IR 05000269/2022001

Integrated Inspection Report 05000269/2022001, 05000270/2022001 and 05000287/2022001

ML22123A236
Person / Time
Site:	Oconee
Issue date:	05/04/2022
From:	Eric Stamm NRC/RGN-II/DRP/RPB1
To:	Snider S Duke Energy Carolinas
Kirk H
References
IR 2022001
Download: ML22123A236 (47)

Text

May 4, 2022 Mr. Steven Snider Site Vice President Duke Energy Carolinas, LLC 7800 Rochester Highway Seneca, SC 29672-0752 SUBJECT: OCONEE NUCLEAR STATION - INTEGRATED INSPECTION REPORT 05000269/2022001, 05000270/2022001 AND 05000287/2022001

Dear Mr. Snider:

On March 31, 2022, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Oconee Nuclear Station. On April 28, 2022, 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.

Six findings of very low safety significance (Green) are documented in this report. Five of these findings involved violations of NRC requirements. One Severity Level IV violation without an associated finding is documented in this report. We are treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

Licensee-identified violations which were determined to be of very low safety significance and Severity Level IV are documented in this report. We are treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violations or the significance or severity of the violations 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.

If you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement 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 II; 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 Room in accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely, Signed by Stamm, Eric on 05/04/22 Eric J. Stamm, Chief Reactor Projects Branch #1 Division of Reactor Projects Docket Nos. 05000269, 05000270 and 05000287 License Nos. DPR-38, DPR-47 and DPR-55 Enclosure w/

Attachment:

As stated

Inspection Report

Docket Numbers: 05000269, 05000270 and 05000287 License Numbers: DPR-38, DPR-47 and DPR-55 Report Numbers: 05000269/2022001, 05000270/2022001 and 05000287/2022001 Enterprise Identifier: I-2022-001-0024 Licensee: Duke Energy Carolinas, LLC Facility: Oconee Nuclear Station Location: Seneca, South Carolina Inspection Dates: January 1, 2022 to March 31, 2022 Inspectors: T. Fanelli, Senior Reactor Inspector C. Fontana, Emergency Preparedness Inspector M. Kennard, Senior Operations Engineer M. Meeks, Senior Operations Engineer J. Nadel, Senior Resident Inspector G. Ottenberg, Senior Reactor Inspector N. Peterka, Fuel Facility Inspector A. Ruh, Senior Resident Inspector S. Sanchez, Senior Emergency Preparedness Inspector N. Smalley, Resident Inspector J. Tornow, Physical Security Inspector J. Walker, Resident Inspector Approved By: Eric J. Stamm, Chief Reactor Projects Branch #1 Division of Reactor Projects Enclosure

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. Licensee-identified non-cited violations are documented in report sections: 71152A and 7115

List of Findings and Violations

Failure to Maintain Lee Combustion Turbine Out of Tolerance Protective Relay Settings Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green None (NPP) 71111.18 Systems FIN 05000269,05000270,05000287/202200 1-01 Open/Closed Inspectors identified a Green finding when the licensee failed to maintain Lee Combustion Turbine out of tolerance relay settings as described in design change and design basis documents. Specifically, relay settings were unknowingly modified in 2006 during planned turbine replacements.

Failure to Use a Procedure Appropriate to the Circumstances While Changing Electrical Lineup of Startup Transformer CT-2 Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.12] - Avoid 71111.20 NCV 05000269,05000270/2021004-02 Complacency Closed A finding with very low safety significance (Green) and an associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when the licensee failed to use a procedure appropriate to the circumstances for an activity affecting quality. Specifically, the procedure for sharing startup transformers between units was inadequate, which led to simultaneous lockouts on CT-1 and CT-2 startup transformers while starting the 2B2 reactor coolant pump (RCP) motor for an uncoupled run.

Inadequate Test Acceptance Criteria Development for Essential Siphon Vacuum Pumps Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green None (NPP) 71111.22 Systems NCV 05000269,05000270,05000287/202200 1-02 Open/Closed Inspectors identified a Green finding and associated non-cited violation of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, when the licensee failed to verify the adequacy of the design of the essential siphon vacuum (ESV) pumps. Specifically, site engineers improperly developed a rotameter flowrate correction factor when establishing test acceptance criteria for routine pump surveillance testing.

Failure to Identify a Condition Adverse to Quality Associated with Essential Siphon Vacuum Pumps Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.1] - 71152A Systems NCV Resources 05000269,05000270,05000287/202200 1-04 Open/Closed Inspectors identified a Green finding and associated non-cited violation of 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, when the licensee failed to promptly identify a condition adverse to quality associated with test acceptance criteria (TAC) for the essential siphon vacuum (ESV) pumps. Specifically, a nuclear condition report (NCR) was not written and thus, an operability determination was not performed for approximately two weeks after inspectors communicated specific concerns about errors in the TAC for the ESV pumps.

Inappropriate Coating on Emergency Feedwater Piping Results in a Notification of Unusual Event Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green None (NPP) 71153 NCV 05000269,05000270,05000287/202200 1-05 Open/Closed A self-revealed Green finding and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified for the licensee's use of an inappropriate coating on emergency feedwater piping in the Unit 2 west penetration room. Specifically, the piping was painted with a coating that had a lower temperature rating than the design temperature of the piping and this resulted in a large amount of smoke being generated during a plant event on February 5, 2022.

Failure to Respond to Priority Process Computer Alarm Condition Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.12] - Avoid 71153 NCV 05000270/2022001-06 Complacency Open/Closed A self-revealed Green finding and associated non-cited violation of technical specification 5.4.1, was identified when the licensee failed to respond to an unexpected 2A feedwater pump turbine controller fault priority process computer alarm.

Failure to Report Valid Actuations of Emergency Feedwater System Cornerstone Severity Cross-Cutting Report Aspect Section Not Applicable Severity Level IV Not Applicable 71153 NCV 05000270/2022001-07

Open/Closed Inspectors identified a Severity Level IV non-cited violation of 10 CFR 50.72(b)(3)(iv)(A) when the licensee failed to notify the NRC within eight hours of a valid actuation of the emergency feedwater system on two occasions. Specifically, the Unit 2 motor driven emergency feedwater pumps were automatically actuated by a low level initiation circuit in response to a low steam generator water level on February 13, 2022, at 1625 EST, and February 21, 2022, at 2207 EST and no NRC notifications per 10 CFR 50.72(b)(3)(iv)(A) were made.

Additional Tracking Items

Type Issue Number Title Report Section Status URI 05000269,05000270,05 Essential Siphon Vacuum 71111.22 Open 000287/2022001-03 Testing LER 05000270/2021-003-00 LER 2021-003-00 for 71153 Closed Oconee Nuclear Station Unit 2, Conditions Prohibited by Technical Specifications Due to SSF and PSW Inoperability LER 05000270/2021-002-00 LER 2021-002-00 for 71153 Closed Oconee Nuclear Station Unit 2, Actuation of the Keowee Hydroelectric Station Due to Loss of AC Power to the Unit 2 Main Feeder Buses

PLANT STATUS

Unit 1 operated at or near 100 percent rated thermal power (RTP) for the entire inspection period.

Unit 2 began the inspection period operating at or near 100 percent RTP until an automatic reactor trip occurred on February 5, 2022, due to loss of power to the four reactor coolant pumps. The unit was restarted on February 21, 2022, however, while at 68 percent RTP during power ascension, a feedwater transient occurred, and a manual reactor trip was initiated from 39 percent RTP due to lowering steam generator water levels associated with a feedwater control valve positioner failure. The unit was returned to 100 percent RTP on February 28, 2022. On March 21, 2022, the unit was reduced to 46 percent RTP to support control rod drive system maintenance and the unit returned to at or near 100 percent RTP for the remainder of the 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, conducted routine reviews using IP 71152, Problem Identification and Resolution, 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.

71111.01 - Adverse Weather Protection

Seasonal Extreme Weather Sample (IP Section 03.01) (1 Sample)

(1) The inspectors evaluated readiness for seasonal extreme weather conditions prior to the onset of seasonal cold temperatures for the following systems: essential siphon vacuum, low pressure injection, and siphon seal water on January 14, 2022.

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 an impending major winter storm on January 16, 2022.

71111.04 - Equipment Alignment

Partial Walkdown Sample (IP Section 03.01) (4 Samples)

The inspectors evaluated system configurations during partial walkdowns of the following systems/trains:

(1) Protected service water system portable pump equipment on January 13, 2021

(2) 1B low pressure injection system during 1A low pressure injection pump replacement on January 25, 2022

(3) Unit 2 high pressure injection system on February 17, 2022

(4) Keowee Hydro Unit 1 during Keowee Hydro Unit 2 outage on March 8, 2022

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 34: Unit 1 4160V switchgear on January 4, 2022

(2) Fire zone 90: Unit 2 auxiliary building 300 level hallway on January 11, 2022

(3) Fire zone 108: Unit 1 east penetration room on February 2, 2022

(4) Fire zone 92: Unit 2 equipment room on February 17, 2022

(5) Fire zone 101: Unit 3 cable room on March 24, 2022

Fire Brigade Drill Performance Sample (IP Section 03.02) (1 Sample)

(1) The inspectors evaluated the onsite fire brigade training and performance during unannounced fire drills on January 18, 2022, and February 4, 2022.

71111.06 - Flood Protection Measures

Inspection Activities - Internal Flooding (IP Section 03.01) (1 Sample)

The inspectors evaluated internal flooding mitigation protections in the:

(1) Unit 1, 2, and 3 control battery rooms 400, 408, 458 and heating ventilation and cooling equipment rooms 505, 520, 565

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 Unit 2 reactor startup on February 14, 2022.

Licensed Operator Requalification Training/Examinations (IP Section 03.02) (1 Sample)

(1) The inspectors observed and evaluated simulator training for an operating crew using simulator exercise guide SAE-R214 on January 26, 2022.

71111.12 - Maintenance Effectiveness

Maintenance Effectiveness (IP Section 03.01) (1 Sample)

The inspectors evaluated the effectiveness of maintenance to ensure the following structures, systems, and components (SSCs) remain capable of performing their intended function:

(1) Keowee generator unit 2 and failure on December 12, 2021 (NCR 2409066).

71111.13 - Maintenance Risk Assessments and Emergent Work Control

Risk Assessment and Management Sample (IP Section 03.01) (6 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) Emergent risk assessment following inoperability of Keowee hydro unit 2, on December 13 and 14, 2021

(2) Unit 1 elevated Green risk due to planned 1A low pressure injection pump motor replacement, on January 24, 2022

(3) Preparations for dropping unit 2 reactor coolant system loops and high risk plant operating state, on February 9 and 10, 2022

(4) Unit 2 elevated Green risk due to planned replacement of a faulted control rod drive pulse generator monitor module, on March 21, 2022

(5) Unit 1 elevated Green risk due to heavy lift of replacement feedwater heater over unit 1 turbine building equipment on March 23, 2022

(6) Unit 3 elevated Green risk due to planned backup instrument air dryer maintenance and emergent nuclear instrument calibration, on March 30, 2022

71111.15 - Operability Determinations and Functionality Assessments

Operability Determination or Functionality Assessment (IP Section 03.01) (7 Samples)

The inspectors evaluated the licensee's justifications and actions associated with the following operability determinations and functionality assessments:

(1) NCR 2412263, 3ESV-1 heat trace temperature low due to insulation not reinstalled

(2) NCR 2414901, Unit 2 emergency feedwater piping exceeded design pressure following a trip under natural circulation conditions

(3) NCRs 2417766 and 2417761, Unit 3 turbine driven emergency feedwater pump test acceptance criteria not met

(4) NCR 2416229, ESV pump capacity test acceptance criteria equation is non-conservative

(5) NCR 2414034, Oil Leaking from top of Keowee Hydro Unit 1 MT-25 dash pot

(6) NCR 2421652, Non-conservative input in OSC-6991 for ESV test acceptance criteria

(7) NCR 2415794, 2RC-67 discharge expansion joint potentially installed backwards

71111.18 - Plant Modifications

Temporary Modifications and/or Permanent Modifications (IP Section 03.01 and/or 03.02) (2 Samples)

The inspectors evaluated the following temporary or permanent modifications:

(1) Modification OD500910, "Install 2 new LM-6000-PC gas turbines at Lee"

(2) Temporary change to abnormal procedure AP/2/A/1700/001, "Unit Runback,"

regarding operator response to certain multiple dropped control rod events, not previously evaluated in the updated final safety analysis report, for an emergent control rod drive system repair.

