IR 05000277/2018003
| ML18317A003 | |
| Person / Time | |
|---|---|
| Site: | Peach Bottom  |
| Issue date: | 11/13/2018 |
| From: | David Pelton Division Reactor Projects I |
| To: | Bryan Hanson Exelon Generation Co, Exelon Nuclear |
| Greives J | |
| References | |
| EA-18-107, EA-18-108 IR 2018003 | |
| Download: ML18317A003 (36) | |
Text
UNITED STATES ber 13, 2018
SUBJECT:
PEACH BOTTOM ATOMIC POWER STATION - INTEGRATED INSPECTION REPORT 05000277/2018003 AND 05000278/2018003, PRELIMINARY WHITE FINDING, AND EXERCISE OF ENFORCEMENT DISCRETION
Dear Mr. Hanson:
On September 30, 2018, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Peach Bottom Atomic Power Station (Peach Bottom), Units 2 and 3. On October 23, 2018, the NRC inspectors discussed the results of this inspection with Mr. Pat Navin, Peach Bottom Site Vice President, and other members of your staff. The results of this inspection are documented in the enclosed report.
The enclosed inspection report discusses a finding that the NRC has preliminarily determined to be White, a finding with low to moderate increased safety significance that may require additional NRC inspections. As described in the enclosed report, the finding is associated with an apparent violation of Title 10 of the Code of Federal Regulations (CFR) Part 50, Appendix B, Criterion XVI, Corrective Action, because Exelon did not establish measures to assure that conditions adverse to quality associated with the E-3 emergency diesel generator (EDG)
scavenging air check valve were promptly identified and corrected which resulted in a failure of the E-3 EDG on June 13, 2018. As a consequence, Exelon also violated Peach Bottom Units 2 and 3 Technical Specification (TS) 3.8.1, since the E-3 EDG was determined to be inoperable for greater than the TS allowed outage time. The finding was assessed based on the best available information using Inspection Manual Chapter (IMC) 0609.04, Initial Characterization of Findings, issued October, 7, 2016, and Exhibit 2 of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012. The basis for the NRCs preliminary significance determination is described in the enclosed report.
As an apparent violation of NRC requirements, this finding is being considered for escalated enforcement action in accordance with the Enforcement Policy, which can be found on the NRCs Website at https://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html. In accordance with IMC 0609, we intend to complete our evaluation and issue our final safety significance determination within 90 days from the date of this letter. The NRCs SDP is designed to encourage an open dialogue between your staff and the NRC; however, the dialogue should not affect the timeliness of our final determination. We believe that we have sufficient information to make a final significance determination.
However, before we make a final decision, we are providing you an opportunity to provide your perspective on this matter, including the significance, causes, and corrective actions, as well as any other information that you believe the NRC should take into consideration. Accordingly, you may notify us of your decision within 10 days from the issue date of this letter to: (1) request a regulatory conference to meet with the NRC and provide your views in person, (2) submit your position on the finding in writing, or (3) accept the finding as characterized in the enclosed inspection report.
If you choose to request a regulatory conference, the meeting should be held in the NRC Region I office within 40 days of your receipt of this letter, and will be open for public observation. The NRC will issue a public meeting notice and a press release to announce the date and time of the conference. We encourage you to submit supporting documentation at least one week prior to the conference in an effort to make the conference more efficient and effective. If you choose to provide a written response, it should be sent to the NRC within 40 days of your receipt of this letter. You should clearly mark the response as Response to Preliminary White Finding and Apparent Violation in Inspection Report No. 05000277/2018003 and 05000278/2018003; EA-18-107, and send it to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region I, and the NRCs Resident Inspector at Peach Bottom.
You may also elect to accept the finding as characterized in this letter and the inspection report, in which case the NRC will proceed with its regulatory decision. However, if you decline to request a regulatory conference or to submit a written response, you relinquish your right to appeal the NRCs final significance determination, in that by not doing either, you would fail to meet the appeal requirements stated in the Prerequisite and Limitation sections of Attachment 2 of IMC 0609.
Please contact Jonathan Greives at 610-337-5337 within 10 days from the issue date of this letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we will continue with our significance determination and enforcement decision.
Because the NRC has not made a final determination in this matter, no Notice of Violation is being issued for this inspection finding at this time. In addition, please be advised that the number and characterization of the apparent violation may change based on further NRC review. The final resolution of this matter will be conveyed in separate correspondence.
In addition, the NRC reviewed Licensee Event Report 05000278/2018-001-00, which described the circumstances associated with a failed reactor core isolation cooling (RCIC) turbine exhaust pressure switch. It was recognized that this failed switch resulted in the Unit 3 RCIC system being inoperable for a period of time that exceeded the allowed outage time of fourteen days detailed in TS 3.5.3, and therefore, was a violation of TSs. A Region I Senior Reactor Analyst (SRA) performed a risk evaluation and determined the issue was of low to moderate safety significance (White).
Although this issue constituted a violation of NRC requirements, the NRC determined that the pressure switch failure which caused the Unit 3 RCIC system to be inoperable was not within Exelons ability to reasonably foresee and correct. As a result, the NRC did not identify a performance deficiency associated with this condition. The NRCs assessment considered Exelons maintenance practices, industry operating experience, vendor and industry maintenance, and testing recommendations. Based on the results of the NRCs inspection and assessment of the RCIC issue, I have been authorized, after consultation with the Director, Office of Enforcement, to exercise enforcement discretion in accordance with NRC Enforcement Policy Section 2.2.4, Exceptions to Using Only the Operating Reactor Assessment Program, and Section 3.10, Reactor Violations with No Performance Deficiency. The Region I Regional Administrator was also consulted regarding enforcement discretion for this issue.
Finally, NRC inspectors documented one finding of very low safety significance (Green) in this report. The finding involved a violation of NRC requirements. The NRC is treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.
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 I; the Director, Office of Enforcement; and the NRCs Resident Inspector at Peach Bottom. In addition, if you disagree with a cross-cutting aspect assignment 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 I, and the NRCs Resident Inspector at Peach Bottom.
In accordance with 10 CFR Part 2.390, Public Inspections, Exemptions, Requests for Withholding, this letter, its enclosure, and your response (if any) will be made available for public inspection and copying in the NRCs Agencywide Documents Access and Management System (ADAMS), accessible from the NRCs Website at http://www.nrc.gov/reading-rm/adams.html and in the NRCs Public Document Room.
Sincerely,
/RA/
David L. Pelton, Acting Director Division of Reactor Projects Docket Numbers: 50-277 and 50-278 License Numbers: DPR-44 and DPR-56
Enclosure:
Inspection Report 05000277/2018003 and 05000278/2018003 w/Attachment:
E-3 Emergency Diesel Generator Failure Detailed Risk Evaluation
Inspection Report
Docket Numbers: 50-277 and 50-278 License Numbers: DPR-44 and DPR-56 Report Numbers: 05000277/2018003 and 05000278/2018003 Enterprise Identifier: I-2018-003-0070 Licensee: Exelon Generation Company, LLC Facility: Peach Bottom Atomic Power Station, Units 2 and 3 Location: Delta, Pennsylvania Inspection Dates: July 1, 2018 to September 30, 2018 Inspectors: J. Heinly, Senior Resident Inspector B. Smith, Resident Inspector J. Bridge, Acting Resident Inspector F. Arner, Senior Reactor Inspector D. Beacon, Project Engineer C. Bickett, Senior Reactor Inspector J. Cassata, Health Physics Inspector M. Orr, Reactor Inspector J. Schoppy, Reactor Engineer Approved By: David L. Pelton, Acting Director Division of Reactor Projects Enclosure
SUMMARY
The U.S. Nuclear Regulatory Commission (NRC) continued monitoring Exelons performance at
Peach Bottom Atomic Power Station (Peach Bottom), Units 2 and 3, by conducting the baseline inspections described in this report in accordance with the Reactor Oversight Process. The Reactor Oversight Process is the NRCs program for overseeing the safe operation of commercial nuclear power reactors. Refer to https://www.nrc.gov/reactors/operating/oversight.html for more information. NRC-identified and self-revealed findings, violations, and additional items are summarized in the table below.
List of Findings and Violations High Pressure Coolant Injection System Exhaust Pressure Switches Exceeded Documented Qualified Life Cornerstone Significance Cross-cutting Report Aspect Section Mitigating Green P.2 - Problem 71152 Systems NCV 05000277/2018003-01 Identification and Closed Resolution,
Evaluation The inspectors identified a Green non-cited violation (NCV) of Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion III, Design Control, because Exelon did not establish measures to ensure that environmental qualification requirements for qualified components were correctly translated into procedures and instructions. Specifically, the end-of-life replacement requirements for the Unit 2 high pressure coolant injection (HPCI) exhaust pressure switches were not translated into maintenance procedures and instructions. As such,
Exelon did not replace the switches prior to the end of their documented qualified life.
Inadequate Corrective Actions Result in the Failure of the E-3 Emergency Diesel Generator Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Preliminary White H.11 - Human 71153 Systems AV 05000277/2018003-02 Performance,
EA-18-107 Challenge the Opened Unknown The inspectors identified a self-revealing preliminary White finding associated with an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, because Exelon did not perform adequate corrective actions on the E-3 emergency diesel generator (EDG)scavenging air check valve assembly. Specifically, Exelon did not perform an adequate repair of an interference fit pin joint during maintenance activities in April 2017 and did not correct an oil leak on the check valve dashpot assembly identified in September 2017, which resulted in the E-3 EDG failure on June 13, 2018.
Additional Tracking Items Type Issue number Title Inspection Status Results Section LER 05000277/2018-002-00 EDG Air Inlet Check 71153 Closed Valve Failure Results in a Condition Prohibited by Technical Specification (TS)
LER 05000278/2018-001-00 Reactor Core Isolation 71153 Closed Cooling (RCIC) System Pressure Switch Failure Results in Condition Prohibited by TS
TABLE OF CONTENTS
PLANT STATUS
INSPECTION SCOPES
................................................................................................................
