IR 05000269/2025001
| ML25129A092 | |
| Person / Time | |
|---|---|
| Site: | Oconee  (DPR-038, DPR-047, DPR-055) |
| Issue date: | 05/13/2025 |
| From: | Robert Williams Division of Operating Reactors |
| To: | Snider S Duke Energy Carolinas |
| References | |
| IR 2025001 | |
| Download: ML25129A092 (1) | |
Text
SUBJECT:
OCONEE NUCLEAR STATION - INTEGRATED INSPECTION REPORT 05000269/2025001 AND 05000270/2025001 AND 05000287/2025001
Dear Steven Snider:
On March 31, 2025, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Oconee Nuclear Station. On May 1, 2025, the NRC inspectors discussed the results of this inspection with you and other members of your staff. The results of this inspection are documented in the enclosed report.
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 II; the Director, Office of Enforcement; and the NRC Resident Inspector at Oconee Nuclear Station.
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 May 12, 2025 Room in accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding.
Sincerely, Robert E. Williams, Jr., Chief Projects Branch 1 Division of Operating Reactor Safety Docket Nos. 05000269 and 05000270 and 05000287 License Nos. DPR-38 and DPR-47 and DPR-55
Enclosure:
As stated
Inspection Report
Docket Numbers:
05000269, 05000270 and 05000287
License Numbers:
Report Numbers:
05000269/2025001, 05000270/2025001 and 05000287/2025001
Enterprise Identifier:
I-2025-001-0028
Licensee:
Duke Energy Carolinas, LLC
Facility:
Oconee Nuclear Station
Location:
Seneca, South Carolina
Inspection Dates:
January 01, 2025 to March 31, 2025
Inspectors:
D. Dang, Resident Inspector
M. Meeks, Senior Operations Engineer
E. Robinson, Resident Inspector
C. Safouri, Senior Resident Inspector
K. Schaaf, Operations Engineer
N. Smalley, Senior Resident Inspector
D. Willis, Team Leader
Approved By:
Robert E. Williams, Jr., Chief
Projects Branch 1
Division of Operating Reactor Safety
SUMMARY
The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting an integrated inspection at Oconee Nuclear 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 Implement Post Maintenance Testing Procedures Appropriate to the Circumstances for the Standby Shutdown Facility Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green NCV 05000269/2025001-01 Open/Closed EAF-RII-2025-0058 None (NPP)71111.12 A self-revealed Green finding and associated non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, was identified when the licensee failed to implement post maintenance testing (PMT) procedures appropriate to the circumstances, which resulted in inoperability of the standby shutdown facility (SSF) for Unit 1. Following replacement of a pressurizer (PZR) heater control switch in July 2022, PMT procedures failed to identify a degraded condition which prevented PZR heaters from operating when required. This resulted in a violation of technical specification (TS) 3.10.1, Standby Shutdown Facility (SSF), and TS 3.0.4, Limiting Condition for Operation (LCO) Applicability.
Additional Tracking Items
Type Issue Number Title Report Section Status LER 05000269/2024-001-00 LER 2024-001-00 for Oconee Nuclear Station,
Unit 1, Standby Shutdown Facility (SSF) Pressurizer Level Switch Configuration Caused by Legacy Procedure Deficiency Resulted in Condition Prohibited by Technical Specifications 71153 Closed LER 05000270/2024-001-00 LER 2024-001-00 for Oconee Nuclear Station,
Unit 2, Common Cause Inoperability of Both Trains of Control Room Ventilation System Outside Air Booster Fans due to Supply Breaker Wiring Deficiency Resulted in a Condition that Could Have Prevented Fulfillment.
71153 Closed
PLANT STATUS
Unit 1 operated at or near 100 percent rated thermal power (RTP) for the entire inspection period.
Unit 2 operated at or near 100 percent RTP for the entire inspection period.
Unit 3 operated at or near 100 percent RTP for the entire inspection period.
INSPECTION SCOPES
Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with their attached revision histories are located on the public website at http://www.nrc.gov/reading-rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared complete when the IP requirements most appropriate to the inspection activity were met consistent with Inspection Manual Chapter (IMC) 2515, Light-Water Reactor Inspection Program - Operations Phase. The inspectors performed activities described in IMC 2515, Appendix D, Plant Status, observed risk significant activities, and completed on-site portions of IPs. 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.
REACTOR SAFETY
71111.01 - Adverse Weather Protection
Impending Severe Weather Sample (IP Section 03.02) (1 Sample)
- (1) The inspectors evaluated the adequacy of the overall preparations to protect risk significant systems from impending severe winter weather on January 10, 2025.
71111.04 - Equipment Alignment
Partial Walkdown Sample (IP Section 03.01) (3 Samples)
The inspectors evaluated system configurations during partial walkdowns of the following systems/trains:
(1)2A reactor building spray (RBS) train while 2B RBS out of service (OOS) for maintenance on February 11, 2025
- (2) Keowee Hydro Unit (KHU) #2 underground emergency power path with KHU #1 overhead OOS on February 18, 2025 (3)3A low pressure injection (LPI) train while 3B LPI was out of service for maintenance on March 5, 2025
71111.05 - Fire Protection
Fire Area Walkdown and Inspection Sample (IP Section 03.01) (5 Samples)
The inspectors evaluated the implementation of the fire protection program by conducting a walkdown and performing a review to verify program compliance, equipment functionality, material condition, and operational readiness of the following fire areas:
- (1) Fire zone 108: Unit 1 east penetration room on January 14, 2025
- (2) Fire zone 92: Unit 2 equipment room on February 10, 2025
- (3) Fire zone 101: Unit 3 cable room on February 10, 2025
- (4) Fire zone 90: Unit 2 auxiliary building 300 level hallway on February 25, 2025
- (5) Fire zone 34: Unit 1 4160V switchgear on March 4, 2025
Fire Brigade Drill Performance Sample (IP Section 03.02) (2 Samples)
- (1) The inspectors evaluated the onsite fire brigade training and performance during an unannounced fire drill on March 9, 2025.
- (2) The inspectors evaluated the onsite fire brigade training and performance during an unannounced fire drill on March 21, 2025.
71111.11B - Licensed Operator Requalification Program and Licensed Operator Performance
Licensed Operator Requalification Program (IP Section 03.04)
71111.11B - Licensed Operator Requalification Program and Licensed Operator
Performance
Licensed Operator Requalification Program (IP Section 03.04)
An inspection was performed to assess the effectiveness of the facility licensee in implementing requalification requirements identified in 10 CFR Part 55, Operators Licenses. Each of the following inspection activities was conducted in accordance with IP
===71111.11, Licensed Operator Requalification Program and Licensed Operator Performance.
