IR 05000269/2021003

Integrated Inspection Report 05000269/2021003 and 05000270/2021003 and 05000287/2021003

ML21301A125
Person / Time
Site:	Oconee
Issue date:	10/28/2021
From:	Eric Stamm Reactor Projects Branch 1
To:	Snider S Duke Energy Carolinas
References
IR 2021003
Download: ML21301A125 (26)

Text

October 28, 2021

SUBJECT:

OCONEE NUCLEAR STATION - INTEGRATED INSPECTION REPORT 05000269/2021003 AND 05000270/2021003 AND 05000287/2021003

Dear Mr. Snider:

On September 30, 2021, the U.S. Nuclear Regulatory Commission ( NRC) completed an inspection at Oconee Nuclear Station. On October 25, 2021, the NRC inspectors discussed the results of this inspection with you and other members of your s taff. The results of this inspection are documented in the enclosed report.

Three findings of very low safety significance (Green) are docu mented in this report. These findings involved violations of NRC requirements. We are treat ing these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcem ent Policy.

If you contest the violations or the significance or severity o f 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 Reg ulatory Commission, ATTN:

Document Control Desk, Washington, DC 20555-0001; with copies t o 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 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 Administ rator, 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,

/RA/

Eric J. Stamm, Chief Reactor Projects Branch 1 Division of Reactor Projects

Docket Nos. 05000269 and 05000270 and 05000287 License Nos. DPR-38 and DPR-47 and DPR-55

Enclosure:

As stated

Inspection Report

Docket Numbers: 05000269, 05000270, and 05000287

License Numbers: DPR-38, DPR-47, and DPR-55

Report Numbers: 05000269/2021003, 05000270/2021003, and 050002 87/2021003

Licensee: Duke Energy Carolinas, LLC

Facility: Oconee Nuclear Station

Location: Seneca, South Carolina

Inspection Dates: July 01, 2021 to September 30, 2021

Inspectors: J. Nadel, Senior Resident Inspector A. Ruh, Resident Inspector N. Smalley, Resident Inspector P. Cooper, Senior Reactor Inspector T. DeBey, Resident Inspector N. Peterka, Fuel Facility Inspector A. Rosebrook, Senior Reactor Analyst

Approved By: Eric J. Stamm, Chief Reactor Projects Branch 1 Division of Reactor Projects

Enclosure SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitori ng the licensees performance by conducting an integrated inspection at Oconee Nu clear Station, in accordance with the Reactor Oversight Process. The Reactor Oversight Proc ess is the NRCs program for overseeing the safe operation of commercial nuclear power react ors. Refer to https://www.nrc.gov/reactors/operating/oversight.html for more information.

List of Findings and Violations

Failure to Verify Capacity of Reactor Building Cooling Units Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green None (NPP) 71111.07A Systems NCV 05000269,05000270,05000287/2021003-01 Open/Closed Inspectors identified a Green finding and associated non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, when the licensee failed to verify the adequacy of design of the reactor building cooling units (RBCUs ). Specifically, the licensee improperly evaluated RBCU performance test data when determinin g the fouling factor and heat transfer capability.

Failure to Assess Internal Flooding Risk of Maintenance Activit y Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.3] - Change 71111.13 Systems NCV Management 05000269,05000270,05000287/2021003-02 Open/Closed The inspectors identified a Green finding and associated NCV of 10 CFR 50.65(a)(4) when the licensee failed to assess the risk associated with high pre ssure service water (HPSW) system alignments during testing.

Failure to Install Shorting Jumpers in the Motor Driven Emergen cy Feedwater Pump 4160V Switchgears Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green None (NPP) 71111.15 Systems NCV 05000269,05000270,05000287/2021003-03 Open/Closed A self-revealed Green finding and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Procedures, Instructions, and Drawings, was iden tified when it was discovered that a set of jumpers depicted on a plant drawing had never bee n installed on terminal blocks in 4160V safety-related switchgear 2TE15 for the 2B motor drive n emergency feedwater pump.

Additional Tracking Items

Type Issue Number Title Report Section Status URI 05000269,05000270, Operation of Normally 71111.18 Closed 05000287/2020003-02 Closed Seismic Boundary Valves

PLANT STATUS

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

Unit 2 operated at or near RTP until August 24, 2021, when powe r was reduced to 25 percent RTP due to a boric acid leak identified in containment. The un it was returned to 100 percent RTP on August 25, 2021, following a disposition that the leak w as not from a primary pressure boundary. Unit 2 operated at or near RTP for the remainder of the inspection period.

Unit 3 operated at or near RTP for the entire inspection period.

INSPECTION SCOPES

Inspections were conducted using the appropriate portions of th e inspection procedures (IPs) in effect at the beginning of the inspection unless otherwise note d. Currently approved IPs with their attached revision histories are located on the public web site 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 inspe ction activity were met consistent with Inspection Manual Chapter (IMC) 2515, Light-Wa ter Reactor Inspection Program - Operations Phase. The inspectors reviewed selected p rocedures and records, observed activities, and interviewed personnel to assess licens ee performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.