REACTOR SAFETY
................................................................................................................
RADIATION SAFETY
..............................................................................................................
OTHER ACTIVITIES - BASELINE
.........................................................................................
INSPECTION RESULTS
..............................................................................................................
EXIT MEETINGS AND DEBRIEFS
............................................................................................ 17
DOCUMENTS REVIEWED
......................................................................................................... 18
ATTACHMENT: E-3 EMERGENCY DIESEL GENERATOR FAILURE DETAILED RISK
EVALUATION ............................................................................................................... A-1
PLANT STATUS
Unit 2
The unit remained at or near rated thermal power (RTP) for the inspection period.
Unit 3
Unit 3 began the inspection period at RT
- P. On September 7, 2018, the unit was down powered
to 29 percent thermal power to perform scheduled maintenance and returned to RTP on
September 9, 2018. On September 22, 2018, the unit was shutdown to repair a pressure
boundary leak from am instrument line associated with the HPCI system. The unit was returned
to RTP on September 25, 2018. On September 30, 2018, the unit experienced an automatic
reactor scram from RTP when two of three main condensate pumps tripped due to a failed
electrical power cable, and remained shutdown through the end of the inspection period.
INSPECTION SCOPES
Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in
effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with
their attached revision histories are located on the public website at http://www.nrc.gov/reading-
rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared
complete when the IP requirements most appropriate to the inspection activity were met
consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection
Program - Operations Phase. The inspectors performed plant status activities described in
IMC 2515, Appendix D, Plant Status, and conducted routine reviews using IP 71152,
Problem Identification, and Resolution. The inspectors reviewed selected procedures and
records, observed activities, and interviewed personnel to assess Exelons performance and
compliance with Commission rules and regulations, license conditions, site procedures, and
standards.
REACTOR SAFETY
71111.01 - Adverse Weather Protection
External Flood (1 Sample)
The inspectors evaluated diesel generator building inoperable flood seals on
August 16, 2018.
71111.04 - Equipment Alignment
Partial Walkdowns (3 Samples)
The inspectors evaluated system configurations during partial walkdowns of the following
systems/trains:
(1) Unit 2 A core spray (CS) with B CS out of service on July 10, 2018
(2) Unit 2 and Unit 3 E-1, E-2, E-3 with E-4 EDGs inoperable on September 17, 2018
(3) Unit 3 high pressure service water (HPSW) following pump, valve, and flow test on
September 28, 2018
71111.05A/Q - Fire Protection Annual/Quarterly
Quarterly Inspection (4 Samples)
The inspectors evaluated fire protection program implementation in the following selected
areas:
(1) Unit 2 and Unit 3 cable spreading room on July 30, 2018
(2) Unit 3 B/D residual heat removal rooms on August 22, 2018
(3) Unit 2 A battery room on August 23, 2018
(4) Unit 2 B 4kilovolt (kV) switchgear room on August 23, 2018
Annual Inspection (1 Sample)
The inspectors evaluated fire brigade performance to an actual fire in the Unit 3 HPSW
room on July 23, 2018. The fire was small, isolated, did not affect any safety-related
equipment, and was promptly extinguished such that no emergency action level declarations
was required.
71111.06 - Flood Protection Measures
Internal Flooding (1 Sample)
The inspectors evaluated internal flooding mitigation protections in the Unit 2 and Unit 3
standby gas room and radwaste basement (91) from July 23, 2018, through July 27, 2018.
71111.11 - Licensed Operator Requalification Program and Licensed Operator Performance
Operator Requalification (1 Sample)
The inspectors observed and evaluated licensed operator requalification training on
August 6, 2018.
Operator Performance (1 Sample)
The inspectors observed and evaluated a Unit 3 summer load drop on September 8, 2018,
and a rod pattern adjustment on September 11, 2018.
71111.12 - Maintenance Effectiveness
Routine Maintenance Effectiveness (3 Samples)
The inspectors evaluated the effectiveness of routine maintenance activities associated with
the following equipment and/or safety significant functions:
(1) Unit 2 and Unit 3 reactor recirculation pump motor adjustable speed drives on July 23,
2018, through July 27, 2018
(2) Unit 3 RCIC on August 22, 2018
(3) Unit 2 and Unit 3 EDGs on September 6, 2018
71111.13 - Maintenance Risk Assessments and Emergent Work Control (5 Samples)
The inspectors evaluated the risk assessments for the following planned and emergent work
activities:
(1) Unit 3 RCIC pressure switch calibration on September 10, 2018
(2) Unit 2 automatic depressurization system (ADS) logic system functional test on
September 12, 2018
(3) Unit 2 and Unit 3 E-4 EDG 24-hour endurance run with offsite line 343 out of service on
September 17, 2018
(4) Unit 3 HPCI logic system functional test on September 19, 2018
(5) Unit 2 and Unit 3 E-2 EDG instrumentation logic test on September 20, 2018
71111.15 - Operability Determinations and Functionality Assessments (3 Samples)
The inspectors evaluated the following operability determinations and functionality
assessments:
(1) Unit 2 and Unit 3 EDGs external flood seal deficiencies on August 23, 2018
(2) Unit 2 and Unit 3 containment atmosphere control / containment atmosphere dilution
primary containment isolation valve failure on September 14, 2018
(3) Unit 3 HPCI differential pressure indicating switch failure on September 21, 2018
71111.19 - Post-Maintenance Testing (4 Samples)
The inspectors evaluated post-maintenance testing for the following maintenance/repair
activities:
(1) Unit 3 A HPSW ventilation repair on August 15, 2018
(2) Unit 3 ADS valve replacement on September 11, 2018
(3) Unit 3 HPCI sensing line leak repair on September 24, 2018
(4) Unit 2 and Unit 3 diesel driven fire pump 2-year overhaul on September 27, 2018
71111.20 - Refueling and Other Outage Activities (1 Sample)
The inspectors evaluated the Unit 3 forced outage activities from September 22, 2018, to
September 26, 2018.
71111.22 - Surveillance Testing
The inspectors evaluated the following surveillance tests:
Routine (4 Samples)
(1) E-4 EDG slow start on July 25, 2018
(2) E-2 EDG alternative shutdown control functional on August 10, 2018
(3) Unit 3 nitrogen backup to ADS on August 22, 2018
(4) Unit 3 RCIC pressure switch calibration on September 10, 2018
RADIATION SAFETY
71124.07 Radiological Environmental Monitoring Program
Site Inspection (1 Sample)
The inspectors verified that the Radiological Environmental Monitoring Program quantified
the impact of radioactive effluent releases to the environment and sufficiently validated the
integrity of the radioactive gaseous and liquid effluent release program.
The inspectors verified that the Radiological Environmental Monitoring Program was
consistently implemented with the licensees TSs and/or Offsite Dose Calculation Manual
and validated that the program meets the design objectives in Appendix I to 10 CFR Part 50.
Groundwater Protection Initiative Implementation (1 Sample)
The inspectors verified that the licensee is continuing to implement the voluntary Nuclear
Energy Institute/Industry Ground Water Protection Initiative.
OTHER ACTIVITIES - BASELINE
71152 - Problem Identification and Resolution
Annual Follow-up of Selected Issues (2 Samples)
The inspectors reviewed Exelons implementation of its corrective action program (CAP)
related to the following issues:
(1) Issue Report (IR) 4050431, Water Found in HPCI Lube Oil System
(2) IR 4146368, HPCI System Exhaust Pressure Switch Environmental Qualification Life
Evaluation
71153 - Follow-up of Events and Notices of Enforcement Discretion
Events (1 Partial Sample)
The inspectors evaluated operator response to the following event.
(1) Unit 3 SCRAM on September 30, 2018. The initial evaluation of this event was in
progress as of the close of this inspection period. The final evaluation of this event will
be conducted during a future inspection.
Licensee Event Reports (LERs) (2 Samples)
The inspectors evaluated the following Exelon event reports which can be accessed at
https://lersearch.inl.gov/LERSearchCriteria.aspx:
(1) LER 05000277/2018-002-00, E-3 EDG Air Inlet Check Valve Failure Results in a
Condition Prohibited by TS (ADAMS Accession No. ML18222A326)
(2) LER 05000278/2018-001-00, RCIC System Pressure Switch Failure Results in Condition
Prohibited by TS (ADAMS Accession No. ML18172A260)
INSPECTION RESULTS
HPCI System Exhaust Pressure Switches Exceeded Documented Qualified Life
Cornerstone Significance Cross-cutting Report
Aspect Section
Mitigating Green P.2 - Problem 71152
Systems NCV 05000277/2018003-01 Identification
Closed and Resolution,
Evaluation
The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design
Control, because Exelon did not establish measures to ensure that environmental
qualification requirements for qualified components were correctly translated into procedures
and instructions. Specifically, the end-of-life replacement requirements for the Unit 2 HPCI
exhaust pressure switches were not translated into maintenance procedures and instructions.
As such, Exelon did not replace the switches prior to the end of their documented qualified
life.
Description: In response to NRC inspectors questions related to failure of the RCIC system
exhaust pressure switch, the station reviewed the environmental qualification binder for the
Unit 2 HPCI system exhaust pressure switches, which are of similar construction, and located
in a similar service environment. Environmental Qualification Binder EQ-PB-026, Static O-
Ring Pressure Switch, stated that the HPCI system exhaust pressure switches were to be
replaced every 43 years in order to maintain their environmental qualification. To meet this
requirement, the switches should have been replaced no later than 2016.
A review of the maintenance history for the HPCI system pressure switches noted that there
were no preventive maintenance replacement tasks for these components, and the switches
had not been replaced as a result of corrective maintenance over the life of the plant. As
such, these pressure switches had exceeded their documented qualified life. The inspectors
determined that this represented a non-conforming condition and reasonable doubt existed as
to the ability of these pressure switches to perform their safety function in a harsh
environment during an event.
