IR 05000458/2023090
| ML23165A102 | |
| Person / Time | |
|---|---|
| Site: | River Bend  |
| Issue date: | 06/26/2023 |
| From: | Ryan Lantz NRC/RGN-IV/DORS/PBC |
| To: | Hansett P Entergy Operations |
| Josey J | |
| References | |
| EA-23-055 IR 2023090 | |
| Download: ML23165A102 (15) | |
Text
June 26, 2023
SUBJECT:
RIVER BEND STATION - NRC INSPECTION REPORT 05000458/2023090 AND PRELIMINARY WHITE FINDING
Dear Phil Hansett:
This letter refers to an inspection conducted from September 19, 2022, to June 8, 2023, by the U.S. Nuclear Regulatory Commission (NRC) at the River Bend Station. The purpose of the inspection was to evaluate the circumstances surrounding the failure of the High Pressure Core Spray (HPCS) transformer feeder during an operability test of the Division III diesel generator on September 19, 2022. On June 8, 2023, a final exit briefing was conducted with Bruce Chenard, General Manager Plant Operations, and other members of your staff. The results of the inspection are documented in the enclosed report.
The enclosed report discusses a preliminary White finding (i.e., a finding with low-to-moderate safety significance that may require additional NRC inspections), with an associated apparent violation. As described in the enclosed report, NRC inspectors reviewed documents and interviewed site personnel to determine whether the HPCS transformer feeder failure was the result of insufficient testing or maintenance. The finding was assessed based on the best available information, using the applicable significance determination process (SDP). The final resolution of this finding will be conveyed in separate correspondence.
The finding has an associated apparent violation which is being considered for escalated enforcement action in accordance with the NRC Enforcement Policy, which can be found at http://www.nrc.gov/about-nrc/regulatory/enforcement/enforce-pol.html. The apparent violation involves the failure to adequately inspect the HPCS transformer feeder in accordance with site maintenance procedures required by Technical Specification 5.4.1.a.
In accordance with NRC Inspection Manual Chapter 0609, we intend to complete our evaluation using the best available information and issue our final significance determination and enforcement decision, in writing, within 90 days from the date of this letter. The significance determination process encourages an open dialogue between your staff and the NRC; however, the dialogue should not impact the timeliness of our final determination.
Before we make a final decision on this matter, we are providing you with an opportunity to either (1) attend a Regulatory Conference where you can present to the NRC your perspective on the facts and assumptions the NRC used to arrive at the finding and assess its significance, or (2) submit your position on the finding to the NRC in writing. If you request a Regulatory Conference, it should be held within 40 days of the receipt of this letter, and 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. The focus of the Regulatory Conference is to discuss the significance of the finding and not necessarily the root cause(s) or corrective action(s) associated with the finding. If a Regulatory Conference is held, it will be open for public observation. If you decide to submit only a written response, such submittal should be sent to the NRC within 40 days of your receipt of this letter.
If you decline to request a Regulatory Conference or to submit a written response, you relinquish your right to appeal the final SDP determination, in that by not doing either, you fail to meet the appeal requirements stated in the Prerequisite and Limitation sections of Attachment 2 of NRC Inspection Manual Chapter 0609.
If you choose to send a written response, it should be clearly marked as a Response to Apparent Violation in NRC Inspection Report 05000458/2023090; EA-23-055 and should include: (1) the reason for the apparent violation or, if contested, the basis for disputing the apparent violation; (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 previously docketed correspondence if the correspondence adequately addresses the required response.
Additionally, your written response should be sent to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Director, Division of Operating Reactor Safety, U.S. Nuclear Regulatory Commission, Region IV, 1600 East Lamar Blvd., Arlington, Texas 76011-4511, and the NRC Resident Inspector at the River Bend Nuclear Station, and emailed to R4Enforcement@nrc.gov, within 40 days of the date of this letter. If an adequate response is not received within the time specified or an extension of time has not been granted by the NRC, the NRC will proceed with its enforcement decision or schedule a Regulatory Conference.
Please contact Jeff Josey at 817-200-1148 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, a Notice of Violation is not being issued at this time. In addition, please be advised that the number and characterization of the apparent violations described in the enclosed inspection report may change as a result of further NRC review.
In accordance with 10 CFR 2.390 of the NRCs Agency Rules of Practice and Procedure, a copy of this letter, its enclosure, and your response, if you choose to provide one, will be made available electronically for public inspection in the NRC Public Document Room and from the NRCs Agencywide Documents Access and Management System (ADAMS), accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html. If you have any questions concerning this matter, please contact Jeff Josey of my staff at 817-200-1148.