Biennial Requalification Written Examinations The inspectors evaluated the quality of the licensed operator biennial requalification written examination administered on March 2025.
Annual Requalification Operating Tests The inspectors evaluated the adequacy of the facility licensees annual requalification operating test.
Administration of an Annual Requalification Operating Test The inspectors evaluated the effectiveness of the facility licensee in administering requalification operating tests required by 10 CFR 55.59(a)(2) and that the facility licensee is effectively evaluating their licensed operators for mastery of training objectives.
Requalification Examination Security The inspectors evaluated the ability of the facility licensee to safeguard examination material, such that the examination is not compromised.
Remedial Training and Re-examinations The inspectors evaluated the effectiveness of remedial training conducted by the licensee, and reviewed the adequacy of re-examinations for licensed operators who did not pass a required requalification examination.
Operator License Conditions The inspectors evaluated the licensees program for ensuring that licensed operators meet the conditions of their licenses.
Control Room Simulator The inspectors evaluated the adequacy of the facility licensees control room simulator in modeling the actual plant, and for meeting the requirements contained in 10 CFR 55.46.
71111.11Q - Licensed Operator Requalification Program and Licensed Operator Performance
Licensed Operator Performance in the Actual Plant/Main Control Room (IP Section 03.01) (1 Sample)
- (1) The inspectors observed and evaluated licensed operator performance in the control room during control rod movement testing, on February 24, 2025.
Licensed Operator Requalification Training/Examinations (IP Section 03.02)===
- (1) The inspectors observed and evaluated a simulator operator training exam in accordance with ASE-29 on March 4, 2025.
71111.12 - Maintenance Effectiveness
Maintenance Effectiveness (IP Section 03.01) (3 Samples)
The inspectors evaluated the effectiveness of maintenance to ensure the following structures, systems, and components (SSCs) remain capable of performing their intended function:
- (1) Nuclear condition report (NCR) 2534840, SSF PZR heater control circuit current switch incorrect configuration on November 8, 2024
- (2) NCR 02540577, review of grounds discovery and repair on unit 125V DC buses on January 14, 2025 and January 27, 2025
- (3) NCR 2546947, maintenance and restoration of train A chiller following trip during refrigerant evaluation testing on March 10, 2025
71111.13 - Maintenance Risk Assessments and Emergent Work Control
Risk Assessment and Management Sample (IP Section 03.01) (5 Samples)
The inspectors evaluated the accuracy and completeness of risk assessments for the following planned and emergent work activities to ensure configuration changes and appropriate work controls were addressed:
- (1) Unit 1 green risk following loss of load center 1XL, on November 2, 2024
- (2) Unit 1 elevated green risk due to 1C LPI motor test work, on February 5, 2025
- (3) Unit 3 elevated green risk due to preventive maintenance on SSF auxiliary service water (ASW) emergency Unit 3 steam generator (SG) supply valves, 3CCW-268 and 287, on February 11, 2025
- (4) Unit 2 elevated green risk due to maintenance on LPI, on the week of February 24, 2025
- (5) Unit 3 elevated green risk due to maintenance on LPI, on March 19, 2025
71111.15 - Operability Determinations and Functionality Assessments
Operability Determination or Functionality Assessment (IP Section 03.01) (6 Samples)
The inspectors evaluated the licensee's justifications and actions associated with the following operability determinations and functionality assessments:
- (1) NCR 2533121, stop check valve 1HP-254 stuck open
- (2) NCR 2541430, Unit 2 turbine driven emergency feedwater (TDEFW) pump test flow below required acceptance criteria on January 12, 2025
- (3) NCR 2541833, standby SSF battery did not meet minimum capacity during performance testing on January 26, 2024
- (5) NCR 2545420, KHU-1 and emergency power overhead path following transformer lockout restoration on February 26, 2025
- (6) NCR 2546711, nitrogen supply pressure for 1MS-93, TDEFW pump turbine steam admission valve, out of band on March 9, 2025
71111.24 - Testing and Maintenance of Equipment Important to Risk
The inspectors evaluated the following testing and maintenance activities to verify system operability and/or functionality:
Post-Maintenance Testing (PMT) (IP Section 03.01) (5 Samples)
- (1) PT/1/A/0251/001, "Low Pressure Service Water Pump Test," following motor replacement, on January 13, 2025
- (2) PT/1/A/0204/007, "1B Reactor Building Spray Pump Test," and train inspection following preventive maintenance, on January 15, 2025
- (3) PT/1/A/0202/011, "1C High Pressure Injection Pump Test," following preventive maintenance, on February 19, 2025
- (4) PT/0/A/0620/009, "Keowee Hydro Operation," following governor speed switch replacement, on February 21, 2025
- (5) PT/1/A/0600/012, "Unit 1 Turbine Driven Emergency Feedwater (TDEFW) Pump Test," following preventive maintenance, on February 27, 2025
Surveillance Testing (IP Section 03.01) (3 Samples)
- (1) PT/0/A/0620/016, "Keowee Hydro Emergency Start Test," on January 8, 2025
- (2) PT/0/A/0600/021, "Standby Shutdown Facility Diesel Generator Run," on January 14, 2025
- (3) PT/3/A/0204/007, "3B Reactor Building Spray Pump Test," on March 14, 2025
Inservice Testing (IST) (IP Section 03.01) (2 Samples)
- (1) PT/2/A/0600/13B, comprehensive test on 2B motor driven emergency feedwater pump, on January 27, 2025
- (2) PT/0/A/0400/005, "SSF Auxiliary Service Water Pump Test," on March 13, 2025
Reactor Coolant System Leakage Detection Testing (IP Section 03.01) (1 Sample)
- (1) PT/1/A/0600/010, increased unidentified reactor coolant leakage on Unit 1, during the week of February 21, 2025
Diverse and Flexible Coping Strategies (FLEX) Testing (IP Section 03.02) (1 Sample)
- (1) FLEX testing, on the week of January 6,
OTHER ACTIVITIES - BASELINE
===71151 - Performance Indicator Verification The inspectors verified licensee performance indicators submittals listed below:
IE01: Unplanned Scrams per 7000 Critical Hours Sample (IP Section 02.01)===
- (1) Unit 1 (January 1 through December 31, 2024)
- (2) Unit 2 (January 1 through December 31, 2024)
- (3) Unit 3 (January 1 through December 31, 2024)
IE03: Unplanned Power Changes per 7000 Critical Hours Sample (IP Section 02.02) (3 Samples)
- (1) Unit 1 (January 1 through December 31, 2024)
- (2) Unit 2 (January 1 through December 31, 2024)
- (3) Unit 3 (January 1 through December 31, 2024)
IE04: Unplanned Scrams with Complications (USwC) Sample (IP Section 02.03) (3 Samples)
- (1) Unit 1 (January 1 through December 31, 2024)
- (2) Unit 2 (January 1 through December 31, 2024)
- (3) Unit 3 (January 1 through December 31, 2024)
MS07: High Pressure Injection Systems (IP Section 02.06) (3 Samples)
- (1) Unit 1 (January 1 through December 31, 2024)
- (2) Unit 2 (January 1 through December 31, 2024)
- (3) Unit 3 (January 1 through December 31, 2024)
===71152A - Annual Follow-up Problem Identification and Resolution Annual Follow-up of Selected Issues (Section 03.03) (1 Partial)
The inspectors reviewed the licensees implementation of its corrective action program related to the following issues:
(1)
(Partial)
NRC inspectors assessed the Safety Conscious Work Environment (SCWE) within the Nuclear Supply Chain (NSC) department at Oconee Nuclear Station. The inspectors conducted interviews with all available staff in the department to assess the licensees environment for raising concerns, and to determine whether challenges existed to maintaining a SCWE.
