ML25023A150
| ML25023A150 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 01/23/2025 |
| From: | John Dixon NRC/RGN-IV/DORS/PBD |
| To: | Sullivan J Entergy Operations |
| Kumana R | |
| References | |
| IR 2024040 | |
| Download: ML25023A150 (1) | |
Text
January 23, 2025 Joseph Sullivan, Site Vice President Entergy Operations, Inc.
17265 River Road Killona, LA 70057
SUBJECT:
WATERFORD STEAM ELECTRIC STATION, UNIT 3 - 95001 SUPPLEMENTAL INSPECTION REPORT 05000382/2024040 AND FOLLOW-UP ASSESSMENT LETTER
Dear Joseph Sullivan:
On December 13, 2024, the U.S. Nuclear Regulatory Commission (NRC) completed a supplemental inspection using Inspection Procedure 95001, Supplemental Inspection Response to Action Matrix Column 2 (Regulatory Response) Inputs, and discussed the results of the inspection and the implementation of your corrective actions with you and other members of your staff.
The NRC performed this inspection to review your stations actions in response to the performance indicator for Unplanned Scrams per 7000 Critical Hours having crossed the Green-to-White threshold in the Initiating Events cornerstone in the second quarter 2024.
On October 21, 2024, you informed the NRC that your station was ready for the supplemental inspection (ADAMS Accession No. ML24295A182).
The NRC determined that your staffs evaluation of the three reactor trip events that led to the White performance indicator identified a root cause. Specifically, your staffs evaluation identified that station leadership had not fully reinforced risk processes to ensure generation risks for critical equipment are identified, evaluated and actions established to effectively eliminate/mitigate reactor trips.
The inspectors determined that the licensee appropriately identified the root cause and contributing causes using systematic methodologies, considered prior occurrences and operating experience, and documented their analyses in sufficient detail. Based on the results of the inspection, the inspectors concluded that the objectives of the inspection procedure were met.
The NRC determined that the completed and planned corrective actions were sufficient to address the performance issue that led to the White performance indicator. Therefore, the performance issue will be closed and no longer be considered as an Action Matrix input as of the date of the exit meeting. Based on the results of the inspection and our Action Matrix assessment, the NRC made the determination to transition Waterford Steam Electric Station, Unit 3 to the Licensee Response Column (Column 1) of the Action Matrix on December 13, 2024, considering the absence of additional Action Matrix inputs.
J. Sullivan 2
One finding of very low safety significance (Green) is documented in this report. This finding involved a violation of NRC requirements. We are treating this violation as a non-cited violation (NCV) consistent with section 2.3.2 of the Enforcement Policy.
If you contest the violation or the significance or severity of the violation documented in this inspection report, 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 IV; the Director, Office of Enforcement; and the NRC Resident Inspector at Waterford Steam Electric Station, Unit 3.
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 IV; and the NRC Resident Inspector at Waterford Steam Electric Station, Unit 3.
This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding.
Sincerely, John L. Dixon, Jr., Chief Reactor Projects Branch D Division of Operating Reactor Safety Docket No. 05000382 License No. NPF-38
Enclosure:
As stated cc w/ encl: Distribution via LISTSERV Signed by Dixon, John on 01/23/25
SUNSI Review
Non-Sensitive
Sensitive
Publicly Available
Non-Publicly Available OFFICE SRI:DORS:EB1 SRI:DORS:EB2 BC:DORS:PBD NAME RKumana GPick JDixon SIGNATURE
/RA/
/RA/
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DATE 01/23/25 01/23/25 01/23/25
Enclosure U.S. NUCLEAR REGULATORY COMMISSION Inspection Report Docket Number:
05000382 License Number:
NPF-38 Report Number:
05000382/2024040 Enterprise Identifier:
I-2024-040-0005 Licensee:
Entergy Operations, Inc.
Facility:
Waterford Steam Electric Station, Unit 3 Location:
Killona, LA Inspection Dates:
December 9, 2024, to December 13, 2024 Inspectors:
R. Kumana, Senior Reactor Inspector G. Pick, Senior Reactor Inspector Approved By:
John L. Dixon, Jr., Chief Reactor Projects Branch D Division of Operating Reactor Safety
2
SUMMARY
The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting a 95001 supplemental inspection at Waterford Steam Electric Station, Unit 3, 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 Take Corrective Actions for Defective Relays Cornerstone Significance Cross-Cutting Aspect Report Section Initiating Events Green NCV 05000382/2024040-01 Open/Closed
[H.12] - Avoid Complacency 71153 The inspectors identified a Green finding and associated non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, when the licensee failed to take prompt corrective actions for a manufacturing defect in safety-related relays, a condition adverse to quality. The failure to take adequate corrective actions led to a reactor trip. Furthermore, the inspectors identified other relays subject to the same potential defect that did not have any corrective actions assigned.
Additional Tracking Items Type Issue Number Title Report Section Status LER 05000382/2024-001-01 Manual Reactor Trip Due to Engineered Safety Features Actuation System Relay Failure 71153 Closed LER 05000382/2024-001-00 Manual Reactor Trip Due to Engineered Safety Features Actuation System Relay Failure 71153 Closed LER 05000382/2024-004-00 Automatic Reactor Trip Due to Lightning Strike 71153 Discussed CAPR 05000382/2024040-02 Waterford 95001 CAPR CR-WF3-2024-03099-00040 Revise Procedures to Incorporate Industry OE for Transformers 95001 Closed CAPR 05000382/2024040-03 Waterford 95001 CAPR CR-WF3-2024-03099-00024 Ensure Generation Risk Processes are Reinforced as a Part of Leadership Job Fundamentals 95001 Discussed
3 CAPR 05000382/2024040-04 Waterford 95001 CAPR CR-WF3-2024-03099-00035 Implement EC-54163913 to eliminate the SPV in the ESFAS system 95001 Discussed CAPR 05000382/2024040-05 Waterford 95001 CAPR CR-WF3-2024-03099-00073 Incorporate Actions to Prevent Recurrence Based on the Findings by the Vendor Performed Ground Grid Study 95001 Discussed CAPR 05000382/2024040-06 Waterford 95001 CAPR CR-WF3-2024-03099-00043 Develop and Implement Acceptance Criteria for Maintenance Procedures 95001 Closed CAPR 05000382/2024040-07 Waterford 95001 CAPR CR-WF3-2024-03099-00084 Develop and Incorporate Quality Requirements for Replacement Relays 95001 Discussed
4 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 - TEMPORARY INSTRUCTIONS, INFREQUENT AND ABNORMAL 71153 - Follow Up of Events and Notices of Enforcement Discretion The inspectors evaluated the following licensee event report (LER):
Follow Up of Events and Notices of Enforcement Discretion (1 Sample 1 Partial)
(1)
LER 05000382/2024-001-00, Manual Reactor Trip Due to Engineered Safety Features Actuation System Relay Failure (ML24136A170) and LER 05000382/2024-001-01, Manual Reactor Trip Due to Engineered Safety Features Actuation System Relay Failure Supplement (ML24312A174).