Sincerely, Signed by Lantz, Ryan on 06/26/23 Ryan E. Lantz, Director Division of Operating Reactor Safety Docket No. 05000458 License No. NPF-47
Enclosure:
NRC Inspection Report 05000458/2023090 w/Attachment: Detailed Risk Evaluation
Inspection Report
Docket Number: 05000458 License Number: NPF-47 Report Number: 05000458/2023090 Enterprise Identifier: I-2023-090-0007 Licensee: Entergy Operations, Inc.
Facility: River Bend Station Location: St. Francisville, LA Inspection Dates: September 19, 2022, to June 8, 2023 Inspectors: R. Deese, Senior Reactor Analyst R. Kumana, Senior Resident Inspector J. Rollins, Senior Project Engineer W. Schaup, Inspection Programs & Assessment Team Leader C. Wynar, Senior Resident Inspector M. Chisolm, Reactor Inspector Approved By: Jeffrey E. Josey, Chief Projects Branch C Division of Operating Reactor Safety Enclosure
SUMMARY
The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting an event follow-up inspection at River Bend Station, 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.
List of Findings and Violations
Failure to Adequately Inspect High Pressure Core Spray (HPCS) Transformer Wiring Resulting in Transformer Failure and Inoperability of HPCS system.
Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Preliminary White [H.12] - Avoid 71153 Systems AV 05000458/2023090-01 Complacency Open EA-23-055 The NRC identified a finding of preliminary low to moderate (white) safety significance and an associated apparent violation of Technical Specification 5.4.1.a for the failure to adequately inspect HPCS transformer wiring in accordance with site maintenance procedures.
Specifically, while inspecting the HPCS transformer on June 21, 2022, the licensee failed to identify improperly stored spare conductors laid across the transformer cores which, on September 19, 2022, caused a phase-to-phase fault and subsequent transformer failure resulting in the inoperability of the HPCS system.
Additional Tracking Items
Type Issue Number Title Report Section Status LER 05000458/2022-04-00 LER 2022-04-00 for River 71153 Closed Bend Station, Unit 1, High Pressure Core Spray Inoperable due to Transformer Failure
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 reviewed selected procedures and records, observed activities, and interviewed personnel to assess licensee performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.
OTHER ACTIVITIES - BASELINE
71153 - Follow Up of Events and Notices of Enforcement Discretion Event Report (IP section 03.02)
The inspectors evaluated the following licensee event report (LER):
- (1) LER 05000458/2022-04-00, High Pressure Core Spray Inoperable due to Transformer Failure (ADAMS Accession No. ML22321A306).
The inspection conclusions associated with this LER are documented in this report under the inspection results section (05000458/2023090-01). This LER is closed.
INSPECTION RESULTS
Failure to Adequately Inspect High Pressure Core Spray (HPCS) Transformer Wiring Resulting in Transformer Failure and Inoperability of HPCS system.
Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Preliminary White [H.12] - Avoid 71153 Systems AV 05000458/2023090-01 Complacency Open EA-23-055 The NRC identified a finding of preliminary white safety significance and an associated apparent violation of Technical Specification 5.4.1.a for the failure to adequately inspect HPCS transformer wiring in accordance with site maintenance procedures. Specifically, while inspecting the HPCS transformer on June 21, 2022, the licensee failed to identify improperly stored spare conductors laid across the transformer cores which, on September 19, 2022, caused a phase-to-phase fault and subsequent transformer failure resulting in the inoperability of the HPCS system.
Description:
On September 19, 2022, the licensee was conducting surveillance test STP-309-0203, Division III Diesel Generator Operability Test. Approximately 5 seconds after starting the diesel, multiple control room alarms and annunciators were received in the main control room for division III equipment along with a fire alarm for the HPCS switchgear room.
Operators secured the division III diesel generator and placed it in maintenance mode.
Operators in the field identified that the HPCS transformer feeder (E22-S003) was visibly damaged. The HPCS transformer feeder powers various division III auxiliary loads required to support the HPCS system. With the failure of the transformer, operators declared the HPCS system and standby service water pump SWP-P2C inoperable.
The licensee performed an apparent cause analysis of the event and determined the apparent cause was improperly stored spare conductors laid across the transformer cores caused a phase-to-phase fault resulting in the failure of the transformer. Additionally, the licensee had a failure analysis performed that supported the apparent cause from the licensees causal analysis.
