IR 05000269/2013005

IR 05000269-13-005, 05000270-13-005, 05000287-13-005; 05000269-13-502, 05000270-13-502, 05000287-13-502; on 10/01/2013 - 12/31/2013; Oconee Nuclear Station Units 1, 2 and 3; Problem Identification and Resolution

ML14037A283
Person / Time
Site:	Oconee
Issue date:	02/06/2014
From:	Gerald Mccoy NRC/RGN-II/DRP/RPB1
To:	Batson S Duke Energy Carolinas
References
IR-13-005, IR-13-502
Download: ML14037A283 (53)

Text

UNITED STATES ruary 6, 2014

SUBJECT:

OCONEE NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000269/2013005, 05000270/2013005, 05000287/2013005 AND EMERGENCY PREPAREDNESS INSPECTION REPORT 05000269/2013502, 05000270/2013502, 05000287/2013502

Dear Mr. Batson:

On December 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Oconee Nuclear Station Units 1, 2, and 3. The enclosed inspection report documents the inspection results, which were discussed on January 13, 2014, with you and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented one finding of very low safety significance (Green) in this report.

This finding involved a violation of NRC requirements. Further, inspectors documented a licensee-identified violation, which was determined to be of very low safety significance, in this report. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the Enforcement Policy. If you contest these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the 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 Regional Administrator, Region II; and the NRC resident inspector at the Oconee Nuclear Station.

As a result of the Safety Culture Common Language Initiative, the terminology and coding of cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting aspects identified in CY 2014 will be coded under the latest revision to IMC 0310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment review. In accordance with 10 Code of Federal Regulations 2.390 of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's document system (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Gerald J. McCoy, Chief Reactor Projects Branch 1 Division of Reactor Projects Docket Nos.: 50-269, 50-270, 50-287 License Nos.: DPR-38, DPR-47, DPR-55

Enclosure:

NRC Integrated Inspection Report 05000269/2013005, 05000270/2013005, 05000287/2013005 and Emergency Preparedness Inspection Report 05000269/2013502, 05000270/2013502, 05000287/2013502 w/Attachment:

Supplementary Information

REGION II==

Docket Nos: 50-269, 50-270, 50-287 License Nos: DPR-38, DPR-47, DPR-55 Report Nos: 05000269/2013005, 05000270/2013005, 05000287/2013005 05000269/2013502, 05000270/2013502, 05000287/2013502 Licensee: Duke Energy Carolinas, LLC Facility: Oconee Nuclear Station, Units 1, 2 and 3 Location: Seneca, SC 29672 Dates: October 1, 2013, through December 31, 2013 Inspectors: E. Crowe, Senior Resident Inspector G. Croon, Resident Inspector N. Childs, Resident Inspector B. Collins, Reactor Inspector (Section 1R08)

M. Coursey, Reactor Inspector (Section 1R08)

R. Williams, Senior Reactor Inspector (Sections 1R08)

J. Laughlin, Emergency Preparedness Inspector (Section1EP4)

M. Meeks, Senior Operations Engineer (Section 1R11)

A. Alen, Reactor Inspector (Section 1R17)

T. Fanelli, Reactor Inspector (Section 1R17)

G. Crespo, Senior Construction Inspector (Section 1R17)

C. Dykes, Health Physicist (Sections 2RS3, 2RS4)

W. Loo, Senior Health Physicist (Sections 2RS1, 4OA1)

A. Nielsen, Senior Health Physicist (Section 2RS5)

G. Ottenberg, Senior Reactor Inspector (Section 4OA5.3)

C. Rapp, Senior Project Engineer (Section 4OA5.3)

J. Rivera, Health Physicist (Sections 2RS2, 4OA1)

Approved by: Gerald McCoy, Chief Reactor Projects Branch 1 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000269/2013-005, 05000270/2013-005, 05000287/2013-005; 05000269/2013-502, 05000270/2013-502, 05000287/2013-502; 10/01/2013 - 12/31/2013; Oconee Nuclear Station Units 1, 2 and 3; Problem Identification and Resolution The report covered a three-month period of inspection by the resident inspectors and 13 Region-based reactor inspectors. One Green non-cited violation (NCV) was identified. The significance of inspection finding is indicated by its color (i.e., greater than Green, or Green,

White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP) dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310,

Components Within the Cross-Cutting Areas dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated June 12, 2012. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process revision 4.

Cornerstone: Mitigating Systems

Green.

An NRC-identified non-cited violation (NCV) of 10 CFR 50.48(c) and National Fire Protection Association Standard 805 (NFPA 805), Section 3.11.4, was identified for the licensees failure to comply with the fire barrier penetration sealing and inspection requirements of the approved fire protection program (FPP). The annular space between the fire barrier opening and the 2 conduit was not properly sealed. The licensee entered the issue in their CAP as PIP O-13-09104, initiated a work order to repair the seal, and implemented an hourly fire watch as required by Oconee Selected Licensee Commitment (SLC) 16.9.5.