Exelon originally calculated the 43-year service life based on a design service temperature of
85°F, as documented in NE-00164, Specification for Environmental Service Conditions -
Peach Bottom Atomic Power Stations Units 2 and 3. In response to the current issue,
Exelon evaluated operability using actual temperature data collected quarterly since 1995 per
Peach Bottom routine test RT-I-094-800-2, Reactor Building Ambient Temperature Data
Collection, and determined a new service temperature of approximately 82°F. Using this
revised value, Exelon calculated a new qualified life of 51 years for the HPCI system pressure
switches which extended the replacement date to 2024. Based on a review of this
temperature data, the technical evaluation that documented the life extension, and a field
walkdown of the switches, the inspectors determined that Exelons conclusion was
reasonable.
The inspectors also determined that the station had a prior opportunity to identify this
condition. Following identification of a similar issue with static O-ring pressure switches on
the residual heat removal system in April 2017, as documented in IR 3997737, Exelon
conducted an extent of condition review. However, this extent of condition review failed to
identify this issue with the HPCI system exhaust pressure switches, even though the switches
are from the same manufacturer, and are documented in the same environmental
qualification binder (EQ-PB-026).
Corrective Actions: Exelon entered this issue into the CAP as IR 4146368, and calculated a
new qualified life of 51 years based on actual service temperatures in the room. As of the
date of this inspection, replacement of the HPCI system exhaust pressure switches was
planned as corrective maintenance for early 2019.
Corrective Action Reference: IR 4146368
Performance Assessment:
Performance Deficiency: The failure to establish measures to ensure that environmental
qualification requirements for qualified components were correctly translated into procedures
and instructions in accordance with 10 CFR Part 50, Appendix B, Criterion III, Design
Control, was a performance deficiency.
Screening: The performance deficiency was more than minor because this issue adversely
impacted the equipment performance attribute of the Mitigating Systems cornerstone
objective to ensure the availability, reliability, and capability of systems that respond to
initiating events to prevent undesirable consequences. This issue is also similar to more-
than-minor examples 3.j and 3.k presented in IMC 0612, Appendix E, Examples of Minor
Issues. Specifically, this performance deficiency resulted in a condition where there was
reasonable doubt as to the operability and reliability of the Unit 2 HPCI exhaust pressure
switches. As such, Peach Bottom needed to conduct an additional engineering evaluation to
extend the service life of the exhaust pressure switches, thus justifying that the switches
would continue to perform their safety function.
Significance: The inspectors assessed the significance of the finding using Exhibit 2 of IMC
0609, Appendix A, The SDP for Findings At-Power. The inspectors determined the finding
was of very low safety significance (Green) because the finding was a deficiency affecting the
reliability of a mitigating structure, system, or component, and the structure, system, or
component maintained its operability or functionality. Specifically, the safety function of the
HPCI system was not lost based upon a technical evaluation which extended the
environmental qualification life of the Unit 2 HPCI system exhaust pressure switches from 43
to 51 years.
Cross-cutting Aspect: This finding had a cross-cutting aspect in the area of Problem
Identification and Resolution, Evaluation, because Exelon did not conduct a thorough extent
of condition evaluation following identification of a similar issue with residual heat removal
pump discharge pressure switches in 2017. Specifically, the stations extent of condition
review failed to identify a similar issue with the Unit 2 HPCI system exhaust pressure
switches, even though the switches are from the same manufacturer, and are documented in
the same environmental qualification binder [P.2].
Enforcement:
Violation: 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires, in part, that
measures shall be established to assure that applicable regulatory requirements and the
design basis are correctly translated into specifications, drawings, procedures, and
instructions.
Contrary to the above, prior to June 12, 2018, Exelon failed to ensure that the design basis
was translated into procedures and instructions. Specifically, Exelon did not incorporate the
environmental qualification requirement associated with end-of-life replacement of the Unit 2
HPCI exhaust pressure switches into preventive maintenance procedures.
Disposition: This violation is being treated as a NCV, consistent with Section 2.3.2 of the
Observations 71152
On September 9, 2017, Exelon staff initiated corrective action IR 4050431 for water found in
the Unit 3 HPCI turbine lube oil reservoir during a weekly HPCI auxiliary oil pump operability
test (RT-O-023-302-3). Operators were taking weekly HPCI lube oil samples in accordance
with an existing adverse condition monitoring plan (ACMP) initiated in May 2017 in response
to a rise in HPCI thrust bearing and casing temperatures (IR 4004135). Operators drained the
water from the lube oil reservoir. Operators, with engineering support, promptly evaluated
HPCI system operability (including past operability) and determined that HPCI remained
operable. Exelon staff revised the existing HPCI lube oil monitoring ACMP to also include
daily lube oil reservoir samples to ensure water content remained below threshold limits and
to drain any water found.
Exelon staff implemented the ACMP to monitor HPCI turbine temperatures and lube oil
moisture content in response to identified leakage past the Unit 3 HPCI steam supply valve
(MO-3-23-014) that resulted in steam condensation in the turbine casing and on the casing
insulation and subsequent water intrusion into the lube oil system. The larger quantity of
water found in the lube oil reservoir on September 9, 2017, was unexpected and not
consistent with the previous ACMP sampling results and trending (including the sample taken
on September 2, 2017). Engineering determined that the most likely cause of the additional
water found in the reservoir was from stroking the HPCI steam supply valve (MO-3-23-014) on
August 31, 2017, during a post-maintenance test following a relay contact replacement
without fully operating the HPCI system. Stroking the steam supply valve with the
downstream HPCI stop and control valves closed allowed steam to condense between the
HPCI supply and stop valves. Subsequently, when the stop and control valves were stroked
during the weekly HPCI auxiliary oil pump operability test, the condensed steam had a path to
the turbine casing and lube oil system.
During the Unit 3 refueling outage (3R21) in October 2017, Exelon staff resolved the MO-3-
23-014 leak-by issue under work orders to open and inspect the valve, perform in-body
repairs, perform preventive maintenance, and upgrade the actuator (Work Orders 04306865,
04306866, and 04181415). In addition, Exelon staff initiated a corrective action to provide
additional guidance and/or precautions while cold stroking the HPCI steam supply valve at
power (4050431-11).
Based on a review of Unit 3 HPCI operating parameters, system walkdowns, and lube oil
sample results, the inspectors noted that Exelons refueling outage work activities on the
steam supply valve effectively addressed the leak-by issue. The inspectors also reviewed
Exelons corrective actions associated with a similar active Unit 2 ACMP addressing
increased monitoring for identified leakage past the Unit 2 HPCI steam supply valve
(MO-2-23-014). The inspectors concluded that Exelon staff had taken timely and appropriate
actions in accordance with Exelons procedures and CAP, and 10 CFR Part 50, Appendix B
and evaluated operability with sufficient technical rigor to support their conclusions. The
inspectors determined that Exelon staffs associated engineering evaluations and trending
were sufficiently thorough and based on the best available information, sound judgment, and
relevant operating experience. The assigned corrective actions were aligned with engineering
evaluations, adequately tracked, appropriately documented, and completed as scheduled.
Based on the documents reviewed, HPCI and RCIC system walkdowns, and discussions with
engineering personnel, the inspectors noted that Exelon personnel identified problems and
entered them into the CAP at a low threshold.
Inadequate Corrective Actions Result in the Failure of the E-3 EDG
Cornerstone Significance Cross-cutting Report
Aspect Section
Mitigating Preliminary White H.11 - Human 71153
Systems AV 05000277/278/2018003-02 Performance,
Opened Challenge the
Enforcement Action (EA)-18-107 Unknown
Introduction: The inspectors identified a self-revealing preliminary White finding associated
with an apparent violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action,
because Exelon did not perform adequate corrective actions on the E-3 EDG scavenging air
check valve assembly. Specifically, Exelon did not perform an adequate repair of an
interference fit pin joint during maintenance activities in April 2017 and did not correct an oil
leak on the check valve dashpot assembly identified in September 2017, which resulted in the
E-3 EDG failure on June 13, 2018.
Description: Peach Bottom has four, 12 cylinder Fairbank Morse EDGs that supply
emergency power to both Unit 2 and Unit 3. Each EDG contains a scavenging air system
which provides compressed cool combustion air into the cylinders. The scavenging air input
to the cylinders is shared between the blower (supercharger) and the two parallel turbo
chargers. The scavenging air check valve controls the contribution of air input between the
blower and outside air to the turbochargers. The check valve is connected to a shaft through
an interference fit pin and the shafts movement is limited/dampened by an oil filled dashpot.
At low loads, the air input to the turbo charger is provided by the blower (scavenging air check
valve closed) and at high loads the check valve opens to supplement the turbo charger
suction with room air.
On April 1, 2017, during a routine preventive maintenance overhaul of the E-3 EDG, station
technicians identified radial play and looseness of the scavenging air check valve on its shaft.
The condition was entered in the CAP under IR 3992819. The station determined that the
cause of the looseness was wear between the shaft, check valve, and interference fit pin. An
engineering change package was developed to remove the interference fit pin, ream out the
hole in the shaft and check valve to a larger size, and manufacture a new interference fit pin.
This first time evolution repair was completed during the planned overhaul and the EDG
successfully passed its post-maintenance testing on April 6, 2017.
On September 20, 2017, the NRC inspectors observed a full load surveillance test of the E-3
EDG and identified an oil leak on the scavenging air check valve dashpot. The station
documented the condition under IR 4054092 and determined that the E-3 EDG was operable
because the amount of oil loss during the test (1 drop per 3 minutes) was low and would not
impact the dashpot function. However, an interim corrective action was established to refill
the oil in the dashpot after each surveillance test run to ensure that adequate inventory in the
dashpot remained to support its design function.