71153 - Follow Up of Events and Notices of Enforcement Discretion Event Report (IP Section 03.02)===
The inspectors evaluated the following licensee event reports (LERs):
- (1) LER 05000269/2024-001-00, Standby Shutdown Facility (SSF) Pressurizer Level Switch Configuration Caused by Legacy Procedure Deficiency Resulted in Condition Prohibited by Technical Specifications (ADAMs Accession No. ML24354A337). The inspection conclusions associated with this LER are documented in this report under Inspection Results Section 71111.12. This LER is Closed.
- (2) LER 05000270/2024-001-00, Common Cause Inoperability of Both Trains of Control Room Ventilation System Outside Air Booster Fans due to Supply Breaker Wiring Deficiency Resulted in a Condition that Could Have Prevented Fulfillment of a Safety Function (ADAMs Accession No. ML24354A312). The inspectors determined that it was not reasonable to foresee or correct the cause discussed in the LER therefore no performance deficiency was identified. The inspectors did not identify a violation of NRC requirements. This LER is Closed.
INSPECTION RESULTS
Failure to Implement Post Maintenance Testing Procedures Appropriate to the Circumstances for the Standby Shutdown Facility Cornerstone Significance Cross-Cutting Aspect Report Section Mitigating Systems Green NCV 05000269/2025001-01 Open/Closed EAF-RII-1025-0058 None (NPP)71111.12 A self-revealed Green finding and associated non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, was identified when the licensee failed to implement PMT procedures appropriate to the circumstances, which resulted in inoperability of the SSF for Unit 1. Following replacement of a PZR heater control switch in July 2022, PMT procedures failed to identify a degraded condition which prevented PZR heaters from operating when required. This resulted in a violation of TS 3.10.1, Standby Shutdown Facility (SSF), and TS 3.0.4, Limiting Condition for Operation (LCO) Applicability.
Description:
The SSF is designed as a standby, manually activated system to provide additional defense-in-depth protection, by serving as a backup to existing safety systems.
The SSF is provided as an alternate means to achieve and maintain the reactor in Mode 3 with reactor coolant system (RCS) temperature greater than or equal to 525F following certain fire, flooding, security, and station blackout (SBO) events. This is accomplished by re-establishing and maintaining reactor coolant pump (RCP) seal cooling, assuring natural circulation and core cooling by maintaining the RCS filled to a sufficient level in the pressurizer, while maintaining sufficient secondary side cooling water, and maintaining the reactor subcritical. The main components of the SSF are the SSF auxiliary service water (ASW) system, SSF portable pumping system, SSF reactor coolant (RC) makeup system, SSF power system, and SSF instrumentation.
The SSF ASW system is used to provide adequate cooling to maintain single phase RCS natural circulation flow in Mode 3 with an average RCS temperature = 525F, unless the initiating event causes the unit to be driven to a lower temperature. In order to maintain single phase flow, an adequate number of Bank 2 Group B and Group C PZR heaters must be operable. These heaters are needed to compensate for ambient heat loss from the PZR. As long as the temperature in the PZR is maintained, RCS pressure will also be maintained. This will preclude hot leg voiding and ensure adequate natural circulation cooling. Since the PZR heaters powered from the SSF during an SSF event do not have their own TS action statement, the SSF ASW system is declared inoperable when those PZR heaters are non-functional. The resulting inoperability of the SSF ASW system does not render other SSF systems inoperable.
On November 7, 2024, Unit 1 was in Mode 5 for a planned refueling outage when a Unit 1 PZR heater group did not turn on during the routine performance of a power transfer test.
During this test, control of Bank 2 Group B and Group C PZR heaters is transferred from the main control room to the SSF control room and functionality is verified. When Bank 2 Group B PZR heaters did not turn on, troubleshooting revealed an issue with the 1RC-IS-0072 current switch (level switch) in the heater control logic circuit. Upon inspection, the configurable jumpers on the level switch did not match the required configuration. This resulted in a condition in which a downstream relay from the level switch, PZR heater permissive relay (GD), would only close in, and therefore allow heaters to be energized, when PZR level was below the low level setpoint of 85 inches. This is the opposite logic of what was desired based on the functionality of the GD permissive relay.
On July 19, 2022, the licensee replaced the Unit 1 SSF PZR level switch with an approved acceptable substitute with the same fit and function but better power supply. However, during the replacement activity, maintenance technicians noted differences in the model numbers between the old and new level switches. Additionally, the work order instructions and procedures were then noted to include vague and confusing steps that required the technicians to interpret drawings with the help of technical support to configure the jumpers.
The PMT calibration procedure IP/0/A/0370/002 C, Standby Shutdown Facility RC System Pressurizer Level and Pressurizer Pressure, was also used to set the jumpers to match the contact status via the calibration data sheet in the procedure. Work was completed and signed off by a quality control (QC) representative. The PMT calibration procedure was performed, and acceptance criteria were met. The licensee later determined that the card was installed with the improper configuration at this time.