71111.19 - Post-Maintenance Testing

Post-Maintenance Test Sample (IP Section 03.01) (7 Samples)

The inspectors evaluated the following post-maintenance testing activities to verify system operability and/or functionality:

(1) PT/3/A/0261/010, Essential Siphon Vacuum System Test, following preventive maintenance on 3ESV-1 float valve, WO 20498262

(2) IP/1-2/A/0250/001 B, Low Pressure Service Water Discharge Pressure and Motor Temperature Instrument Calibration, after replacement of standby low pressure service water pump auto start agastat relay, WO 20412551

(3) PT/2/A/0152/020, AFIS Circuitry Test following 2FDW-32 positioner shuttle valve replacement, WO 20522750

(4) IP/0/B/4980/001 5T, Transformer 5T Relay Testing following preventive maintenance on 87T5TX differential relay, WO 20318402

(5) PT/1/A/0203/006 A, Low Pressure Injection Pump Test - Recirculation, following 1A LPI Pump Motor Replacement, WO 20499131

(6) IP/0/A/4980/062 A, Westinghouse Stuck Breaker Failure Unit (SBFU) Relay Test, after replacement of PCB-28 breaker failure relay 62B, WO 20429529

(7) NWS-T-75 "NWS Safety Valve Test Procedure for DUKE Energy - Oconee Nuclear Station Pressurizer Safety Valves" data package following refurbishment of spare pressurizer safety valves for 2RC-67 and 68, purchase order 03139690

71111.20 - Refueling and Other Outage Activities

Refueling/Other Outage Sample (IP Section 03.01) (1 Partial)

(1) (Partial)

The inspectors evaluated Unit 2 forced outage O2F30B activities from February 5, 2022, to February 21, 2022. The inspectors completed inspection procedure sections 03.01 (c7),

(d1) and (d2).

71111.22 - Surveillance Testing

The inspectors evaluated the following surveillance testing activities to verify system operability and/or functionality:

Surveillance Tests (other) (IP Section 03.01) (6 Samples)

(1) PT/3/A/0261/010, Essential Siphon Vacuum System Test, on January 14, 2022

(2) PT/0/A/0600/021, Operation of the SSF Diesel Generator on February 24, 2022

(3) PT/3/A/0600/012, Turbine Driven Emergency Feedwater Pump Test on February 28, 2022

(4) PT/2/A/0203/006, 2B Low Pressure Injection Pump Test - Recirculation on March 1, 2022

(5) PT/3/A/0600/013, 3A Motor Driven Emergency Feedwater Pump Test on March 1, 2022

(6) PT/1/A/0600/012, Turbine Driven Emergency Feedwater Pump Test on March 3, 2022

Inservice Testing (IP Section 03.01) (1 Sample)

(1) PT/2/A/2200/019, KHU-2 Turbine Sump Pump IST Surveillance, on January 20, 2022

71114.01 - Exercise Evaluation

Inspection Review (IP Section 02.01-02.11) (1 Sample)

(1) The inspectors evaluated the biennial emergency preparedness exercise during the week of March 28, 2022. The simulated scenario began with a failure of the B-train reactor core cooling monitoring system (A-train already out-of-service) on Unit 1, thus meeting the criteria for declaration of an Unusual Event. A short time later, the 1B feedwater pump tripped causing a main turbine runback. This significant plant transient, coupled with the inability to monitor certain Unit 1 reactor core cooling parameters, met the conditions for declaration of an Alert. As severe weather moved through the area, a lightning strike directly to the remaining Unit 1 offsite power source transformer, resulted in a complete loss of power and subsequent reactor trip, which met the conditions for declaration of a Site Area Emergency. Despite the simulated scenario being a no-release radiological exercise, the Offsite Response Organizations adequately demonstrated their ability to implement emergency actions.

71114.04 - Emergency Action Level and Emergency Plan Changes

Inspection Review (IP Section 02.01-02.03) (1 Sample)

(1) The inspectors evaluated submitted Emergency Action Level, Emergency Plan, and Emergency Plan Implementing Procedure changes during the week of March 28, 2022. This evaluation does not constitute NRC approval.

71114.06 - Drill Evaluation

Drill/Training Evolution Observation (IP Section 03.02) (1 Sample)

The inspectors evaluated:

(1) Training drill 2022-01 on March 7, 2022, which included emergency response organization team 3 and participation from the emergency operations facility

71114.08 - Exercise Evaluation - Scenario Review

Inspection Review (IP Section 02.01 - 02.04) (1 Sample)

(1) The inspectors reviewed and evaluated in-office, the proposed scenario for the biennial emergency plan exercise at least 30 days prior to the day of the exercise.

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, 2021 - December 31, 2021)

(2) Unit 2 (January 1, 2021 - December 31, 2021)

(3) Unit 3 (January 1, 2021 - December 31, 2021)

IE03: Unplanned Power Changes per 7000 Critical Hours Sample (IP Section 02.02) (3 Samples)

(1) Unit 1 (January 1, 2021 - December 31, 2021)

(2) Unit 2 (January 1, 2021 - December 31, 2021)

(3) Unit 3 (January 1, 2021 - December 31, 2021)

IE04: Unplanned Scrams with Complications (USwC) Sample (IP Section 02.03) (3 Samples)

(1) Unit 1 (January 1, 2021 - December 31, 2021)

(2) Unit 2 (January 1, 2021 - December 31, 2021)

(3) Unit 3 (January 1, 2021 - December 31, 2021)

MS07: High Pressure Injection Systems (IP Section 02.06) (3 Samples)

(1) Unit 1 (January 1, 2021 - December 31, 2021)

(2) Unit 2 (January 1, 2021 - December 31, 2021)

(3) Unit 3 (January 1, 2021 - December 31, 2021)

EP01: Drill/Exercise Performance (DEP) Sample (IP Section 02.12) (1 Sample)

(1) April 1, 2021, through December 31, 2021 EP02: Emergency Response Organization (ERO) Drill Participation (IP Section 02.13) (1 Sample)

(1) April 1, 2021, through December 31, 2021 EP03: Alert And Notification System (ANS) Reliability Sample (IP Section 02.14) (1 Sample)

(1) April 1, 2021, through December 31, 2021

71152A - Annual Follow-up Problem Identification and Resolution Annual Follow-up of Selected Issues (Section 03.03)

The inspectors reviewed the licensees implementation of its corrective action program related to the following issues:

(1) NCR 2409104, Standby shutdown facility breakers left out of position during mode changes

71153 - Follow Up of Events and Notices of Enforcement Discretion Event Followup (IP Section 03.01)

(1) The inspectors evaluated a CT-3 transformer lockout during planned breaker failure relay maintenance and licensees response on January 26, 2022.

(2) The inspectors evaluated a Unit 2 reactor trip due to loss of power to all four reactor coolant pumps and subsequent declaration of a notice of unusual event for indications of a fire in the west penetration room on February 5, 2022.

(3) The inspectors evaluated a Unit 2 manual reactor trip due to failure of 'A' feedwater control valve with lowering 'A' steam generator level and licensees response on

===February 21, 2022.

Event Report (IP Section 03.02) (2 Samples)===

The inspectors evaluated the following licensee event reports (LERs):

(1) LER 05000270/2021-003-00, Conditions Prohibited by Technical Specifications Due to SSF and PSW Inoperability (ADAMS Accession No. ML22038A969). The inspection conclusions associated with this LER are documented in this report under Inspection Results Sections 71152 and 71153.

(2) LER 05000270/2021-002-00, Actuation of the Keowee Hydroelectric Station Due to Loss of AC Power to the Unit 2 Main Feeder Buses (ADAMS Accession No.

ML22026A530). The inspection conclusions associated with this LER are documented in Inspection Report 05000269, 05000270, 05000287/2021004 (ADAMS Accession No. ML22040A188) under Inspection Results Section 71111.20.

Personnel Performance (IP Section 03.03) (1 Sample)

(1) The inspectors evaluated a Unit 2 plant heat up, actuation of emergency feedwater on low steam generator level, and the licensees performance on March 13, 2022.

Reporting (IP Section 03.05) (1 Sample)

(1) The inspectors reviewed the circumstances surrounding actuation of unit 2 motor driven emergency feedwater pumps from a low level initiation circuit while in mode 3 on February 13, 2022, and while in mode 1 on February 21,

INSPECTION RESULTS

Failure to Maintain Lee Combustion Turbine Out of Tolerance Protective Relay Settings Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green None (NPP) 71111.18 Systems FIN 05000269,05000270,05000287/20220 01-01 Open/Closed Inspectors identified a Green finding when the licensee failed to maintain Lee Combustion Turbine out of tolerance relay settings as described in design change and design basis documents. Specifically, relay settings were unknowingly modified in 2006 during planned turbine replacements.

Description:

The updated final safety analysis report, section 8.2.1.4, describes that the Lee Combustion Turbines (LCTs) can power the Oconee standby bus when there is inadequate power from the generating units, the 230kV switching station and the hydro units. Oconees design basis document (DBD) OSS-0254.00-00.2011, 100kV Alternate Power System Design Basis Document, included a system specific design criterion that stated, To resolve concerns of a combustion turbine generator malfunction when aligned to the dedicated 100kV line to Oconee, each combustion turbine generator is equipped with out of tolerance (OOT)protection. A voltage or frequency OOT of greater than +/-10% will cause an automatic generator breaker trip after a time delay. This OOT logic was originally added in 1999 to satisfy Oconees commitment #2 from Duke Powers Response to NRR and AEOD Draft Report on the Oconee Emergency Power System, dated October 31, 1996 (ADAMS Accession No. ML15118A449). The commitment was described as: Voltage and frequency protection will be added to preclude out-of-tolerance voltage or frequency from damaging Oconees auxiliary equipment. Both under and over voltage and frequency relays will be installed on the Lee dedicated path at Oconee. These relays, in a 2 of 3 configuration with an appropriate time delay to allow for loading transients, will be incorporated into the SL breaker trip logic. This commitment was later modified in Duke Powers letter, Additional Information Related to the NRCs Interim Report on the Oconee Emergency Power System, dated October 1, 1998, (Legacy ADAMS Accession No. 9810090301) to locate the protection devices at the Lee Steam Station.

In 2006, minor design change OD500910, revised Oconee design and licensing documentation when two new combustion turbines were installed to replace the three existing combustion turbines at the Lee Steam Station. The modification scope and supporting basis for a 10 CFR 50.59 evaluation of the changes stated that, The design for the new LCTs does not alter the existing +/-10% out of tolerance (OOT) frequency and voltage logic (e.g., same function, trip setpoints, same 2 out of 3 logic, same time delay, etc.) that was used for Oconee equipment protection.

In October 2021, inspectors identified that site calculation OSC-11581, U1/2/3, Keowee EPS and 100kV APS Voltage Adequacy Analyses, indicated that LCT undervoltage protection was disabled, which conflicted with the description of the LCT OOT logic described in the DBD. Since Oconee design engineers assumed no undervoltage protection existed, transient loading of Oconee electrical loads was not evaluated for potentially activating protective relay settings. Following investigation, the licensee determined that the LCT OOT logic was still active, but the setpoints and time delays were not as originally designed. Namely, the voltage settings were +10.4% / -20% and frequency was +/-3.33% with a 15 second time delay. The licensee determined these settings were modified in 2006 when the new LCTs were installed, and that they were adequate to prevent undesired activation during the loading transients evaluated in OSC-11581. In January 2022, inspectors questioned whether the -20% voltage setting was adequate to fulfill the commitment of protecting Oconees auxiliary equipment from degraded voltage. The licensees design calculations did not demonstrate acceptable performance of Oconees auxiliary equipment within the full range of the -20% voltage setting.