Inspectors reviewed the event and determined that the licensee failed to adequately perform work order 53003640 E22-S003 - Clean, Test, E22-S003 Transformer. Specifically, section 4.1 Clean and Inspect, subsection 4.1.1.6, requires, in part, that the licensee inspect the interior of the transformer enclosure for signs of rodent intrusion (droppings, debris, and abraded cable/wire insulation) AND note any signs of intrusion in comments. If cables are found damaged, the work order requires the licensee to initiate necessary corrective actions to identify and correct the problem. Subsection 4.1.1.10 states INSPECT all wiring for signs for degradation, cracked insulation AND overheating." Additionally, subsection 4.1.1.13 requires the licensee to Inspect for loose nuts, bolts, set screws or other fasteners.
Due to an inadequately performed inspection, the licensee failed to identify spare conductors housed inside the transformer cabinet or note the condition of their associated jacket insulation. The licensees apparent cause analysis identifies these spare conductors as causing the faulted condition and subsequent failure of the HPCS transformer. The inspectors determined that the transformer cabinet is designed to support inspection of internal components and wiring. No spatial challenges or internal component impediments were identified during review of documentation that would prevent identification of the spare conductors. The failure of the licensee to identify these spare conductors, assess the health of their insulation, and take appropriate corrective action allowed for a latent error to remain uncorrected until component failure.
Corrective Actions: The licensee entered the condition into its corrective action program and evaluated a replacement transformer under engineering change EC 93841. The replacement transformer was installed as a temporary modification under work order 00586001 and is currently being evaluated for acceptance as a permanent modification.
Corrective Action References: CR-RBS-2022-05422, EC 93841, and CR-RBS-2023-04821
Performance Assessment:
Performance Deficiency: The failure to properly inspect all wiring for signs of degradation, cracked insulation, and overheating, and inspect for loose nuts, bolts, set screws, or fasteners was a performance deficiency.
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 failure to adequately inspect the HPCS transformer adversely affected the mitigating systems cornerstone objective because it resulted in the inoperability of systems that mitigate the effects of initiating events and prevent core damage.
Significance: The inspectors assessed the significance of the finding using IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The degraded condition represents a loss of the probabilistic risk assessment function of a single train technical specification system for greater than its technical specification allowed outage time and therefore screening instructs performance of a detailed risk evaluation. A detailed risk evaluation was performed and concluded that the increase in core damage frequency resulting from the HPCS transformer failure was estimated to be 6.6E-6/year (White).
Cross-Cutting Aspect: H.12 - Avoid Complacency: Individuals recognize and plan for the possibility of mistakes, latent issues, and inherent risk, even while expecting successful outcomes. Individuals implement appropriate error reduction tools. Specifically, licensee personnel failed to use all information available, assumed that there were no latent conditions, and did not use error reduction techniques to ensure that all areas of the transformer were inspected and that the failed cables were properly secured.
Enforcement:
Violation: Technical Specification 5.4.1.a, requires, in part, that written procedures shall be established, implemented, and maintained covering the activities recommended in Regulatory Guide 1.33, revision 2, Appendix A. Regulatory Guide 1.33, revision 2, Appendix A, section 9.a, requires, in part, that maintenance that can affect the performance of safety-related equipment should be properly preplanned and performed in accordance with written procedures, or documented instructions appropriate to the circumstances.
The licensee established Work Order 53003640 to clean, inspect, and test HPCS transformer E22-S003. Work Order 53003640 step 4.1.10 requires, in part, to inspect all wiring for signs of degradation, cracked insulation and overheating, and step 4.1.13 requires, in part, to inspect for loose nuts, bolts, set screws or other fasteners.
Contrary to the above, on June 21, 2022, the licensee failed to implement procedures recommended by Regulatory Guide 1.33, revision 2, Appendix A. Specifically, when performing a cleaning and inspection of HPCS Transformer E22-S003, the licensee failed to adequately perform Work Order 53003640 step 4.1.10 to inspect all wiring for signs of degradation, cracked insulation and overheating, and step 4.1.13 to inspect for loose nuts, bolts, set screws or other fasteners. As a result, the transformer failed, causing the HPCS system and standby service water pump SWP-P2C to be inoperable.
Enforcement Action: This violation is being treated as an apparent violation pending a final significance (enforcement) determination.
EXIT MEETINGS AND DEBRIEFS
The inspectors verified no proprietary information was retained or documented in this report.