The licensees causal investigation determined that a legacy error existed in the calibration data sheet for the level switch in procedure IP/0/A/0370/002 C. This procedure was written prior to 1999 and had not been used for this application before. No other units level switch had been replaced using this procedure. Acceptance criteria for the procedure utilized in IP/0/A/0370/002 C for the PMT listed a certain contact as close on PZR low level, which is the opposite logic that is needed functionally (open). The acceptance criteria were incorrect as written, but were met during the PMT, and therefore were documented as satisfactory.
Due to the plant configuration in July 2022 (Unit 1 was in Mode 1), the designated PMT did not identify the incorrectly configured level switch, and the system was returned to service.
The power transfer test conducted in November 2024, which is only performed during unit outages, energizes the downstream PZR permissive relay GD during the procedure and would have identified the incorrectly configured level switch. The function of controlling PZR heaters from the SSF is not tested by any other routine TS surveillance. This issue does not meet the criteria for an old design issue as described by the NRC Enforcement Policy.
Corrective Actions: The licensee corrected the jumper configuration for the affected level switch on Unit 1, completed an extent of condition review of Units 2 and 3, and revised the post maintenance test procedure to correct the acceptance criteria and improve procedure directions.
Corrective Action References: 253480, 2534824
Performance Assessment:
Performance Deficiency: The licensees failure to implement post maintenance testing using procedures appropriate to the circumstances following the replacement of the Unit 1 SSF PZR level switch was a performance deficiency (PD). Specifically, in July 2022, following replacement of the Unit 1 SSF PZR level switch, post maintenance testing did not identify that the level switch was configured such that the PZR heaters controlled by the SSF would not energize until PZR level was below 85 inches, instead of preventing operation at or below 85 inches.
Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Configuration Control 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 PD resulted in the unavailability of normal pressurizer heater function and control from the SSF for over two years. The PD is also similar to example 5.b in IMC 0612 Appendix E, Examples of Minor Issues.
Significance: The inspectors assessed the significance of the finding using IMC 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The condition was screened using IMC 0609 Appendix A, The Significance Determination Process for Findings At-Power," and IMC 0609 Appendix F, Fire Protection Significance Determination Process. IMC 0609 Appendix A, Exhibit 2, question A2 and/or A3, can both be answered YES since the equipment was unable to perform its Probabilistic Risk Assessment (PRA) function for greater than the TS allowed outage time. Therefore, this issue screened to requiring performance of a detailed risk assessment. From IMC 0609 Appendix F, questions 1.4.7 A and B were answered NO, question 1.4.7 C was answered YES, and question 1.5.1 was answered NO since the condition was not modeled. Therefore, a Phase II evaluation was required.
A regional senior reactor analyst (SRA) conducted a detailed risk assessment for this condition. The SRA identified that neither the NRCs Standardized Plant Analysis Risk (SPAR) model nor Dukes Computer Aided Faulty Tree Analysis (CAFTA) model, appropriately modelled the standby shutdown facility powered pressurizer heaters (SSF PZR HTRs). The SSF PZR HTRs were required in order to overcome ambient losses from the pressurizer and maintain subcooling margin in the RCS, ensuring that single phase flow was maintained. When SSF PZR HTRs were unavailable, the SSF auxiliary service water system was considered inoperable per the plants technical specification basis. However, due to plant modifications such as installation of the protected service water system and a reconfiguration of the SSF RCS letdown line, the condition could no longer be accurately modelled using loss of SSF auxiliary service water as a surrogate and no other modeling tools were available.
Due to this fact the SRA used NRC Inspection Manual Chapter 0609 Appendix M, Significance Determination Process Using Qualitative Criteria, to perform this risk assessment. A Planning Significance and Enforcement Review Panel (SERP) was conducted on February 28, 2025, to approve this approach. The dominant accident sequence was a large fire in the turbine building resulting in loss of onsite and emergency power (station blackout) and failure of the protected service water system. The full risk assessment can be found in Attachment A of this report. Plant risk was determined to be of very low safety significance (Green).
Cross-Cutting Aspect: Not Present Performance. No cross-cutting aspect was assigned to this finding because the inspectors determined the finding did not reflect present licensee performance.
Enforcement:
Violation: 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings,"
states, in part, that activities affecting quality shall be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and shall be accomplished in accordance with these instructions, procedures, or drawings.
Licensee procedure IP/0/A/0370/002 C, Standby Shutdown Facility RC System Pressurizer Level and Pressurizer Pressure, was used to replace and test the Unit 1 SSF PZR level switch, a safety-related component that supports operability of the SSF ASW system.
Oconee Technical Specification LCO 3.10.1 requires, in part, that the SSF Instrumentation and the SSF Auxiliary Service Water System shall be OPERABLE in Modes 1, 2, and 3. TS 3.10.1, Condition A, requires the SSF ASW system to be restored to OPERABLE within 7 days. If Condition A is not met for reasons other than maintenance, Condition G requires the plant must be in Mode 3 within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> and Mode 4 within 84 hours9.722222e-4 days <br />0.0233 hours <br />1.388889e-4 weeks <br />3.1962e-5 months <br />.
Oconee Technical Specification 3.0.4 requires, in part, "When an LCO is not met, entry into a mode or other specified condition in the applicability shall only be made: a. When the associated actions to be entered permit continued operation in the mode or other specified condition in the applicability for an unlimited period of time.
Contrary to the above, on July 19, 2022, the licensee failed to prescribe an activity affecting quality by documented instructions or procedures appropriate to the circumstances.
Specifically, the post maintenance testing procedure for replacing the Unit 1 SSF PZR level switch, IP/0/A/0370/002 C, did not contain appropriate identify that a level switch in the pressurizer heater control logic circuit was configured incorrectly during maintenanceance.
As a result, the SSF ASW system was rendered inoperable on Unit 1 from July 19, 2022, until November 8, 2024, while in Modes 1, 2, and 3. With the SSF ASW system in inoperable status, the licensee failed to perform the required actions specified in TS 3.10.1, Conditions A and G, within the allowable completion times, and meet the mode entry requirements in TS 3.0.4 when Unit 1 entered Mode 3 on November 21, 2022, following a planned refueling outage.
Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.
Assessment 71152A SCWE Assessment of Oconee Nuclear Station Nuclear Supply Chain Department:
Based on interviews with Oconee Nuclear Supply Chain staff/managers and reviews of the latest safety culture survey results, the team did not identify any concerns with the safety-conscious work environment. The majority of employees interviewed appeared willing to raise nuclear safety concerns through multiple avenues. Most interviewees were aware of the licensee's employee concerns program and stated they would use the program, if necessary.
