21 notification. As a result,
ExGen accepted and installed the part at FitzPatrick on December 16, 2017. The HPCI
system was subsequently declared inoperable on April 10, 2020, during a planned
surveillance test due to the defect identified in the Part 21 notification. This also caused the
HPCI system to be inoperable for greater than its technical specification allowed outage time
in accordance with NRC reportability guidelines.
Description: The HPCI system at FitzPatrick provides an emergency source of water
following a transient or accident. This high pressure source of coolant is delivered from two
water sources using steam generated from the reactor to drive the associated turbine and
pump. The HPCI system pump can deliver up to 4,250 gallons per minute and may be
operated across a wide range of reactor pressures. The HPCI system pump and turbine are
supported by an oil system designed to lubricate bearings and provide adequate pressure to
control the steam turbine stop and control valves.
On November 7, 2017, the NRC issued Order NRC-2017-0177 establishing Exelon
Generation, LLC (ExGen) as the owner, operator, and holder of the FitzPatrick Renewed
Facility Operating License No. DPR-59. ExGen owns or co-owns and operates 22 nuclear
reactors at 13 sites in four states. As stated, in part, in the application dated August 18, 2016
(ML16235A081), and approved by NRC Order NRC-2017-0177, ExGen provided that:
integration of the operation of FitzPatrick with Exelon Generations
current fleet of nuclear power plants, will allow consolidated operations of
FitzPatrick and the other nuclear units operated by Exelon Generation.
The seamless integration of FitzPatrick into Exelon Generations
operations will create a single organization with responsibility over all of
the plants for which it is the licensed operator.
Exelon Corporation, the parent company of ExGen, also operates a central supply
organization (Business Services Company, LLC (BSC)) that provides support for day-to-day
nuclear station (site) operations with a dual reporting relationship to the centralized supply
organization and the site organization. ExGen implements a fleet-wide quality assurance
program, along with procurement and warehouse procedures for all its associated nuclear
Enclosure 2
2
stations to verify, store, and move components between stations using BSC personnel. Once
accepted within the ExGen Quality Management System, a component can be installed at the
site of receipt, or moved and installed at another facility.
On December 11, 2008, ExGen received, inspected, and accepted a HPCI oil pressure
control valve, stock code 11466532. On July 1, 2010, ExGen was notified of a defective part
when General Electric-Hitachi issued MFN 10-192 (ML101820160), Part 21 Reportable
Condition Notification: Failure of HPCI Turbine Overspeed Reset Control Valve
Diaphragm. The Part 21 identified a vulnerability associated with the HPCI system oil PCV
actuator diaphragm due to a manufacturing error. This error resulted in inadequate fabric
reinforcement that is critical to ensure durability and reliability of the diaphragm, preventing
tearing of the diaphragm when used in the HPCI turbine lube oil system turbine trip and reset
valves (PCVs). The failure of the HPCI system PCVs diaphragm results in a loss of HPCI
system turbine lubricating and control oil through the failed diaphragm. According to the
Part 21 notification, depending on the amount of oil lost and the system demands, this loss
could ultimately result in a failure of the HPCI system. ExGen engineering staff entered
issue report (IR) 1086768 into their corrective action program and assigned actions including
direction to BSC staff to address the Part 21.
Exelon procedure SM-AA-102, Warehouse Operations, Revision 14, Attachment 3,
Section 1.5.2 required, Items found to be of suspect quality or deficient (e.g., items identified
externally via 10 CFR Part 21 defect reporting or items identified internally by maintenance)
shall be:
1. Placed on Hold status electronically to prevent allocation and inadvertent issue. In
Passport this may require the item to be issued from stock, then returned, moved from
[pending] to [hold] status.
2. Physically segregated from acceptable items with the same Catalog ID/Stock Code.
BSC staff working for ExGen at Limerick identified a PCV subject to the Part 21 notification at
the Limerick facility, but did not segregate or place an electronic hold on the PCV in their
component tracking database to prevent PCV installation with the defective diaphragm as
required by internal procedures following the July 1, 2010, Part 21 notification. BSC staff
documented the nonconformance in the component tracking database which referenced
IR 1086768. However, procedure SM-AA-102 did not include a standard method to
document Part 21 deficiencies within the component tracking database. Instead, there were
several options for documenting a Part 21 notification within this system, and ExGen relied on
skill of the craft for determining how to implement the procedural requirement.
On November 19, 2010, SM-AA-102 was revised to require, conspicuous signage that
shows these items are on hold, in addition to the electronic hold and physical separation.