The inspection conclusions associated with this LER and an associated non-cited violation are documented in this report under IP 71153 in the Inspection Results section. This LER is closed.
(2)
(Partial) LER 05000382/2024-004-00, Automatic Reactor Trip Due to Lightning Strike (ML24228A105).
The inspectors reviewed aspects of this LER, but the review was insufficient to close it. The results of this inspection should be considered during subsequent reviews and closure of the LER. This LER remains open.
95001 - Supplemental Inspection Response to Action Matrix Column 2 (Regulatory Response)
Inputs The inspectors reviewed and selectively challenged aspects of the licensees problem identification, causal analysis, and corrective actions in response to degraded performance that led to the Waterford Steam Electric Station, Unit 3 facility being moved into Column 2 of the Action Matrix for the Unplanned Scrams per 7000 Critical Hours performance indicator crossing into the White threshold, as described by the following events:
Event 1 - main steam isolation system relay failure: On March 16, 2024, while at approximately 100 percent power, main feedwater isolation valve 2, FW-184B, and main steam isolation valve 2, MS-124B, began closing resulting in steam generator levels lowering. As a result of these indications, control room operators initiated a manual reactor trip. The cause of the event was a failure of the K313A main steam isolation system
5 actuation relay in the engineered safety features actuation system (ESFAS). The relay failed due to a manufacturing defect.
Event 2 - main transformer B: On March 21, 2024, while at 98 percent power, main transformer B experienced a failure that resulted in a fire and automatic reactor trip. The direct cause of the failure was determined to be a failure of a high voltage bushing. The causal investigation identified gaps in implementing industry accepted preventive maintenance and testing strategies to detect early failure of high voltage bushings.
Event 3 - lightning strike (core protection channels B and D): On June 16, 2024, while at approximately 100 percent power an automatic trip occurred from the actuation of reactor protection system channels B and D core protection calculator auxiliary trip signals. The auxiliary trip signals resulted from both an asymmetrical steam generator transient and a variable overpower trip. The analysis of the event concluded that the likely cause of the plant trip resulted when multiple lightning strikes introduced a voltage transient to instrumentation that provides input to core protection calculator channels B and D.
Objective: Ensure that the root and contributing causes of significant individual and collective White performance issues are understood.
The inspectors reviewed the root cause evaluation (RCE) the licensee conducted for crossing the White threshold for the Unplanned Scrams per 7000 Critical Hours performance indicator, as documented in the Updated Inspection Plan and Assessment Follow-up Letter for Waterford Steam Electric Station, Unit 3 dated August 21, 2024 (Report 05000382/2024005 (ML24232A254)). The plant had experienced three plant trips in 62 days.
The inspectors evaluated the following: identification of the issues, when and how long the issues existed, prior opportunities for identification, documentation of significant plant-specific consequences and compliance concerns, use of systematic methodology to identify causes with a sufficient level of supporting detail, consideration of prior occurrences, and identification of any potential programmatic weaknesses in performance.
NRC Assessment: The inspectors concluded that this objective was Met. The inspectors determined that the licensee appropriately identified the root cause and contributing causes using systematic methodologies, considered prior occurrences and operating experience, and documented their analyses in sufficient detail.
The licensee used multiple techniques to analyze the three events and identified the following root cause and contributing causes:
Root cause: Leadership has not fully reinforced risk processes to ensure generation risks for critical equipment are identified, evaluated, and actions established to effectively eliminate/mitigate reactor trips.
Contributing cause 1: Less than adequate corrective action program behaviors in that certain risk significant conditions were not entered into the corrective action program for further evaluation and when entered into the corrective action program, not appropriately evaluated for timely action to prevent reactor trips.
6 Contributing cause 2: System engineers and maintenance personnel over-reliance on vendor personnel for interpretation and review of testing results of main transformer B.
Contributing cause 3: Operating experience has not been fully implemented into maintenance strategies for critical equipment to ensure failure mechanisms are identified and mitigated.
a.
Identification. This White performance indicator resulted from three independent plant trips caused by three different self-revealed events that occurred on March 16, March 21, and June 16, 2024. The inspectors did not identify any concerns with the licensee characterization of these events.
b.
Exposure Time. The plant had experienced three plant trips in 62 days that resulted in exceeding the White threshold of the Unplanned Scrams per 7000 Critical Hours performance indicator. The inspectors determined that the licensee had identified an exposure time associated with each of the plant trips as follows:
Event 1: In 2022, the licensee identified a manufacturing defect in the motor-driven relay (MDR)-7034 relays, the specific model of relay used for the K313A main steam isolation system actuation relay.
Event 2: In 1997, the licensee changed procedures to remove evaluating power factor test results.
Event 3: In 2006, the licensee identified that external events could disturb the grounding grid causing a core protection calculator channel B trip. In 2010 following another ground grid disturbance the license identified that a design change may be needed.
The inspectors determined that the licensee appropriately addressed the exposure time.
c.
Identification Opportunities. The licensee identified additional opportunities for identification as follows:
Event 1: The licensee identified that they had evidence of the relay manufacturing defect since June 2022 when a similar failure resulted in a reactor trip. In addition, the licensee was aware that the relays constituted a single point vulnerability (SPV) trip risk as early as 2008.
Event 2: The licensees review of site actions and fleet operating experience identified the following:
On March 31, 1997, the licensee deleted the section of the procedure that performed power factor testing that created a future error trap since it did not identify that power factor testing should be reviewed.
On September 17, 2003, although the licensee added core ground testing as an optional test to Procedure ME-004-051, Main Transformer B, revision 9,
7 section 9.4, as specified in CR-WF3-2002-01813, CA 23, neither the licensee nor their vendors had performed this testing.
On December 30, 2004, the licensee decided to not participate in power factor training at River Bend Station because contractors performed the testing without considering the impact on the ability of personnel to have the requisite knowledge to oversee vendor personnel.
The licensee identified numerous instances between 2011 and 2017, when they did not record the Doble test results for main transformer B - April 23, 2011, December 12, 2012, May 6, 2014, and December 2, 2015.
The licensee identified numerous instances when they did not write condition reports (CRs) for questionable indications from Doble testing of main transformer B - November 13, 2009, April 19, 2017, January 16, 2019, October 3, 2020, April 2, 2022, and October 20, 2023.
Event 3: The licensee had identified two prior occurrences related to the probable cause:
Condition report CR-WF3-2006-02204 described that a lightning strike induced a trip on core protection channel B; however, because only a single channel tripped, the licensee initiated a broke-fix disposition. The broke-fix disposition explored multiple avenues but did not identify the exact cause other than the nearby lightning strike. This involved a different style of core protection calculator since the licensee replaced their core protection calculator in 2022.
Condition report CR-WF3-2010-00637 described that a blown rectifier at a nearby facility caused a grid perturbation and failures of numerous equipment.
After investigating (CR-WF3-2010-01187), the licensee initiated a capital project to upgrade their grounding grid. Subsequently, the licensee did not implement the modification in 2017 because of the unlikely nature of the events (i.e., no events from 2010 to 2016) and cost versus benefit of implementing the modification. The licensee decided to take no further actions unless the grid conditions changed.