On June 13, 2018, during a quarterly full load surveillance test, the E-3 EDG was operating at
full load when elevated exhaust temperatures were observed and a metallic noise was heard
near the turbocharger assembly. The operators emergently shut down the EDG, declared it
inoperable, and entered the condition into their CAP under IR 4146926. The turbo charger
was inspected and technicians identified that the scavenging air check valve interference fit
pin had become displaced from the shaft and entered/damaged the suction side of the
aluminum turbo charger compressor blades. The aluminum debris from the damaged blades
migrated through the scavenging air inlet and into the diesel generator cylinders and
contaminated the diesel generator lube oil and exhaust systems. Exelon performed
immediate corrective actions to include an extensive emergent overhaul of the diesel
generator to remove all of the contaminants and inspect, assess, and replace critical internal
components, as necessary. In addition, the site replaced the scavenging air check valve
assembly along with the supporting dashpot assembly. The inspectors performed extensive
inspection and assessment of Exelons corrective actions and post-maintenance testing and
did not identify any additional issues of concern. The E-3 EDG successfully passed its post-
maintenance testing on June 23, 2018. The inspectors evaluated the extent of condition and
determined that the scavenging air check valve assemblies on the other three EDGs had
been recently inspected and no conditions adverse to quality had been identified.
Furthermore, no repairs had been performed to the scavenging air check valve assemblies on
the other three EDGs.
Exelon performed a cause evaluation to determine the apparent and contributing causes that
led to the interference fit pin becoming displaced and damaging the E-3 EDG. Exelon
determined that the apparent cause was that the interference fit pin repair in April 2017 was
inadequate. Specifically, the hole through the shaft and check valve was not cleanly reamed
and the interference fit pin was undersized which resulted in insufficient interference between
the pin, shaft, and check valve body. Furthermore, it was identified that the leaking dashpot
assembly had not been refilled with oil after every diesel run, as recommended through the
CAP, and was found with low oil level. The degraded dashpot allowed greater forces to be
exerted on the check valve, shaft, and pin assembly and contributed to the pin becoming
dislodged.
Corrective Actions: Exelon performed immediate corrective actions on the E-3 EDG to
include the replacement of the scavenging air check valve and dashpot assembly, clean the
internal contaminants, and inspect, assess, and replace critical internal components as
necessary. Furthermore, Exelon plans to perform training/briefings on the inadequate
maintenance/engineering practices that contributed to the failure.
Corrective Action Reference: IR 4146926
Performance Assessment:
Performance Deficiency: The inspectors identified that the failure to perform adequate
corrective actions to address the degraded scavenging air check valve assembly which
resulted in the E-3 EDG failure was a performance deficiency that was within Exelons ability
to foresee and correct. Specifically, the E-3 EDG was declared inoperable due to the
inadequate corrective actions associated with the scavenging air check valve interference pin
repair and the leaking dashpot assembly.
Screening: The finding was more than minor, because it was associated with the equipment
performance attribute of the Mitigating Systems cornerstone and adversely impacted the
cornerstone objective to ensure the availability of systems that respond to initiating events to
prevent undesirable consequences (i.e., core damage). Specifically, the E-3 EDG was
unavailable to perform its safety function as a result of Exelons inadequate corrective
actions.
Significance: The inspectors evaluated the significance of this finding using IMC 0609,
Appendix A, The SDP for Findings at Power, Exhibit 2 - Mitigating Systems Screening
Questions. The inspectors determined that the finding resulted in the actual loss of function
of a single train (E-3 EDG) for longer than its allowed TS outage time and required a detailed
risk evaluation.
A Region I Senior Reactor Analyst (SRA) performed a detailed risk evaluation. The finding
was preliminarily determined to be of low to moderate safety significance (White). The risk
important sequences were dominated by external fire risk. Specifically, a postulated fire in
the 4kV switchgear rooms. The internal event risk was dominated by a weather related loss
of offsite power, operator failure to establish a Conowingo tie line setup, failure of the E-2
EDG to run, failure to recover an EDG, failure to cross tie emergency busses, failure to
recover offsite power, and a failure of RCI
- C. See Attachment, E-3 EDG Failure Detailed Risk
Evaluation, for a detailed review of the quantitative criteria considered in the preliminary risk
determination.
Cross-Cutting Aspect: The inspectors determined this finding had a cross-cutting aspect in
the area of Human Performance, Challenge the Unknown, because Exelon did not
adequately challenge the risks involved with the first time evolution repair on the scavenging
air check valve and the degraded/leaking dashpot condition. The risks were not well
understood and inadequately managed through the CAP. [H.11]
Enforcement:
Apparent Violation:
CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires that measures shall
be established to assure conditions adverse to quality are promptly identified and corrected.
Peach Bottom Units 2 and 3 TS 3.8.1 requires all four EDGs to be operable in Mode 1 and if
any one EDG is determined to be inoperable, it shall be returned to an operable status within
days or 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 April 1, 2017, to June 13, 2018, Exelon did not establish
measures to assure that conditions adverse to quality associated with the E-3 EDG
scavenging air check valve were promptly identified and corrected. Specifically, after
identifying on April 1, 2017, that the E-3 EDG scavenging air check valve was loose due to
wear around the interference fit pin and identifying on September 20, 2017, that there was an
oil leak on the scavenging air check valve dashpot, Exelon did not take adequate corrective
actions to address the adverse conditions. As a result, on June 13, 2018, during a quarterly
surveillance test, the scavenging air check valve interference fit pin dislodged from the shaft
and entered/damaged the suction side of the aluminum turbo charger compressor blades.
Consequently, the E-3 EDG was rendered inoperable prior to June 13, 2018, for a period
longer than its TS allowed outage time, and the unit had not been shut down and placed in
Mode 3.
Disposition: This violation is being treated as an apparent violation (AV) pending a final
significance determination. The disposition of this violation closes LER 05000277/2018-002-
00.
Reactor Core Isolation Cooling System Pressure Switch Failure Results in Condition
Prohibited by TS
Enforcement EA-18-108 71153
Discretion
Description: On April 22, 2018, during a routine surveillance test of the RCIC system, the
RCIC turbine tripped approximately 28 seconds after startup, prior to the system reaching
rated flow and pressure. Concurrent with the RCIC trip, an alarm was received for RCIC
turbine high exhaust pressure; however, local indications did not indicate a true high pressure
in the exhaust line. Therefore, the RCIC system was declared inoperable and TS 3.5.3,
Condition A was entered, which requires the RCIC system to be restored to operable within
days. Troubleshooting determined that the B RCIC exhaust pressure switch (PS-3-13-
2b) had prematurely tripped at normal operating pressure due to an age-related failure of the
instrument diaphragm and O-ring. The RCIC system had been previously verified as
operable during its last surveillance run on January 16, 2018.
Corrective Actions: The failed pressure switch was replaced and the station performed an
extent of condition review/inspection of similar pressure switch instruments. Following
replacement of the switch, RCIC was retested and restored to operable on April 23, 2018.
Furthermore, actions were established to modify the turbine trip logic to remove the single
point trip vulnerability.
Corrective Action Reference: IR 4129583
Enforcement:
Violation: Peach Bottom Unit 3 TS 3.5.3 requires that the RCIC system shall be operable in
Mode 1, and if RCIC becomes inoperable, it shall be returned to operable status within 14
days or the plant shall be placed in Mode 3 within the next 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />.
Contrary to the above, based on relevant causal information, Unit 3 RCIC was likely
inoperable prior to April 22, 2018, for a period greater than the TS allowed outage time of 14
days, and Unit 3 had not been placed in Mode 3. Specifically, on April 22, 2018, the Unit 3
RCIC turbine tripped during startup for a routine surveillance test due to a degraded turbine
exhaust pressure switch which resulted in an inoperability time of greater than 14 days.
Internal inspection on the switch identified that it failed due to corrosion from water intrusion
which had existed for an extended period of time.
Severity/Significance: For violations warranting enforcement discretion, IMC 0612 does not
require a detailed risk evaluation; however, safety significance characterization is appropriate.
A Region I SRA performed a best estimate analysis of the safety significance using the Peach
Bottom Unit 3 Standardized Plant Analysis Risk (SPAR) model, Version 8.51 and Systems
Analysis Programs for Hands-On Integrated Reliability Evaluations (SAPHIRE), Version 8.1.8.
This model was used to evaluate the internal events increase in core damage frequency
(CDF) per year. The SRA performed a site visit to review Exelons fire model output to
estimate the external risk contributor of the issue. The final risk evaluation estimated the total
(internal and external events risk) increase in CDF to be in the mid E-6/yr range, or of low to
moderate safety significance. The SRA evaluated the internal and external events risk
contribution due to the inoperability of the RCIC system for an assumed 47 day exposure
time.
The analyst used the guidance in the Risk Assessment Standardization Project (RASP)
Handbook, Volume I, Section 2.4, Revision 2.0, to estimate an exposure time using a time
divided by two (t/2) approach. This would represent the time from the last successful
surveillance test divided by two. The approach is appropriate for periodically operated
components that fail due to a degradation mechanism that gradually could affect the
component during the standby period. Given this approach, the internal event contribution
was calculated to estimate the internal event risk increase due to the conditional failure of the
RCIC pump to successfully start. The increase for internal events was estimated at 2.5E-6/yr
increase in CD
operator action failure to depressurize, and HPCI system failures. The SRA noted from
discussions with Exelon staff that the RCIC system was assumed to be non-recoverable
given the nature of the failure.
To estimate the external risk contribution, the SRA had several discussions and a site visit to
review Exelons preliminary fire model outputs for the conditional failure of the RCIC system
for the 47 days. The 47 days included a conservative additional day for repair time. The SRA
reviewed Exelons fire risk analysis and noted that one of the dominant risk increase
contributors was fire within the 13kV switchgear room. Several other fire areas were
reviewed and the SRA noted that the core damage sequences appeared technically
reasonable given the plant areas and values assumed for mitigating equipment. Exelons
preliminary results showed an increase in external event CDF/yr for the conditional failure of
RCIC for 47 days to be approximately 4.5E-6/yr. The SRA determined the results to be
reasonable.
Exelons model for internal events resulted in an increase in CDF/yr of 1.05E-6/yr which was
considered to compare well with the NRC SPAR model. Exelon performed a review of the
large early release frequency (LERF) impact and determined an overall increase in LERF due
to both external and internal events for the RCIC failure for 47 days to be a nominal 6E-8/yr.