Starting on March 20, 2020, in response to the National Emergen cy declared by the President of the United States on the public health risks of the coronavi rus (COVID-19), resident and regional inspectors were directed to begin telework and to remo tely access licensee information using available technology. During this time, the resident insp ectors performed periodic site visits each week, increasing the amount of time on site as loca l COVID-19 conditions permitted.

As part of their onsite activities, resident inspectors conduct ed plant status activities as described in IMC 2515, Appendix D; observed risk significant ac tivities; and completed on site portions of IPs. In addition, resident and regional baseline in spections were evaluated to determine if all or a portion of the objectives and requirement s stated in the IP could be performed remotely. If the inspections could be performed remot ely, they were conducted per the applicable IP. In some cases, portions of an IP were comple ted remotely and on site. The inspections documented below met the objectives and requirement s for completion of the IP.

REACTOR SAFETY

71111.01 - Adverse Weather Protection

Impending Severe Weather Sample (IP Section 03.02) (1 Sample)

(1) The inspectors evaluated the main control room response to a tornado warning, entry into procedure AP/0/A/1700/006, Natural Disaster, on August 17, 2021.

71111.04 - Equipment Alignment

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

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

(1) Low pressure service water system for Unit 3 on July 29, 20 21, following failure of 3A pump to run (2) Train 2B of motor driven emergency feedwater on August 12, 2021, during maintenance on the 2A train (3) Keowee Units 1 and 2 on September 2, 2021, following breake r maintenance and alignment swap (4) Train 3A of high pressure injection on September 9, 2021, f ollowing pump surveillance and alignment swap

71111.05 - Fire Protection

Fire Area Walkdown and Inspection Sample (IP Section 03.01) (5 Samples)

The inspectors evaluated the implementation of the fire protect ion 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 15: Unit 2 main feedpump area, on August 10, 2021 (2) Fire zone 106: Unit 1 cable room, on August 30, 2021 (3) Fire zone 29: Unit 3 4160V switchgear, on August 30, 2021 (4) Fire zone 81: Unit 2 auxiliary building 200 level hallway, on September 3, 2021 (5) Fire zone 110: Units 1/2 control room, on September 26, 2021

71111.06 - Flood Protection Measures

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

The inspectors evaluated internal flooding mitigation protectio ns in the:

(1) Auxiliary building elevation 783' and 771' corridors

71111.07A - Heat Sink Performance

Annual Review (IP Section 03.01) (1 Sample)

The inspectors evaluated readiness and performance of:

(1) Unit 2 reactor building cooling units A, B, and C

71111.07T - Heat Sink Performance

Heat Exchanger (Service Water Cooled) (IP Section 03.02) (3 Sam ples)

The inspectors evaluated heat exchanger/sink performance on the following:

(1) Safe shutdown facility (SSF) HVAC Condenser #1 (CCW-CD-0001 )

(2) Low pressure injection Cooler 1B - 1LPI-HX-000B (3) Reactor building cooling unit A - 1RBCHX000A

71111.11Q - Licensed Operator Requalification Program and Licen sed 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 per formance in the control room during a pump swap and comprehensive pump test for Unit 3 low pressure service water system on August 3, 2021, and during tornado warn ing on August 17, 2021.

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

(1) The inspectors observed and evaluated team skill exercises on multiple units with the following scenarios: 1) elevated reactor coolant system (RCS) d ose equivalent iodine, turbine master trip to hand, 1A main steam line break, 1A steam generator tube rupture; 2) loss of startup transformer (CT) 4, Keowee Hydro Un its (KHU) operational checks, support Unit 3 loss of CT3; 3) loss of CT3, RCS/low pre ssure injection (LPI)

leakage on July 8, 2021.

71111.12 - Maintenance Effectiveness

Maintenance Effectiveness (IP Section 03.01) (2 Samples)

The inspectors evaluated the effectiveness of maintenance to en sure the following structures, systems, and components (SSCs) remain capable of pe rforming their intended function:

(1) Protected service water system, failures of 3B high pressur e injection (HPI) pump transfer switch and 3HP-24 control switch on March 29, 2021, an d May 13, 2021, respectively (nuclear condition reports (NCR) 2382256, 2376228)

(2) Unit 3 containment isolation penetrations and valves, failu res on April 16, 2020, April 28, 2020, and July 11, 2020 (NCRs 2327394, 2327585, 233892 7, 2325782)

Aging Management (IP Section 03.03) (1 Sample)

The inspectors evaluated the effectiveness of the aging managem ent program for the following SSCs that did not meet their inspection or test accep tance criteria:

(1) Keowee Units 1 and 2 penstock and power tunnel four-year ci vil inspection, NCR 2390576

71111.13 - Maintenance Risk Assessments and Emergent Work Contr ol

Risk Assessment and Management Sample (IP Section 03.01) (4 Sam ples)

The inspectors evaluated the accuracy and completeness of risk assessments for the following planned and emergent work activities to ensure config uration changes and appropriate work controls were addressed:

(1) Units 1, 2, and 3 elevated yellow risk on July 8, 2021, due to fire protection system flow testing

(2) Unit 3 yellow risk on July 12, 2021, during 3C LPI pump and protected service water battery charger #1 maintenance (3) Units 1, 2, and 3 elevated green risk on July 20, 2021, due to both Keowee hydrostation units out of service for planned maintenance and i nspection (4) Unit 2 green risk on August 24, 2021, with yellow grid risk and Unit 2 at 25 percent power due to reactor coolant system leakage in containment

71111.15 - Operability Determinations and Functionality Assessm ents

Operability Determination or Functionality Assessment (IP Secti on 03.01) (6 Samples)

The inspectors evaluated the licensee's justifications and acti ons associated with the following operability determinations and functionality assessme nts:

(1) Work request (WR) 20206702, work order (WO) 20484010, NCR 0 2392361, Unit 2 motor driven emergency feedwater pump after motor failing to ru n and exceeding starting duties while troubleshooting (2) NCR 2392364, 2B motor driven emergency feedwater pump damag ed terminal block (3) NCRs 2394935 and 2395220, Unit 2 unidentified leakage incre ase and discovery of boric acid in Unit 2 containment basement (4) NCR 2396614, gas void identified at 3BS-27 and 3BS-28 measu ring 0.012 cubic feet (5) NCR 2399553, steam leak from bottom flange of 2MS-95 during turbine driven emergency feedwater pump testing (6) NCR 2399025, closing function of 1, 2, and 3HP-26 not evalu ated in motor operated valve program

71111.19 - Post-Maintenance Testing

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

The inspectors evaluated the following post-maintenance test ac tivities to verify system operability and functionality:

(1) IP/2/A/0400/022, KHU-2 Turbine Sump Pump Level Control Swit ch Calibration, after level switch replacement, WO 20474456, on July 7, 2021 (2) PT/3/A/0203/006 A, Low Pressure Injection Pump Test - Recir culation, for the 3C LPI pump following pump internals replacement, WO 20429385, on July 14, 2021 (3) OP/0/A/2000/041, KHS - Modes of Operation, maintenance runs on Keowee Hydroelectric Units 1 and 2 following a dual unit maintenance o utage, on July 21, 2021 (4) IP/3/A/4980/051 A, CO-5, CO-6, CO-7, CO-8, and CO-11 Relay Test, and IP/3/A/4980/050 A, Brown Boveri GR-5 Ground Shield Relay Test, following relay replacements on 3TC-11 for 3A low pressure service water pump, WOs 20483072, 20483069, on July 28, 2021 (5) MP/0/A/1200/010 A, Relief Valve Set Pressure Testing and Ad justment, and leak checks following replacement of K1-AB-17 on ACB-1, on August 31, 2021 (6) IP/0/A/2001/002, Inspection and Maintenance of Keowee Hydro Station Air Circuit Breakers, following replacement of ACB-4 low-low pressure switc h, on September 2, 2021 (7) PT/2/A/0600/012, Turbine Driven Emergency Feedwater Pump Te st, following an electrical relay replacement, on September 28, 2021

71111.22 - Surveillance Testing

The inspectors evaluated the following surveillance tests:

Surveillance Tests (other) (IP Section 03.01) (5 Samples)

(1) PT/2/A/0600/013, 2B Motor Driven Emergency Feedwater Pump T est, on April 26, 2021 (2) OP/0/A/1600/010, SSF Diesel-Generator, monthly surveillance run, on July 14, 2021 (3) PT/0/A/0620/009, Keowee Hydro Operations, Unit 2 operabilit y run, on July 22, 2021 (4) PT/0/A/0620/009, Keowee Hydro Operations, Unit 1 operabilit y run, on July 22, 2021 (5) PT/0/A/0400/15, SSF Submersible Pump Test, on September 14, 2021

Inservice Testing (IP Section 03.01) (1 Sample)

(1) PT/0/A/0250/025, HPSW Pump and Fire Protection Flow Test, o n September 24, 2021

RCS Leakage Detection Testing (IP Section 03.01) (1 Sample)

(1) PT/0/A/0102/008, Rebaselining of Unit 2 unidentified leakag e values, on September 1, 2021

71114.06 - Drill Evaluation

Drill/Training Evolution Observation (IP Section 03.02) (1 Samp le)

The inspectors evaluated:

(1) Training drill 2021-02 on August 18, 2021, which included t urnover from Team 4 to Team 1, Shift C, and included partici pation from the Emergency Operations Facility and the Joint Information Center.