The inspectors determined that the licensee appropriately identified missed opportunities for each of the events.
d.
Risk and Compliance. The inspectors determined that the licensee had identified and understood the risk of each event. The inspectors identified the following associated with each event:
Event 1: The licensee cause analysis identified that they had failed to take prompt action to mitigate the potential for a single relay failure. The licensee identified that the potential consequence of the failure was a reactor trip. The inspectors identified a violation associated with the cause of the event that is documented below.
Event 2: The licensee cause analysis identified that they had inadequate maintenance procedures related to Doble testing of the main, auxiliary, and startup transformers. The
8 licensee further identified that the unavailability of the deluge system allowed the fire to become worse than it should have. These issues were previously dispositioned as:
Self-revealed Green finding in Inspection Report 05000382/2024003 (FIN 05000382/2024003-02 ML24311A182) because the procedures did not contain testing instructions to appropriately identify degraded conditions prior to failure.
Self-revealed Green finding in Inspection Report 05000382/2024011 (FIN 05000382/2024011-01 ML24274A079) because the licensee failed to ensure the transformer deluge system provided more than 0.25 gpm per square foot of water to the surface of the main and start-up transformers to minimize the impact of fires.
Event 3: The licensee identified a probable causal factor related to risk management for their failure to correct the plant grounding system. Because the core protection calculator functioned as designed, the inspectors determined that no compliance issues existed.
In addition, as documented in CR-WF3-2024-04132, the licensee isolated core protection channel B because the channel tripped on August 17, 2024, when a lightning strike occurred. The licensee performed this action to allow increased reliability from grid disturbances through the remainder of the cycle by reducing the risk of spurious reactor trips.
e.
Methodology. The licensee employed systematic evidence based causal analysis to reliably and scrutably determine the root and contributing causes of the White performance issue including barrier analysis, event and causal factor charting, common cause review, performance analysis from the main transformer B failure, and organizational and programmatic evaluation.
f.
Level of Detail. The inspectors determined that the licensee conducted and documented the overall root cause evaluation, as well as the condition analyses for each event, in sufficient detail commensurate with the significance and complexity of the issue and regulatory requirements.
g.
Operating Experience. The licensee reviewed operating experience for each individual event. The inspectors determined that the licensee identified failure to adequately incorporate operating experience as a contributing cause to the White performance indicator.
Event 1: The licensee identified the following internal and external operating experience that was relevant to the relay failure:
On June 24, 2022, an identical relay at Waterford failed in a similar way and resulted in a reactor trip. The licensee identified this as a prior opportunity to address design and the quality issues with the relays.
The licensee identified multiple events at other sites involving failures of similar relays.
9 Event 2: The licensee review of external operating experience identified numerous instances that might have prevented the event if reviewed in a more critical manner or implemented effectively. The inspectors noted that in particular the licensee had missed several opportunities to identify that they had inadequate procedures related to power factor testing. Specific examples include:
On December 19, 2002, the licensee implemented SOER 02-3, Large Power Transformer Reliability, recommendation 4B3 that requires the contract manager to verify vendors are qualified to perform the work and required site personnel to verify that the vendor performs work in accordance with site work control programs, policies and standards. The licensee concluded that they had not effectively implemented this operating experience.
On September 9, 2007, the licensee concluded the Indian Point, Unit 2 main transformer fire did not apply because of manufacturer differences. The apparent cause identified this as a missed opportunity to reevaluate their procedure acceptance criteria.
On March 25, 2009, the site procedure requirement to provide training for oversight of contractors, as required by SOER 02-3 recommendation 4A3, was deleted when the licensee discontinued the site procedure and implemented a similar corporate procedure.
On April 29, 2009, Pilgrim reported bushing power factor test failures; however, the operating experience had not been assigned to site personnel to evaluate.
The licensee identified this as a missed opportunity to reinforce the need to review power factor test results.
On July 14, 2010, the licensee did not include all performance requirements in Procedure ME-004-051, as recommended by SOER 10-1, Large Power Transformer Reliability.
On November 7, 2010, the licensee concluded the Indian Point Unit 2 main transformer fault did not apply because of manufacturer differences. The apparent cause identified this as a missed opportunity to reevaluate their procedure acceptance criteria.
On May 9, 2015, an Indian Point Unit 3 main transformer fire occurred because of a high energy fault on a phase A bushing; however, the operating experience had not been assigned to site personnel for evaluation. The licensee determined that had the operating experience been assigned then a reevaluation of the Procedure ME-004-051 test criteria may have occurred.
Event 3: The licensee determined that external operating experience identified similar events related to lightning strikes. However, the events had not resulted in a reactor trip because of disruption of the grounding grid.
In 2006 a lightning strike had induced a trip on core protection calculator channel B (prior system) but did not cause a reactor trip since only a single
10 channel actuated. The licensee identified that they had a prior opportunity to correct the condition.
The licensee identified that several external events at other facilities had occurred when lightning strikes had directly resulted in equipment failure. One similar external event had occurred at Arkansas Nuclear One, Unit 1.
h.
Common Cause. Although not required because this involved one White finding input in the Initiating Events cornerstone, the licensee performed a common cause analysis of the three independent events. The inspectors determined that the individual events combined with the evaluation of commonalities among them focused on single point vulnerabilities that would result in a reactor trip.
Objective: Ensure that the extent of condition and extent of cause of individual and collective White performance issues are identified.
The inspectors independently assessed the extent of condition and extent of cause evaluations that the licensee performed for each individual event and for the root cause evaluation related to the White performance indicator.
NRC Assessment: The team concluded that this objective was Met. Overall, the licensee appropriately identified the extent of condition and, generally, appropriately identified the extent of cause for the performance issues.
The inspectors reviewed the extent of condition for each event and for the root cause evaluation as described below and did not identify concerns. As part of the root cause evaluation, the licensee revisited the extent of condition for the individual events. Similarly, the inspectors reviewed the extent of cause evaluations that the licensee performed for each individual event and for the root cause evaluation. The inspectors identified that, in some cases, the licensees extent of condition and cause evaluations did not broadly review other activities and focused on single point vulnerabilities that posed a trip risk. The inspectors identified other areas where the licensee may have the same extent of condition or cause.
This is documented below as General Weakness 1.
The inspectors determined that the licensee assessed the events and performed a safety culture analysis for the root cause and each of the common causes that reflected the results of their evaluation. For the root cause the licensee identified a lack of questioning attitude by senior managers and executives, as demonstrated by design reviews not focused sufficiently on generation risks, not asking probing questions, and not challenging managers to ensure degraded conditions were fully understood and appropriately resolved. The licensee identified a lack of communication to the plant staff related to nuclear safety being the overriding priority. The inspectors determined that the licensee established corrective actions to reinforce the importance of risk and communication of that risk at all levels of the organization.
11 Extent of Condition The licensee performed extent of condition reviews for the White performance indicator and the three individual events.