EXIT MEETINGS AND DEBRIEFS
The inspectors verified that no proprietary information was retained or documented in this report.
- On May 1, 2025, the inspectors presented the integrated inspection results to Steven Snider and other members of the licensee staff.
- On March 20, 2025, the inspectors presented the operator requalification inspection results to Steven Snider and other members of the licensee staff.
DOCUMENTS REVIEWED
Inspection
Procedure
Type
Designation
Description or Title
Revision
or Date
Corrective
Action
Documents
2500888
Miscellaneous
Risk Profiles for Units 1, 2,
and 3 for the week of
January 6, 2025
Procedures
AD-OP-ONS-
20
Severe Weather
Preparations
001
Drawings
OFD-102A-2.1
Flow Diagram of Low
Pressure Injection System
Borated Water Supply and
LPI Pump Suction
Drawings
OFD-103A-2.1
Flow Diagram of Reactor
Building Spray System (BS)
Miscellaneous
Clearance PRT-0-25-K1
OVH OOS-0048
Miscellaneous
OSS-0254.00-00-
1034
(MECH) Design Basis for the
Reactor Bldg Spray System
Miscellaneous
OSS-0254.00-00-
2005
(ELECT) Keowee Emergency
Power Design Basis
Document
Procedures
AD-OP-ALL-0201
Protected Equipment
Work Orders
20693858
Calculations
OSC-9314
NFPA 805 Transition Risk-
Informed Performance-Based
Fire Risk Evaluation
006
Corrective
Action
Documents
2539605, 02538783
Fire Plans
CSD-ONS-PFP-
Pre-Fire Plan for U1 Auxiliary
Building Elevation 796
001
Fire Plans
CSD-ONS-PFP-
Pre-Fire Plan For U1
Auxiliary Building Elevation
809
Fire Plans
CSD-ONS-PFP-
Pre-Fire Plan for U1 Turbine
Building Elevation 796
Fire Plans
CSD-ONS-PFP-
Pre-Fire Plan for U2 Auxiliary
Building Elevation 796
2
Fire Plans
CSD-ONS-PFP-
Pre-Fire Plan for U2 Turbine
Building Elevation 775
Fire Plans
CSD-ONS-PFP-
Pre-Fire Plan for U3 Auxiliary
Building Elevation 809
Miscellaneous
O-0310-FZ-028
Turbine Building - Unit 1 Fire
Protection Plan Fire Area and
Fire Zone Boundaries Plan at
Mezzanine EL 796+6
Inspection
Procedure
Type
Designation
Description or Title
Revision
or Date
Miscellaneous
O-0310-K-008
Auxiliary Building & Reactor
Building - Unit 2 Fire
Protection Plan & Fire
Barrier, Flood & Pressure
Boundaries Plan at EL 796+6
& EL 797+6
Miscellaneous
O-0310-K-012
Auxiliary Building - Unit 3
Fire Protection Plan & Fire
Barrier, Flood & Pressure
Boundaries Plan at EL 809+3
Miscellaneous
O-0310-L-002
Turbine Building - Unit 2 Fire
Protection Plan and Fire
Barriers, Flood, and Pressure
Boundaries Plan at EL 775+0
Miscellaneous
O-0310-L-004
Turbine Building - Unit 1 Fire
Protection Plan and Fire
Barrier, Flood, and Pressure
Boundaries Plan at
Mezzanine EL 796+6
Procedures
AD-OP-ALL-0207
Fire Brigade Administrative
Controls
007
Procedures
AP/0/A/1700/025
Standby Shutdown Facility
Emergency Operating
Procedure
070
Procedures
AP/0/A/1700/0403
Fire Brigade Response
Procedure
2
Procedures
AP/2/A/1700/050
Challenging Plant Fire
006
Work Orders
280757
Miscellaneous
ASE-29
Simulator Exercise Guide
Miscellaneous
CSD-EP-ONS-
0101-02
Oconee Nuclear Station
Classification of Emergency
004
Procedures
AD-OP-ALL-0103
Standards for Operations
Continuous Performance
Improvement
011
Procedures
PT/2/A/0600/015
Control Rod Movement
2
Corrective
Action
Documents
2534840, 2540577, 2534607,
2546947, 2546757, 2547209
Drawings
OEE-149-01
Pressurizer Heaters
Arrangement & Legend
Drawings
OEE-149-12
Elementary Diagram SSF
Press. HTR Group C Bank 2
Drawings
OEE-149-8
Elementary Diagram SSF
Press. HTR Group B Bank 2
Drawings
OEE-163-16B
Elementary Diagram Standby
Shutdown Facility Control
Transfer
Drawings
OEE-163-18
Elementary Diagram SSF
Inspection
Procedure
Type
Designation
Description or Title
Revision
or Date
Transducer Power and
Metering
Drawings
OM 201.0009.001
Unit 1 Pressurizer General
Arrangement
D17
Miscellaneous
OSC-3144
Pressurizer Heat Losses
Miscellaneous
OSS-0254.00-00-
1033
(MECH) Design Basis
Specification for Reactor
Coolant System
058
Procedures
AD-EG-ALL-1103
Procurement Engineering
Products
Procedures
AD-EG-ALL-1137
Engineering Change Product
Selection
Procedures
AD-EG-ALL-1155
Post Modification Testing
008
Procedures
AD-EG-ALL-1311
Failure Investigation Process
(FIP)
Procedures
AD-MN-ALL-1000
Conduct of Maintenance
Procedures
AP/0/A/1700/025
Standby Shutdown Facility
Emergency Operating
Procedure
070
Procedures
IP/0/A/0370/002
C
Standby Shutdown Facility
RC System Pressurizer Level
and Pressurizer Pressure
075
Procedures
IP/0/B/0200/037
C
Pressurizer Ambient Heat
Loss Test
2
Procedures
OP/0/A/1107/008
Isolation of DC Systems
Between Units
016
Procedures
PT/1/A/0600/024
SSF Comprehensive Control
Transfer Verification
24
Work Orders
281743, 20705003,
20421049
Corrective
Action
Documents
2533997, 2548087
Drawings
O-0703-D
One Line Diagram Station
Auxiliary Circuits 600V/208V/
L/C 1X5 & MCC 1XH, 1XK,
1XL & 1XT
066
Drawings
O-0703-E
One Line Diagram Station
Auxiliary Circuits 600V/208V
L/C 1X6 & MCC 1XI, 1XN,
1XP & 1XQ
077
Drawings
OFD-102A-3.1
Flow Diagram of Low
Pressure Injection System
(Borated Water Supply and
LPI Pump Suction)
Drawings
OFD-102A-3.2
Flow Diagram of Low
Pressure Injection System
(LPI Pump Discharge)
Inspection
Procedure
Type
Designation
Description or Title
Revision
or Date
Miscellaneous
Clearance PRT-3-25-3A
LPIP OOS-0056
Miscellaneous
Risk Profile for Unit 1 for the
week of February 5th