However, BSC staff at Limerick did not use conspicuous signage on the PCV.
On December 16, 2017, ExGen issued purchase order (P.O.) 637326 to move the HPCI
system PCV from the Limerick warehouse to FitzPatrick during a planned HPCI system
maintenance window. During a HPCI maintenance window in December 2017, ExGen
replaced the HPCI PCV diaphragm and spring as part of preventive maintenance. Following
maintenance, ExGen was unsuccessful at restoring HPCI due to inadequate pressures in the
oil system. ExGen did not have a replacement PCV on site at the time, and subsequently
located the subject PCV at Limerick.
Enclosure 2
3
To effect the movement of the part, BSC staff at Limerick and FitzPatrick followed the
process prescribed in the ExGen Quality Assurance Program Manual (QAPM),
Revision 0. QAPM Section A, Management, stated, the requirements and commitments
contained in the QAPM are mandatory and must be implemented, enforced, and adhered to
by all individuals and organizations. QAPM, Section 5, Procurement Verification, required
that, a program is established and implemented to verify the quality of purchased items and
services at intervals and to a depth consistent with the item's or service's importance to
safety, complexity, and quantity and the frequency of procurement. QAPM, Section 6,
Identification and Control of Items, required a program to be established and implemented
to identify and control items to prevent the use of incorrect or defective items.
The inspectors determined that, in spite of utilizing the above process, staff involved with
transferring the HPCI PCV and inspecting and accepting it at FitzPatrick did not identify the
nonconformance, even though the information was readily available in both the ExGen
component tracking database and corrective action database. The defective valve was
accepted using a Product Quality Certificate dated December 12, 2008. This Product Quality
Certificate was invalidated by the July 1, 2010 Part 21 notification. The PCV was
subsequently installed in the FitzPatrick HPCI system during the maintenance window on
December 16, 2017.
Staff involved with transferring the HPCI PCV and inspecting and accepting it at FitzPatrick
reasonably had access to information about the nonconformance through at least two
means. First, to receive the part at FitzPatrick, BSC staff at FitzPatrick accessed the
component tracking database and removed a 'hold' due to a shelf life concern. The
inspectors reviewed the component tracking database and identified that information on
IR 1086768, the IR associated with the 10 CFR Part 21 notification, was present in the
database and could reasonably be identified by a qualified procurement engineer when
performing a review of available information to address the hold'. Second, the Part 21
information was available to the staff through the ExGen corrective action program, as
IR 1086768 was noted in the component tracking database. The IR had not been resolved at
the time the part was moved to and accepted at FitzPatrick, and this information would have
been available to any staff involved with this activity.
As a result of the defective part installation, on April 10, 2020, at 1:15 AM, while conducting
monthly technical specification surveillance testing of the HPCI auxiliary oil system, operators
identified an oil leak on pressure control valve (PCV), 23PCV-12. The auxiliary oil pump was
secured and the HPCI system was still considered operable by ExGen staff. Operators were
not able to definitively quantify the initial leak. At 3:00 AM, a second start of the auxiliary oil
pump was attempted to quantify the leak. During the second run, operators estimated the
leak to be 1.3 gpm. Thus, the HPCI system was declared inoperable and placed the station
into a higher licensee-established risk category (Yellow). ExGen notified the NRC of the
inoperability per 10 CFR Part 50.72(b)(3)(v)(D) via Event Notification 54647. The 23PCV-12
valve was replaced and the HPCI system restored to operable status on April 10, 2020,
at 8:02 PM.
Corrective Actions: ExGen performed immediate corrective actions to replace the defective
HPCI system PCV. ExGen also performed a fleet-wide stand down for procurement staff
to conduct additional training. Additionally, ExGen created a separate action for each ExGen
site to validate that a similar condition does not exist regarding dispositioning Part 21
components with inaccurate codes in their parts tracking database. Furthermore, ExGen
Enclosure 2
4
revised its warehouse and procurement procedures, adding steps pertaining to items subject
to 10 CFR Part 21 notifications and items with holds.
Corrective Action References: IR 4334315, IR 4348906
Performance Assessment:
Performance Deficiency: The inspectors determined that ExGen failed to ensure that
purchased material conformed to all procurement requirements and to reject a nonconforming
item and prevent its installation and use as required by 10 CFR Part 50, Appendix B, Criterion
VII, Control of Purchased Material, Equipment, and Services, and Criterion XV, Non-
conforming Materials, Parts, and Components, which was within their ability to foresee and
prevent.