The licensees failure to comply with the fire barrier penetration sealing and inspection requirements of the approved fire protection program was a performance deficiency. This performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of protection against external factors (i.e.,

fire) and adversely affected the cornerstone in that the fire barrier could not be relied upon to fully perform its function. The finding was screened using NRC IMC 0609, Appendix F, Fire Protection Significance Determination Process, and determined to be of very low safety significance (Green) because safety significant equipment was located a sufficient distance from the degraded penetration and the reactors ability to reach and maintain a safe shutdown condition was not impacted. The cause of this finding was determined to have a cross-cutting aspect of H.2(c) in the Resources component of the Human Performance area because the licensee did not ensure that complete, accurate, and up-to-date design documentation and procedures were available because adequate guidance was not included in the maintenance inspection procedures to allow personnel to identify a degraded condition. (Section 4OA2.3)

Violations of very low safety significance that were identified by the licensee have been reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered in the licensee's CAP. These violations and associated CAP tracking numbers are listed in Section 4OA7.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at approximately 100 percent rated thermal power (RTP).

The Unit was shut down to Mode 5 on November 12, 2013, to repair a leak on high pressure injection (HPI) piping inside containment. The unit returned to 100 percent RTP on December 2, 2013, where it remained for the rest of the inspection period.

Unit 2 began the inspection period at approximately 100 percent RTP and remained there until a planned end-of-cycle power coast down commenced on October 3, 2013. The unit was removed from service on October 12, 2013, and entered the refueling outage. The unit returned to 100 percent RTP on December 7, 2013, where it remained for the rest of the inspection period.

Unit 3 began the inspection period at approximately 100 percent RTP where it remained until the unit was manually tripped on October 24, 2013 due to feed water oscillations. The unit returned to 100 percent RTP on October 28, 2013, where it remained for the rest of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

Readiness for Seasonal Extreme Weather Conditions: The inspectors reviewed the licensees preparations for adverse weather associated with the cold ambient temperatures at the site. This included field walkdowns to assess the material condition and operation of freeze protection equipment, as well as other preparations made to protect plant equipment from freezing conditions. In addition, the inspectors reviewed the licensees procedures for preparing for cold weather and conducted interviews with personnel responsible for implementing the licensees cold weather protection program to assess the licensees ability to identify and resolve deficient conditions associated with cold weather protection equipment prior to cold weather events. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R04 Equipment Alignment

a. Inspection Scope

Partial Walkdown: The inspectors performed the three partial walkdowns listed below to assess the operability of redundant or diverse trains and components when safety-related equipment was inoperable or out-of-service and to identify any discrepancies that could impact the function of the system potentially increasing overall risk. The inspectors reviewed applicable operating procedures and walked down system components, selected breakers, valves, and support equipment to determine if they were correctly aligned to support system operation. The inspectors reviewed protected equipment sheets, maintenance plans, and system drawings to determine if the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the corrective action program (CAP). Documents reviewed are listed in the

.

• Unit 3 condensate and feedwater systems following maintenance that addressed system oscillations during orange site risk condition

• Unit 1 and 2 electrical distribution system during orange risk condition for mid-loop RCS conditions

• Unit 1 low pressure injection system during orange risk condition for mid-loop RCS conditions Full System Walkdown: The inspectors performed a full system walk down of the Unit 3 emergency feedwater system (EFW) after reviewing applicable operating procedures and design basis documents to determine correct system lineup. The inspectors walked down system components, selected breakers, and support equipment to determine if they were correctly aligned to support system operation. The inspectors reviewed open work orders, open modification documents, and active operator work arounds to determine their overall impact on the Unit 3 EFW system. Open Problem Investigation Program (PIP) items were also reviewed to ensure system and equipment issues were being identified and entered into the CAP. The Unit 3 EFW system health report was reviewed to ensure system issues were being tracked by engineering and addressed as appropriate. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R05 Fire Protection

a. Inspection Scope

Fire Area Tours: The inspectors walked down accessible portions of the six plant areas listed below to assess the licensees control of transient combustible material and ignition sources, fire detection and suppression capabilities, fire barriers, and any related compensatory measures. The inspectors observed the fire protection suppression and detection equipment to determine if any conditions or deficiencies existed which could impair the operability of that equipment. The inspectors selected the areas based on a review of the licensees safe shutdown analysis probabilistic risk assessment and sensitivity studies for fire-related core damage accident sequences. Documents reviewed are listed in the Attachment.

• Unit 1 auxiliary boiler area (fire zone 24)

• Unit 1 Low Pressure Injection (LPI) hatch area (fire zone 70)

• Unit 2 6900/4160 volt switchgear area (fire zone 33)

• Unit 2 LPI hatch area (fire zone 67)

• Unit 2 Reactor building (fire zone 123)

• Unit 3 Air handling room (fire zone 113)

b. Findings

No findings were identified.