Therefore, the SRA review of the dominant sequences and Exelons LERF results affirmed
that LERF did not increase the risk over that determined from the increase in CDF.
Basis for Discretion: The inspectors determined that the maintenance strategy for these
switches was consistent with requirements and standards that existed at the time and that
there was no relevant operating experience that would have reasonably necessitated
consideration of additional maintenance actions. As a result, no performance deficiency was
identified.
The inspectors assessment considered:
The industry, regulatory, and Exelon service life standards were reviewed for static O-
ring pressure switches. Exelons assessment of the pressure switch service condition
(critical, mild conditions, low-duty cycle) required a preventive maintenance task to
perform periodic calibration and to replace the switch as-required. There was no
time-based replacement task prescribed by any standard for this switch. The
inspectors determined that Exelons assessment was adequate and the corresponding
preventive maintenance activities met applicable standards.
The subject pressure switch was installed during original construction and the
calibration results of the pressure switch had been satisfactory from 2003 until the
2018 failure. The inspectors reviewed the maintenance and calibration history on the
pressure switch and did not identify any adverse trends or conditions adverse to
quality that would have required further evaluation or replacement of the pressure
switch.
Industry operating experience information available to Exelon did not identify the
potential for the age-related failure mode of the pressure switch o-ring and diaphragm
that occurred at Peach Bottom.
The NRC determined that it was not reasonable for Exelon to have been able to foresee and
prevent this violation of NRC requirements, and as such, no performance deficiency existed.
Therefore, the NRC has decided to exercise enforcement discretion in accordance with
Sections 2.2.4 and 3.10 of the NRC Enforcement Policy and refrain from issuing enforcement
action for the violation of TSs (EA-18-108). Further, because Exelons actions did not
contribute to this violation, it will not be considered in the assessment process or the NRC
Action Matrix.
EXIT MEETINGS AND DEBRIEFS
The inspectors verified no proprietary information was retained or documented in this report.
On October 23, 2018, the inspectors presented the quarterly resident inspector inspection
results to Mr. Pat Navin, Peach Bottom Site Vice President, and other members of the Exelon
staff.
DOCUMENTS REVIEWED
71111.05Q
Procedures
PF-78H, Revision 9, Turbine Building Common, Cable Spreading and Computer Rooms -
Elevation 150-0
PF-117, Revision 10, Unit 3 Turbine Building, Emergency Battery Switchgear Rooms -
Elevation 135-0
PF-127, Revision 10, Unit 2 Turbine Building, Emergency Battery Switchgear Rooms -
Elevation 135-0
Procedures
DD-20, Revision 1, Operations Department Description
OP-AA-1, Revision 1, Conduct of Operations
OP-AA-100, Revision 0, Description of the Exelon Nuclear Conduct of Operations Manual
OP-AA-20, Revision 0, Conduct of Operations Process Description
Miscellaneous
Appendix H, Generic Licensed Operator Observation Checklists
Procedures
ST-I-01G-100-2, Revision 7, ADS Channel A Logic System Functional test
WC-AA-104, Revision 28, Integrated Risk Management
WC-AA-104-F-01, Revision 0, Risk Screening / Mitigation Plan
Miscellaneous
DBD No. P-S-31, Revision 4, ADS
Procedures
RT-M-40H-925-3, Revision 7, HPSW/ESW Pump Room Ventilation Logic System Functional
Test
04705247-03 04705247-04
Procedures
HU-AA-1211-F-01, Revision 4, Pre-Job Briefing Checklist
OP-AA-101-111-1001, Revision 20, WRO Work Release Checklist
RT-O-052-750-2, Revision 10, E-2 Diesel Alternative Shutdown Control Functional
SI3P-7-9102-B1C2, Revision 8, Calibration Check of Drywell Pressure Instruments PT/PR
9102B and Backup Nitrogen Supply to ADS Pressure Instruments PT/PS/DPS 9142B
ST-O-052-202-2, Revision 22, E-2 Diesel Generator Slow Start and Full Load Test
Procedures
CY-AA-130-201, Revision 006, Radiochemistry Quality Control
CY-AA-170-1100, Revision 004, Quality Assurance for Radiological Monitoring Programs
QA-ES-200, Revision 001 EIS Quality Assurance Program Manual - Technical Services
K-QAM-1, QA Manual, Teledyne Brown Engineering Environmental Services, Revision 32
Issue Reports
04164092
Documents:
ODCM, Revision 016, Offsite Dose Calculation Manual, 12/21/2017
NEI 07-07 Peer Assessment Report 2016
2017 Annual Radiological Environmental Operating Report 75
71152
Procedures
COL 23.1.A-3, Revision 24, HPCI System
M-C-750-001, Revision 22, RCIC Turbine Major Inspection
M-C-756-001, Revision 33, HPCI Turbine Inspection
OP-AA-108-115, Revision 21, Operability Determinations
PI-AA-120, Revision 8, Issue Identification and Screening Process
PI-AA-125, Revision 6, CAP Procedure
RRC 13.1-2, Revision 4, RCIC System Operation during a Plant Event
RRC 23.1-3, Revision 6, HPCI System Operation during a Plant Event
RT-O-023-302-3, Revision 25, HPCI Turbine Overspeed Trip Reset Time Check/Adjustment
and HPCI Auxiliary Oil Pump and Manual Trip Lever Tension Test
RT-I-094-800-2, Revision 4, Reactor Building Ambient Temperature Data Collection
SO 13.1.A-3, Revision 15, RCIC System Alignment for Automatic or Manual
SO 23.1.A-3, Revision 24, HPCI System Setup for Automatic or Manual Operation
SO 23.1.B-3, Revision 22, HPCI System Manual Operation
Completed Surveillance Tests, Functional Tests, and Post-Modification Tests
ST-I-023-100-2, HPCI Logic System Functional Test, performed 5/2/18
ST-I-023-100-3, HPCI Logic System Functional Test, performed 4/21/16
ST-O-023-300-2, HPCI Pump, Valve, Flow and Unit Cooler Functional and In-Service Test
without Vibration Data Collection, performed 6/7/18
ST-O-023-300-3, HPCI Pump, Valve, Flow and Unit Cooler Functional and In-Service Test
without Vibration Data Collection, performed 6/28/18
Issue Reports
03997737 0966085 2418959 2625671 2722895 3961408
4001946 4004135 4005532 4005664 4020045 4033575
4054013 4054022 4055480 4055985 4059811 4067994
4086666 4088214 4095900 4095901 4096366 4098271
4098695 4099040 4114591 4146368 4114824 4114847
24240 4129583 4151091 4153864 4163279 4165993*
4166046* 4195491 4306865 4692435 4692438 4749239
- IR written as a result of this inspection
Drawings
280-A-10, Revision 22, Floor Plan 91-6
M-1-J-6 Sh. 1, Revision 6, Outline HPCI Pump Drives
Miscellaneous
11187-2204, Revision 17, Pipe Break Outside Containment HELB Compartment Analysis
4004135-04, Revision 0 and 1, MO-3-23-014 (HPCI Turbine Steam Supply Valve) Steam
Leak-by Monitoring Adverse Condition Monitoring and Contingency Plan
4096366-02, Revision 0, MO-2-23-014 (HPCI Turbine Steam Supply Valve) Steam Leak-by
Monitoring Adverse Condition Monitoring and Contingency Plan
EQ-PB-026, Revision 0, Static O-Ring Pressure Switch, dated 8/26/2014
Franklin Institute Research Laboratory Report F-A5653-6, Environmental Qualification Testing
of Class 1E Equipment SOR Pressure Switch 5N-AA3 Peach Bottom Atomic Power
Station, Units 2 and 3, dated 1/17/1984
NE-00164, Revision 6, Specification for Environmental Service Conditions Peach Bottom
Atomic Power Station Units 2 and 3
NRC Information Notice 94-84: Air Entrainment in Terry Turbine Lubricating Oil Systems,
dated 12/2/94
OBSR 2017-184971, Engineering Event Free Clock Reset Communication, dated 10/11/17
PM-0785, Revision 6D, Power Rerate Evaluation - LOCA/High Energy Line Break Analysis
Unit 2 Room 8 Temperature Data from October 1995 through July 2018
System Health Reports, System Walkdowns, & Trending
20P033 OL1 & OL2 Pump Bearing Lube Oil Sample Analysis Results, 5/3/17 - 6/7/18
20P036 OL1 & OL2 Pump Bearing Lube Oil Sample Analysis Results, 6/18/17 - 7/28/18
20P038 Gearbox Lube Oil Sample Analysis Results, 5/3/17 - 6/7/18
20S037 Pump (Sump) Lube Oil Sample Analysis Results, 5/3/17 - 6/7/18
20S038 OL1 Bearing Lube Oil Sample Analysis Results, 6/18/17 - 7/28/18
30P033 OL1 & OL2 Pump Bearing Lube Oil Sample Analysis Results, 6/21/17 - 6/28/18
30P036 OL1 & OL2 Pump Bearing Lube Oil Sample Analysis Results, 4/11/17 - 7/24/18
30P038 Gearbox Lube Oil Sample Analysis Results, 6/21/17 - 6/28/18
30S037 Pump (Sump) Lube Oil Sample Analysis Results, 9/20/17 - 6/28/18
30S038 OL1 Bearing Lube Oil Sample Analysis Results, 4/11/17 - 7/24/18
U2 HPCI ACMP IR 4096366 Lube Oil Sump Sample Results, 1/26/18 - 8/11/18
U3 HPCI ACMP IR 4004135 Lube Oil Sump Sample Results, 3/24/17 - 10/22/17
Unit 2 and Unit 3 High Pressure Injection (RCIC & HPCI) System Health Report, dated 8/1/18
Unit 2 and Unit 3 HPCI Turbine Temperature Trends, April 2017 - July 2018
Technical Evaluations
EC 624540
Vendor Manuals
M-1-JJ-30, Revision 9, HPCI Terry Turbine Manual
VPF 2059-44-2, RCIC Turbine Manual, March 1972
71153
Procedures
AD-AA-101-1002, Attachment 1, Revision 1, Procedure Approval Form
ER-AA-520, Revision 1, Instrument Performance Trending
FF-01, Revision 23, Fire Brigade
IC-11-00001, Revision 3, Calibration of Plant Instrumentation and Equipment
IC-C-11-00010, Revision 2, Calibration of Pressure and Vacuum Switches
M-052-002, Revision 42, Diesel Engine Maintenance
M-052-006, Revision 18, Diesel Run After Major Overhaul
PF-132, Revision 9, Diesel Generator Building, General Area - Elevation 127-0
PI-AA-120, Revision 8, Issue Identification and Screening Process
PI-AA-125-1003, Revision 4, RCIC Turbine Trip on Startup
RT-O-052-253-2, Revision 39, E-3 Diesel Generator Inspection Post-Maintenance Functional
Test
SI3P-13-72-ABCE, Revision 7, Calibration Check of RCIC Pump and Turbine Pressure
Switches PS 3-13-67-1 and PS 3-13-72A/B
SO 52A.8.C, Revision 43, Diesel Generator Running Inspection
ST-O-013-3, Revision 12, RCIC Pump, Valve, Flow and Unit Cooler Functional and In-Service
Test without Vibration Data Collection
ST-O-052-313-2, Revision 21, E-3 Diesel Generator Slow Start Full Load and IST Test
ST-O-052-414-2, Revision 26, E-4 Diesel Generator Fast Start and Full Load Test
TQ-AA-223-F050, Revision 0, Nuclear Generating Station Instrument Maintenance
Initial Training Program
TQ-AA-223-F050, Revision 14, Nuclear Generating Station Instrument Maintenance
Training Program
WC-AA-111, Revision 5, Surveillance Program Requirements
Drawings
280-M-359, Sheet 2, Revision 48, RCIC System
280-M-360, Sheet 2, Revision 54, RCIC Pump Turbine Details
Issue Reports
0446457 3960207 3992819 4054092 4129583
29691 4146368 4146926 4149044 4155919
4166846
Miscellaneous
DBD No. P-S-07, Revision 18, Diesel Generator and Auxiliary Systems
EPRI, Service Life Assessment Guide, An Aging Assessment Reliability Process,
2016 Technical Report
SRS A-5, Revision 0, EQ Supplemental Review Sheet (SRS)
Fairbanks Morse, Inlet Air Check Valve Lubrication, Service Information Letter, Dated
February 18, 1985
Information Notice No. 87-16: Degradation of Static O-Ring Pressure Switches, In 87-16,
Dated April 2, 1987
LER 2-18-002, EDG Air Inlet Check Valve Failure Results in a Condition Prohibited by TSs
LER 3-18-001, RCIC System Pressure Switch Failure Results in Condition Prohibited by TSs
Lube Oil Flushing Procedure
PBAPS PORC Agenda, dated June 21, 2018PEA-98441, Failure Analysis of a Pressure Switch
Manufacturer: Static-O-Ring (SOR, Inc.)