White performance indicator: For this extent of condition, the licensee looked at other performance indicators for the potential to exceed the threshold for White due to impacts from equipment vulnerabilities. The licensee did not consider taking additional actions because the other performance indicators had a high margin to the White threshold.
Event 1: The licensee limited the extent of condition review to other relays that were considered single point vulnerabilities.
Event 2: The licensee limited the extent of condition to other large power transformers (i.e.,
main transformers, unit auxiliary transformers, and startup transformers) with similar configurations (i.e., bushings).
Event 3: The licensee performed a failure modes analysis that logically eliminated other potential causes for the core protection calculator parameter changes that caused the auxiliary trips.
Extent of Cause The licensee performed extent of cause reviews for the root cause and three contributing causes, as well as the direct cause for each of the three events.
Root Cause: The licensee considered whether the inadequate leadership behaviors were present in other risk processes or other leadership levels with a focus on single point vulnerability mitigation.
Contributing cause 1: The licensee considered whether the inadequate corrective action program behaviors existed in other departments.
Contributing cause 2: The licensee considered whether the over-reliance on vendors existed in other applications that affected work on single point vulnerabilities.
Contributing cause 3: The licensee considered whether the failure to incorporate operating experience existed in other single point vulnerability elimination strategies.
Event 1: The licensee considered whether there were deficiencies with other single point vulnerability elimination modifications, and whether other defects could be present in motor-driven relays.
Event 2: The licensee completed an extent of cause evaluation related to other activities that involved vendor testing, although not required to complete this activity for an apparent cause analysis. The vendor testing activities review included: main generator inspections; dissolved gas, furanic, and oil analyses for main transformers; steam generator testing; and reactor vessel internals inspections. The inspectors noted that the licensee had assessed the capabilities of the engineers to review the activities for each of the corrective actions.
12 Event 3: The licensee performed a failure modes analysis related to the trip of core protection calculator channels B and D that identified the probable cause as lightning strikes near the site inducing a voltage transient on their grounding grid. The licensee established condition report CR-W3-2024-03099, CA 81 to track performing a future extent of cause after completing the grounding study, which specified perform a review of affected critical equipment which could be susceptible evaluate and address, as necessary.
General Weakness 1 The inspectors identified a general weakness associated with the extent of condition and extent of cause reviews performed by the licensee. While the licensee did look at some other areas where the conditions and causes could be present, the inspectors considered some of the reviews to be narrowly focused on single point vulnerabilities and generation risk when the licensee could reasonably have looked at other areas affecting nuclear safety.
For example:
The licensee considered the overall condition to be equipment vulnerabilities that had a risk for another plant trip with the corresponding impact to the performance indicator. They considered performance indicators affecting other cornerstones besides Initiating Events, but had not reviewed equipment failures that could cause other performance indicators to cross the White threshold because those performance indicators had more than 50 percent margin remaining. However, the inspectors noted that a series of events could result in exceeding a threshold in a short period of time. As an example, the inspectors noted that the Unplanned Scrams per 7000 Critical Hours performance indicator had substantial margin prior to the second event; however, this changed quickly to a concern after the second event occurred. The inspectors reviewed the recent history of equipment failures impacting other performance indicators, notably mitigating systems performance indicators (MSPI), and identified that there were two failures of mitigating systems performance indicator equipment within the past year. The inspectors considered it appropriate to extend the condition to look at vulnerabilities in other performance indicators.
The licensee limited the extent of condition for the manufacturing defect in MDR-7034 relays to other relays that could be potential single point vulnerabilities.
However, the licensee had other model MDR-7034 relays installed in safety-related applications that were not single point vulnerabilities. Despite the potential for the manufacturing defect condition to be present, the licensee did not consider additional actions to identify and correct this condition. The inspectors documented this issue in a non-cited violation below.
The licensee used the extent of cause for main transformer B they performed as part of their initial evaluation as the extent of cause for their root cause evaluation without additional review. The level of review for the apparent cause extent of cause assessed knowledge levels and capability of the program owners but did not evaluate for interface failures in their procedures. The inspectors determined this was an insufficient depth of review for the root cause evaluation because the interface failures for other vendor testing activities should have been evaluated.
The main transformer B apparent cause had concluded that personnel interfacing with vendors had insufficient knowledge and abilities to adequately oversee the vendor testing process and identified numerous opportunities to upgrade procedures
13 based on operating experience. However, the extent of cause for the apparent cause analysis (condition report CR-WF3-2024-01597, CA 68) concluded that the program owner for steam generator inspections was well versed in the requirements for steam generator inspection and fully competent for reviewing vendor products for compliance with program requirements.
During interviews, the inspectors determined that the steam generator group had continued to analyze the circumstances surrounding a data error that resulted in the steam generator tube integrity issues, as described in condition report CR-WF3-2023-17005. The steam generator group had revised Procedure CEP-SG-001, Steam Generator Primary Side Examinations and Maintenance, attachment 15.2, Oversight Checklist, to check for use of proper sizing calibration curves. The inspectors determined that the licensee extent of cause for the root cause evaluation failed to identify this ongoing review hence failed to identify that the oversight of the steam generator testing required additional procedural guidance like that identified by the apparent cause analysis for the main transformer B failure.
The licensee extended the contributing cause of failing to incorporate operating experience (Contributing Cause 3) to other areas where operating experience may not have been incorporated, but the actions for correcting the cause were focused on areas affecting single point vulnerabilities and large transformers. The inspectors noted that failure to incorporate operating experience could occur in other risk significant activities.
The licensee documented this weakness in condition report CR-WF3-2024-05884.
Objective: Ensure that completed corrective actions to address and preclude repetition of White performance issues are timely and effective.
The inspectors assessed the appropriateness and timeliness of the licensees corrective actions.
NRC Assessment: The inspectors concluded that this objective was Met. The inspectors determined, for the completed actions, the licensee generally implemented timely and effective corrective actions to preclude repetition (CAPR). However, the inspectors identified some differences between the CAPR descriptions that were approved as part of the licensees corrective action program and the actual actions taken. The licensee took actions to modify the descriptions of the CAPRs to match the completed actions. This is documented below as General Weakness 2.
a.
Completed Corrective Actions to Preclude Repetition The inspectors determined that the licensee appropriately implemented CAPRs for event 2 by addressing contributing causes 2 and 3.
Cause CAPR Contributing Cause 3 Closed CAPR 3 [Revised in response to NRC concerns]:
CR-WF3-2024-03099-00040 Revise ME-004-(051, 052, 061, 071) to implement recommendations from SOER 02-3, Large Power
14 Cause CAPR Transformers Reliability; SOER 10-1, Large Power Transformer Reliability; IER 21-04; Recommendation 7 -
Vendor Oversight, and Industry OE.
Intent of this action is to ensure industry lessons learned are incorporated in the site procedures.
Contributing Cause 2 Closed CAPR 4 [Revised in response to NRC concerns]:
CR-WF3-2024-03099-00043 Develop and implement acceptance criteria in ME-004-(051, 052, 061, 071). Also, include steps to initiate a CR and contact system engineering for any values approaching acceptance criteria, outside of acceptable limits, and suspect indications. Include the actual nameplate data in the associated procedure steps.