Miscellaneous
Defense-in-Depth Status
Sheet for November 1, 2024,
at 1600
Miscellaneous
Defense-in-Depth Status
Sheet for November 2, 2024,
at 0400
Miscellaneous
Risk Profile for Unit 3 for the
week of March 17th, 2025
Miscellaneous
Clearance OPS-3-23-LPI-3A
LPIP DRN-1215
Miscellaneous
CSD-WC-ONS-
240-00
2
Miscellaneous
OSC-6551
PRA Analysis of
Maintenance Rule Availability
Performance Criteria
2
Miscellaneous
OSS-0254.00-00-
1006
(MECH) Design Basis
Specification for the Spent
Fuel Cooling System
034
Miscellaneous
Risk Profile for
Unit 2 for the
week of February
24th
Miscellaneous
Risk Profile for
Unit 3 for the
week of February
11th
Procedures
AD-NF-ALL-0501
Electronic Risk Assessment
Tool (ERAT)
Procedures
AD-OP-ALL-0210
Operational Risk
Management
004
Procedures
AD-PI-ALL-0106
Cause Investigation
Checklists
Procedures
AD-WC-ALL-0240
On-Line Risk Management
Process
Procedures
AD-WC-ALL-0420
Shutdown Risk Management
Procedures
IP/0/A/2001/003 K
Inspection and Maintenance
of 600 Volt K-Line Breakers
039
Procedures
IP/0/A/2001/003 L
Refurbishing 600 Volt K-Line
Air Circuit Breaker
033
Procedures
IP/0/A/2001/015
PSW 13.8/4.16 kV Square D
Type VR Vacuum Circuit
Breaker Inspection and
Maintenance
007
Procedures
OP/3/A/1102/008
On-Line Vale Lineup for MOV 035
Inspection
Procedure
Type
Designation
Description or Title
Revision
or Date
Maintenance
Procedures
OP/3/A/1104/004
Low Pressure Injection
System
2
Work Orders
20699603, 20437227,
20706948, 20690548,
20687402, 20623800
Calculations
OSC-11505
HPI Pump Motor Upper
Bearing Oil Cooler
Performance Degradation
Allowance
Corrective
Action
Documents
2541430, 02541833,
2513617, 2527500,
2543252, 2533121,
2354722, 2545420, 2544934,
24508, 2323274, 2546711,
2471779
Drawings
O-422-M-4
Instrument Details Steam to
Emergency FDWP Trip Valve
Control
Drawings
OFD-101A-1.4
Flow Diagram of High
Pressure Injection System
(Charging Section)
051
Drawings
OFD-101A-1.4
Flow Diagram of High
Pressure Injection System
(Charging Section)
2
Drawings
OFD-122A-1.4
Flow Diagram of Main Steam
System Emergency
Feedwater Pump Turbine
Steam Supply and Exhaust
Drawings
OFD-127C-1.1
Flow Diagram of Nitrogen
System (Nitrogen Supply to
Actuation)
Drawings
ONTC-1-124B-
20-001
Motor Coolers Test
Acceptance Criteria
004
Miscellaneous
OM 251-0762.001
Outline Drawing For 6 CCI
Drag Valve With Warming
Disk, DMV-1265
Miscellaneous
OM 314.0586.001
Review of Pioneer HPI Pump
Upper Motor Bearing
Analysis and Certificate of
Compliance
000
Miscellaneous
OSS-0254.00-00-
1001
(MECH) High Pressure
Injection and Purification &
Deborating Demineralizer
Systems
066
Miscellaneous
OSS-0254.00-00-
(MECH) Design Basis
064
Inspection
Procedure
Type
Designation
Description or Title
Revision
or Date
1004
Specification for Standby
Shutdown Facility Reactor
Coolant Makeup System
Miscellaneous
OSS-0254.00-00-
25
Design Basis Specification
for the Instrument Air System
Miscellaneous
OSS-0254.00-00-
4001
(MECH) Design Basis Spec
for Reactor Building
Containment Isolation
046
Miscellaneous
PTR001511 (4)
LCR-21 NUC
Low Capacity, Lead-Acid
Battery Laboratory Report
6438
Procedures
IP/0/A/3000/023 S
SSF Battery DCSFS
Performance Test
005
Procedures
IP/0/A/3000/023 S
SSF Battery DCSFS
Performance Test
005
Procedures
IP/1/A/0275/021
Unit 1 Emergency Feedwater
System Nitrogen System
Instrument Calibration
2
Procedures
MP/0/A/1200/132
A
Valve - Anchor
Darling/Ladish - Flanged
Bonnet - Swing Check -
Disassembly, Repair, and
Assembly
033
Procedures
OP/0/A/1600/006
Operation of SSF
KSF1/KSF2 Inverters And
SSF CSF/CSFS Battery
Chargers
033
Procedures
PT/1/A/0230/015
High Pressure Injection
Motor Cooler Performance
Test
2
Procedures
PT/1/A/0600/028
IMS-93 Nitrogen Supply
Leakage Test
008
Procedures
PT/2/A/0600/012
Turbine Driven Emergency
Feedwater Pump Test
099
Work Orders
20690265, 20531943,
267684, 20595784,
20376789, 20174297,
20540583, 20714044,
284505
Corrective
Action
Documents
2538150, 2540131,
2519656, 2500872, 2326549,
2513249, 2537631, 2390857,
2544935, 2201417, 2546947,
2546757, 2295170, 2539268
Drawings
OFD-102A-3.1
Flow Diagram of Low
Pressure Injection System
(Borated Water Supply and
LPI Pump Suction)
065
Inspection
Procedure
Type
Designation
Description or Title
Revision
or Date
Drawings
OFD-102A-3.2
Flow Diagram of Low
Pressure Injection System
(LPI Pump Discharge)
049
Drawings
OFD-103A-3.1
Flow Diagram of Reactor
Building Spray System
2
Drawings
OFD-133A-2.5
Flow Diagram of Condenser
SSF Aux Service
063
Drawings
ONTC-0-103A-
0005-001
BS Pump Performance Test
Acceptance for Pump Total
Developed Head
Miscellaneous
CSD-EG-ONS-
1619.1000
Diverse and Flexible Coping
Strategies (FLEX) Program
Document - Oconee Nuclear
Station
005
Miscellaneous
OSS-0254.00-00-
1005
(MECH) Design Basis
Specification for the Standby
Shutdown Facility Auxiliary
Service Water System
047
Miscellaneous
OSS-0254.00-00-
1034
Design Basis Specification
for the Reactor Building
Spray System
29
Miscellaneous
OSS-0254.00-00-
2005
(ELECT) Keowee Emergency
Power Design Basis
036
Procedures
IP/1/A/0400/049
KHU-1 Governor Speed
Switch Instrument Calibration
Procedures
MP/0/A/1300/003
Pump - Ingersoll-Rand -
Low Pressure Service Water
- Rotating Assembly -
Removal and Replacement
039
Procedures
MP/0/A/1840/040
A
Pumps - Motors -