Corrective Actions: The protective relay settings were restored to the +/- 10% voltage and frequency settings on March 29, 2022, by work order 44291736.

Corrective Action References: 2403757, 2411493

Performance Assessment:

Performance Deficiency: The failure to maintain LCT OOT relay settings as described in the system specifications of OSS-0254.00-00.2011, and minor design change OD500910, was a performance deficiency. Specifically, these design documents relied on existing relay settings to be maintained, but the settings were unknowingly modified in 2006 during planned turbine replacements.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Design 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, with the existing -20% voltage relay setting, malfunctions affecting the output voltage of a LCT could have subjected Oconee auxiliary equipment to inadequate voltage conditions without activating an automatic protective trip of the LCT generator breaker.

Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using exhibit 2, Mitigating Systems Screening Questions, inspectors determined the finding to be of very low safety significance (Green). Specifically, the finding was a deficiency affecting the protective relay design for the LCTs, but it did not affect the capability of the LCTs to perform their PRA function to supply power at adequate voltage and frequency.

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:

Inspectors did not identify a violation of regulatory requirements associated with this finding.

Failure to Use a Procedure Appropriate to the Circumstances While Changing Electrical Lineup of Startup Transformer CT-2 Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.12] - Avoid 71111.20 NCV 05000269,05000270/2021004-02 Complacency Closed A finding with very low safety significance (Green) and an associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified when the licensee failed to use a procedure appropriate to the circumstances for an activity affecting quality. Specifically, the procedure for sharing startup transformers between units was inadequate, which led to simultaneous lockouts on CT-1 and CT-2 startup transformers while starting the 2B2 reactor coolant pump (RCP) motor for an uncoupled run.

Description:

On November 27, 2021, the licensee was performing outage maintenance activities in preparation for Unit 2 startup following a refueling outage. At the time, Unit 1 was in Mode 1 at 100 percent power with electrical loads being powered from its own main transformer, 1T. Unit 2 was in Mode 5 with loads being powered from its normal offsite power source, startup transformer CT-2. Unit 3 was in Mode 1 at 100 percent power and was unaffected by this event. While starting the 2B2 RCP for an uncoupled motor run, both Unit 1 and Unit 2 offsite power sources, CT-1 and CT-2, lost power. Unit 1 did not lose power since its electrical loads were being powered from its own main turbine transformer, 1T. Unit 2 lost power for approximately 31 seconds before regaining power from a different offsite power source, transformer CT-5. For Unit 2, this loss of offsite power (LOOP) caused a loss of decay heat removal (DHR) capability as well as a partial loss of spent fuel pool (SFP)cooling. Upon investigation, the cause of the loss of both offsite power sources was the activation of the lockout relays on each transformer. The licensee found that two switches in the startup transformer crossover scheme, switches B and F, were not in their expected positions. The licensee investigated the lockout relay activations and determined that the B transfer switch being in the incorrect position was the cause of the LOOP. No reactor coolant system temperature changes were noted during the short period of time where DHR was lost. Units 1 and 2 shared SFP temperature increased 9.4 degrees over 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> and 53 minutes before full SFP cooling could be procedurally restored.

In planning for future electrical lineup changes during the Unit 2 refueling outage, the licensee approved a procedure revision request (PRR) for the procedure to share startup transformers between units, OP/0/A/1107/011 F, Revision 19, in October 2021. This revision was specifically requested to incorporate steps to allow the operators to completely isolate CT-2 while either Unit 1 or Unit 3 supplied Unit 2 electrical loads from their own startup transformer, CT-1 or CT-3 respectively. The goal of this revision was to eliminate confusion associated with how to get from a state of Unit 2 startup transformer being cross-tied with either Unit 1 or 3 to isolating CT-2 completely after swapping the Unit 2 main feeder bus (MFB) power supplies to CT-5, an alternate offsite power source. The PRR was processed in accordance with Duke Energy fleet-wide procedure AD-DC-ALL-0201, Development and Maintenance of Controlled Procedure Manual Procedures, Revision 27. Part of this process includes requirements for technical reviews to be done to ensure that the procedure, with any changes or additions to it, is safe, technically accurate, achieves the intended purpose, and meets all standards and requirements for performance, as described in procedure section 5.9.2. However, this revision was improperly prepared and included an error which repositioned incorrect switches while restoring from Unit 2 sharing startup transformers with Unit 1. Specifically, in Enclosure 4.2 (Unit 2 Sharing CT-1 Removal and Restoration of CT-2),step 2.2.1.G has the operator position the switches for sharing Unit 3 to normal, instead of Unit 1. This allowed transfer relay switches B and F to be left in the incorrect position, thus causing the subsequent transformer lockout and LOOP event. There were at least 3 required review points in the PRR review process per AD-DC-ALL-0201 that could have caught this error, specifically the technical review (PRRT) in step 2, the cross-discipline review (PRRI) in step 3, and the validation review (PRRV) in step 11. Additionally, it was pointed out by several personnel involved that the A, B, C component identification scheme of the transfer relay switches contributed to the error because the function of each switch and which units are affected is less obvious.

Corrective Actions: Operations staff identified the mispositioned switches and returned them to the required positions. The licensee executed another PRR to fix the error in OP/0/A/1107/011 F, Revision 19. The licensee also initiated a Corporate Functional Area Manager (CFAM) Escalation concerning procedure review quality due to several recent additional occurrences of procedural technical errors not being detected during the procedure technical or validation reviews.

Corrective Action References: NCR 2406969, PRR 2406977, NCR 2408602

Performance Assessment:

Performance Deficiency: The licensees failure to perform an adequate technical review of the PRR for the procedure, Sharing Startup Transformers Between Units, OP/0/A/1107/011 F Revision 19, in accordance with, Development and Maintenance of Controlled Procedure Manual Procedures, AD-DC-ALL-0201 Revision 27, was a performance deficiency.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Procedure Quality 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 perform an adequate technical review caused a LOOP and subsequent loss of DHR and partial loss of SFP cooling while performing maintenance on 2B2 RCP on November 27, 2021.

Significance: The inspectors assessed the significance of the finding using Appendix G, Shutdown Safety SDP. The inspectors reviewed the performance deficiency using IMC 0609 Attachment 4, Initial Characterization of Findings, which directs the inspectors: go to IMC 0609 Appendix G, Shutdown Significance Determination Process. The inspectors used IMC 0609 Appendix G, Attachments 1 and 2 to conduct a Phase I and Phase II screening and determined the performance deficiency could not be screened to Green and a phase III evaluation is required. An Oconee site specific shutdown model was developed to support this evaluation with support from Idaho National Laboratories and coordination with the licensee PRA staff. The HQ risk analyst and the regional SRA used SAPHIRE 8 version 8.2.5 and Oconee Units 1, 2, and 3 SPAR model version 8.63 which was then modified as discussed in the detailed risk analysis attached to this report. The plant was in mode 5, plant operating state (POS) II, late time window, post refuel, and 16 days after plant shutdown.

Since the performance deficiency was a precursor for a plant centered loss of offsite power during preparations for plant startup, an event assessment was conducted. The dominant accident sequence was a plant centered loss of offsite power, failure of emergency power to restore the buses resulting in a station black out, and failure to recover emergency or offsite power within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. The results of the detailed risk assessment concluded that plant risk was 8E-7 and therefore the issue screened to Very Low Safety Significance (Green). The detailed risk analysis is included as Attachment 1 to this report.

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. In this case, complacency through multiple levels of technical procedure review, a lack of recognition of the inherent risk associated with the transfer relay switches, and the failure to use adequate descriptive component identifications for the transfer switches all contributed to the event.

Enforcement:

Violation: 10 CFR Part 50, Appendix B, Criterion V, 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. Contrary to the above, on November 27, 2021, the licensee failed to use a procedure appropriate to the circumstances for an activity affecting quality. Specifically, the procedure for sharing startup transformers between units, OP/0/A/1107/011 F, Revision 19, contained an error that specified the incorrect position for two transfer relay switches.

Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Inadequate Test Acceptance Criteria Development for Essential Siphon Vacuum Pumps Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green None (NPP) 71111.22 Systems NCV 05000269,05000270,05000287/20220 01-02 Open/Closed Inspectors identified a Green finding and associated non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, when the licensee failed to verify the adequacy of the design of the essential siphon vacuum (ESV) pumps. Specifically, site engineers improperly developed a rotameter flowrate correction factor when establishing test acceptance criteria for routine pump surveillance testing.

Description:

The ESV pumps are QA-1 single-stage liquid ring vacuum pumps that are part of the emergency condenser circulating water (ECCW) system. They function to remove air from the condenser circulating water piping to ensure a siphon maintains flow from Lake Keowee to the low pressure service water system in the case of a loss of offsite power event. Technical specification (TS) surveillance requirement 3.7.8.7 tests the ESV pumps to verify that the pumps provide adequate capacity for this safety function. Periodic test PT/1,2,3/A/0261/010, Essential Siphon Vacuum System Test, measures the air flow through the pumps using a calibrated rotameter, but the indicated value is required to be corrected to the pressure and temperature conditions at the pump suction. Engineers derived the correction factor in site calculation OSC-6991, Test Acceptance Criteria for ESV Pumps.

Nominally, the system was designed to operate at 295 actual cubic feet per minute (acfm) at a suction pressure of 21 inches of mercury (inHg) vacuum and the test acceptance criteria allowed the pump to degrade no lower than 280 acfm because other ECCW system tests had their acceptance criteria based on this minimum ESV pump capacity.

On February 1, 2022, inspectors identified concerns with the derivation of the flowrate correction factor in OSC-6991. Inspectors identified that a friction factor of 0.2 was used when 0.02 was intended. Additionally, the formula for correction of rotameter flow to actual flow based on calibration temperature and pressure was inverted when compared to equations published by rotameter manufacturers. Once corrected, the errors amounted to approximately a 9% reduction in actual overall pump performance. Of the three ESV pumps for each of the three reactors, two pumps on unit 3 and two pumps on unit 2 no longer met the acceptance criteria and the remaining pumps maintained between 2% and 5% margin to the 280 acfm limit.

The associated operability reviews determined that the 2A, 2C, 3A, and 3C ESV pumps and 2A and 3A ECCW siphon headers were inoperable. A TS limiting condition for operability (LCO) did not apply due to the allowances for shared configurations in TS 3.7.8. Subsequently, these pumps were retested (with less vacuum present at the pump suction), which yielded air flows greater than 280 acfm and they were declared operable.

Inspectors have opened an unresolved item regarding the apparent variation in pump performance and control of vacuum levels during surveillance testing. Additionally, engineers completed an engineering change to revise the ECCW system test acceptance criteria to allow the ESV pump test acceptance criteria to be lowered to 251 acfm. Using this modified test acceptance criteria, the licensee concluded the pumps were always operable.

Corrective Actions: The licensee reevaluated recent pump test performance, performed retests of several pumps and revised the test acceptance criteria to lower the required flow from the ESV pumps.

Corrective Action References: 2416229, 2421652

Performance Assessment:

Performance Deficiency: The licensees failure to verify the adequacy of the design of the ESV pumps per 10 CFR Part 50, Appendix B, Criterion III, was a performance deficiency. Specifically, site engineers improperly developed a rotameter flowrate correction factor in OSC-6991 when establishing test acceptance criteria for routine pump surveillance testing.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Design 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, after evaluating the calculation errors, there was a reasonable doubt about the equipments operability resulting in the 2A, 2C, 3A, and 3C ESV pumps and the 2A and 3A ECCW siphon headers being declared inoperable. Assumptions in other calculations were also revised in order to reduce the acceptance criteria for the pumps.

Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using Exhibit 2, Mitigating Systems Screening Questions, inspectors determined the finding was of very low safety significance (Green) because it was a deficiency affecting the qualification of the ESV pumps, but they maintained their operability based on the licensee's determination that the test acceptance criteria could be changed.

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 III, required, in part, that design control measures shall provide for checking the adequacy of design, such as by the performance of design reviews and that these measures shall be applied to items such as delineation of acceptance criteria for inspection and tests. Contrary to the above, since January 8, 1998, the design reviews delineating the acceptance criteria for ESV pump testing did not verify the adequacy of design of the ESV pumps due to calculational errors. Specifically, site engineers improperly developed a rotameter flowrate correction factor in OSC-6991 when establishing test acceptance criteria for routine pump surveillance testing which non-conservatively affected interpretation of the test results.

Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Unresolved Item Essential Siphon Vacuum Testing 71111.22 (Open) URI 05000269,05000270,05000287/2022001-03

Description:

Inspectors identified an unresolved item. Technical specification surveillance requirement 3.7.8.7 requires the licensee to, "Verify the developed capacity of each required ESV pump at the test point is greater than or equal to the required capacity." The technical specification bases for the surveillance describe that, "The vacuum level must be within a prescribed range during this measurement to ensure that the flowmeter is on-scale and the pump operating liquid is not cavitating. Note that the pump is a constant volume machine. Thus, there is not a single test point but a range of acceptable vacuum levels." Inspectors noted that the current test procedure, PT/1,2,3/A/0261/010, "Essential Siphon Vacuum System Test," included a 21 inches of mercury (inHg) upper limit on ESV tank vacuum present during testing, but there was no corresponding lower limit. Calculation OSC-6961, "ECCW Siphon Air Inleakage Model ESV System Performance Model and Test Acceptance Criteria," described that the expected level of vacuum present at the ESV tank during design basis conditions was approximately between 21 and 18 inHg. However, surveillance testing was typically conducted with tank vacuum in the range of 14 to 10 inHg. Engineers did not view the difference between test and design basis conditions to be a problem because the ESV pumps were expected to perform equally well over a broad range of vacuum conditions since they ideally operate as constant volume machines. Despite expecting consistent performance, the most recent test procedure revision added a note that, "In a review of past performance test results... the acceptance criteria... is more likely to be met if flowrate is throttled to greater than or equal to 160 standard cubic feet per minute." This guidance instructed operators to apply only enough throttling to bring the rotameter to the upper end of its scale when measuring air flow. Recent tests performed at lower indicated flows and higher tank vacuums were found to not satisfy the acceptance criteria. Engineers explained the performance variation as potentially relating to the development of choked flow when the test line is excessively throttled and that this may invalidate the rotameter correction factor that is used to interpret the indicated flow reading. The licensee has subsequently performed analyses to support lowering the acceptance criteria to gain margin during testing, but the licensee has not measured actual pump performance under design basis conditions due to concerns that additional throttling may result in a choked flow condition and provide invalid test data.

Planned Closure Actions: In order to determine whether a performance deficiency exists, the inspectors need additional information supporting the assumption that the ESV pumps can be expected to provide essentially equivalent volumetric flow at design basis vacuum conditions as compared to the less demanding conditions created during routine surveillance testing.

Licensee Actions: As described in the corrective actions for NCV 05000269,05000270,05000287/2022001-02, "Inadequate Test Acceptance Criteria Development for Essential Siphon Vacuum Pumps," the licensee has reanalyzed the ESV system requirements which resulted in less required flow from the ESV pumps. Using the new criteria, the pumps generally operate with more than 12% margin; however, it is not clear whether this margin diminishes under the different conditions that could be present during a design basis event. The licensee's evaluations note other areas of conservatism such as the assumed air in-leakage rate to be handled by the ESV system as compared to actual system tightness demonstrated during routine emergency condenser cooling water system testing.

Corrective Action References: 2425510 Failure to Identify a Condition Adverse to Quality Associated with Essential Siphon Vacuum Pumps Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.1] - 71152A Systems NCV Resources 05000269,05000270,05000287/20220 01-04 Open/Closed The inspectors identified a Green finding and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, when the licensee failed to promptly identify a condition adverse to quality associated with test acceptance criteria (TAC) for the essential siphon vacuum (ESV) pumps. Specifically, a nuclear condition report (NCR) was not written and thus, an operability determination was not performed for approximately two weeks after inspectors communicated specific concerns about errors in the TAC for the ESV pumps.

Description:

The ESV pumps are QA-1 components that are part of the ESV and emergency condenser circulating water systems. They function to remove air from the condenser circulating water piping to ensure a siphon maintains flow from Lake Keowee to the low pressure service water system in the case of a loss of offsite power event. On February 1, 2022, inspectors communicated specific apparent calculation issues involving performance test acceptance criteria used to verify operability of the ESV pumps during periodic technical specification (TS) surveillance testing. Specifically, the inspectors communicated two issues with calculation OSC-6991, Test Acceptance Criteria for ESV Pumps, Revision 3. First, that the friction factor used on page 16 of the calculation was 0.2 when 0.02 was intended. Second, that the formula for correction of rotameter flow to actual flow based on calibration temperature and pressure was inverted when compared to equations published by rotameter manufacturers. Inspectors also identified that the above two errors, if confirmed, would have an impact on the formula used during surveillance test PT/3/A/0261/010, Essential Siphon Vacuum System Test, Revision 28.

The licensee acknowledged receipt of the communicated issues during discussions at a weekly meeting with the residents on February 1, 2022. They indicated at the time that the appropriate engineer would be identified to follow up on the concerns. On February 5, 2022, Oconee Unit 2 experienced an automatic reactor trip, a notification of unusual event, and a forced outage through February 27, 2022. On February 15, 2022, the ESV TAC concerns were discussed again during a meeting between the residents and the licensee. The residents emphasized the importance of taking prompt action to document conditions adverse to quality in the corrective action program and evaluating issues that can affect technical specification test acceptance criteria for impacts on operability. Later that day, the licensee wrote NCR 2416229, which documented and confirmed the errors in the calculation. The associated operability reviews determined that the 2A, 2C, 3A, and 3C ESV pumps did not meet the test acceptance criteria of their most recent test when the calculational errors were properly corrected, resulting in them being declared inoperable. This also resulted in the 2A and 3A emergency condenser cooling water (ECCW) headers being declared inoperable. A technical specification limiting condition for operation did not apply due to the allowances for multiple configurations in TS 3.7.8, ECCW.

On February 16, 2022, the licensee wrote a nuclear condition report to acknowledge the delay between communication of the NRC concerns and corrective action program documentation with subsequent confirmation that operability of multiple ESV pumps was affected. Subsequent discussions revealed that engineering resources had been prioritized to respond to the February 5, 2022, and subsequent events over review of the NRC ESV TAC concerns.

Corrective Actions: The licensee wrote a NCR to acknowledge the delay between communication of the NRC concerns and the confirmation that operability of multiple ESV pumps was affected. Additional corrective actions were initiated to correct and revise the ESV TAC calculation and retest the ESV pumps.

Corrective Action References: 2416229, 2416463

Performance Assessment:

Performance Deficiency: The failure to promptly identify a condition adverse to quality associated with ESV TAC as required by 10 CFR Part 50, Appendix B, Criterion XVI, was a performance deficiency. Specifically, the licensee inappropriately delayed identification of errors in ESV pump TAC, conditions adverse to quality, that initially impacted operability of multiple ESV pumps.

Screening: The inspectors determined the performance deficiency was more than minor because if left uncorrected, it would have the potential to lead to a more significant safety concern. Specifically, an unrecognized increase in risk would occur when conditions with a substantive functional impact on the capability of a system to perform its specified safety function are not promptly identified, evaluated, and corrected.

Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using exhibit 2, Mitigating Systems Screening Questions, inspectors determined the finding was of very low safety significance (Green) because the finding was not a degraded condition that represented a loss of PRA system or function as defined in the Plant Risk Information e-Book (PRIB) or the licensees PRA for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Specifically, the delayed identification of the conditions adverse to quality did not result in a loss of function.

Cross-Cutting Aspect: H.1 - Resources: Leaders ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety.

Specifically, engineering resources were prioritized to other onsite events over evaluation of the ESV TAC concerns communicated by the inspectors.

Enforcement:

Violation: 10 CFR Part 50, Appendix B, Criterion XVI, requires, in part, that conditions adverse to quality be promptly identified and corrected. Contrary to the above, a condition adverse to quality associated with ESV TAC was communicated to the licensee on February 1, 2022, but was not identified in the corrective action program until February 15, 2022. Specifically, several errors in the TAC calculation impacted the testing results of ESV pumps and evaluation of this condition was delayed in the corrective action program.

Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Licensee-Identified Non-Cited Violation 71152A This violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Violation: Oconee Nuclear Station Unit 2 Renewed Facility Operating License Condition 3.D required, in part, Duke Energy Carolinas, LLC shall implement and maintain in effect all provisions of the approved fire protection program that comply with 10 CFR 50.48(a) and 10 CFR 50.48(c) and NFPA 805. NFPA 805 section 3.2.3 requires procedures to be established for implementation of the fire protection program. Oconee implemented this NFPA requirement, in part, through procedure OP/2/A/1102/001, Controlling Procedure for Unit Startup. In order to satisfy the fire protection plan, section 11.6.2 of enclosure 4.1 of OP/2/A/1102/001, required operators to ensure breaker 2XSF-F2B for valve 2RC-219 (SSF high flow reactor coolant letdown control valve) was open after reactor coolant temperature was greater than or equal to 525°F when preparing to enter technical specification mode

2. Contrary to the above, on December 12, 2021, the licensee failed to ensure the breaker

was open. Specifically, operators transferred signatures from a previous completion of the procedure steps without recognizing that the breaker had been repositioned by subsequent activities. As a result, the unit was operated in an unanalyzed condition for approximately 36 hours4.166667e-4 days <br />0.01 hours <br />5.952381e-5 weeks <br />1.3698e-5 months <br /> in modes 1 and 2 between December 12 and 13, 2021.

Significance/Severity: Green. Using IMC 0609, Appendix F, "Fire Protection Significance Determination process," inspectors, with the assistance of a senior risk analyst (SRA),determined the finding was of very low safety significance (Green). Specifically, screening questions 1.5.1-A and 1.5.1-B were both answered "Yes" because the plant had a fire PRA capable of adequately evaluating the risk associated with the finding and the licensee's risk-based evaluation for this fire finding indicated a change in core damage frequency to be less than 1E-6 per year, and the evaluation result was accepted by an SRA.

Corrective Action References: 2409104 Licensee-Identified Non-Cited Violation 71152A This violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Violation: 10 CFR 50, Appendix B, Criterion V requires, 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. Site procedure OP/2/A/1600/008, enclosure 4.1, SSF RC Makeup and Letdown Systems Lineup for Standby, required operators ensure breaker 2XSF-F4C (Unit 2 safe shutdown facility reactor coolant makeup pump (RCMUP) breaker)was closed as part of preparations for mode 3 operation as directed by OP/2/A/1102/001, Controlling Procedure for Unit Startup. Contrary to the above, on December 5, 2021, procedure OP/2/A/1102/001 was not appropriate to the circumstances because step 9.2 of 4.1 did not require reperformance of OP/2/A/1600/008, enclosure 4.1, when the RCMUP breaker was opened to support a pressurizer cooldown after the enclosure was last performed. Specifically, the procedure allowed operators to accept an earlier performance of the system lineup although subsequent activities repositioned the RCMUP breaker without restoration. These events resulted in reactor operation with the RCMUP inoperable in modes 1, 2 and 3 for 205 hours0.00237 days <br />0.0569 hours <br />3.38955e-4 weeks <br />7.80025e-5 months <br /> between December 5 and 13, 2021.

Significance/Severity: Green. Inspectors used inspection manual chapter (IMC) 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, and determined that the detailed risk evaluation was required because the single train system was inoperable for greater than its technical specification 7 day allowed outage time. A senior risk analyst determined the finding was of very low safety significance (Green). Specifically, a detailed risk evaluation for this finding indicated a change in core damage frequency to be less than 1E-6 per year.

Corrective Action References: 2409104 Inappropriate Coating on Emergency Feedwater Piping Results in a Notification of Unusual Event Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green None (NPP) 71153 NCV 05000269,05000270,05000287/20220 01-05 Open/Closed A self-revealed Green finding and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was identified for the licensee's use of an inappropriate coating on emergency feedwater piping in the Unit 2 west penetration room. Specifically, the piping was painted with a coating that had a lower temperature rating than the design temperature of the piping and this resulted in a large amount of smoke being generated during a plant event on February 5, 2022.