On June 8, 2023, the inspectors presented the inspection results to Bruce Chenard, General Manager Plant Operations, and other members of the licensee staff.
DOCUMENTS REVIEWED
Inspection Type Designation Description or Title Revision or
Procedure Date
71153 Corrective Action CR-RBS-2022-
Documents 5422
71153 Drawings 244A9094 Neutral Grounding Resistor Drawing 06/02/1981
71153 Drawings 828E537AA HPCS Power Supply System
71153 Engineering E-222-E22-S002 480 VAC Standby Motor Control Center Load Tabulation
Evaluations including Cable Verification
71153 Engineering G13.18.3.6*019 HPCS (Division III) Diesel Generator Loading
Evaluations
71153 Miscellaneous 3.221.418.000.001 HPCS Transformer Installation instructions 11/28/1979
71153 Miscellaneous SDC-203 High Pressure Core Spray System Design Criteria Rev 5
11/22/2011
71153 Miscellaneous SDC-303 Safety Related 480V Electrical Distribution System Design Rev 1
Criteria 06/30/2003
71153 Miscellaneous SDC-309/405 High Pressure Core Spray Diesel Generator Division III, Rev 3
Diesel Generator Building Ventilation system design criteria 11/20/2004
71153 Miscellaneous VTD-G080-1312 General Electric Ventilated Dry-Type Transformers 11/08/1995
71153 Self-Assessments CR-RBS-2023- HPCS Inoperable due to Transformer Feeder Malfunction 03/13/2023
0412 Root Cause Evaluation
71153 Work Orders 53003640 E22-S003 Clean Test E22-S003 Transformer
71153 Work Orders 586001 FIN Troubleshoot E22-S003 Failure
River Bend Station (River Bend)
High Pressure Core Spray Transformer
Detailed Risk Evaluation
Conclusion: The increase in core damage frequency (CDF) resulting from the licensees failure
to properly clean and inspect the Division III 480v transformer, which caused the high pressure
core spray (HPCS) transformer to fail, was estimated to be 6.6E-6/year (White).
Influential Assumption:
The exposure time was 40 days. Inspectors concluded that the HPCS transformer E22-S003
failed upon starting of the HPCS diesel generator (DG) for a surveillance run. When the diesel
generator was started, HPCS DG room ventilation fan, 1HVP-FN3A, started as designed. This
large load, which is powered through the HPCS transformer, was assumed to have drawn a
large starting current. This large current draw created heating of the transformer and the
improperly located, loose spare cable such that the insulation on the spare cable was degraded
to the point that the electrical shorting event occurred, resulting in the failure of the transformer.
The inspectors assumed that the next start after the last successful surveillance run 28 days
earlier would have resulted in failure of the transformer. The licensee replaced the transformer
days later. Using the t + repair time method, the analyst used an exposure time of 40 days.
Model Modifications:
The HPCS transformer was not modeled in the SPAR model for River Bend. The analyst
created a basic event for the transformer using template event ZT-TFM-FC,
Transformer Fails to Operate, from the SPAR template event library. The analyst
placed this basic event under fault trees HCS-SS, HPCS Support Systems, and
SSW P2C, Standby Service Water Pump Train 2C Is Unavailable, to represent the
impact on the plant for the loss of the HPCS transformer.
Because River Bend has developed Diverse and Flexible Coping (FLEX) Strategies, the
analyst incorporated use of these FLEX strategies into the model. The analyst changed
the basic event FLX-XHE-XM-ELAP, Operators Fail to Declare ELAP when Beneficial,
from a failure probability of 1.0 to 1.0E-2 to reflect nominal probabilistic success for the
decision to employ these strategies. For the FLEX equipment failures, the analyst noted
that the River Bend SPAR model used failure data for the FLEX equipment that was
typical of installed permanent equipment at the plant. After a review of the dominant
sequences using these failure data, the analyst noted that only one sequence (the 31st
most dominant sequence) included use of the FLEX strategies. From that review and
judging that any change of FLEX failure data to the higher industry observed failure rate
data would have a minimal impact on the results, the analyst did not alter the FLEX
failure rate data.