Intent of this action is to update procedure guidance in ME-004-(051, 052, 061, 071) to ensure acceptance criteria is defined and CR initiation steps are included. Engineering is to be contacted for any challenges with test results to identify degradation with transformer health.
b.
Other Completed Corrective Actions The inspectors sampled other completed corrective actions (non-CAPRs) for each cause to determine the appropriateness and timeliness of the corrective actions to correct each cause documented in condition report CR-WF3-2024-03099. The inspectors identified that one completed corrective action was closed to the life cycle management process and noted that this was not consistent with licensee Procedure EN-LI-102, Corrective Action Program, revision 54. After discussing this concern with the licensee, the licensee wrote condition report CR-WF3-2024-05878 to address the improperly closed corrective action.
The inspectors determined that this was a minor performance deficiency. The inspectors did not have any additional concerns.
Cause Corrective Action Root Cause The licensee developed a list of desired behaviors to reduce challenges to generation risk; performed detailed evaluations of relay related single point vulnerabilities; implemented numerous actions to eliminate single point vulnerabilities; established quantitative values for checking proper operation of the relays; and implemented the corrective actions recommended by Socotec Engineering for evaluating relays.
The licensee also created actions to perform additional maintenance and testing on large transformers.
Contributing Cause 1 The licensee initiated actions for multiple departments to perform read and sign to reinforce corrective action program behaviors and established workshops for personnel implementing the corrective action program to account for risk insights.
15 Cause Corrective Action Contributing Cause 2 The licensee identified full scope Doble testing that included updating procedures and preventive maintenance actions and established preventive maintenance activities at the correct frequency to ensure that maintenance activities could address adverse indications before component failure.
Contributing Cause 3 The licensee developed a case study related to the failure in the vendor oversight and the failure to incorporate operating experience for main transformer and presented the case study to electrical maintenance and engineers to ensure personnel understood what had occurred and apply the lessons to future activities.
General Weakness 2 The inspectors reviewed the two CAPRs that had been completed at the time of the inspection (CR-WF3-2024-03099-00040 and CR-WF3-2024-03099-00043). Upon review of the implementing procedures, the inspectors determined that the CAPR wording could not be implemented as written. Specifically, CAPR CR-WF3-2024-03099-00043 included a requirement to initiate a CR and contact System Engineering for any values reaching alert criteria, outside of acceptable limits, error messages, and suspect indications. The inspectors identified that the procedures did not contain any alert criteria nor would personnel receive error messages. CAPR CR-WF3-2024-03099-00040 included an action to incorporate findings from planned update to the system health reporting and monitoring plans for large transformers. However, that update had not been completed and the licensee did not expect to make any additional changes to the procedures upon completion. While the inspectors did not identify any concern that the CAPRs as implemented were not adequate to preclude repetition, the documented and approved CAPRs deviated from the actual corrective actions that were implemented. Procedure EN-LI-102, Corrective Action Program, revision 54, attachment 9 requires that any change in wording or intent of a CAPR must be approved by the performance review group. Subsequently, the licensee revised the CAPR wording to match the implemented corrective actions. The licensee documented this weakness in condition reports CR-WF3-2024-05882 and CR-WF3-2024-05941.
Objective: Ensure that pending corrective action plans direct prompt and effective actions to address and preclude repetition of White performance issues.
The inspectors assessed the appropriateness and timeliness of the licensees planned corrective actions.
NRC Assessment: The inspectors concluded that this objective was Met. The licensee established four additional CAPRs described in the table below that address their failure to reinforce risk processes for critical equipment and ensure that personnel identify, evaluate, and take actions to effectively eliminate/mitigate reactor trips. When complete, the NRC plans to inspect and assess the planned CAPRs as described in the results section.
However, the inspectors identified a weakness associated with the planned effectiveness reviews for the CAPRs. The licensee took actions to modify the effectiveness reviews. This is documented as General Weakness 3.
16 a.
Planned Corrective Actions to Preclude Repetition The licensee had four open CAPRs associated with the root cause that addressed site behaviors, future modifications, and evaluations to eliminate the probable cause for the reactor trip caused by the lightning strike. The inspectors determined that the licensee had planned appropriate CAPRs to address the identified technical aspects of the root cause and the behavior aspects identified by the root cause evaluation.
Cause CAPR Root Cause Open CAPR 1: CR-WF3-2024-03099-00024 Action C: Teach (sustainability) Include the EN-OM-132 Nuclear Risk Management Process in initial and/or continuing training for First Line Supervisors and above to include specifics of elimination and mitigation of generation risk of critical equipment issues and conservative actions to mitigate risk if not well understood, expectations to challenge to risk identify and methods to mitigate in accordance with referenced procedures and processes. Include what risk management processes must be addressed for an indeterminate issue cause.
Intent is to provide a mechanism for ensuring generation risk processes are reinforced as a part of leadership job fundamentals.
Event 1: Relay failure Open CAPR 2: CR-WF3-2024-03099-00035 ESFAS SPV Elimination Modification Implement EC-54163913 to eliminate the SPV in the ESFAS system during RF26.
The intent of this action is to remove the SPV in the ESFAS system by implementing the changes specified in EC-54163913. This action aimed to enhancing the reliability and safety of the ESFAS system by eliminating potential failure points that could compromise the systems functionality in critical situations.
Event 3: Lightning strike Open CAPR 5: CR-WF3-2024-03099-00073 Based on the results of the ground grid study, CR-WF3-2024-03067 CA-10, perform a review of the causes and corrective actions and initiate a CAPR through preventive maintenance strategies to detect degradation, provide monitoring, and ensure reliability of the plant grounds. This action is also intended to update the effectiveness reviews incorporated into this root cause evaluation.
The intent of this action is to update this document with the result of CR-WF3-2024-03067 CA-10 and incorporate actions to prevent recurrence based on the findings by the vendor performed ground grid study and updating any actions needed based on the conclusions of the study.
17 Cause CAPR Event 1: Relay failure Open CAPR 6: CR-WF3-2024-03099-00084 Develop and Incorporate quality requirements for replacement MDR relays, in SPV applications, which will include electrical testing and visual inspections. Electrical checks of the relay coil inductance and resistance shall be performed before and after the burn-in period to ensure that the manufacturers defect is detected prior to installation. The resistance and inductance values should be as follows:
Resistance: 42 Ohms (+/- 10%)
Inductance: 0.850 Henries (+/- 10%)
The intent of this action is to ensure that a faulty relay is not introduced into the plant which could result in another plant scram.
b.
Other Planned Corrective Actions The inspectors reviewed a sample of the other planned corrective actions (non-CAPRs) for each cause to determine the appropriateness and timeliness of the corrective actions to correct each cause documented in condition report CR-WF3-2024-03099. The inspectors did not have any concerns with the planned corrective actions.