Model 6N-AA3, dated May 30, 2018e
PEA MRC Agenda for July 2, 2018
Work Orders
618948
E-3 EMERGENCY DIESEL GENERATOR FAILURE DETAILED RISK EVALUATION
Conclusion:
The total increase in core damage frequency (CDF) for the performance deficiency related to
the degraded E-3 emergency diesel generator (EDG) turbochargers was estimated to be
Preliminary White, a finding of low to moderate safety significance. The calculated conditional
risk increase is dependent on the assumed exposure time, assumption of EDG failure, credit
considered for FLEX implementation and is dominated by external events such as postulated
fires within both Units 4kV switchgear rooms. Based on an initial best estimate assumption that
the degraded condition would fail the function of the E-3 EDG, the assumed exposure time, and
consideration of risk mitigation provided by FLEX strategies using sensitivity analyses, the
increase in CDF/yr was determined to be within the range of 4.5E-6/yr to 6E-6/yr for Unit 2, and
5.6E-6/yr to 8.5E-6/yr for Unit 3.
Influential Assumptions
This review consisted of determining the best estimate risk increase for the internal and external
postulated events for Unit 2 and Unit 3. This required various key assumptions for this
determination including the following:
EDG Functionality and Common Cause Failure
The failure probability for the Standardized Plant Analysis Risk (SPAR) model basic event
for the E-3 EDG, EPS-DGN-FR-DGC, was changed to TRUE, to represent the failure and to
account for the increased potential for common cause failure of the remaining EDGs. An
increased common cause failure probability is used based upon the performance deficiency
described in this report, which when viewed in a broader context could have resulted in a
failure of other EDGs. This assumption is consistent with guidance in Risk Assessment
Standardization Project (RASP) Volume 1, Section 5.
Exposure Time
Exposure time for the failed E-3 EDG was established at 196 days. The analyst used the
RASP Volume I guidance, Section 2.5, for a run time component failure. This approach is
appropriate for standby operated components that fail due to a degradation mechanism that
affects the component during its operation, since this was a vibration induced failure.
Per this guidance, the exposure time starts when the component no longer had the
capability to operate for the probabilistic risk assessment (PRA) mission time (i.e. 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />).
The analyst reviewed E-3 EDG surveillance test results and added up the run time hours to
determine when the EDG had proven a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run time period. The results of this review
showed that in early December 2017, the EDG had over a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> proven run time and
therefore the exposure time was taken from that time until the failed test on June 13, 2018.
This period amounted to a best estimate exposure time of 186 days. Additionally, the E-3
EDG was out of service for repairs for an additional 10 days, which would amount to a total
exposure time due to this performance deficiency of 196 days.
In this case, two degraded conditions existed including an inadequate check valve shaft to
disk interference fit, which would result in higher vibration of the shaft and disk at any loads,
and a hydraulic dashpot which was not kept filled with oil. The dashpot assembly provides
some resistance against the valve opening and controls the rate of valve motion as it opens
or closes. It also dampens out oscillations caused by changes in air flow, engine load, and
anything else that could change the air flow pattern through the valve. Discussions with
Exelon personnel indicated that even at low EDG loads with the check valve to the
turbocharger not yet open there is vibration visually observed on the shaft mechanism which
is induced by EDG operation. The analyst noted that with the dashpot not filled, there would
be less dampening effect in the closed position and with the shaft not fit to the disc (design
is an interference fit), this would increase the stress on the pin connecting the shaft and inlet
check valve (disc) even at low loads and EDG startup. Additionally, the analyst noted that
during the failed surveillance test, the time period that the machine was near the estimated
2500 kW check valve opening load was of a very short duration (i.e. minutes). Because the
operator did not hear any issues with the machine for up to at least 20 minutes after full load
conditions were met (2750kW area), it is uncertain when exactly the pin failed as it would
likely not take very long for this pin to cause the damage that was observed with the
turbochargers rotating at speeds of 16,000 rpm. In summary, the E-3 EDG was verified to
be in the range of load equivalent to the estimated initial opening of the check valve for a
very short duration of time, which creates uncertainty when the pin would have failed due to
an overall vibration mechanism and it may have failed once it reached full load conditions.
The analyst noted that Exelons assessment of the direct cause of the failure within
Licensee Event Report (LER) 05000277/2018-002-0 was reasonable and the LER indicated
that several causal factors existed, including shaft bushing wear and inadequate shaft to
disk fit, which resulted in higher vibration of the shaft and disk. With the higher vibration,
tolerances for the interference fit of the pin to the disk shaft were not adequate to prevent
the pin from becoming dislodged. The analyst noted that vibration would exist at various
unknown levels due to the degraded condition from low load throughout loads above the
continuous rating of the E-3 EDG. There was no evidence that vibration for this degraded
condition would not have existed internal to the check valve throughout a spectrum of EDG
loading. Lastly, the analyst noted that during an actual loss of offsite power (LOOP) event,
loading can and will vary as operators start and remove equipment in response to plant
conditions. For instance, the analyst observed in a simulator demonstration that when
residual heat removal (RHR) was placed in service at designated allowed flowrate the
loading on the E-3 EDG was a nominal 3000 k
- W. However, when RHR flowrate was
reduced to the lower limits allowed within procedural guidelines, the load on the E-3 EDG
dropped to just below 2600 kW. Loading changes such as this would be anticipated during
actual events and changes on the check valve demand and positioning would not be
unexpected.
Standardized Plant Analysis Risk (SPAR) Model Changes and Sensitivity Analyses
A further detailed review of the NRC Peach Bottom SPAR model outputs resulted in identifying
several conservatisms. The SPAR model was modified to include FLEX modifications, which
the station had developed in response to NRC Order 12-049, Order to Modify Licenses with
Regard to Requirements for Mitigation Strategies for Beyond-Design-Basis External Events
(ML12054A735), and affected how the units would respond to an extended loss of alternating
current power. The plant-specific modifications that were included in the revised model were
described in Exelons Overall Final Integrated Plan (ML13059A305). Additionally, the analyst
determined that a second conservative modeling issue existed. Specifically, for postulated
recirculation pump seal failures, the reactor core isolation cooling (RCIC) system was not being
credited as capable of makeup for the postulated leak, which the analyst determined would
likely be well below the capability of the RCIC system. Therefore, through discussions with INL
personnel, a revised version of the model was developed in order to more accurately model the
change in risk due to this performance deficiency.
The analyst noted the Peach Bottom Unit 2 NRC SPAR model had much more detail
incorporated for external hazard events than the Unit 3 model and therefore used Unit 2 as a
surrogate for the determination of the increase in CDF due to the finding. The E-3 EDG referred
to in this evaluation is referred to in the SPAR model as the C EDG in the following
discussions.