Miscellaneous Components -
Lubrication Post
Maintenance Testing
004
Procedures
MP/0/A/3009/017
A
Visual Inspection and
Electrical Motor Tests Using
baker Equipment
004
Procedures
MP/0/A/3009/020
B
Motor - QA - Electric -
Removal, Replacement, and
Post Maintenance Testing
044
Procedures
OP/0/A/1106/019
Keowee Hydro at Oconee
114
Procedures
OP/0/A/2000/013
KHU-1 Generator
29
Procedures
OP/0/B/1106/033
Primary System Leak
Identification
23
Procedures
OP/3/A/1104/004
Low Pressure Injection
System
2
Procedures
OP/3/A/1104/005
Reactor Building Spray
System
044
Inspection
Procedure
Type
Designation
Description or Title
Revision
or Date
Procedures
PT/0/A/0400/005
SSF Auxiliary Service Water
Test
070
Procedures
PT/0/A/0600/021
Standby Shutdown Facility
Diesel - Generator Operation
018
Procedures
PT/0/A/0620/009
Keowee Hydro Operation
056
Procedures
PT/0/A/0620/016
Keowee Hydro Emergency
Start Test
055
Procedures
PT/1/A/0202/011
High Pressure Injection
Pump Test
108
Procedures
PT/1/A/0204/007
Reactor Building Spray Pump
Test
106
Procedures
PT/1/A/0251/001
Low Pressure Service Water
Pump Test
114
Procedures
PT/1/A/0600/012
Turbine Driven Emergency
Feedwater Pump Test
109
Procedures
PT/2/A/0600/013
Motor Driven Emergency
Feedwater Pump Test
077
Procedures
PT/3/A/0204/007
Reactor Building Spray Pump
Test
099
Work Orders
20700430, 20692464,
20702695, 20702296,
20616064, 20614788,
20631913, 20614191,
20678484, 20600155,
20695656, 20283832,
20622468, 20713656,
20570704, 20700763,
20702807
71151
Corrective
Action
Documents
NCR 2534818
71151
Miscellaneous
MSPI Margin and Derivation
Reports for the High
Pressure Injection System for
Unit 1 for the 4th quarter
24
71151
Miscellaneous
MSPI Margin and Derivation
Reports for the High
Pressure Injection System for
Unit 2 for the 1st quarter
24
71151
Miscellaneous
MSPI Margin and Derivation
Reports for the High
Pressure Injection System for
Unit 3 for the 4th quarter
24
Corrective
Action
Nuclear Condition
Report(s)
2491256, 2493255
Inspection
Procedure
Type
Designation
Description or Title
Revision
or Date
Documents
Miscellaneous
Independent Assessment of
the Work Environment of the
Oconee Nuclear Station
Warehouse Operations and
Support Team November
24
Corrective
Action
Documents
2534840, 2434572
A
IMC 0609 Appendix M, Significance Determination Process Using Qualitative Criteria
(ADAMS Accession No. ML24192A216)
Exhibit 1: Results of the Initial Evaluation
1.
Describe the influential assumptions used in the initial evaluation: The degraded
condition created by the performance deficiency is the rendering of the Unit 1
pressurizer heaters powered from the common standby shutdown facility (SSF) to be
inoperable and unable to do their safety function. Without pressurizer heater input,
ambient losses from the pressurizer would cause the pressurizer to cool and subcooling
margin for the reactor coolant system would be lost, allowing boiling to occur in the core
and allowing the bubble to collapse in the pressurizer. Two phase flow will continue to
cool the core until hot leg voiding occurs and no natural circulation flow through the core
will take place until the RCS transitions into boiler-condenser mode (steam cooling), at
which time an equilibrium temperature will be reached as long as adequate make up in
maintained. Although the TS basis requires the SSF auxiliary service water system to be
considered inoperable when pressurizer heaters are unavailable, the SSF auxiliary
service water system is still able to perform its probabilistic risk assessment (PRA)
function to provide secondary side cooling until natural circulation is lost in the primary.
Since this takes between 13-15 hours to occur, it is not appropriate to use the SSF ASW
system as a surrogate for this condition. The core damage sequences of concern are
station blackout events (SBO), internal fire events which result in a SBO, and internal
and external flooding events. The same basic condition was evaluated as a Yellow
significance old design issue in 2011 although the detailed risk assessment had three
orders of magnitude of uncertainty (from Red to White). The dominate accident
sequence was a large fire in the turbine building. The pressurizer (PZR) heater function
is not modelled in the Standardized Plant Analysis Risk (SPAR) model or the licensees
Computer Aided Faulty Tree Analysis (CATFA) model. Since 2011 several key plant
modifications have been implemented:
(a) The installation of the protected service water (PSW) system. This system
provides an alternate means of feeding steam generators, provides an alternate
source of power for plant equipment such as high pressure injection pumps, and
powers alternative banks of PZR heaters. The system and cables do not pass
through the turbine building. However, the alternate PZR heater power was not
modelled in the SPAR or CAFTA models.
(b) The SSF letdown line was modified to change the suction location from the
letdown heat exchangers off the cold leg of the RCS, to off the hot leg, and
replaced the isolation valve from an orifice and a gate valve to an actual throttle
valve. This makes the operators action to throttle letdown flow to match SSF
RCS makeup flow more likely to be successful and avoid lifting of a pressurizer
safety valve.