OTHER ACTIVITIES - BASELINE

71151 - Performance Indicator Verification

The inspectors verified licensee performance indicators submitt als listed below:

MS09: Residual Heat Removal Systems (IP Section 02.08) (3 Sampl es)

(1) Unit 1 (July 1, 2020 through June 30, 2021)

(2) Unit 2 (July 1, 2020 through June 30, 2021)

(3) Unit 3 (July 1, 2020 through June 30, 2021)

BI01: Reactor Coolant System (RCS ) Specific Activity Sample (IP Section 02.10) (3 Samples)

(1) Unit 1 (July 1, 2020 through June 30, 2021)

(2) Unit 2 (July 1, 2020 through June 30, 2021)

(3) Unit 3 (July 1, 2020 through June 30, 2021)

71152 - Problem Identification and Resolution

Semiannual Trend Review (IP Section 02.02) (1 Sample)

(1) The inspectors reviewed the licensees corrective action pr ogram and the 1T2021 Trending Report on July 15, 2021, for potential adverse trends in work planning and implementation risk recognition that might be indicative of a m ore significant safety issue.

Annual Follow-up of Selected Issues (IP Section 02.03) (1 Sampl e)

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

(1) NCRs 2392172, 2392364, 2391434, 2B motor driven emergency f eedwater pump repeat failure to run in February 2021 and August 2021 due to d amaged terminal block.

OTHER ACTIVITIES - TEMPORARY INSTRUCTIONS, INFREQUENT AND ABNOR MAL

2515/194 - Inspection of the Licensees Implementation of Indus try Initiative Associated With the Open Phase Condition Design Vulnerabilities In Electric Power S ystems (NRC Bulletin 2012-01)

Revision 0 of this Temporary Instruction (TI) was previously in spected, and closed, in Inspection Report 2019013 (ADAMS ML19318G943.) However, a subsequent revi sion to the Nuclear Energy Institute (NEI) Voluntary Initiative (Revision 3) provid ed plants the option of to leave the open phase protection (OPP) system in monitoring mode only in l ieu of activating the automatic trip circuitry, provided it was supported by a risk evaluation. Revision 1 (and later Revision 2) of this TI was issued to provide inspection guidance for the new o ption.

The inspectors reviewed licensee analyses and procedures that d emonstrated operator manual actions would successfully miti gate the impact of an open phase condition (OPC). The analyses were reviewed remotely, and the procedures were review ed and walked down on site. The inspectors completed Section 03.01c of TI 2515/194, Revision 2.

The inspectors verified that modeling used for the OPC reflecte d the as-designed and as-built plant, assumptions made by the licensee were reasonable, and li censee procedures were adequate to successfully respond to an OPC. The inspectors als o verified that human reliability analysis and recovery evaluations were done in accordance with NEI and voluntary initiative guidance.

During the two-year monitoring period there were two instances of spurious actuations of the OPP logic which would have resulted in a loss of off-site power. These spurious trips were documented in the licensee correct ive action program as action request (AR) 2296030 (October 2019) and AR 2356836 (November 2020). Both spurious t rips were the result of grid perturbations due to switching operations in the switchyard. C orrective actions included additional monitoring consultation with the vendor and recommen ded changes to the time delay relay setting. The OPP system was not in automatic so there wa s no impact on plant operations.

INSPECTION RESULTS

Failure to Verify Capacity of Reactor Building Cooling Units Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green None (NPP) 71111.07A Systems NCV 05000269,05000270,05000287/2021003-01 Open/Closed Inspectors identified a Green finding and associated non-cited violation (NCV) of 10 CFR Part 50, Appendix B, Criterion III, Design Control, when the licensee failed to verify the adequacy of design of the reactor building cooling units (RBCUs ). Specifically, the licensee improperly evaluated RBCU performance test data when determinin g the fouling factor and heat transfer capability.

Description: RBCU fouling is routinely monitored during plant operation because tube-side fouling from the low pressure service water system increases ov er time and reduces the capability of the RBCUs. On November 18, 1997, site engineers revised calculation OSC-5667, Reactor Building Cooling Unit Performance Test - Uni t 3, to use a different methodology for calculating the internal fouling factor reflect ed by performance test data. Engineers made this revision because the performance tes t data of brand-new cooling coils were analyzed with validated vendor software and the resu lts indicated that the coils were performing as if they were somewhat fouled. Engineers sus pected the lost cooling performance was related to a non-uniform airflow distribution a cross the coil, rather than fouling, and that the fouling factors being obtained during per formance tests were higher than what truly existed. Engineers used the fouling factor and vendor-provided tables to extrapolate the RBCU cooling capacity to design basis accident conditions for comparison against acceptance criteria derived from cooling capacity assum ptions in the plants safety analyses. If the obtained fouling factors were overly/conserva tively high, then RBCU performance was being underpredicted which prompted more freque nt testing. Engineers, in consultation with the vendor, sought to obtain a more realistic fouling factor by determining an effective RBCU coil length from the clean coil test data. A reduced surface area was assumed by reducing the length of the coils in the software unt il a zero fouling factor was obtained. After doing this for all nine RBCUs, a statistical a verage of those reduced lengths plus two standard deviations was established as the ef fective RBCU coil length. This artificial coil length amounted to 73 percent of the actual coil length and represented a reduction in coil capacity attributable to non-fo uling sources and was used when determining the fouling factor from all routine RBCU perfo rmance tests since 1997 for all three units.