Description:

On February 5, 2022, at 0343 EST, Oconee Unit 2 experienced an automatic reactor trip caused by the simultaneous tripping of all four reactor coolant pumps (RCPs)when their breakers opened due to activation of undervoltage relaying caused by failure of a single potential transformer fuse for a voltage sensing circuit on the 7kV normal bus. At 0347 EST, multiple fire alarms were received from the west penetration room in the auxiliary building. The onsite fire brigade responded to the west penetration room and found that the entire room was full of thick smoke. At 0357 EST, the site declared a notification of unusual event (NOUE) due to the indications of a fire that would not be extinguished within 15 minutes. Subsequently, offsite fire resources were requested and deployed within the protected area to assist with the response.

After finding no obvious signs of combustion in the west penetration room and completing ventilation of the smoke, maintenance technicians and others were able to gain entry to the room for further investigation of the source of smoke. It was discovered that sections of emergency feedwater piping had sustained damage and degradation to the coating on the outside of the piping. The coating was cracked and flaking off and the smell of the damaged coating was consistent with the smell of the smoke. It was later determined that the portions of the emergency feedwater piping that experienced coating degradation were consistent with the flow path of approximately 450°F feedwater that would be expected following a reactor trip with no RCPs running. Following a reactor trip with RCPs providing forced reactor coolant system cooling, and where main feedwater injection remains available, no flow would be expected through emergency feedwater injection lines in the penetration rooms. However, following a reactor trip where the reactor coolant system is cooling without RCPs under a natural circulation flow regime, feedwater is sent through a different flow path to an emergency feedwater feed ring located higher in the steam generators in order to promote better flow through the reactor coolant system. A previous, similar event where all RCPs were lost at 100% power at Oconee was not identified based on a historical review.

The licensee later determined that the coating on these sections of emergency feedwater piping was not appropriate for the potential design temperature that the piping could experience. Review of the site Field Coating Specification Manual, Revision 7, and OMCS-0170.02 Service Level II, Oconee Maintenance Coating Schedule, Revision 12, determined that there were two different coatings authorized for the piping in question. Neither authorized coating was rated to the 450°F temperature that the piping experienced, with one being rated to 200°F and the other to 300°F. It was not possible to verify which of the two coatings had been installed, but it was confirmed that neither should have been allowed for the emergency feedwater piping in this area. Information contained in the coating data sheets about their degradation and testing at temperatures higher than their design was consistent with the observations of the smoke and coating degradation seen in the west penetration room. Specifically, the observations of no flames, no signs of combustion such as black burns or soot, and the smell and consistency of the smoke itself were all accordant with a degradation or smoldering of the coating without an actual fire.

Corrective Actions: The licensee wrote NCRs 2414872 and 2414918 to address the NOUE and the source of the smoke in the west penetration room. Corrective actions included removal and abatement of the existing coatings on affected piping on all three units and evaluation of a longer-term solution to appropriately protect the piping.

Corrective Action References: 2414872, 2414918

Performance Assessment:

Performance Deficiency: The failure to select and install a proper coating rated for the expected design conditions of the emergency feedwater piping in the west penetration room, in accordance with the requirements of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was a performance deficiency.

Screening: The inspectors determined the performance deficiency was more than minor because it could reasonably be viewed as a precursor to a significant event. Specifically, the inappropriate coating resulted in the declaration of a NOUE, required onsite and offsite fire brigade resources to respond, limited access to the west penetration room for a period after the trip, and created a distraction during operator reactor trip response.

Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Using exhibit 1, Initiating Events Screening Questions, inspectors determined the finding was of very low safety significance (Green) because it did not impact the frequency of a fire or internal flooding initiating event. This determination was based, in part, on the above conclusions that no fire or flame resulted from this event.

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 III, Design Control, requires in part that measures shall be established for the selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of the structures, systems, and components. Contrary to the above, from sometime prior to the early 2000s until February 2022, measures were not established for the selection and review for suitability of application of materials that are essential to the safety-related functions of structures, systems, and components. Specifically, sections of emergency feedwater piping in the west penetration rooms of all three units had coatings applied that were not suitable for the maximum design temperature of the piping.

Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Failure to Respond to Priority Process Computer Alarm Condition Cornerstone Significance Cross-Cutting Report Aspect Section Initiating Events Green [H.12] - Avoid 71153 NCV 05000270/2022001-06 Complacency Open/Closed A self-revealed Green finding and associated non-cited violation (NCV) of technical specification 5.4.1, was identified when the licensee failed to respond to an unexpected 2A feedwater pump turbine controller fault priority process computer alarm.

Description:

On February 5, 2022, Unit 2 experienced a reactor trip and subsequent forced outage to resolve equipment issues. On February 11, 2022, while the unit was in cold shutdown with decay heat removal through the low pressure injection system, a fault occurred on the 2A feedwater pump controller while the pump was out of service. The alarm was indicated by the process computer as a priority alarm. AD-OP-ALL-1000, Conduct of Operations, section 5.5.2, Alarms, stated that, operators will respond to all alarms, expected or unexpected, including priority process computer alarms. The alarm response guide required the operator to notify maintenance personnel to investigate, determine the cause, and attempt to reset the alarm. Operators acknowledged the alarm, and it remained active, but no action was taken per the alarm response guide since the pump was not presently needed for cold shutdown operations. On February 13, 2022, the unit was moved to the hot standby mode of operation for plant heat up greater than 250°F, which would require operation of the main feedwater pumps. Additional operators dedicated to the heat up evolution were brought in to supplement the operating crew. With the process computer alarm still active, plant heat up was commenced using the 2A feedwater pump per OP/2/A/1102/001, Controlling Procedure for Unit Startup, and OP/2/A/1106/002 B, FDWPT Operation, Enclosure 4.1, Startup of 2A FDWPT. These procedures did not direct operators to evaluate whether the pumps had a controller fault alarm present, nor did operators identify the presence of the process computer alarm or the fault light locally at the pump prior to the evolution.

Once the feedwater pump was started, the controller fault disabled the servo that allows the pump to change its operating speed to provide higher discharge pressure. This capability was important for the evolution because secondary plant pressures were being raised from approximately 100 psig to 885 psig, but a feedwater pump remaining at minimum speed could only produce approximately 770 psig at the steam generator. Once steam generator pressure exceeded approximately 770 psig, the feedwater pump could no longer produce enough discharge pressure to maintain flow to the steam generators. As a result, the 'A' and

'B' steam generator levels began to lower from 26 to 20 inches in the extended startup range over the next 4.5 minutes. Once one generator had a level that was below 21 inches for more than 30 seconds, the motor driven emergency feedwater pumps were automatically actuated by low level initiation circuitry. The emergency feedwater system restored and maintained steam generator levels while problems with the main feedwater pump controller were investigated and later resolved.

Corrective Actions: Maintenance technicians reset the fault alarm and replaced a potentially degraded knife switch prior to recommencing plant heat up.

Corrective Action References: 2415861, 2415853

Performance Assessment:

Performance Deficiency: The failure to respond to a priority process computer alarm per AD-OP-ALL-1000, section 5.5.2, Alarms, was a performance deficiency. Specifically, operators failed to take alarm response actions for an unexpected 2A feedwater pump turbine controller fault priority process computer alarm.

Screening: The inspectors determined the performance deficiency was more than minor because it was associated with the Human 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 respond to an alarm condition resulted in an inability to maintain steam generator water levels and an emergency feedwater actuation during a plant heat up on February 13, 2022.

Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Inspectors used exhibit 1, Initiating Events Screening Questions, and concluded the finding was of very low safety significance (Green). Specifically, screening question B for Transient Initiators was answered as No because the reactor was already shutdown when the loss of main feedwater occurred; therefore, the finding did not cause both a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of a trip to a stable shutdown condition.

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. In this case, multiple shifts of operators, and the supplemental operators performing the plant heat up evolution, did not recognize the latent issue (fault alarm) associated with the 2A feedwater pump controller prior to relying on the pump for plant heat up.

Enforcement:

Violation: Technical specification 5.4.1, required, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in regulatory guide (RG) 1.33, revision 2, appendix A, February 1978. RG 1.33, section 1, Administrative Procedures, requires procedures for authorities and responsibilities for safe operation and shutdown. This requirement was partly implemented by the licensees procedure AD-OP-ALL-1000, Conduct of Operations. AD-OP-ALL-1000 section 5.5.2, Alarms, required that operators will respond to all alarms, expected or unexpected, including priority process computer alarms. Contrary to the above, on February 11, 2022, operators failed to respond to an unexpected 2A feedwater pump turbine controller fault priority process computer alarm.

Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Failure to Report Valid Actuations of Emergency Feedwater System Cornerstone Severity Cross-Cutting Report Aspect Section Not Severity Level IV Not 71153 Applicable NCV 05000270/2022001-07 Applicable Open/Closed The inspectors identified a Severity Level IV non-cited violation (NCV) of 10 CFR 50.72(b)(3)(iv)(A) when the licensee failed to notify the NRC within eight hours of a valid actuation of the emergency feedwater system on two occasions. Specifically, the Unit 2 motor driven emergency feedwater pumps were automatically actuated by a low level initiation circuit in response to a low steam generator water level on February 13, 2022, at 1625 EST, and February 21, 2022, at 2207 EST and no NRC notifications per 10 CFR 50.72(b)(3)(iv)(A) were made.

Description:

Example 1) At approximately 1102 EST, on February 13, 2022, while in operating mode 3, the licensee began raising pressure in the Unit 2 main steam system in preparation for reactor startup. As steam generator pressures were being increased from 100 to 885 pounds per square inch (psig), the 2A main feedwater pump failed to respond to increased speed demand due to a controller fault that kept the pump running at its low speed setting. Once steam generator pressure exceeded approximately 770 psig, the feedwater pump could no longer produce enough discharge pressure to maintain flow to the steam generators. As a result, the 'A' and 'B' steam generator levels began to lower from 26 to 20 inches in the extended startup range over the next 4.5 minutes. Once one generator had a level that was below 21 inches for more than 30 seconds, the motor driven emergency feedwater pumps were automatically actuated by low level initiation circuitry. The emergency feedwater system restored and maintained steam generator levels while problems with the main feedwater pump controller were investigated and later resolved.

Example 2) At approximately 2205 EST, on February 21, 2022, while operating in mode 1 at 68% power, the 2A main feedwater control valve failed to a closed position. As a result, the

'A' steam generator level began to lower from 95 to 18 inches in the extended startup range over the next 2 minutes. Once the 'A' steam generator had a level that was below 21 inches for more than 30 seconds, the motor driven emergency feedwater pumps were automatically actuated by low level initiation circuitry. Operators manually tripped the reactor at approximately the same time the emergency feedwater pumps were actuated. The emergency feedwater system restored and maintained steam generator levels and operators stabilized the plant to normal post-trip conditions. At 0144 EST, on February 22, 2022, the licensee reported the manual actuation of the reactor protection system via event notification 55750 per 10 CFR 50.72(b)(2)(iv)(B); however, there was no other report made for the valid actuation of the emergency feedwater system per 10 CFR 50.72(b)(3)(iv)(A).

On both occasions, the licensee used internal guidance from a job aid referenced by procedure AD-LS-ALL-0006, Notification/Reportability Evaluation. The licensee considered the emergency feedwater actuations to be invalid since the low level initiation signal was not credited in the safety analysis. Inspectors concluded that the licensee incorrectly characterized this actuation as invalid. NUREG-1022, revision 3, states that valid actuations are those that are initiated in response to actual plant conditions or parameters satisfying the requirements for initiation of the system. In this case, an actual low level in a steam generator satisfied the requirements for initiation of the motor driven emergency feedwater pumps.

Corrective Actions: The licensee made the required notifications on March 23, 2022, and initiated actions to submit a Licensee Event Report (LER).

Corrective Action References: 2421220

Performance Assessment:

The inspectors determined this violation was associated with a minor performance deficiency.

Enforcement:

The ROPs significance determination process does not specifically consider the regulatory process impact in its assessment of licensee performance. Therefore, it is necessary to address this violation which impedes the NRCs ability to regulate using traditional enforcement to adequately deter non-compliance.