(c) The licensee adopted National Fire Protection Association (NFPA) 805 and
developed a Regulatory Guide 1200 Fire PRA. For this significance
determination process (SDP), the licensee made a modification to model the
PSW PZR heaters. The dominant human error probabilities (HEPs) were 1)
A
Failure to Restore Pressurizer Heaters via Protected Service Water Power
(1NPZRPSWDHE) and 2) Operators Failing to Throttle SSF Letdown to prevent
lifting Pressurizer Safety Valves (1NPZRPSVDHE). PSW PZR heaters are not
considered to be available for fires in the east penetration room and fires which
result in a main control room evacuation (as the heaters are controlled from the
main control room.)
(d) The licensee performed a thermal hydraulic analysis for this condition and
identified the following. Without SSF pressurizer heaters it would take
approximately 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br /> to lose subcooling margin (SCM). At this point the
pressurize bubble would collapse and the plant would go into solid plant
operations. Once SCM was lost, two phase flow would begin in the RCS and
after approximately 45 minutes, natural circulation flow would be lost. At this
point, the RCS would rapidly begin to heat up and cause inflows into the
pressurizer causing rapid pressure increases making it challenging to maintain
pressure and prevent lifting a pressurizer relief valve. After about 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />
without natural circulation, the RCS level would lower until the transition to boiler-
condenser mode occurred and temperature would stabilize via steam cooling.
During a loss of coolant accident (LOCA), this transition is relatively short;
however, during an SBO scenario this transition is longer and the possibility of
lifting safety relief valves and losing RCS inventory is more likely during this time
frame. Based on this, core damage can be prevented by restoring PSW supplied
pressurizer heaters or by troubleshooting and repairing the SSF supplied
pressurizer heaters during the first 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />. Operators would have an indication
that SSF powered pressurizer heaters failed to energize during the first hour of
the event. (The heaters energized light would not come on when the action was
directed by procedure to use heaters to maintain RCS Pressure.)
2.
Sensitivities: The SRA compared the SPAR model results and cutsets from the detailed
risk assessment performed in 2011 and the SPAR model internal events results and
cutsets using the current SPAR model revision 8.82. The current model includes the
PSW water supply to the steam generators and the backup power supply to the high
pressure injection pumps. The 2011 SPAR model was dominated by a loss of instrument
air event. This event has been significantly refined in the current model. Internal events
are about two orders of magnitude lower in the current model. Qualitatively this can be
applied to previous fire SDP results as well.
The licensees CAFTA model, using the model changes discussed above, used baseline
values of HEPs 1NPZRPSWDHE and 1NPZRPSVDHE set at 1E-2. The model was
most sensitive to 1NPZRPSVDHE. Given the uncertainty related to the success of this
term, once natural circulation is lost under solid plant conditions, values of 1E-1 to 1E-3
would be reasonable, and result in risk results of 2E-6 to 2E-8.
3.
Identify any information gaps in defining the influential assumptions used in the initial
evaluation: The HEP assumptions are extremely difficult to quantify. The plant conditions
are not covered in normal training and actions would be contrary to the same actions
taken before subcooling was lost. However, there would be substantial time to brief
operators and restore power to the heaters.
Initial Evaluation Result: Bounding result is 2E-6 using best available data and surrogates.
Exhibit 2: Considerations for Evaluation of Decision Attributes
Table 1:
Qualitative Decision-Making Attributes for NRC Management Review
Decision Attribute
Basis for Input to Decision - Provide
qualitative and/or quantitative information for
management review and decision making.
Defense-in-Depth
Defense in depth has been enhanced with the
addition of the PSW system. Although a
weather related or grid related loss of offsite
power (LOOP) would also assume PSW to be
unavailable, PSW significantly mitigates the
impact of any other LOOP events and major
fire in the turbine building since the PSW
cables and piping do not run through the
turbine building.
Safety Margin
Safety margin is higher than it was in 2011.
During the 2011 Detailed Risk Evaluation, it
was concluded that the Thermal Hydraulic
Code of Record was not effective in modeling
two-phase flow, so core damage was
assumed to occur early in the event. The
current Thermal Hydraulic Code used for this
evaluation shows operators have a substantial
amount of time for recovery and/or repair
efforts before natural circulation flow is lost
between 13-15 hours.
Extent of Condition
The Unit 2 and Unit 3 SSF PZR heaters and
PSW powered PZR heaters for all three units
were not affected by this performance
deficiency; however, since it was a
maintenance related event, common mode
still must be considered.
Degree of Degradation
The heater block assembly was installed
incorrectly, not allowing the SSF powered
PZR heater to energize until the low-level set
point was reached (85), vice deenergizing
them at that point. The error was troubleshot
and repaired in approximately five hours after
discovery, demonstrating that the condition
was potentially recoverable via repairs.
Exposure Time
The condition was present since 2022. For
SDP purposes, the maximum 1-year exposure
time was applied.
Recovery Actions
1) Recover PZR heater function using the
PSW system. The PSW heaters use
an independent circuit and power
different heater banks. 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />
available. Note: Procedures exist for
placing both PSW and SSF system in
service in parallel during an event.
When both systems are available,
operators will secure one of the
systems. However, the SSF PZR
heater availability is not considered in
the procedure.
2) Repair SSF heaters by replacing the
mis-wired heater block or rewiring. 13
hours available.
Additional Qualitative
Considerations
The SSF letdown line modifications make
throttling significantly easier decreasing the
HEP for the first 13 hours1.50463e-4 days <br />0.00361 hours <br />2.149471e-5 weeks <br />4.9465e-6 months <br />, but from 13-17
hours it would be a more significant challenge.
The modification also allows for some
bleeding of steam from the RCS, which would
likely delay the loss of natural circulation for a
short additional period of time.
The SRA assumed an HEP of 1E-3 for hours
0-13, and HEP of 1E-1 for hours 13-17, and
an HEP of 1E-2 for hours 17-24. This would
give a time-weighted HEP of 2E-2 for the 24-
hour PRA mission time.
Conclusion: Given the plant modifications and improved level of thermal hydraulic modelling
which defines the substantial amount of time available before SSF throttling becomes
significantly more difficult, the SRA recommends using the adjusted value of 1NPZRPSVDHE at
2E-2. This would also conservatively account for the repair option.
Using the licensees baseline data and adjusting for the HEP, the Delta CDP would be less than
1E-6, which corresponds to a finding of Very Low Safety Significance (GREEN).
Result of management review (COLOR):
GREEN