Because of the nature of this particular failure of an EDG, the postulated events of importance
become associated with scenarios where alternative offsite alternate current (AC) power
sources are not available. As noted, one of the major plant modifications made within the last
few years, is an extensive change to the strategies of how to handle situations where there is, in
part, a complete loss of alternating current to the safety busses. FLEX or mitigating strategies
have been developed to provide additional protection for scenarios where it is not expected an
AC source can be readily recovered. Therefore, changes to the SPAR model were required to
ensure that the model matched the reality of the plant and procedures. This was incorporated
through a revision provided by INL SPAR model experts, and was revised by the analyst
through the knowledge of how the FLEX strategy would be implemented. In this way, some
amount of appropriate credit is recognized. It is, however, recognized that equipment used is
often portable with limited reliability data available to-date. Also, there are operator actions
required to achieve success. Therefore, uncertainty was considered by providing various
changes in assumptions for FLEX equipment failure rates through different sensitivity
evaluations. In this way, the impact of varying these assumptions could be observed and a
reasonable bounding approach could be achieved. Notwithstanding this, by using different
assumptions through a spectrum of failure rates this provides information to use a best estimate
risk informed evaluation of this degraded condition.
This revised model was then used to assess the internal events contribution to risk from this
degraded condition. Additionally, through discussions with Exelon staff, it was recognized that
several revisions were made to the Peach Bottom external event fire model. Therefore, the
existing Unit 2 SPAR model version 8.50 for fire external events was not used in the calculation
of external fire risk and the licensees fire model results were reviewed and considered. The
analyst reviewed a sample of core damage cutsets with Exelon personnel and determined them
to represent technically justified scenarios through a review of specific fire areas and the logic of
impact on applicable equipment.
The SPAR model for external events such as seismic and high wind did appear to have
appropriate core damage cutsets and therefore was used to evaluate other external events.
The revised SPAR model which incorporated FLEX strategies was linked to the seismic and
high wind event trees to ensure that FLEX would be credited as appropriate. Therefore, the
NRC SPAR model was used to develop a best estimate risk increase for internal events and for
postulated seismic and high wind external events.
Because there is very little data associated with portable type FLEX equipment, several different
sensitivities were performed using different values for FLEX equipment reliability to see what
impact this would have on the overall risk contribution for the failed EDG. Several different
cases were run which varied the FLEX equipment failure probabilities to gain an understanding
of the impact on the overall risk contribution. This was performed for both the external events
(Fire, Seismic, High Wind) and internal events. This included a spectrum of values including the
use of Exelons initial preliminary values for FLEX equipment reliability along with several
different cases such as increasing the fail to start (FTS) by a factor of 2 and the fail to run (FTR)
by a factor of 2, along with a case where the FTS was increased by over an order of magnitude
and the FTR was increased by a factor of 2. Lastly, a case considered bounding and likely
conservative was run for fire which used FLEX equipment failure rates of 0.1.
Per discussions with Exelon staff, for the development of the FLEX equipment reliability data
used in the Peach Bottom internal events and fire PRA models, no plant specific data was
collected or used. The Peach Bottom models use plant specific data gathered through
December 31, 2013, when applicable; however, data gathering for Peach Bottom FLEX
equipment did not begin until 2016. Therefore equipment failure probabilities for Exelons initial
BASE case are based on the 2015 version of NUREG/CR-6928 data. Exelon recognized that
equipment used as part of the FLEX strategies includes portable equipment such as FLEX
pumps and FLEX diesel generators (DGs). Therefore, they had performed initial sensitivity
assessments where the random failure probabilities of portable equipment, which lacks specific
data, is estimated as double those of similar permanently installed components.
LICENSEE BASE CASE per discussion (BC) FLEX failure probabilities
FLEX DG FTR for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> 3.65E-2
FLEX diesel driven (DD) makeup pump FTS 3.15E-3
FLEX DD makeup pump FTR 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> 4.75E-2
SENSITIVITY 1 - basecase failure probabilities doubled (2x sensitivity) used for internal events
FLEX DG FTR for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> 7.3E-2
FLEX DD makeup pump FTS 6.3E-3
FLEX DD makeup pump FTR 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> 9.5E-2
SENSITIVITY 2 - Used for fire results *
FLEX DG FTR for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> 7.3E-2
FLEX DD makeup pump FTR 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> 9.5E-2
SENSITIVITY 2 - Used for internal events/seismic/high wind SPAR model runs *
FLEX DG FTR for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> 9E-2
FLEX DD makeup pump FTR 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> 9E-2
similar FTR probability with difference insignificant to final results
SENSITIVITY 3 - Used only for fire external events
FLEX DG FTR for 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> 0.1
FLEX DD makeup pump FTR 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br /> 0.1
Internal Event Conditional Risk
Internal events were not a dominant contributor to risk and therefore only two sensitivities were
run. Sensitivity 1 and Sensitivity 2 were run to explore the changes in CDF increase given
different assumed FLEX equipment failure rates.
Sensitivity 2 - Internal (Slightly higher order of magnitude FTS and higher FTR)
A change set was developed to change the FLEX equipment failure rates including the FLEX
operator action failure probabilities for FLX-XHE-XM-480 and FLX-XHE-XM-RPV to a value of
0.1. This would factor in the potential impact of dependency related to multiple operator action
failures within a core damage sequence. A condition case change set was then developed
using the above conditions along with setting the EPS-DGN-FR-DGC to TRUE as the
conditional case.
The base case was 5.5E-6/yr and the conditional case was 6.83E-6/yr.
The increase in CDF was therefore 1.33E-6/yr x (196 days/365 days) = 7.2E-7/yr.
The dominant cutsets were as follows:
LOOP weather related, operator failure to establish Conowingo tie line setup, failure of
the E-2 EDG to run, failure to recover an EDG, failure to cross tie emergency busses,
failure to recover offsite power, convolution factor, and a failure of RCI
- C.
LOOP weather related, operator failure to establish Conowingo tie line setup, the E-2
EDG fails to run, failure to recover an EDG, failure to cross tie emergency busses, failure
to recover offsite power, a convolution factor, and failure to stage or run or load the 480V
Sensitivity 1 - Failure rates of 2x or double the NUREG/CR 6928 data
The same method was employed to develop change sets for the base case and conditional
case altering the FLEX equipment failure rates and failing the E-3 EDG FTR in the conditional
case.
The base case was 5.5E-6/yr and the conditional case was 6.67E-6/yr.
The increase in CDF was therefore 1.17E-6/yr x (196/365) =6.3E-7/yr
Several examples of dominant cutsets are as follows:
LOOP grid related, failure to establish Conowingo tie line, E-2 EDG out for test and
maintenance, failure to recover EDG, failure to cross tie emergency busses, failure to
recover offsite power, and RCIC failure
LOOP grid related, failure to establish Conowingo tie line, E-2 EDG out for test and
maintenance, failure to recover an EDG, failure to cross tie emergency busses, failure to
recover offsite power, and failure to stage or run or supply a FLEX reactor pressure
vessel pump.
Fire External Event Conditional Risk
It was determined that fire risk was the dominant contributor to risk. This was true for both the
impact on Unit 2 and Unit 3 with a slightly higher increase in CDF/yr for Unit 3. The areas of
importance from a fire perspective were related to the switchgear rooms.
Both of the Unit 2 and Unit 3 fire areas which dominated the conditional increase in risk were
associated with the 4kV switchgear rooms and contributed over 80% for each unit of the risk
contribution.
FLEX sensitivities were varied and more important for the external fire events. These were
applied to evaluate the impact of the varying assumptions for the reliability of the FLEX
equipment. The impact of the various equipment failure rate sensitivities was analyzed.
The analyst noted that the operator actions to gain access to, deploy, hook up, and start the
equipment was typically given a value of 0.1 for the human error probability by the licensee for
the fire scenarios. This was consistent with a SPAR-H human error probability calculation with
performance shaping factors of barely adequate time, high stress, moderately complex, and
nominal training and procedures. Additionally, factoring in the potential for low dependency
given this could be the second operator failure action in a cutset would result in a value close to
0.1. Therefore the analyst determined this was a reasonable value to go along with the various
sensitivities associated with the equipment as well.
Sensitivity 3 - Increasing FLEX equipment failure probability to 0.1
Unit 2 fire risk increase in CDF given E-3 FTR
9.1E-6/yr x exposure time (196 days/365 days) = 4.9E-6/yr increase in CDF/yr
Unit 3 fire risk increase in CDF given E-3 FTR
1.4E-5/yr x (196/365) = 7.5E-6/yr increase in CDF/yr
The analyst considered this to be a reasonable best estimate for a bounding assessment given
the high failure rates assumed which exceed actual failure rates to date at the station observed
with the limited data set.
Sensitivity 2 - Increasing FLEX equipment FTS over order magnitude and 2x baseline FTR
Unit 2 fire risk increase in CDF given E-3 FTR
8.19E-6/yr x 196/365) = 4.4E-6/yr increase in CDF/yr
Unit 3 fire risk increase in CDF given E-3 FTR
1.25E-5/yr x 196/365 = 6.7E-6/yr increase in CDF/yr
Licensee Base Case per discussion (Using NUREG/CR-6928 data 2015 version)
Unit 2 fire risk increase in CDF given E-3 FTR
6.5E-6/yr x 196/365 = 3.5E-6/yr increase in CDF/yr
Unit 3 fire risk increase in CDF given E-3 FTR
8.5E-6/yr x 196/365 = 4.6E-6/yr increase in CDF/yr
The analyst considered Sensitivity 2 to likely be more representative of the actual failure rates
given the limited data to date, however more importantly, the analyst considered the three
sensitivities above to be in agreement with the best estimate overall risk estimate of a White
issue or of low to moderate risk significance.
Dominant Fire Areas
Several of the dominant fire areas were as follows:
Unit 2
An area which contributed a nominal 30% of the risk increase was associated with fire area 35
(E23 4kV Switchgear Room). The significant contributor or event were electrical/high energy
arc faults (HEAFs), fires involving 4kV Bus Duct 00A20 or the E23 4kV Switchgear. The top
core damage cutsets involved the fire scenario initiating event, the operator failure to perform
the 4kV EDG backfeed, and the operator errors associated with aligning the FLEX generator
and performing a deep direct current (DC) load shed to extend battery life to support alignment
of the FLEX generator.