Inspectors assessed that the methodology change may be appropri ate for the purpose of determining the actual physical fouling of the coils, howeve r, the negative effect on RBCU capacity from the suspected non-uniform airflow in Oconee s installation was no longer being accounted for by the method. This negative effect was im portant because the vendors tables for extrapolating RBCU performance to accident condition s were based on similar software that assumed a uniform air distribution across the ful l actual coil length. Secondly, adjustments to the fouling factor associated with instrument un certainty of performance test equipment was originally derived based on the full coil length and was not re-derived for analyses using a shorter coil length, which was non-conservativ e. An additional complicating factor was that performance testing was done with the RBCU fan in high speed, whereas during an accident, the fan would be operated in low speed. Ho w the fan speed related to the

air distribution effect was not readily known, but engineers su spected that the negative effect would be less in low speed.

When these calculational errors were evaluated, revisions to ot her calculations were required to establish operability of the RBCUs. The post-accident conta inment analyses were re-run assuming a 23 percent reduction in the previously assumed RBCU capacity to generate a new post-accident temperature profile. The effect resulted in a temperature increase of approximately 10 degrees Fahrenheit over the course of the acci dent. Some conservatism was removed from the environmental qualification of reactor bui lding equipment to accommodate the elevated post-accident temperature effects and the licensee determined the equipment would still achieve the required post-accident li fe.

Corrective Actions: The licensee reperformed the post-accident containment analyses with a reduced RBCU capacity and initiated actions to revise environme ntal qualification calculations, test acceptance criteria, and the updated final s afety analysis report.

Corrective Action References: NCR 2386632 Performance Assessment:

Performance Deficiency: The licensees failure to verify the a dequacy of design of the RBCUs per 10 CFR Part 50, Appendix B, Criterion III, was a perf ormance deficiency.

Specifically, the licensee impr operly evaluated RBCU performance test data when determining the fouling factor and heat transfer capability.

Screening: The inspectors determined the performance deficienc y 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 initiati ng events to prevent undesirable consequences. Specifically, after evaluating the calculation e rrors, there was a reasonable doubt about the equipments operability, which reduced assuranc e in the equipments capability and required the licensee to revise other calculatio ns in order to establish operability.

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 design of the RBCUs, but they maintained their operability.

Cross-Cutting Aspect: Not Present Performance. No cross-cuttin g 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, suc h as by the performance of design reviews. Contrary to the above, since November 18, 1997, the design review calculations for RBCU performance test evaluations did not veri fy the adequacy of design of the RBCUs due to the use of non-conservative methods. Specific ally, the licensee improperly evaluated RBCU performance test data when determining the fouli ng factor and heat transfer capability.

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

Failure to Assess Internal Flooding Risk of Maintenance Activit y Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green [H.3] - Change 71111.13 Systems NCV Management 05000269,05000270,05000287/2021003-02 Open/Closed The inspectors identified a Green finding and associated non-ci ted violation (NCV) of 10 CFR 50.65(a)(4) when the licensee failed to assess the risk ass ociated with high pressure service water (HPSW) system alignments during testing.

Description: On July 8, 2021, the licensee conducted performan ce test PT/0/A/0250/024, Fire Protection System Three Year Flow Test. The purpose of the test was to verify adequate flow through fire protection piping headers by alignin g flow from the elevated water storage tank (EWST) through various HPSW fire hydrants around t he site. Enclosure 13.2 of the test required the primary instrument air compressor to be r emoved from service since the test would affect the normal HPSW cooling supply to that compre ssor. The limits and precautions of the procedure stated, Anytime HPSW-21, HPSW-958 or 3HPSW-453 [are]

open, Auxiliary Building flood concerns must be considered. T his note was purposed to alert operators to the fact that certain alignments during the test w ould effectively bypass the 600 gallon per minute flood limiting valve, HPSW-960, because the t est would open alternate 16-inch and 4-inch auxiliary building (AB) supply valves that c ould supply a piping failure in the AB. During the test, operators appropriately entered selec ted licensee commitment 16.9.11a, condition A, to restore the valves to a fu nctional status within seven days. In terms of a maintenance risk assessment required by li censee procedure AD-WC-ALL-0240, On-line Risk Management Process, the licensee had assessed the risk of the primary instrument air compressor being out of service a nd determined the risk was Green and that normal work controls were adequate. Inspector s noted that the internal flooding risk associated with directly connecting the 90,000 ga llon EWST to the 16-inch non-seismic piping on the second floor of the AB through HPSW-2 1 and HPSW-958, was not considered in the risk assessment. When considered, the risk w ould indicate Yellow risk and require shift manager approval as well as other risk manage ment actions.

In March of 2020, Duke corporate probabilistic risk assessment specialists provided the site with new electronic risk assessment tool (ERAT) codes associate d with AB flooding in document CSD-WC-ONS-0240, ONS ERAT Guidance. One new code wa s specifically intended for application when either HPSW-21 or HPSW-958 are o pened and remain open.