Cause Corrective Action Root Cause The licensee planned additional actions to develop and set expected leadership behaviors using risk information; actions to measure implementation effectiveness; actions to evaluate whether best practices incorporated into plant processes; and, based on the results of the ground grid study, evaluate critical equipment affected by electrical ground grid disturbances and initiate condition reports to address vulnerabilities and track actions until resolved.
Contributing Cause 1 The licensee planned additional actions to reinforce corrective action program and risk behavior to other departments including security, training, performance improvement, and regulatory assurance.
Contributing Cause 2 The licensee planned additional actions to update the vendor service agreement for large transformers.
Contributing Cause 3 The licensee planned additional actions to develop training for electrical maintenance and engineering for vendor oversight.
Implement an outage oversight plan to evaluate for any gaps during implementation.
General Weakness 3 The inspectors evaluated the effectiveness reviews for the identified CAPRs. The licensee specified the guidance for conducting effectiveness reviews in Procedures JA-PI-01, Analysis Manual, revision 18, and EN-LI-118, Causal Analysis Process, revision 38. The inspectors determined that the licensee had not specified effectiveness reviews that implemented the guidance in their procedures. For example, the inspectors noted that the success criteria for many of the effectiveness reviews consisted of reviewing whether any
18 additional trips had occurred because of ineffective action and did not have criteria for monitoring success of the actions being implemented. However, Procedure JA-PI-01 specifies that effectiveness review success criteria should not be a verification of the absence of events.
In addition, the licensee designed two of the effectiveness reviews to be completed after 6 months following the CAPR action being implemented. The inspectors questioned whether the 6-month period provided sufficient time and opportunities to identify effectiveness of the CAPRs. The licensee designed the effectiveness reviews as observations for inadequate behaviors during scheduled meetings and working groups. After discussing the trip criteria and timing criteria concerns with the licensee, the licensee revised the effectiveness reviews during the inspection. The revised effectiveness review criteria expanded the evaluation time and changed the criteria to reflect the absence of the inadequate behaviors instead of the absence of consequential events. The inspectors reviewed the changes and did not have any additional concerns with the revised effectiveness reviews. The licensee documented this weakness in CR-WF3-2024-05839.
Conclusion Overall, the inspectors determined that the licensees problem identification, causal analyses, and corrective actions sufficiently addressed the performance issues that led to the White performance indicator for Unplanned Scrams per 7000 Critical Hours. All inspection objectives, as listed in IP 95001, were met and this inspection is therefore closed.
Open items such as CAPRs will be inspected as part of the ongoing NRC baseline inspection program.
INSPECTION RESULTS Failure to Take Corrective Actions for Defective Relays Cornerstone Significance Cross-Cutting Aspect Report Section Initiating Events Green NCV 05000382/2024040-01 Open/Closed
[H.12] - Avoid Complacency 71153 The inspectors identified a Green finding and associated non-cited violation of 10 CFR 50, Appendix B, Criterion XVI, Corrective Action, when the licensee failed to take prompt corrective actions for a manufacturing defect in safety-related relays, a condition adverse to quality. The failure to take adequate corrective actions led to a reactor trip. Furthermore, the inspectors identified other relays subject to the same potential defect that did not have any corrective actions assigned.
==
Description:==
The inspectors reviewed the causes of a reactor trip that occurred on March 16, 2024. Operators manually inserted the trip after a spurious closure of the steam generator 2 main feedwater and main steam isolation valves, which was caused by the failure of a safety-related relay. The licensee identified that a manufacturing defect was present in the relay that caused overheating of the connection of the coil winding to the lead wire leading to an early failure of the relay. The licensee procured the relays from a third-party dedicating entity who in turn procured them from a commercial vendor.
This same manufacturing defect was also present in a relay that resulted in an earlier trip on June 24, 2022. The licensee reviewed their corrective actions from 2022 and identified that
19 they had missed two corrective actions that could have either identified the failed relay or prevented it from causing a trip.
The licensee had previously planned a modification that would eliminate the relay as a single point vulnerability for trip risk. This modification was developed prior to the 2022 event and planned for implementation at the next opportunity in the fall 2023. However, in 2023, prior to implementation of the modification, the licensee discovered several inadequacies that led them to postpone the modification until 2025. As a result, the single point vulnerability remained present when the relay failed in March 2024.
The licensee also identified after the 2024 trip that an additional action had been planned but never taken. This action was to review and update the bridging strategy to ensure that appropriate mitigating actions for the relays could be taken until the modification was in place.
The licensee failed to complete this action, and this failure was not identified until the second reactor trip. The inspectors determined that this action could have resulted in additional testing or compensatory actions that could have prevented the second relay from failing. This aspect of the violation was self-revealed.
Finally, the inspectors reviewed the corrective actions developed by the licensee after the second failure in 2024. After that failure, the licensee implemented additional testing to identify defective relays. They tested all relays considered single point vulnerabilities as well as the remaining relays in the warehouse. As a result, they identified an additional relay associated with the steam generator 1 isolation circuit that exhibited signs of having the same or similar defect. Additionally, they took actions to perform this testing as part of their preventive maintenance strategy.
The inspectors questioned why these additional corrective actions were not planned for the population of safety-related relays that were not grouped into the single point vulnerability category. The inspectors determined that, based on the available information, the potential defect could be present in the remaining relays and was a condition adverse to quality for which the licensee did not have any corrective actions in place. This aspect of the violation was NRC identified.
Corrective Actions: The licensee has implemented testing and removed some defective relays from the plant. Actions to perform testing on the remaining relays have been entered into the corrective action program.
Corrective Action References: CR-WF-2024-05894 Performance Assessment:
Performance Deficiency: The failure to take prompt corrective action to correct a condition adverse to quality affecting safety-related relays is a performance deficiency. Specifically, the licensee failed to implement a planned modification or take mitigating actions to address manufacturing defects that resulted in a reactor trip.
Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to take corrective actions led to another failed relay that resulted in an additional reactor trip.
20 Significance: The inspectors assessed the significance of the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using exhibit 1, Initiating Events Screening Questions, the inspectors determined the finding required a detailed risk evaluation because the finding caused both a reactor trip and the loss of mitigation equipment relied upon to transition the plant to a stable shutdown condition.
Specifically, the finding caused a loss of main feedwater to one steam generator.
A senior reactor analyst performed the detailed risk evaluation and determined the incremental conditional core damage probability (CCDP) to be 3.8E-7, or of very low safety significance (Green). The analyst used a modified version of the Waterford SPAR model, revision 8.81, run on SAPHIRE, version 8.2.11, to perform initiating events analysis to estimate the CCDP of the reactor trip. The analyst modified the model to: (1) correct a modeling error in the loss of seal cooling modeling, which was erroneously flagging the occurrence of a reactor coolant pump seal loss of coolant accident if train A of the auxiliary component cooling water system was unavailable for reactor trips; (2) remove switchgear room cooling dependency for offsite power to the 4160 V engineered safety features electrical buses after the licensee demonstrated that the temperature in the switchgear rooms would not exceed temperatures typically associated with electrical equipment failures; (3) adjust the human error probability for the failure to align the permanent temporary emergency diesel to reflect the newer diesel generator alignment adopted by the station; and (4) add common cause failures of the equipment affected by the relay failure.