Severity: Based on the examples provided in section 6.9 of the Enforcement Policy, dated January 14, 2022, "Inaccurate and Incomplete Information or Failure to Make a Required Report," the performance deficiency was determined to be a SL IV violation. Specifically, example 6.9 states that a SL IV violation involves a failure to make a report to the NRC in accordance with 10 CFR 50.72.

Violation: 10 CFR 50.72, "Immediate notification requirements for operating nuclear power reactors," section (b)(3)(iv)(A) requires, in part, the licensee to notify the NRC as soon as practical and in all cases within eight hours of the occurrence of any event or condition that results in valid actuation of any of the systems listed in paragraph (b)(3)(iv)(B) of that section. Paragraph (b)(3)(iv)(B)(6) included the emergency feedwater system for pressurized water reactors. Contrary to the above, at 0025 EST on February 14, 2022, and 0607 EST on February 22, 2022, the licensee failed to notify the NRC within eight hours of the valid actuation of the Unit 2 motor driven emergency feedwater pumps.

Enforcement Action: This violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Licensee-Identified Non-Cited Violation 71153 This violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Violation: 10 CFR 50, Appendix B, Criterion V, requires, 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. Contrary to above, on November 30, 2021, operators failed to accomplish enclosure 4.1, "Normal Lineup of PSW System for Standby," in accordance with OP/0/A/1650/001, "PSW System." Specifically, operators completed a Unit 2 system alignment checklist from the procedure prior to completing the initial conditions of the procedure. Performing the procedure out of sequence resulted in leaving valves 2PSW-8, 10 and 200 in a closed position which prevented the ability to supply either Unit 2 steam generator from the PSW pump while the reactor was in mode 1 or 2 on two occasions: 1)between December 6 and 7, 2021; and 2) again on December 7, 2021, following a period of mode 3 operation.

Significance/Severity: Green. Inspectors used inspection manual chapter (IMC) 0609, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, and determined that the period of misalignment of the single train protected service water system did not represent a loss of the system for greater than its technical specification 14 day allowed outage time or a loss of a PRA system and/or function as defined in the Plant Risk Information eBook for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

Corrective Action References: 2408472 Licensee-Identified Non-Cited Violation 71153 This violation of very low safety significance was identified by the licensee and has been entered into the licensee corrective action program and is being treated as a non-cited violation, consistent with Section 2.3.2 of the Enforcement Policy.

Violation: 10 CFR 50.72, "Immediate notification requirements for operating nuclear power reactors," section (b)(2)(iv)(B), requires, in part, the licensee to notify the NRC as soon as practical and in all cases within four hours of the occurrence of any event or condition that results in actuation of the reactor protection system (RPS) when the reactor is critical except when the actuation results from and is part of a pre-planned sequence during testing or reactor operation. Contrary to the above, an automatic Unit 2 reactor trip occurred on February 5, 2022, at 0343 Eastern Standard Time (EST) and the licensee failed to notify the NRC within four hours of this RPS actuation. The required report was made on February 5, 2022, at 0745 EST.

Significance/Severity: Severity Level IV. Based on the examples provided in section 6.9 of the Enforcement Policy, dated January 14, 2022, "Inaccurate and Incomplete Information or Failure to Make a Required Report," the performance deficiency was determined to be a Severity Level (SL) IV violation. Specifically, example 6.9 states that a SL IV violation involves a failure to make a report to the NRC in accordance with 10 CFR 50.72.

Corrective Action References:

EXIT MEETINGS AND DEBRIEFS

The inspectors verified no proprietary information was retained or documented in this report.

On April 28, 2022, the inspectors presented the integrated inspection results to Mr.

Steven Snider and other members of the licensee staff.

On March 31, 2022, the inspectors presented the Emergency Preparedness Exercise inspection results to Mr. Steven Snider and other members of the licensee staff.

DOCUMENTS REVIEWED

Inspection Type Designation Description or Title Revision or

Procedure Date

71111.01 Miscellaneous CSD-WC-ALL- Severe Weather Preparations and Considerations 4

0390-01

Procedures OP/0/A/1104/037 Plant Heating 008

OP/0/A/1104/041 Auxiliary Building Ventilation 046

OP/0/A/1106/041 Turbine Building Ventilation 011

OP/0/B/1104/050 Weather Related Activities 006

OP/1/A/1104/051 ESV System 028

PT/0/A/0110/017 Cold Weather Protection 016

RP/0/A/1000/035 Severe Weather Preparations 006

Work Orders 20412553, 20425218

71111.04 Corrective Action 2412141

Documents

Drawings O FD-102A-01-0 Flow Diagram of Low Pressure Injection System Borated 072

Water Supply & LPI Pump Suction

O FD-102A-01-02 Flow Diagram of Low Pressure Injection System (LPI Pump 062

Discharge)

O FD-124B-01-01 Flow Diagram of Low Pressure Service Water System 070

(Auxiliary Building Services)

OFD-101A-2.1 Flow Diagram of High Pressure Injection System Letdown 51

Section

OFD-101A-2.2 Flow Diagram of High Pressure Injection System Storage 46

Section

OFD-101A-2.3 Flow Diagram of High Pressure Injection System Charging 34

Section

OFD-101A-2.4 Flow Diagram of High Pressure Injection System Charging 48

Section

Miscellaneous OM 209-0128.001 PSW Service Water Portable Submersible Pump - Gorman 0

Rupp Model S8B1-E100 (8) Spec Data

Procedures AD-OP-ALL-0201 Protected Equipment 9

MP/0/A/1300/100 Maintenance Support for PSW Portable Pump Test 1

OP/1/A/1104/004 Low Pressure Injection System 160

OP/2/A/1104/002 HPI System 177

Inspection Type Designation Description or Title Revision or

Procedure Date

71111.05 Calculations OSC-9293 NFPA 805 Transition Radioactive Release G-1 Table 004

OSC-9314 NFPA 805 Transition Risk-Informed Performance-Based 006

Fire Risk Evaluation

OSC-9375 ONS Fire PRA - Fire Scenario Report 009

Fire Plans CSD-ONS-PFP- Pre-Fire Plan for U2 Auxiliary Building Elevation 796 001

2AB-0796

CSD-ONS-PFP- Pre-Fire Plan for U3 Auxiliary Building Elevation 809 000

3AB-0809

O-0310-FZ-010 AB - Unit 2 Fire Protection Plan, Fire Area & Fire Zone 004

Boundaries Plan at EL 796+6 & EL 797+6

O-0310-K-008 Fire Protect AB U2 EL 796+6 023

Procedures AD-EG-ALL-1520 Transient Combustible Control 14

MP/0/A/1705/019 Fire Protection - SLC Related Fire Doors - HELB Doors - 28

Annual Inspections

71111.06 Calculations OSC-10790 Oconee Nuclear Station Internal Flooding Analysis 3

OSC-11769 Analysis of Postulated HELBs Outside of Containment 4

Corrective Action 2410381

Documents

Drawings O-401B Piping Layout Mezzanine Floor Plan Turbine Building 60

O-439A Piping Layout East Penetration Room Elevation 809-3 to 82

21-6 Auxiliary Building

O-510N Miscellaneous Piping El. 822-0 - Auxiliary Building Plan & 30

Sections

71111.11Q Miscellaneous OP-OC-SAE- Simulator Exercise Guide (SAE-R214) 03c

R214

Procedures AD-OP-ALL-1000 Conduct of Operations 18

AD-TQ-ALL-0420 Conduct of Simulator Training and Evaluation 18

AP/0/A/1700/006 Natural Disaster 033

EP/1/A/1800/001 Unit 1 EOP Immediate Manual Actions and Subsequent 003

Actions

OP/2/A/1102/001 Controlling Procedure for Unit Startup 282

OP/2/A/1102/001 Controlling Procedure for Unit Startup 284

71111.13 Calculations OSC-11805 Generic Load Drop Analysis for Turbine Building Operating 1

Floor Lifts

Inspection Type Designation Description or Title Revision or

Procedure Date

Corrective Action 2422061

Documents

Miscellaneous Phoenix ONS Unit 3 Risk Profile for March 30, 2022

Unit 3 Operator Logs for March 30, 2022

Phoenix ONS Unit 1 risk profile for January 24, 2022

Unit 2 Defense in Depth Status Sheet 10:15 02/10/2022

Operations Communications External Department Guidance, 01/26/2022

Feedwater Heater Replacement Heavy Lifts on Turbine

Deck - Elev. 822+0

Procedures AD-WC-ALL-0240 On-line Risk Management Process 3

AP/2/A/1700/001 Unit Runback 17

Work Orders 20525787

71111.15 Calculations OSC-6596 Mechanical Design Inputs for the ESV System 8

OSC-6991 Test Acceptance Criteria for ESV Pumps 4

OSC-6991 Test Acceptance Criteria for ESV Pumps 5

Corrective Action 2414034, 01905031, 2417766, 2417761

Documents

2415080

Drawings KFD-111A-1.1 Flow Diagram of Depressing Air System and Vacuum Break 14

System

OFD-121D-2.1 Flow Diagram of Emergency Feedwater System 42

Miscellaneous Work Request 20218987

NWS Traveler # Valve S/N BL-08890 02/11/2022

2-48

Procedures PT/1/A/2200/002 KHU-1 Bi-Monthly Surveillance 021

PT/1/A/2200/022 KHU-1 Control Valve IST Surveillance 009

Work Orders 20412553

71111.18 Calculations OSC-10902 Oconee 2 Cycle 31 SDM Verification with 2 Dropped Rods 0

OSC-11581 U1/2/3, Keowee EPS and 100kV APS Voltage Adequacy 1

Analyses

OSC-4300 Protective Relay Settings 39

OSC-6578 UFSAR Section 15.7 - Dropped Rod Analysis 6

Inspection Type Designation Description or Title Revision or

Procedure Date

Corrective Action 2403757, 2411493, 2417190, 2419707, 2417475, 2419726,

Documents 2419536, 2419983, 2420522

Drawings 03-SL-1300.01- Lee CT Replacement Project Overall One Line Diagram 4

00-01

Engineering NSM ON-53015 0

Changes

Miscellaneous Duke Power letter, Response to NRR and AOED Draft October 31,

Reports on the Oconee Emergency Power System 1996

Duke Power letter, Oconee Integrated Emergency Power February 25,

and Engineered Safeguards Functional Test Keowee and 1997

Lee Voltage and Frequency Protection Modification

NRC letter, Interim Report - Oconee Nuclear Station March 17,

Emergency Electrical Power System 1998

NRC letter, Final Report - Oconee Nuclear Station, Units 1, January 19,

2, and 3 - Emergency Electrical Power System 1999

ONEI-0400-567 Oconee 2 Cycle 31 Core Operating Limits Report 1

OSS-0254.00-00- 4kV Essential Auxiliary Power System 24

2000

Procedures AD-OP-ONS- Oconee Specific Abnormal Operation Guidance 4

0002

AP/2/A/1700/001 Unit Runback 17

PT/2/A/1103/015 Reactivity Balance Procedure (Unit 2) 77

PT/3/A/0261/010 Essential Siphon Vacuum System Test 29

71111.19 Calculations OSC-7339 ESV Float Valve Test Acceptance Criteria 1

Corrective Action 2412263, 2415767, 2422845

Documents

Drawings OFD-102A-01-02 Flow Diagram of Low Pressure Injection System (LPI Pump 062

Discharge)