Internal Events:
The River Bend SPAR model, version 8.80, with the previously mentioned modifications,
on SAPHIRE, version 8.2.8, was used to complete this evaluation. In the Event and
Condition Assessment module of SAPHIRE, the analyst set the basic event created for the
HPCS transformer to TRUE for an exposure time of 40 days. This input yielded 31 core
damage sequences that contributed at least one percent to the total estimate in the increase
in CD
- F. From this group of sequences, the analyst eliminated internal flooding
sequences FLI-AB-141_03FP-G sequence 2-104-25, FLI-AB-95_07SWC-M sequence 2-096,
and FLI-AB-70_05SW-L sequence 2-096. These sequences assume HPCS would be lost
during these flood events, so failure of the HPCS transformer would result in no increase in CDF
because HPCS would still not be available. The analyst adjusted the sequences input to the
increase in CDF to zero.
The analyst incorporated the change described above to the results from the Event and
Condition Assessment module, which resulted in an estimate on the increase in CDF from
internal events from the performance deficiency of 3.01E-6/year.
External Events:
Fire Events: The analyst noted that the licensee had a peer reviewed fire PRA model which they
used to attain various risk-informed license amendments. The analyst considered this model to
be the best source of information for estimating the increase in CDF from fire events. The
licensee provided the top 100 cutsets and top 22 fire sequences to the analyst from their fire
PRA model where the HPCS transformer was non-functional for fire sequences. The table
below lists the top 22 fire scenarios and their associated increase in CDF.
Fire Scenario Increase in CDF
Transformer Yard 1 Burnout 4.10E-7
Load Center NJS-LDC1AB Fire 2.83E-7
Auxiliary Building West / Elevation 70 feet Burnout 2.37E-7
Load Center EJS*LDC2B Fire 2.06E-7
Load Center EJS*LDC2A Fire 2.01E-7
Auxiliary Building Walkway / Reactor Water Cleanup
1.75E-7
Pumps Burnout
Turbine Building South of 8-Line / Elevation 67 feet 6
1.68E-7
inches Burnout
ENB Inverter and Battery 1A Room Burnout 1.38E-7
Turbine Building North of 8-Line / Elevation 67 feet 6
1.35E-7
inches Burnout
Turbine Building Air Removal Equip Room / Elevation
1.26E-7
Burnout
Turbine Building Generator and Exciter / Elevation 123
1.19E-7
feet 6 inches Burnout
Cable Chase I - Transient Burnout 1.17E-7
Auxiliary Building West / Elevation 95 feet Burnout 1.12E-7
Radwaste Building / Elevation 166 feet Burnout 9.88E-8
Air Compressor Canopy Full Burnout 9.65E-8
Bus C71-S001A Fire 9.58E-8
Turbine Building Off-Gas Area / Elevation 123 feet 6
8.82E-8
inches Burnout
Turbine Building Clean and Dirty Lube Oil Tank
7.91E-8
Burnout
Service Water Cooling Switchgear Building Burnout 7.82E-8
Normal Switchgear Building Room 1B Full Burnout 7.30E-8
Fuel Building All Areas Burnout 7.29E-8
Normal Switchgear Building Motor Control Center,
Switchgear and Heating, Ventilation, and Air 6.79E-8
Conditioning Burnout
TOTAL 3.18E-6
The analyst noted that these values included a plant availability factor of 8.98E-1 which the
licensee added to make the values represent at-power risk. To make the value more
representative of the 40-day exposure time in which the plant was always at full power, the
analyst divided this tables results by the plant availability factor to revise the estimate to the
estimate in the increase in CDF for these top 22 scenarios to 3.54E-6/year. The analyst used
this estimate even though there were additional less significant fire scenarios that would
increase risk further.
Seismic Events: The analyst used the SPAR model to evaluate the performance deficiency for
the increase in CDF due to seismic events. The analyst removed cutsets which contained the
failure of the Division III battery because its failure would render HPCS non-functional before the
transformer would fail. This method estimated the increase in CDF from seismic events to be
5.62E-8/year. Results are in the table below:
Seismic Range Increase in CDF
Earthquake 0.1g to 0.3g 1.36E-9/year
Earthquake 0.3g to 0.5g 3.40E-9/year
Earthquake 0.5g to 1.0g 4.20E-8/year
Earthquake 1.0g to 1.5g 9.25E-9/year
Earthquake greater than 1.5g 2.69E-10/year
Total Estimate of CDF Increase from Internal and External Events: The inputs to determine
the total increase in CDF are contained in the table below:
Input Value
Internal Events 3.01E-6/year
Fire Events 3.54E-6/year
Seismic Events 5.62E-8/year
Total 6.61E-6/year
The total estimate in the increase of CDF is estimated to be 6.6E-6/year, or of low to moderate
safety significance (White).