The analyst modeled the event as a transient with main feedwater isolation valve B and main steam isolation valve B closed, along with an increased failure rate of 6.67E-1 of the remaining main feedwater and main steam isolation valves. The analyst also assumed that the failure of main feedwater pump A was caused by the event and included it in the results.
Per initiating events analyses methodologies, the analyst then subtracted out the core damage probability, obtained from applying the nominal reactor trip (or TRANSIENT) frequency of 5.18E-1/year and the valve failure probabilities to their nominal failure probabilities, which yielded an incremental CCDP of 3.8E-7. Dominant sequences were transients that were further challenged by failures of safety relief valves and high-pressure recirculation. The CCDP was mitigated because the main feedwater and condenser remained available. The analyst used IMC 0609, Appendix H, Containment Integrity Significance Determination Process, to determine that the performance deficiency when evaluated for incremental conditional large early release probability would be of very low safety significance. Because of the unlikely occurrence of a simultaneous external event, the increase in incremental conditional CCDP from external events was qualitatively considered to be negligible.
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, the licensee failed to recognize the inherent risk of not taking additional actions to ensure the presence of manufacturing defects in the relays did not cause unexpected failures and actuations of plant equipment.
Enforcement:
Violation: Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, the licensee take prompt corrective actions for a condition adverse to quality.
21 Contrary to the above, from June 2022 to December 13, 2024, the licensee failed to take prompt corrective action for a condition adverse to quality. Specifically, between June 2022 and March 2024, the licensee failed to correct a defect in safety-related relays installed in systems classified as single point vulnerabilities, and from March 2024 to December 13, 2024, they failed to correct the same defect in other safety-related relays.
Enforcement Action: This violation is being treated as a non-cited violation, consistent with section 2.3.2 of the Enforcement Policy.
LER (Discussed)
LER 2024-004-00 for Waterford Steam Electric Station, Unit 3, Automatic Reactor Trip Due to Lightning Strike LER 05000382/2024-004-00 71153
==
Description:==
At 12:33 p.m. CDT, on June 16, 2024, while in Mode 1 at approximately 100 percent power an automatic trip occurred because reactor protection system because of channels B and D core protection calculator auxiliary trip signals. The auxiliary trip signals resulted from both an asymmetrical steam generator transient (ASGT) and a variable overpower trip (VOPT). The analysis of the event concluded that the likely cause of the plant trip resulted when multiple lightning strikes introduced a voltage transient to instrumentation that provides input to core protection calculator channels B and D.
The inspectors reviewed the apparent cause analysis documented in condition report CR-WF3-2024-03097 and associated evaluations in the root cause evaluation documented in condition report CR-WF3-2024-03099. The inspectors determined that the licensee had performed a detailed review and identified the most probable cause and causal factors. The inspectors identified no concerns with the licensee analysis, corrective actions taken, and planned corrective actions. The licensee established actions to evaluate their grounding grid during refueling outage RF26 in April 2025. Based upon this study, the licensee plans to develop additional corrective actions.
As documented in CR-WF3-2024-04132, the licensee isolated core protection channel B because the channel tripped on August 17, 2024, when a lightning strike occurred.
In addition, the licensee established a corrective action to adjust the time delay for core protection calculator auxiliary trips. The vendor for the core protection calculator system was analyzing the system to identify the amount of additional delay for the auxiliary trip inputs and would produce a safety analysis to support the time delay. The corrective actions are planned to be completed by the end of 2026.
This LER will remain open pending further review.
CAPR (Closed)
Waterford 95001 CAPR CR-WF3-2024-03099-00040 Revise Procedures to Incorporate Industry OE for Transformers CAPR 05000382/2024040-02 95001
==
Description:==
This CAPR was:
Revise ME-004-(051, 052, 061, 071) to implement recommendations from SOER 02-3, Large Power Transformers Reliability; SOER 10-1, Large Power Transformer Reliability; IER 21-04; Recommendation 7 - Vendor Oversight, and Industry OE.
22 Intent of this action is to ensure industry lessons learned are incorporated in the site procedures.
This CAPR was completed at the time of the inspection and the inspectors reviewed the CAPR implementation. The inspectors verified that the changes to the procedures incorporated the recommendations of the operating experience and confirmed that the licensee referenced the operating experience in the procedures. The inspectors identified a general weakness because the approved corrective action to preclude repetition did not accurately reflect the procedure changes implemented. After the licensee corrected the description of the corrective action, the inspectors determined that licensee had satisfactorily implemented the corrective action to preclude repetition.
This CAPR is closed.
CAPR (Discussed)
Waterford 95001 CAPR CR-WF3-2024-03099-00024 Ensure Generation Risk Processes are Reinforced as a Part of Leadership Job Fundamentals.
CAPR 05000382/2024040-03 95001
==
Description:==
This CAPR is:
Action C: Teach (sustainability) Include the EN-OM-132 Nuclear Risk Management Process in initial and/or continuing training for First Line Supervisors and above to include specifics of elimination and mitigation of generation risk of critical equipment issues and conservative actions to mitigate risk if not well understood, expectations to challenge to risk identify and methods to mitigate in accordance with referenced procedures and processes.
Include what risk management processes must be addressed for an indeterminate issue cause.
Intent is to provide a mechanism for ensuring generation risk processes are reinforced as a part of leadership job fundamentals.
The inspectors reviewed the plan for implementation of this CAPR and determined that the licensee established an acceptable plan. The licensee was tracking this CAPR in their corrective action program as CR-WF3-2024-03099-00024 and planned to implement this CAPR by January 23, 2025.
This CAPR will remain open pending further review.
CAPR (Discussed)
Waterford 95001 CAPR CR-WF3-2024-03099-00035 Implement EC-54163913 to eliminate the SPV in the ESFAS system CAPR 05000382/2024040-04 95001
==
Description:==
This CAPR is:
ESFAS SPV Elimination Modification Implement EC-54163913 to eliminate the SPV in the ESFAS system during RF26.
The intent of this action is to remove the SPV in the ESFAS system by implementing the changes specified in EC-54163913. This action aimed to enhancing the reliability and safety
23 of the ESFAS system by eliminating potential failure points that could compromise the systems functionality in critical situations.
The inspectors reviewed the plan for implementation of this CAPR and determined that the licensee established an acceptable plan. The licensee was tracking this CAPR in their corrective action program as CR-WF3-2024-03099-00035 and planned to implement this CAPR by June 10, 2025.
The inspectors did not review the technical adequacy of the modification itself or verify the planned modification would comply with regulatory requirements. Future reviews by inspectors after the modification is implemented should assess whether the final configuration would preclude repetition of the event, while also maintaining compliance with all applicable regulatory requirements.
This CAPR will remain open pending further review.