Implementing supervisors did not apply this ERAT code because t he test procedure had an enclosure describing compensatory actions to realign the HPSW s ystem in the event of a fire or AB flood event. Inspectors evaluated these compensatory act ions as insufficient to maintain the isolation valves as still being capable of perform ing their intended function for their required duration (available). AD-WC-ALL-0240, Attachmen t 1, Availability Determination, section 1.11 stated components that are out of normal alignment during testing are unavailable, unless one of the following is met: a) the component would be automatically repositioned to its safety position if needed to perform its safety function, b) the test procedure provides appropriate guidance for realigning in the event the SSC is needed to perform its safety function, c) manual action can be taken by a designated operator to restore the component. In this case, the use of a designated operator to perform manual actions to

support equipment availability required meeting several additio nal criteria such as: approval from the operations shift manager that the manual actions were adequate, consideration of other duties of the personnel performing the manual actions, and consideration of the time limit for performing the manual actions. The licensee had not performed or made an assessment of these factors. Inspectors assessed that a large HPSW piping failure during these test alignments could permit flowrates in excess of 10,00 0 gallons per minute into the AB from the static pressure of the EWST. Automatic starting of one or both of the 6,000 gallon per minute HPSW pumps could also occur as the EWST level dropped, which could exacerbate the flooding. Considering that the maximum accumula tion volume determined in calculation OSC-8671, Auxiliary Building Flood Design Values, was conservatively determined to be approximately 40,000 gallons before flooding c ould spill over the protective curbing, a very limited amount of time appeared to be available for implementation of the procedures compensatory measures. Operators were briefed on t he actions but were not required to remain in the vicinity of the isolation valves duri ng testing. Based on the multiple steps required and the various locations that the individuals p erforming the testing could be located and would need to respond to, there was reasonable doub t that the actions would be, virtually certain of success (i.e., probability nearly equ al to one during accident conditions), as required by AD-WC-ALL-0240, Attachment 1.

A review of additional HPSW testing procedures revealed that PT /0/A/0250/005, High Pressure Service Water Pump Functional Test, and PT/0/A/0250/0 25, HPSW Pump and Fire Protection Flow Test, contained similar deficiencies. A review of testing from the previous 12 months revealed an additional occurrence on Septemb er 2, 2020, where site risk should have been classified as Yellow during the simulta neous removal from service of the 2B low pressure injection train.

Corrective Actions: The licensee updated the model work orders for three HPSW system test procedures to apply the proper risk assessment coding.

Corrective Action References: NCR 2391095 Performance Assessment:

Performance Deficiency: The licensees failure to perform a ri sk assessment when required by licensee procedure AD-WC-ALL-0240 was a performance deficien cy. Specifically, the licensee failed to assess the risk associated with unavailabili ty of normally closed HPSW flood isolation valves when routine system testing opened them.

Screening: The inspectors determined the performance deficienc y was more than minor because it was associated with the Protection Against External Factors attribute of the Mitigating Systems cornerstone and adversely affected the corne rstone objective to ensure the availability, reliability, and capability of systems that r espond to initiating events to prevent undesirable consequences. The mitigating cornerstone objective s were adversely affected since overall elevated plant risk would put the plant into a hi gher licensee-established risk category. Specifically, when considered, plant risk would have been assessed as Yellow on July 8, 2021, and September 2, 2020, when HPSW isolation val ves were open in conjunction with other planned maintenance activities.

Significance: The inspectors assessed the significance of the finding using Appendix K, Maintenance Risk Assessment and Risk Management SDP. Using flowchart 1, Assessment of Risk Deficit, inspectors determined the finding was of very low safety significance (Green) because the incremental core damage probab ility deficit (ICDPD) was

less than 1E-6. The assumptions used were an incremental core damage frequency deficit of 1E-5 per year with a cumulative exposure time of 128 hours0.00148 days <br />0.0356 hours <br />2.116402e-4 weeks <br />4.8704e-5 months <br /> o f isolation valve unavailability during routine HPSW tests in the previous 12 months, resulting in an ICDPD of 1.5E-7.

Cross-Cutting Aspect: H.3 - Change Management: Leaders use a s ystematic process for evaluating and implementing change so that nuclear safety remai ns the overriding priority. In this case, change management gaps associated with implementatio n of a new online risk management procedure, AD-WC-ALL-0240, in 2019, coupled with sit e-specific ERAT code changes through CSD-WC-ONS-0240 in 2020, led to the continued u se of existing site test procedures without evaluating whether new risk coding was requi red or whether availability guidance was being met.

Enforcement:

Violation: 10 CFR 50.65(a)(4) required, in part, that before p erforming maintenance activities (including but not limited to surveillance, post-maintenance te sting, and corrective and preventive maintenance), the licensee shall assess and manage t he increase in risk that may result from the proposed maintenance activities. Contrary to t he above, the licensee failed to perform an adequate risk assessment in that the overall mainten ance risk assessments performed by the licensee for all plant maintenance to be perfo rmed during the weeks of July 8, 2021, and September 2, 2020, were inadequate because th ey failed to account for HPSW internal flood isolation valves that were concurrently out of service.