OM 254.0451.001 NWS Safety Valve Test Procedure for Duke Energy - 4

Oconee Nuclear Station Pressurizer Safety Valves

OM 254.0452.001 NWS Refurbishment Procedure for Duke Energy - Oconee 1

Nuclear Station Pressurizer Safety Valve

ONTC-0-130A- Oconee Nuclear Station 1, 2, 3ESV-1, 2 Full Opening 1

0004-001 Acceptance and Closure Verification Test

Inspection Type Designation Description or Title Revision or

Procedure Date

ONTC-0-130A- Oconee Nuclear Station 1, 2, 3ESV-1, 2 Full Opening 1

0004-002 Acceptance and Closure Verification Test

ONTC-1-102A- Unit 1 LPI Pump Performance Test Acceptable and 1

0030-01 Required Action Setpoints for Pump Total Developed Head

ONTC-1-102A- Unit 1 LPI Pump Performance Test Acceptable and 1

0030-02 Required Action Setpoints for Pump Total Developed Head

Procedures IP/0/0101/007 Control Relay Replacement 028

IP/0/B/4980/001 Transformer ST Relay Testing 1

5T

IP/1-2/A/0250/001 Low Pressure Service Water Discharge Pressure and Motor 014

B Temperature Instrument Calibration

PT/1/A/0203/006 Low Pressure Injection Pump Test - Recirculation 093

A

PT/2/A/0152/020 AFIS Circuitry Test 027, 029

Work Orders 20295960, 20499131, 20318402, 20412551

71111.20 Procedures OP/2/A/1102/001 Controlling Procedure for Unit Startup 282

OP/2/A/1103/011 Draining and Nitrogen Purging RCS 102

71111.22 Calculations OSC-6586 Emergency Siphon Vacuum Pump Sizing Calculation 1

OSC-6595 Mechanical Design Inputs for the Essential Siphon Vacuum 8

System

OSC-6991 Test Acceptance Criteria for ESV Pumps 3

OSC-7339 ESV Float Valve Test Acceptance Criteria 1

Drawings KFD-102A-2.1 Flow Diagram of Turbine Sump Pump System 12

O-423E-2 Piping Layout ESV / SSW Intake Dike Trench 2

O-423E-4 Piping Layout Essential Siphon Vacuum Intake Dike Trench 2

O-424A Piping Layout Miscellaneous Outside Yard Piping General 40

Layout

O-951-A Conduit & Equipment Layout Intake Structure Plan, Sections 14

& Details

ONTC-0-130A- ESV Pump Capacity Test Acceptance Criteria 1

0001-001

ONTC-0-133A- ECCW Test Acceptance Criteria 6

0001-001

ONTC-0-133A- ECCW Test Acceptance Criteria 6

Inspection Type Designation Description or Title Revision or

Procedure Date

0001-003

Miscellaneous NWS Traveler # Valve S/N: BT-04976 11/09/2021

21-314

NWS Traveler # Valve S/N: BL-08890 11/08/2021

21-315

OSS-0254.00-00- Design Basis Spec for Keowee Turbine Sump Pump (TS) 14

1047 System

Procedures PT/1/A/0600/012 Turbine Driven Emergency Feedwater Pump Test 95

PT/2/A/0203/006 Low Pressure Injection Pump Test- Recirculation 88

PT/3/A/0261/020 ECCW System Test 10

PT/3/A/0600/012 Turbine Driven Emergency Feedwater Pump Test 95

PT/A/0600/21 Operation of the SSF Diesel Generator 98

71151 Miscellaneous Unit 1, 2, 3 MSPI Indicator Margin Reports, High Pressure

Injection System for period ending December 2021

71152A Calculations OSC-10255 ONS MSO Expert Panel Report 3

Corrective Action 2050877

Documents

Drawings OFD-131A-2.2 Flow Diagram of PSW System Steam Generator and HPI 2

Pump Motor Cooling Service

Engineering 403752 Modify U2 SSF RCS Letdown Line to Support SSF 16

Changes Operability in All Modes

Miscellaneous Framatome Inc. Oconee EC 403752 Impacts Related to NFPA 805 3

Engineering

information

Record 51-

285914-003

Procedures OP/0/A/1650/001 PSW System 5

OP/2/A/1103/005 Pressurizer Operation 46

71153 Calculations OSC-4168 A Loss of MFW Event with EFW in Manual 1

OSC-6217 Loss of Main Feedwater Without Anticipatory Reactor Trip 6

Corrective Action 2406969, 2276396, 2321719, 2416451, 1832100

Documents NCR 2415499 Post Trip Review of Unit 2A and 2B SG Pressure 02/09/2022

Drawings O-807-E Connection Diagram Switchyard Static Relay Boards Panels

No. SRF9 & SRF10

Inspection Type Designation Description or Title Revision or

Procedure Date

OEE-71-2 Elementary Diagram Start Up Transf. No. CT3 Diff. Lock Out 17

OLD-2004-07 Logic Diagram 230kV Switchyard Breaker Failure Relaying 0

Miscellaneous Oconee Unit 2 - 02/21/2022 Safety Analysis Transient

Response Review

OSS-0254.00-00- 230kV Switchyard System 26

2004

Procedures Reportability Reference Guide - Job Aid 2 8

AD-LS-ALL-0006 Notification/Reportability to the NRC 4

AD-OP-ONS- Oconee Specific Abnormal Operations Guidance 3

0002

IP/0/A/4980/062 A Westinghouse SBFU Relay Test 16

PT/0/A/0811/002 Trip/Transient Review 19

Detailed Risk Analysis for NCV 05000269,05000270/2021004-02, Failure to Use a

Procedure Appropriate to the Circumstances While Changing Electrical Lineup of Startup

Transformer CT-2

SRA Analysis Number: OCO-2022-001

Analysis Type: SDP Phase III

Inspection Report # 2021-004 (AV/TBD) and 2022-001 (Green NCV)

Plant Name: Unit Number: Oconee Unit 2

Enforcement Action #: N/A

OVERALL RISK SUMMARY

While in mode 5 shutdown operations, the licensee experienced a startup transformer lockout

and loss of offsite power (LOOP) to Oconee Unit 2 when a Reactor Coolant Pump (RCP) was

started for an uncoupled run. This condition caused a temporary loss of shutdown cooling for

approximately 31 seconds before power was restored and shutdown cooling was automatically

restored. An error in a procedure had caused protective electrical relays to be mis-aligned which

caused the LOOP. A risk evaluation estimated the conditional core damage probability (CCDP)

to be 8.0E-7 for Unit 2.

BACKGROUND

On November 27, 2021, Oconee experienced a Unit 1 start-up transformer (CT-1) and Unit 2

start-up transformer (CT-2) lock out. At the time, Unit 1 was 100 percent power in Mode 1, and

Unit 2 was in Mode 5 for a refueling outage. Unit 2 was powered from CT-2 and was starting the

2B2 RCP motor for an uncoupled run. When the 2B2 RCP switch was placed to the start

position, CT-1 and CT-2 locked out. Unit 1 did not lose power since it was being powered from

the Unit 1 auxiliary transformer. Unit 2 lost power and shutdown cooling for approximately 31

seconds before regaining power from transformer CT-5 via the Main Feeder Bus Monitor Panel

powered by the 100KV Central Switchyard. CT-5 had been aligned from the 100KV Central

Switchyard and was energizing the standby busses prior to the CT-2 lockout.

When power returned, the previously running Residual Heat Removal (RHR) pump

automatically re-started because the loss of power did not cause any loads to strip off the

emergency bus. Over the following 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br />, the operations department worked to restore plant

systems to a normal condition and reset the CT-2 lockout and restore normal alignment of

offsite power.

PERFORMANCE DEFICIENCY

The licensees failure to perform an adequate technical review of the PRR for the procedure,

Sharing Startup Transformers Between Units, OP/0/A/1107/011 F Revision 19, in accordance

with, Development and Maintenance of Controlled Procedure Manual Procedures, AD-DC-

ALL-0201 Revision 27, was a performance deficiency.

DATE OF OCCURRENCE

November 27, 2021.

SAFETY IMPACT

The CT-2 lockout and LOOP for Unit 2 caused a loss of normal decay heat removal.

Detailed Risk Analysis for NCV 05000269,05000270/2021004-02, Failure to Use a

Procedure Appropriate to the Circumstances While Changing Electrical Lineup of Startup

Transformer CT-2

RISK ANALYSIS/CONSIDERATIONS

Assumptions

1. This is a shutdown event in mode 5, Plant Operating State (POS) II, Late Window (post

refueling), 16 days after shutdown.

2. A plant specific shutdown risk model was developed using the guidelines in IMC 0609

Appendix G and taking into account Oconee unique site features and Oconee normal and

abnormal operating procedures.

3. This is an initiating event assessment using a LOOP as the initiating event. However, this

was a smaller plant-centered LOOP that caused the startup transformer to lockout and

become un-available. Offsite power from the grid and switchyard(s) remained available and

would have been available due to the nature of this event. Therefore, the model was

changed to credit the 100KV Central switchyard line both as a source of power for the main

feeder bus, and as a source for the Protected Service Water (PSW) facility.

4. Some potential failures were considered recoverable including the ability for operators to

recover the CT-2 transformer lockout, and recovery of offsite power. Failures for the E1 and

E2 breakers failing to open were given a recovery credit as a sensitivity analysis.

5. Steam generator cooling was not available, and the Reactor Coolant System (RCS) was

already vented since steam generator primary hand holes were removed.

6. FLEX mitigating strategies and equipment were not credited in the analysis. Although,

potentially FLEX strategies could be deployed and used for some of the risk scenarios,

FLEX is not modeled in NRC models for shutdown conditions. Discussion with licensee

regarding FLEX determined that, in the station blackout (SBO) scenario cutsets, had an

ELAP been declared there is no conflict with the existing strategies contained within

Oconees procedure for a loss of decay heat. For longer running scenarios, FLEX pumps

that could make up to the RCS would eventually be staged and could be available as

another backup source of injection into the RC

S.

7. In the SD-M5-SBO event tree, it has been assumed that if offsite power can be recovered,

the scenario will be successful. This is due to a combination of having an expansive amount

of time before core damage would occur combined with multiple options for cooling the

reactor.

8. Oconee has additional methods of providing forced flow to their RCS including via their

PSW which has the capability of providing power to the High-Pressure Injection (HPI)

pumps, and Oconee has a Safe Shutdown Facility (SSF) that can power an RCS makeup

pump that can provide a limited flow via the RCP seal lines. These features were verified to

have been available and were incorporated into the site-specific shutdown event trees.

Detailed Risk Analysis for NCV 05000269,05000270/2021004-02, Failure to Use a

Procedure Appropriate to the Circumstances While Changing Electrical Lineup of Startup

Transformer CT-2

PRA Model used for basis of the risk analysis:

SAPHIRE software version 8.2.5 and Oconee Standardized Plant Analysis Risk (SPAR) model

version 8.63 were used.

The SPAR model was modified by Idaho National Labs (INL) to include shutdown plant

condition event trees to better assess a LOOP while in mode 5. INL also modified the modeling

of the PSW facility to model a source of power from the 100KV Central Switchyard.

Additionally, the model was adjusted for the initiating event analysis as follows:

1. Modified top event for SG COOL to Fail - based on fact that steam generator cooling wasnt

available and was not recoverable.

2. Modified top event for SD-DEP to Succeed - based on fact that the RCS was already

vented, and the loss of offsite power would not change that. The primary hand-holes were

the open vent source, so it was a physical opening of the primary.

3. The SD-M5E-LOOP event tree in the SPAR model was changed. The original event tree

contained a top event for Alternating Current (AC) Power Recovery; however, the individual

recovery events were moved into the EPS tree, making this top event no longer required.

Additionally, the model was changed because, previously, regardless of whether emergency

power was successful or not, the model would transfer to the same event tree, SD-M5E-

LORHR-T. This was acceptable because event tree linkage rules would activate different

flag sets depending upon whether power was available, but it was determined to be more

efficient to create a separate event tree for shutdown plant conditions in mode 5 SBO

scenarios and this event tree was named SD-M5-SBO.

The new SD-M5-SBO tree has an additional top event for forced feed from the Reactor

Coolant Makeup Pump (RCMU) powered from the SSF. This top event was included as a

separate top event on the SBO tree because it would have different AC power recovery

criteria (12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />) than forced feed from HPI pumps would have.

This SBO tree also has a final top event for AC Power Recovery and has terms for either a

24-hour AC power recovery term if forced feed is successful or a shorter requirement for AC

power to be recovered within 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> if either gravity feed or forced feed from the RCMU

pump succeeds.

The 12-hour AC power recovery is represented in the model by basic event OEP-XHE-XL-

NR12H at a failure probability of 1.51E-1. This value can be changed via a change set for

sensitivity analysis.