ExGen implemented the requirements of 10 CFR Part 50, Appendix B using the Quality
Assurance Program Manual (QAPM), Revision 0 in 2017. Section A, Management, stated,
the requirements and commitments contained in the QAPM are mandatory and must be
implemented, enforced, and adhered to by all individuals and organizations. Section 5,
Procurement Verification, required a program to be established and implemented to verify
the quality of purchased items and services. Section 6, Identification and Control of Items,
required a program to be established and implemented to identify and control items to
prevent the use of incorrect or defective items. Procedure SM-AA-102 implemented these
procurement verification requirements.
On December 16, 2017, ExGen failed to verify that the PCV conformed to procurement
documents and did not identify that the PCV was nonconforming. Consequently, the PCV
containing the defective diaphragm was not rejected and was, instead, accepted using a
Product Quality Certificate dated December 9, 2008, which was subsequently invalidated by
the Part 21 notification issued July 1, 2010. The PCV was installed at FitzPatrick on
December 16, 2017 and failed on April 10, 2020.
Screening: The inspectors determined the performance deficiency was more than minor
because it was associated with the Equipment Performance attribute of the Mitigating
Systems cornerstone and adversely affected the cornerstone objective to ensure the
availability, reliability, and capability of systems that respond to initiating events to prevent
undesirable consequences. Specifically, the HPCI system was unavailable to perform its
safety function as a result of the failed PCV.
Significance: The inspectors assessed the significance of the finding using Appendix A, The
Significance Determination Process (SDP) for Findings At-Power. The inspectors reviewed
Inspection Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings,
and determined the finding affects the mitigating system cornerstone. The inspectors
evaluated the significance of this finding using Inspection Manual Chapter (IMC) 0609,
Appendix A, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2
- Mitigating Systems Screening Questions. The inspectors determined that the finding
represented a loss of the PRA function of a single train, the HPCI system, for greater than its
technical specification (TS) allowed outage time and required a detailed risk evaluation
(DRE).
A Region I Senior Reactor Analyst (SRA) performed a detailed risk evaluation. The finding
was determined to be of low to moderate safety significance (White). The risk important core
damage sequences were dominated by internal events, primarily loss of condenser heat sink
Enclosure 2
5
and loss of main feedwater. The dominant core damage sequence is loss of condenser heat
sink, failure of high-pressure injection (HPI), and failure to manually depressurize the
reactor. See Enclosure 1 to this final determination report and the Attachment, HPCI Oil
PCV Failure Detailed Risk Evaluation, to the preliminary determination report (ADAMS
Accession Number: ML21020A108) for a detailed review of the quantitative and qualitative
criteria considered in the final risk determination.
Cross-Cutting Aspect: H.1 - Resources: Leaders ensure that personnel, equipment,
procedures, and other resources are available and adequate to support nuclear safety. The
cause of the finding was determined to be associated with a cross-cutting aspect
of Resources in the Human Performance area because ExGen staff failed to identify and
address a nonconformance during verification of the quality of the HPCI system
PCV. Specifically, the inspectors determined there were multiple ways for ExGen to
reasonably identify a nonconformance associated with the PCV diaphragm which had not
been addressed. Furthermore, procurement implementing procedures did not provide
adequate guidance to ensure that procedure users would identify and resolve this issue.
Having comprehensive steps within the relevant procedure would likely have prevented
installation of the defective part at FitzPatrick.
ENCLOSURE 3
Exelon Generation Company, LLC
Docket No. 50-333
James A. FitzPatrick Nuclear Power Plant
License No. DPR-59
During an NRC inspection conducted from April 10, 2020, through December 14, 2020, and for
which an inspection exit meeting was conducted on December 14, 2020, violations of NRC
requirements were identified. In accordance with the NRC Enforcement Policy, the violations
are listed below:
A. Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion VII,
Control of Purchased Material, Equipment, and Services, requires, in part, that
measures shall be established to assure that purchased material, equipment, and
services, whether purchased directly or through contractors and subcontractors conform
to procurement documents. Documentary evidence that material and equipment conform
to the procurement requirements shall be available at the nuclear power plant or fuel
processing plant site and shall be sufficient to identify the specific requirements, such as
codes, standards, or specifications, met by the purchased material or equipment.