Large Early Release Frequency (LERF): The analyst evaluated the increase in large early
release frequency using Inspection Manual Chapter 0609, Appendix H, Containment Integrity
Significance Determination Process. The unavailability of the HPCS transformer was treated as
a Type A finding in Appendix H because it can influence likelihood of accidents leading to core
damage as well as being a contributor to LERF. The analyst screened out all sequences except
station blackout and high reactor coolant system pressure sequences per Table 6.1, Phase 1
Screening - Type A Findings at Full Power by eliminating all sequences with the success
depressurization top event. For the station blackout and high reactor coolant system pressure
sequences, the analyst applied the applicable assessment factors from Table 6.2, Phase 2
Assessment Factors - Type A Findings at Power. This resulted in an increase in LERF from
internal events of 3.4E-7/year. The analyst noted this estimate was comparable to the internal
events estimate for the increase in CDF relative to the NRCs significance thresholds and opted
to use CDF as the risk metric for significance determination.
Sensitivities: The analyst estimated the increase in CDF for changes to key assumptions made
in the evaluation.
13-day exposure time: The analyst postulated a 13-day exposure time, which would
reflect the transformer failure being treated as a failure of continuously running
equipment (24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> plus 12 days repair time) and estimated the increase in CDF as
2.1E-6/year. This sensitivity gives confidence that the estimate was not of very low
safety significance (Green).
Inclusion of all potential fire scenarios: The licensee provided the top 22 fire scenarios
which had an increase in CDF from the HPCS transformer failure of 3.54E-6/year. More
fire scenarios (scenarios 23 and on) would be included if a more accurate estimate were
made. To support a timely analysis, the analyst just used the top 22 scenarios.
Information from the license in the top 100 cutsets indicated that the increase in CDF
from all fire scenarios could be as high as 6.93E-6/year, which would make the total
increase in CDF from all events equal to 9.9E-6/year. This sensitivity gives confidence
the estimate was not of substantial safety significance (Yellow). The analyst reserved the
rights to perform further refinement of the contribution of fire events to the total estimate
of the increase in CDF.
Consideration of common cause: The analyst did not model the HPCS transformer as
part of a common cause group, despite the possibility of other large dry 4160v/480v
transformers in the plant having the same condition leading to the possibility of their
failure. Had this common cause vulnerability been modeled, the quantitative estimate for
the increase in CDF would have been higher. The analyst reserved the rights to perform
this modeling.
Use of licensee-suggested model enhancements: After discussing the sequences with
the licensee, the analyst performed sequence-specific adjustments to several of the
sequences produced from the SPAR model to reflect actual plant and operator
response. The analyst reviewed sequence 59-12 for grid-related LOOPs, plant-centered
LOOPs, switchyard-centered LOOPs, and weather-related LOOPs. This sequence
progresses with a failure of the emergency diesel generators upon a LOOP leading to a
station blackout. Additionally, high pressure injection to the reactor vessel is lost when
feedwater is lost due to the LOOP, reactor core isolation cooling (RCIC) is lost due to
probabilistic failures, and HPCS is lost due to the performance deficiency. Offsite power
and diesel generators are not recovered within 30 minutes, leading to core damage. The
analyst ran a change set on the four LOOP sequences with the HPCS transformer
faulted and the RCIC failure-to-run basic event set to 2.58E-2 (which represents RCIC
failing to run for 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />) to eliminate the counting of failures of RCIC to run for hours
to 24 since this sequence results in core damage in the first few hours. Additionally for
loss of main feedwater sequence 13, the analyst credited the availability of the control
rod drive pumps after 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> as an adequate injection source and therefore used a
6-hour mission time for RCIC failures to run (4.07E-2). The consideration of these
changes lowered the estimate of the increase in CDF from internal events to
2.6E-6/year.
Uncertainties: The analyst performed an uncertainties analysis using the Monte Carlo method
with 5000 runs on the internal events estimate in SAPHIRE. The distribution of results was tight
around the point estimate with 80 percent of the results in the range of 1.0E-6 to 1.0E-5. The
shape of the distribution of the results contained 19 percent less than 1.0E-6 and 1 percent
greater than 1E-5, making the distribution skewed low. Because of this skew in the internal
events results, the analyst judged that inclusion of the increase in CDF from fire events would
not appreciably alter the large majority of the results falling within the 1.0E-6 to 1.0E-5 range.
A-5