The value for 24-hour AC power recovery is based on basic event OEP-XHE-XL-NR24HPC

which is taken from industry collected failure probability of recovery of offsite power within 24

hours from a plant-centered LOOP.

Detailed Risk Analysis for NCV 05000269,05000270/2021004-02, Failure to Use a

Procedure Appropriate to the Circumstances While Changing Electrical Lineup of Startup

Transformer CT-2

When the AC power recovery top event was removed and the M5-SBO event tree was

added as a transfer tree, the linkage rules for the SD-M5E-LOOP needed to be modified.

They were changed to the following to reflect that a SBO would trigger the appropriate flag

set.

IF /SD-EPS THEN

EVENTREE(SD-M5E-LOOP) = FLAG(ETF-M5E-LOOP);

ELSE EVENTREE(SD-M5E-LOOP) = FLAG(ETF-M5E-SBO);

ENDIF

4. Other modifications were made to the event tree for SD-M5E-LORHR-T including removing

the top event for containment sump recirculation (SD-SUMP-RECIRC). This top event would

have only been queried if forced feed was successful and was determined to be

unnecessary in the model since decay heat levels were low, the RCS makeup rate needed

would be low, combined with the high likelihood of recovery of AC power within 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />.

5. Fault Tree ACP-B6T (Failure of Power from 4KV Bus B6T) was modified to account for the

fact that for this specific event the plant-centered LOOP that Oconee experienced was not a

loss of offsite power to the grid and that it would not have affected the 100KV switchyard

source.

Deleted sub trees ACP-B6T029 and ACP-B6T0210 which contained house events for Loss

of Coolant Accidents (LOCAs) and Stuck Open Relief Valve (SORV) that wasnt applicable

to this event.

Deleted sub tree ACP-B6T32 for LOOP Strips Central Feed this contained House Events

(HE) for grid-related LOOP and weather-related LOOPs that were not applicable

6. Fault tree OEP-VCF-LP-CLOPT for consequential LOOP was modified by removing some

sub trees that didnt apply to this event. Also removed were complimented house events that

were not applicable the specific LOOP being evaluated. To do this sub trees EPS-100KV-

CENT-2. And ACP-B6T029 were deleted.

Sub tree EPS-CENT-100KV1 was also removed from the model since it contained house

events for different types of LOOP events that we were not evaluating for this specific event

analysis. In this case 100KV switchyard remained available and was not affected by the

plant-centered LOO

P.

7. A recovery credit was provided for the CT-2 lockout. Specifically, this was a Human Error

Probability (HEP) through SPAR-H analysis modeling the operators ability to identify and

correct the procedural error and fix the procedure and reset from the lockout within the first 4

hours of the event. Diagnosis and Action steps were all nominal except for diagnosis

stress level which is set to high, and procedures set to incomplete. This created an HEP

with a failure probability of 4.01E-1. The event is called OEP-XHE-CT-LOCKOUT.

Detailed Risk Analysis for NCV 05000269,05000270/2021004-02, Failure to Use a

Procedure Appropriate to the Circumstances While Changing Electrical Lineup of Startup

Transformer CT-2

The main fault trees for EPS-MFB2 and EPS-MFB1 were modified by putting this new event

into sub gates EPS-MFB2017 EPS-MFB1016 under an AND gate with the failure of the CT-

transformer. This recovery event essentially becomes AC power recovery for this model.

This then puts the modified tree with transformer recovery, in each of the 3 busses for each

Main Feeder Bus (MFB) tree. Licensee has said that they feel that if a station blackout had

been entered with this lockout that they could have recovered from the CT-2 lockout and re-

aligned their relays within as fast as 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br />.

8. A recovery event was created for operators failing to recover the E1 and E2 breakers within

the first 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of the event as ACP-XHE-E1E2-RECOVERY. These breakers provide

power from the CT-2 startup transformer to the Oconee Unit 2 Main Feeder Busses. This

event was placed in an AND gate with the E1 and E2 breaker failures, this value has been

set to a failure probability of .5. This represents a 50% failure rate for operators recovering

from the E1 E2 breakers failing to open. This is modeled to occur in the first 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> of the

event. The licensee has an electrical restoration procedure in which operators would

eventually be cued to attempt to open the breakers from the main control board. Additional

recovery steps could be taken, and its reasonable that Oconee would take action to try to

get the breakers open even if the details are not known for all the potential means of failure

and recovery. Note: this recovery is not credited in the base results and is only used as a

sensitivity analysis.

9. The basic event HPI-XHE-XA-PWRB6T was changed for operators failing to align power

from 4KV bus B6T. This was in the model at a screening value of .1. Oconee has procedure

in EOP Enclosure 5.42 for PSW Power and Pump Alignment - that would bring power to the

PSW from the 13KV Fant Line from the 100KV Central switchyard. If power is available to

PSW through the Fant line and 100KV switchyard, then this procedure is not complicated,

its verification of a power indication light and then starting the PSW booster pump. This

would be the case in most sequences in the cutsets. As a result of reviewing this procedure

it is appropriate to change this basic event from a screening value of 0.1 into a SPAR-H

Human Reliability Model event.

Diagnosis was set to yes (operators in the control room going through the Loss of

decay heat removal procedure would have to find the need to direct this step). For

diagnosis, time was set to extra, stress set to high, remaining performance

shaping factors set to nominal. Action time was set to extra; stress was set to

high, complexity set to nominal, experience/training set to low, everything else

left at nominal. This changed the failure rate to 2.6E-3 which still may be

conservative value considering time could be considered expansive.

10. Basic event HPI-XHE-XM-PSWCOOL was changed in the model. This was in the model at a

failure rate of 1.0. However, a review of this action revealed that this step is a simple

operator action. Like the above description for HPI-XHE-XA-PWRB6T the same procedure,

EOP Enclosure 5.42 for PSW Power and Pump alignment, has a step to start the PSW

booster pump to provide cooling water for HPI pump motors. As a result, this was changed

from 1.0 to a SPAR-H model.

Detailed Risk Analysis for NCV 05000269,05000270/2021004-02, Failure to Use a

Procedure Appropriate to the Circumstances While Changing Electrical Lineup of Startup

Transformer CT-2

Performance shaping factors for diagnosis was given extra time, high stress, with

everything else nominal. Action was set to extra time, high stress, experience set

to low with everything else nominal for a failure rate of 2.6E-3.

This change was not influential in risk results.

11. Basic event, ACP-XHE-XM-100KV was set to False in a change set, because Oconee Unit 2

was aligned to bring power back through the 100KV Central Switchyard without any

operator action required. It was recognized that the same basic event is used in the EPS-

LEE fault tree, and since if LEE failed and was required, there would be some operator re-

alignment required of the 100KV switchyard breakers, a new basic event with the same

failure rate as ACP-XHE-XM-100KV was created and substituted into the EPS-LEE fault

tree called ACP-XHE-XM-100KV-FOR-LEE so it wouldnt be affected by any changes to

ACP-XHE-XM-100KV.

2. Basic events LPI-MDP-RS-A and LPI-MDP-CF-FR for low pressure injection pump A failing

to restart for recirculation (including from common cause) were removed from the fault tree

SD-DHR-A-TRAINA. This event represented a potential failure to restart the pump if the

pump needed to be secured and restarted to support containment sump recirculation. But

since the top event for containment sump recirculation was removed, this event was no

longer needed.

13. A new basic event was created called, HPI-MDP-RS-A representing HPI pump A failing to

restart if multiple demands are required. This event was included in the fault tree for HPI-

TRAIN-A. If forced feed were used as a means for decay heat removal from the high-

pressure injection pumps, they would be cycled on and off as needed by operations since

the flow capacity of these pumps will exceed the amount needed for core cooling and

procedural guidance exists to cycling the pumps on and off as needed to preserve BWST

level.

14. Credit for operators ability to initiate gravity feed was modified. The event SD-XHE-XM-

90MGF is an HEP that existed in the model. A review of this HEP showed it to not have a

diagnosis element. Since a major component of this action is diagnosis in nature, diagnosis

was added with all events set to nominal values except for available time which was set to

extra, and stress was set to high. This changed the calculated HEP failure rate from 1E-3

to 3E-3.

The following model changes were made in the form of a change set.

1) Set items for breakers N1 and N2 (from the auxiliary transformer to the main feeder bus)

failing to open to False because these breakers should have already been open when

the main generator is offline in an outage. This also includes the common cause failure

event for these breakers of ACP-CRB-CF-N1N2 and basic events ACP-XHE-XR-N1 and

N2 for latent human errors (these were also set to False)

Detailed Risk Analysis for NCV 05000269,05000270/2021004-02, Failure to Use a

Procedure Appropriate to the Circumstances While Changing Electrical Lineup of Startup

Transformer CT-2

2) Transformer CT-3 in the model (representing the Unit 2 startup transformer CT-2) was

set to True, this is modeling the CT-2 lockout that occurred with basic event, ACP-TFM-

FC-CT3 (230KV swyd startup source transformer CT-3 fails)

3) ACP-XHE-XM-100KV (Operators fail to align the 100KV transmission system) was

changed to False this is because no operator action was required to align the 100KV

transmission system, it was aligned to power CT-5 automatically.

4) IE-SD-M5E-LOOP set to T to initiate the event

5) RHR MOV valves (A Train) - Since one train of the RHR system was already aligned

and in service at the time of the CT-2 lockout, those Motor Operated Valves (MOVs)

would not change state. As a result, numerous A Train RHR MOV valves were changed

to False

a. LPI-MOV-CC-LP1

b. LPI-MOV-CC-LP2

c. LPI-MOV-CF-DISCH

d. LPI-MOV-CC-LP17

e. LPI-MOV-OC-LP11

f. LSW-MOV-CC-4

g. LSW-MOV-CF-45

h. LPI-MOV-OC-LP12

Detailed Risk Analysis for NCV 05000269,05000270/2021004-02, Failure to Use a

Procedure Appropriate to the Circumstances While Changing Electrical Lineup of Startup

Transformer CT-2

CALCULATIONS

Event assessments were conducted using the ECA module of SAPHIRE.

Conditional Core Damage Probability (CCDP)

The CCDP for the initiating event was estimated to be 8E-7 in the base risk estimate.

Sensitivity Analysis (CCDP)

Two areas of uncertainty were addressed by performing sensitivity analyses.

The ability to recover AC power at the 12-hour point by either recovering the CT-2 lockout or by

recovering from a potential failure of both E1 and E2 breakers failing to open was studied via a

sensitivity analysis. By changing the default recovery failure rate from .15 to a new failure

probability of 0.3 changed the CCDP value to 9.2E-7.

Another sensitivity provided a recovery credit to represent the operators ability to being able to

manually open the E1 or E2 breaker in the event that they failed to open within the first 4 hours4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br />

of the event. Event ACP-XHE-E1E2 RECOVERY was assigned failure rate of .5. This credit

lowered the CCDP to 5.8E-7. It is likely that had breakers E1 and E2 failed to open, that

operators would have been able to manually open one of the breakers. However, there are

multiple ways in which the breakers could fail to open (electrically or manual binding) that

makes crediting the recovery in the base results difficult. Instead, the decision was made to

show the recovery as a sensitivity.

EXTERNAL EVENTS CONSIDERATIONS

Since the performance deficiency represents a precursor to a specific initiating event (a Plant-

Centered LOOP due to a CT-2 lockout) and required the starting of a large electrical motor

during preparations plant start up, the analyst determined that condition being modeled did not

warrant additional consideration of contribution from external events.

LARGE EARLY RELEASE FREQUENCY IMPACT

Since the event occurred 16 days into an outage, per IMC 0609, Appendix H, Containment

Integrity Significance Determination Process, LERF is not considered to be significant after 8

days.

CONCLUSIONS/RECOMMENDATIONS

The estimated risk for this event was a CCDP of 8E-7, which was less than the 1E-6/year

boundary for low to moderate (White) significance. Therefore, the issue associated with a

lockout of the CT-2 transformer was of very low safety significance (Green) for Unit 2.

Analyst: M. Leech Date: 3/23/22

Reviewed By: A. Rosebrook Date: 3/31/22

8