Contrary to the above, on December 16, 2017, the licensee did not ensure measures
were established to assure that purchased material, equipment and services conform to
procurement documents. Specifically, the licensee did not ensure that a replacement
high pressure coolant injection (HPCI) system oil pressure control valve (PCV)
conformed to procurement documents. As a result, on December 16, 2017, the licensee
accepted and installed for use a PCV at the James A. FitzPatrick Nuclear Power Plant
(FitzPatrick) that had a known nonconforming material defect (i.e., defective diaphragm)
that was first identified in a 10 CFR Part 21 report on July 3, 2010.
B. Title 10 CFR Part 50, Appendix B, Criterion XV, Nonconforming Materials, Parts, or
Components, requires that measures shall be established to control materials, parts, or
components which do not conform to requirements in order to prevent their inadvertent
use or installation. Nonconforming items shall be reviewed and accepted, rejected,
repaired, or reworked in accordance with documented procedures.
FitzPatrick Technical Specification (TS 3.5.1), in part, requires the HPCI system to be
operable in Modes 1, 2, and 3 with reactor steam dome pressure >150 psig. If the HPCI
system is determined to be inoperable, it shall be returned to an operable status within
14 days. If not restored to an operable status, the unit shall be shut down and in Mode 3
within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Contrary to the above, from December 16, 2017, to April 10, 2020, the licensee did not
ensure that measures were established to control materials, parts, or components which
do not conform to requirements in order to prevent their inadvertent use or installation
and did not ensure that nonconforming items shall be reviewed and accepted, rejected,
repaired, or reworked in accordance with documented procedures. Specifically, staff
involved with the sale, inspection, and installation of the HPCI PCV to FitzPatrick failed
to ensure the PCV conformed to all procurement requirements and failed to reject the
nonconforming item. As a result, the valve was accepted and installed for use at
Enclosure 3
2
FitzPatrick. On April 10, 2020, the HPCI system was declared inoperable during a
monthly surveillance test as a result of a leak and system oil loss from the
nonconforming HPCI PCV that would have prevented the system from performing its
safety function. Consequently, the HPCI system was rendered inoperable prior to
April 10, 2020, for a period longer than its TS allowed outage time, and the unit was not
shut down and placed in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> in accordance with NRC reportability
guidelines.
These violations are categorized collectively as a problem and are associated with a White
Significance Determination Process finding.
Pursuant to the provisions of 10 CFR 2.201, Exelon Generation Company, LLC (the licensee) is
hereby required to submit a written statement or explanation to the U.S. Nuclear Regulatory
Commission, ATTN: Document Control Desk, Washington, DC 20555-0001 with a copy to the
Regional Administrator, Region I, and a copy to the NRC Resident Inspector at the facility that is
the subject of this Notice, within 30 days of the date of the letter transmitting this Notice of
Violation (Notice). This reply should be clearly marked as a "Reply to a Notice of Violation;
EA-20-138" and should include for each violation: (1) the reason for the violation, or, if
contested, the basis for disputing the violation or severity level, (2) the corrective steps that
have been taken and the results achieved, (3) the corrective steps that will be taken, and (4) the
date when full compliance will be achieved. Your response may reference or include previous
docketed correspondence, if the correspondence adequately addresses the required response.
If an adequate reply is not received within the time specified in this Notice, an order or a
Demand for Information may be issued as to why the license should not be modified,
suspended, or revoked, or why such other action as may be proper should not be taken. Where
good cause is shown, consideration will be given to extending the response time.
If you contest this enforcement action, you should also provide a copy of your response, with
the basis for your denial, to the Director, Office of Enforcement, United States Nuclear
Regulatory Commission, Washington, DC 20555-0001.
Because your response will be made available electronically for public inspection in the NRC
Public Document Room or from the NRCs document system (ADAMS), accessible from the
NRC Web site at http://www.nrc.gov/reading-rm/adams.html, to the extent possible, it should not
include any personal privacy, proprietary, or safeguards information so that it can be made
available to the public without redaction. If personal privacy or proprietary information is
necessary to provide an acceptable response, then please provide a bracketed copy of your
response that identifies the information that should be protected and a redacted copy of your
response that deletes such information. If you request withholding of such material, you must
specifically identify the portions of your response that you seek to have withheld and provide in
detail the bases for your claim of withholding (e.g., explain why the disclosure of information will
create an unwarranted invasion of personal privacy or provide the information required by
10 CFR 2.390(b) to support a request for withholding confidential commercial or financial
information). If safeguards information is necessary to provide an acceptable response, please
provide the level of protection described in 10 CFR 73.21.
In accordance with 10 CFR 19.11, the licensee may be required to post this Notice within two
working days of receipt.
Dated this 20th day of April 2021.