CAPR (Discussed)
Waterford 95001 CAPR CR-WF3-2024-03099-00073 Incorporate Actions to Prevent Recurrence Based on the Findings by the Vendor Performed Ground Grid Study CAPR 05000382/2024040-05 95001
==
Description:==
This CAPR is:
Based on the results of the ground grid study, CR-WF3-2024-03067 CA-10, perform a review of the causes and corrective actions and initiate a CAPR through preventive maintenance strategies to detect degradation, provide monitoring, and ensure reliability of the plant grounds. This action is also intended to update the effectiveness reviews incorporated into this RCE.
The intent of this action is to update this document with the result of CR-WF3-2024-03067 CA-10 and incorporate actions to prevent recurrence based on the findings by the vendor performed ground grid study and updating any actions needed based on the conclusions of the study.
The inspectors reviewed the plan for implementation of this CAPR and determined that the licensees plan was acceptable. The licensee was tracking this CAPR in their corrective action program as CR-WF3-2024-03099-00073 and planned to implement this CAPR by February 15, 2025.
The licensee established condition report CR-W3-2024-03099, CA 81 to track performing a future extent of cause after completing the grounding study, which specified perform a review of affected critical equipment which could be susceptible evaluate and address, as necessary. Since the ground grid study would likely result in additional actions, future inspectors should review the actions taken for CA 81 and any yet to be determined corrective actions specified by the licensee.
This CAPR will remain open pending further review.
24 CAPR (Closed)
Waterford 95001 CAPR CR-WF3-2024-03099-00043 Develop and Implement Acceptance Criteria for Maintenance Procedures CAPR 05000382/2024040-06 95001
==
Description:==
This CAPR was:
Develop and implement acceptance criteria in ME-004-(051, 052, 061, 071). Also, include steps to initiate a CR and contact System Engineering for any values approaching acceptance criteria, outside of acceptable limits, and suspect indications. Include the actual nameplate data in the associated procedure steps.
Intent of this action is to update procedure guidance in ME-004-(051, 052, 061, 071) to ensure acceptance criteria is defined and CR initiation steps are included. Engineering is to be contacted for any challenges with test results to identify degradation with transformer health.
A self-revealed Green finding was issued in NRC Inspection Report 05000382/2024003 (FIN 05000382/2024003-02) because the procedures did not contain testing instructions to appropriately identify degraded conditions prior to failure.
This CAPR was completed at the time of the inspection and the inspectors reviewed the CAPR implementation. The inspectors identified a general weakness because the approved corrective action to preclude repetition did not accurately reflect the procedure changes implemented. After the licensee corrected the description of the corrective action, the inspectors determined that licensee had satisfactorily implemented the corrective action to preclude repetition.
This CAPR is closed.
CAPR (Discussed)
Waterford 95001 CAPR CR-WF3-2024-03099-00084 Develop and Incorporate Quality Requirements for Replacement Relays CAPR 05000382/2024040-07 95001
==
Description:==
This CAPR is:
Develop and Incorporate quality requirements for replacement MDR relays, in SPV applications, which will include electrical testing and visual inspections. Electrical checks of the relay coil inductance and resistance shall be performed before and after the burn-in period to ensure that the manufacturers defect is detected prior to installation. The resistance and inductance values should be as follows:
1.
Resistance: 42 Ohms (+/- 10%)
2.
Inductance: 0.850 Henries (+/- 10%)
The intent of this action is to ensure that a faulty relay is not introduced into the plant which could result in another plant scram.
The inspectors reviewed the plan for implementation of this CAPR and determined that the licensees established an acceptable plan. The licensee was tracking this CAPR in their corrective action program as CR-WF3-2024-03099-00084 and had planned to implement this CAPR by January 15, 2025, at the time of the onsite inspection.
25 The inspectors did not assess the technical adequacy of the testing or verify whether the licensee had appropriately incorporated it into procurement specifications and testing. Future reviews by inspectors after completion of these efforts should ensure that the revised procurement standard effectively addresses the manufacturing defects.
This CAPR will remain open pending further review.
EXIT MEETINGS AND DEBRIEFS The inspectors verified no proprietary information was retained or documented in this report.
On December 13, 2024, the inspectors presented the 95001 supplemental inspection results to Joseph Sullivan, Site Vice President, and other members of the licensee staff.
26 DOCUMENTS REVIEWED Inspection Procedure Type Designation Description or Title Revision or Date Corrective Action Documents CR-WF3-2006-02204, 2010-01187, 2018-02341, 2022-04908, 2023-15383, 2023-16189, 2023-17005, 2023-17094, 2024-01460, 2024-01597, 2024-01609, 2024-01731, 2024-03067, 2024-03099, 2024-03910, 2024-04019, 2024-04074, 2024-04132, 2024-04377, 2024-04960, 2024-05058, 2024-05213 Corrective Action Documents Resulting from Inspection CR-WF3-2024-05773, 2024-05833, 2024-05839, 2024-05840, 2024-05842, 2024-05878, 2024-05879, 2024-05880, 2024-05882, 2024-05884, 2024-05894, 2024-05941 Engineering Changes 54163193 ESFAS Single Point Vulnerability Elimination 0
JA-PI-01 Analysis Manual 18 LCM WF3 0095 Core Protection Calculator (CPC) Auxiliary Trip Time Delay LO-WF3-2024-00069 Effectiveness Review for CR-WF3-2024-03099 NA LO-WF3-2024-00070 2nd Effectiveness Review for CR-WF3-2024-03099 NA LO-WF3-2024-00085 Effectiveness Review for CR-WF3-2024-03099 - Event 1 NA LO-WF3-2024-00086 Effectiveness Review for CR-WF3-2024-03099 - Event 2 NA LO-WF3-2024-00087 Effectiveness Review for CR-WF3-2024-03099 - Event 3 NA LTR-CDMP-24-26 (PROP)
Responses to Entergy Regarding Westinghouse Corrective Action Program IR-2024-6286 0
Miscellaneous QC-00149136 MDR7034 Qualification Test Plan 12/03/2019 CEP-SG-001 Steam Generator Primary Side Examinations and Maintenance 8
EN-DC-115 Engineering Change Process 32, 33 EN-DC-144 System Health Management 4
95001 Procedures EN-DC-175 Single Point Vulnerability Review Process 12
27 Inspection Procedure Type Designation Description or Title Revision or Date EN-FAP-LI-001 Performance Improvement Review Group (PRG) Process 22 EN-LI-102 Corrective Action Program 52, 54 EN-LI-104 Self-Assessment and Benchmark Process 19 EN-LI-118 Causal Analysis Process 38 EN-OE-100 Operating Experience Program 36, 37 EN-OM-132 Nuclear Risk Management Process 3
EN-OP-104 Operability Determination Process 20 EN-WM-100 Work Order Generation, Screening and Classification 22 ME-004-051 Main Transformer B 313 ME-004-052 Main Transformer A 317 ME-004-061 Unit Auxiliary Transformer 313 ME-004-071 Startup Transformer 329 UNT-006-033 Technical Specifications Frequency List 12 Self-Assessments LO-WF3-2024-0075 Pre-Inspection Assessment Worksheet for IP 95001 Inspection 10/04/2024 Work Orders WO 54193032