A second area contributing at least 15% of the total fire risk was associated with the E12 4kV
Switchgear Room. The contributing events were associated with electrical/HEAF fires involving
the 4kV Bus Duct 00A19 and the E12 4kV Switchgear.
The significant core damage cutsets involved fire scenario HEAFs at E12 and 00A19 along with
common cause failure of the E-1 and E-4 or E-2 and E-4 EDGs. Additional core damage
cutsets involve the same initiating events with random failure of the E-2 and either failure of the
operator action to perform 4kV backfeed or failure of the E-4 DG. The analyst noted that Exelon
appropriately had not credited FLEX in these cutsets as the fires damage division 1 equipment
that disables the use of FLEX phase 1 equipment.
The analyst noted that through a review of fire related cutsets it was evident that Exelon
appropriately modeled the loss of FLEX capability when the RCIC system was impacted or
equipment significant to the FLEX implementation strategy was affected.
Unit 3
An area that contributed at least 33% of the total fire risk was associated with fire scenarios
within the E23 4kV Switchgear Room. Some of the events consisted of electrical/HEAF fires
involving 4kV bus duct 00A20 or the E23 4kV Switchgear. The top core damage cutsets involve
the fire scenario initiating event, the operator action failure to perform the 4kV EDG backfeed,
and the operator action failures associated with aligning the FLEX generator or performing a
deep DC load-shed to extend battery life to support alignment of the FLEX generator.
Another dominant fire area was associated with fires in the E22 4kV Switchgear Room. The
events consisted of electrical/HEAF fires involving 4kV bus duct 00A20 or the E22 4kV
Switchgear. The top core damage cutsets involve the fire scenario initiating event, the failure to
perform the 4kV EDG backfeed, and the failures associated with aligning the FLEX generator or
performing a deep DC load-shed to extend battery life to support alignment of the FLEX
generator.
Other External Event Risk Contribution
The following external events, High Wind and Seismic, were calculated using the SPAR Unit 2
model. A comparison of model runs, indicated that both units were very similar in nature and
therefore the runs for the Unit 2 model will be considered identical contributions for Unit 3 for
these events.
High Wind 90 mph
Sensitivity 2 - Slightly higher order of magnitude FTS and higher FTR Internal events
A change set was developed to change the FLEX equipment failure rates including the FLEX
operator action failure probabilities for FLX-XHE-XM-480 and FLX-XHE-XM-RPV to a value of
0.1. This would factor in low dependency as a second error in a sequence. A condition case
change set was then developed using the above conditions along with setting the EPS-DGN-
FR-DGC to TRUE as the conditional case.
The base case was 7.6E-8/yr and condition case was 2.58E-7/yr
The increase in risk was therefore 1.82E-7/yr x 196/365 = 9.5E-8/yr or on the order of 1E-7/yr.
The dominant cutset was events with high winds, failure to establish the Conowingo tie line, the
E-2 EDG in test and maintenance, failure to recover an EDG, failure to crosstie the emergency
buses, a conditional LOOP given the wind 0.5, operator failure to recover offsite power, and
RCIC failure.
Sensitivity 1 - Failure rates of 2x or double the Licensee NUREG/CR numbers
The same method was employed to develop change sets for the base case and conditional
case altering the FLEX equipment failure rates and failing the E-3 EDG FTR in the conditional
case.
The base case was 7.55E-8/yr and the conditional case was 2.36E-7/yr
The increase in risk was therefore 1.6E-7/yr x 196/365 = 8.5E-8/yr
The dominant cutset was similar to the above case.
Seismic Events
The final external event evaluated were the Seismic events which fell into 5 bins relative to the
strength of the seismic event.
For this case a base case and conditional case was run, then the cutsets for each were
gathered into the core damage seismic end state to ensure that they were not being double
counted.
Sensitivity 2 - Order of magnitude approximately for FTS and 2x or double FTR)
The base case for the gathered cutsets was 1.62E-5/yr and the condition case was 1.68E-5/yr.
The increase in risk was 6E-7/yr x 196/365 = 3.2E-7/yr
Several dominant cutsets were a seismic event in bin 3 (0.5-0.75g) with a LOOP, FTR of the
E-2 EDG, and a seismic induced small break loss-of-coolant-accident or a failure of the RCIC
lube oil cooler or a failure of the FLEX generator.
Sensitivity 1 - Failure rates of 2x or double the Licensee NUREG/CR numbers
The change in risk between the base case and conditional case was
5.7E-7/yr x 196/365 = 3.1E-7/yr
The dominant cutsets were a bin 3 seismic event, with a LOOP, and failure of E-2 EDG to run
and failure to deploy/start the FLEX DD makeup pump.
The analyst reviewed portions of the Peach Bottom PRA summary notebook relative to the
analysis of large early release frequency (LERF). The licensee evaluated a Level 2
methodology analyzing issues such as magnitude and timing of calculated radionuclide releases
through level 2 containment event trees. The analyst noted that the Licensee had used a LERF
multiplier for both units relative to the CDF sequences of a nominal 5E-2. Therefore, this does
not increase the LERF importance with respect to risk over or beyond that calculated for the
CDF/yr increase.
A bounding result was associated with Unit 3 (Sensitivity 3 for FLEX) for the conditional change
in LERF and was a 4.3E-7/yr annualized increase in risk due to the degraded E-3 EDG. This
would result in 4.3E-7/yr x 196 days/365 days = 2.3E-7/yr increase in LERF due to the
condition. This bounds any LERF contribution from internal events and therefore the best
estimate of risk is represented by the estimated increase in total CDF/yr for the condition.
For LERF, per Inspection Manual Chapter 0609, Appendix H, Table 5.2, LERF factors of 1.0
and 0.6 are used for high pressure core damage accident sequences with the drywell dry or
flooded, respectively. These Appendix H LERF factors are considered conservative bounding
values. More recent insights from an NRC Office of Research sponsored study by Energy
Research, Inc. (ERI/NRC-03-04), November 2003 and subsequent State of the Art Reactor
Consequence Analysis Project at Peach Bottom Nuclear Power Station (NUREG/CR-7110)
have identified that improved modeling and analysis of anticipated types and sizes of reactor
coolant ruptures, projected containment heating and fuel-coolant interactions, and operator
actions taken to flood containment in accordance with Severe Accident Management
Guidelines, significantly reduce the potential for containment breach and the likelihood of a
LER
- F. Furthermore, the dominant sequences discussed throughout this review would result in
considerable time (estimated 8-10 hours) before postulated core damage and an a potential
additional 8-10 hours until containment breach. Therefore, the above reports indicate a more
benign containment response at the time of vessel breach, in terms of direct containment
heating and fuel-coolant interaction-induced containment failure. Therefore, the analyst
determined Exelons LERF evaluation to be reasonable.
Model comparisons and Licensee Risk Preliminary Methodology
Exelons internal events analysis for the conditional failure of the E-3 when evaluated for a 196
day exposure time by the analyst was found to be very similar with regard to the calculation of
the contribution of the increase in CDF/yr for internal events (i.e. nominal 5E-7/yr). This gives
added confidence that the NRC SPAR model and the licensees internal events model were
reasonably aligned in the assessment of the issue.
Per discussions with Exelon PRA personnel, it is believed that FLEX should be credited in any
scenario where there is the complete loss of AC power, except for conditions where RCIC is
impacted which is the phase I strategy for FLEX. The analyst determined this to be a
reasonable conclusion and recognized through a review of various fire scenario cutsets, that
FLEX credit was appropriately not being considered for cases which impacted the FLEX
procedures and strategy.
Preliminary Conditional Risk Increase Calculation CDF/yr
Total Risk Internal + External Events
Using the lower FLEX failure rates of sensitivity analysis
Unit 2
Fire 3.5E-6/yr + Internal 6.3E-7/yr + High Wind 8.5E-8/yr + Seismic 3.2E-7/yr = 4.5E-6/yr
Unit 3
Fire 4.6E-6/yr + Internal 6.3E-7/yr + High Wind 8.5E-8/yr + Seismic 3.2E-7/yr = 5.6E-6/yr
Higher FLEX failure rates of sensitivity analysis
Unit 2
Fire 4.9E-6/yr + Internal 7.2E-7/yr + High Wind 9.5E-8/yr + Seismic 3.2E-7/yr = 6E-6/yr
Unit 3
Fire 7.5E-6/yr + Internal 7.2E-7/yr + High Wind 9.5E-8/yr + Seismic 3.2E-7/yr = 8.5E-6/yr
Therefore, the analyst noted that the increase in CDF/yr for the failure of the E-3 EDG was
within the range of 4.5E-6/yr to 6E-6/yr for Unit 2 and 5.6E-6/yr to 8.5E-6/yr for Unit 3.
This would represent a Preliminary White issue or of low to moderate safety significance for the
conditional failure of the E-3 EDG for both Unit 2 and Unit 3.
Qualitative Considerations
As noted, FLEX was not initially incorporated into the SPAR model. This was recognized and a
modification was made to the appropriate Unit 2 Peach Bottom SPAR model (used as a
surrogate for Unit 3 also) to appropriately consider risk reduction for FLEX strategies.
A sensitivity was run for the potential effect of a reduction in risk going backwards crediting run
time of the E-3 EDG over the 186 days prior to failure. This would result in some additional time
for recovery of offsite power. This sensitivity evaluation showed an insignificant change to the
overall risk conclusions and does not apply to the dominant risk contributor or fire scenarios.
It should also be noted that actual postulated LOOP scenarios would result in the E-3 EDG
loading being different in that the loads on the EDG are not gradually increased similar to that
observed when sharing load on the grid and picking up load during surveillance testing. In a
postulated LOOP, the start of large equipment such as an RHR pump motor may result in
higher stress or impact loading to equipment such as the degraded turbochargers inlet check
valve noted in this evaluation. This would just be an additional uncertainty regarding the failure
mechanism and timing. This significance determination process analysis, including assumed
exposure time is thought to capture any of these uncertainties and provide a best estimate risk
evaluation for this issue.