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

Failure to Install Shorting Jumpers in the Motor Driven Emergen cy Feedwater Pump 4160V Switchgears Cornerstone Significance Cross-Cutting Report Aspect Section Mitigating Green None (NPP) 71111.15 Systems NCV 05000269,05000270,05000287/20210 03-03 Open/Closed A self-revealed Green finding and associated non-cited violatio n (NCV) of 10 CFR Part 50, Appendix B, Criterion V, Procedures, Instructions, and Drawing s, was identified when it was discovered that a set of jumpers depicted on a plant drawing ha d never been installed on terminal blocks in 4160V safety-related switchgear 2TE15 for th e 2B motor driven emergency feedwater pump.

Description: On August 2, 2021, the licensee began routine lub rication and breaker testing maintenance on the 2B motor driven emergency feedwater (MDEFW) pump. The pump was started for post-maintenance testing and it tripped a few secon ds after being started. The overload trip relays were found triggered. Troubleshooting acti vities, which included multiple subsequent pump starts with electrical data recording equipment connected, led to the discovery of degraded neutral wire connections on a terminal bl ock in the 2TE15 4160V switchgear cabinet. The wires on the terminal block go to a cur rent transformer (CT) that is used for motor current display and to determine when an overcur rent condition exists for the motor. The purpose of the terminal block is to short all four C T wires together. There is a shorting bar that spans the four terminals to create a short. S ite electrical drawing OEE-217-

55, 4160 Switchgear #2TE Unit #15 2B Motor Driven Emergency Fe edwater Pump 2B, Revision 9, also indicated that three jumpers should be install ed to provide a redundant shorting path. Those jumpers were not installed on the 2B MDEFW pump terminal block. Site personnel also found that the screws holding the shorting bar w ere loose, leading to poor electrical contact with the terminals and subsequent arcing and overheating of the wire on terminal #3. The looseness of these contacts and the associated damage to wire #3 was determined to be the cause of the pump trip. The residents note d that, had the jumpers been installed as prescribed by OEE-217-55, they would have provided redundant shorting, and would have prevented the trip of the 2B MDEFW pump. A subsequen t extent of condition inspection revealed that the shorting bar screws were loose by a range of 1/16 to 1 full turn and the jumpers were not installed on all five remaining MDEFW pumps across all three Oconee units. The jumpers were also shown installed on plant dr awings OEE-117-90, OEE-117-91, OEE-217-54, OEE-317-66, and OEE-317-67 for the othe r five MDEFW pumps. No evidence of overheating or arc damage was found on th e other pumps and no similar failures had occurred on the other pumps. The residents noted that the terminal bar and jumpers are an integral part of the switchgear itself, were shown on the manufacturers drawing, and therefore the failure to install the jumpers is an original plant construction issue.

It was also noted that the 2B MDEFW pump experienced an identic al failure during surveillance testing on February 1, 2021. At that time, a relay was replaced, and the pump operated satisfactorily. A subsequent cause evaluation after th e August 2, 2021, failure determined that the failure in February was due to the same cau se, namely the loose screws and arcing on the terminal block.

On October 4, 2021, the licensee made a report to the NRC under 10 CFR 50.73(a)(2)(i)(B)

for a condition prohibited by technical specifications after th ey determined that the 2B MDEFW pump had been rendered inoperable from February 1, 2021, through August 4, 2021, due to the missing jumpers and the terminal blo ck loose screws and arcing.

The resulting intermittent failures reduced the reliability of the pump to the point where reasonable assurance of operability no longer existed.

Corrective Actions: The licensee replaced the 2B MDEFW pump te rminal block and installed shorting jumpers as shown in the station drawing OEE-217-55. A fter an extent of condition review revealed that the jumpers were missing and terminal scre ws were loose on the five remaining MDEFW pumps, all shorting bar screws were tightened, and the required shorting jumpers were installed on all MDEFW pump switchgears.

Corrective Action References: NCR 2392364 Performance Assessment:

Performance Deficiency: The licensees failure to install shor ting jumpers in safety-related 4160V switchgears for the motor dr iven emergency feedwater pumps, as prescribed in station drawings such as OEE-217-55, was a performance deficiency.

Screening: The inspectors determined the performance deficienc y was more than minor because it was associated with the Equipment Performance attrib ute of the Mitigating Systems cornerstone and adversely affected the cornerstone obje ctive to ensure the availability, reliability, and capability of systems that respo nd to initiating events to prevent undesirable consequences. Specifically, shorting jumpers shown in station drawing OEE-217-55, were not installed on switchgear 2TE15 in accordanc e with that drawing. The

missing shorting jumpers contributed to the failure of the 2B m otor driven emergency feedwater pump to run after it was started on August 2, 2021.

Significance: The inspectors assessed the significance of the finding using Appendix A, The Significance Determination Process (SDP) for Findings At-Power. The inspectors assessed the significance of the finding using Inspection Manual Chapter 0609, Appendix A, The Significance Determination Process for Findings At-Power, date d December 20, 2019. Using Exhibit 2, Mitigating Systems Screening Questions, the inspec tors determined that a detailed risk evaluation was required because the finding did i nvolve loss of the PRA function of a single train of the emergency feedwater system for greater than its technical specification allowed outage time.

A regional Senior Reactor Analyst (SRA) preformed a detailed ri sk assessment for the degraded condition. The SRA modeled the condition using the Oco nee Units 1, 2, and 3 SPAR model version 8.60 dated May 3, 2019, and SAPHIRE 8 Versio n 8.2.3. The exposure period was from the failed surveillance test on February 1, 202 1, until discovery and return to service on August 4, 2021, a period of 184 days. MDEFW pump B ( EFW-MDP-FS-B) was set to failure to start. Common cause failure adjustments were auto matically made for a common cause failure of both MDEFWs in accordance with RASP manual gui dance. The dominant accident sequence was a plant transient with a failure of main feedwater and all emergency feedwater. The change in core damage frequency for a 184-day ex posure period was approximately 2.8 E-7 which corresponds to a finding of very lo w safety significance (Green).

Cross-Cutting Aspect: Not Present Performance. No cross-cuttin g aspect was assigned to this finding because the inspectors determined the finding did not reflect present licensee performance.

Enforcement:

Violation: 10 CFR Part 50, Appendix B, Criterion V, states, in part, that activities affecting quality shall be prescribed by documented instructions, procedu res, or drawings, of a type appropriate to the circumstances and shall be accomplished in a ccordance with these instructions, procedures, or drawings. Contrary to the above, s ince original construction, the licensee failed to install shorting jumpers in the safety-relat ed 4160V switchgears for the motor driven emergency feedwater pumps on all three units, as p rescribed in station drawings OEE-117-90, OEE-117-91, OEE-217-54, OEE-217-55, OEE-31 7-66, and OEE-317-67.

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

URI Operation of Normally Closed Seismic Boundary Valves 71111.18 URI 05000269,05000270,05000287/2020003-02 Description: In 1998, NCR 1880594 described a need to develop a site licensing position for the opening of normally closed, manually operated, seismic boun dary valves and whether any specific limitations or compensatory actions were required. In May of 2000, the licensee established a position and modified UFSAR Section 3.7.3.9, Int eraction of Other Piping with Piping Designed for Seismic Conditions, through implementation of UFSAR Change Package 99-219. The change concluded that opening any seismic b oundary valve was acceptable and would not impact system operability for evolutio ns with a clearly definable beginning and end time and that the expectation was that the va lve would be in the closed

position much more than it would be in the open position. After this position was challenged by inspectors, the licensee determined that the original approv ed 10 CFR 50.59 review that was used to change UFSAR Section 3.7.3.9 could not be located. Inspectors opened this unresolved item (URI) to determine if the licensees method of operating seismic system boundary valves in the past had created any risk-significant re gulatory issues.

In response to the opening of this URI, the licensee took sever al actions. Firstly, they created a UFSAR change package that will remove the vague language unsu pported by a valid 10 CFR 50.59 review regarding operation of seismic boundary valves from Section 3.7.3.9 of the UFSAR. In addition, the licensee created calculation OSC-11334, "Seismic to Non-Seismic Piping Boundary Valve Review," Rev 0. This calculation establis hed a new licensing basis review of all seismic boundary valves in the plant to support t he modified language in UFSAR Section 3.7.3.9. Seismic boundary valves were categorized into groups based on several factors, such as whether they are open or closed in mode 1. The list of valves was then evaluated for their potential to adversely affect the safety-re lated functions of structures, systems, and components (SSCs) if a break were to occur in non-seismic piping. The calculation identified no significant issues with any of the re viewed valves. Inspectors performed a detailed review of the calculation and its assumpti ons and reviewed a sample of valves through smart sample selection on the 2021 power operate d valve (POV) engineering team inspection in August 2021.

Inspectors determined through the reviews described above that all the performance deficiencies identified, which include the missing 10 CFR 50.59 record, the unsupported UFSAR language, and a missing analysis which was identified for a specific valve during the POV inspection, were minor. Specifically, all the more than min or screening questions in IMC 0612, Issue Screening, were answered "no" for all performance d eficiencies identified. Additionally, the sample-based review of calculatio n OSC-11334 did not identify any examples of seismic boundary valve operation that challenge d the safety-related function of an SSC.

Corrective Action Reference(s): NCRs 2347573, 2393991

EXIT MEETINGS AND DEBRIEFS

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

• On August 26, 2021, the inspectors presented the Triennial Hea t Sink inspection results to Steve Snider and other members of the licensee staff.

• On September 30, 2021, the inspectors presented the TI-194 Rev ision 2 inspection results to Steve Snider and other members of the licensee staff.

• On October 25, 2021, the inspectors presented the integrated i nspection results to Steve Snider and other members of the licensee staff.

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