1R06 Flood Protection Measures

a. Inspection Scope

Internal Flooding Review: The inspectors reviewed risk-important plant design features and licensee procedures to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analysis documentation associated with internal plant areas to determine the effects of flooding for the area listed below. The internal area was selected and walked down based on the flood analysis calculation. The inspectors reviewed sealing of doors, holes in elevation penetrations, sump pump operations and potential flooding sources. The inspectors reviewed CAP documents to ascertain the licensee was identifying and resolving issues. Documents reviewed are listed in the Attachment.

• 3A Low Pressure Injection Pump Room

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

a. Inspection Scope

Non-Destructive Examination (NDE) Activities and Welding Activities: The inspectors conducted an on-site review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system (RCS), steam generator (SG) tubes, risk-significant piping and components and containment systems.

The inspectors activities included a review of NDEs to evaluate compliance with the applicable edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC),Section XI (Code of record: 1998 Edition through 2000 Addenda), and to verify that indications and defects (if present) were appropriately evaluated and dispositioned in accordance with the requirements of the ASME Code,Section XI, acceptance standards.

The inspectors observed the following NDEs mandated by the ASME Code Section XI to evaluate compliance with the ASME Code Section XI and Section V requirements and, if any indications or defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

Ultrasonic Testing (UT)

• Low Pressure Injection Pipe-to-Elbow Weld 2LP-217-4, 10, ASME Class 1

• Low Pressure Injection Elbow-to-Pipe Weld 2LP-217-5, 10, ASME Class 1

• Low Pressure Injection Pipe-to-Elbow Weld 2LP-217-13, 10, ASME Class 1 The inspectors also reviewed records of the following non-destructive examinations mandated by the ASME Code Section XI to evaluate compliance with the ASME Code Section XI and Section V requirements and, if any indications or defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

Liquid Penetrant Testing (PT)

• Weld #2-54A-0008-03-98, Building Spray System, 2, ASME Class 2 During non-destructive surface and volumetric examinations performed since the previous refueling outage, the licensee did not identify any recordable indications that were accepted for continued service. Therefore, no NRC review was completed for this inspection procedure attribute.

The inspectors observed the following pressure boundary welds completed for risk-significant systems during the Unit 2 refueling outage to evaluate if the licensee applied the preservice non-destructive examinations and acceptance criteria required by the Construction Code. In addition, the inspectors reviewed the welding procedure specification, welder qualifications, welding material certification and supporting weld procedure qualification records, to evaluate if the weld procedures were qualified in accordance with the requirements of Construction Code and the ASME Code Section IX.

• Weld numbers 2-BS-0036-91 through - 96, Inspection Ports on Building Spray System Piping, 2 OD, ASME, Class 2

• Weld numbers 2-HP-0495-57 through -63, 2.5 Motor Operated Valve 2HP-1, High Pressure Injection System, Class 1

• Weld numbers 2-HP-0524-50 through -56, 2.5 Motor Operated Valve 2HP-2, High Pressure Injection System, Class 1 PWR Vessel Upper Head Penetration (VUHP) Inspection Activities: For the Unit 2 vessel head a volumetric examination was required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D). The inspectors reviewed portions of the Unit 2 ultrasonic (UT)examinations and reviewed NDE records for penetration Nos. 2, 21, 28, 45 and 63, to evaluate if the activities were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). In particular, the inspectors evaluated if the required UT examination scopes and coverages were achieved and if limitations (if applicable) were recorded in accordance with the licensees procedures.

Additionally, the inspectors evaluated if the licensees criteria for UT examination quality and instructions for resolving interference and masking issues were consistent with 10 CFR 50.55a.

Boric Acid Corrosion Control (BACC) Inspection Activities: The inspectors reviewed the licensees BACC program activities to ensure implementation with commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary, and applicable industry guidance documents. Specifically, the inspectors performed an on-site record review of procedures and the results of the licensees containment walk-down inspections performed during the current fall refueling outage. The inspectors also interviewed the BACC program owner, conducted an independent walkdown of containment to evaluate compliance with licensees BACC program requirements, and verified that degraded or non-conforming conditions, such as boric acid leaks, were properly identified and corrected in accordance with the licensees BACC and corrective action programs.

The inspectors reviewed the following condition reports and associated corrective actions related to evidence of boric acid leakage to evaluate if the corrective actions completed were consistent with the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B, Criterion XVI.

• PIP O-11-13969, Unit 2 EOC25 Startup - Mode 3 Discovery Items (2HP-209)

• PIP O-12-08011, Unit 2 RB Tour Results (MODE 1) (2RC-206)

• PIP O-13-07265, Unit 2 RB Tour Results (MODE 1) (2RC-206)

The inspectors reviewed the following licensee evaluations of RCS components with boric acid deposits to evaluate if degraded components were documented in the corrective action system. The inspectors also evaluated the corrective actions for any degraded RCS components against the component ASME Code Section XI, and other licensee-committed documents:

• PIP O-11-14729, 2LWD-391 Has Excessive Dry Boron Leak

• PIP O-12-08859, 2HPI-IV-0132 Has Rust-Colored Boric Acid Deposits

• PIP O-13-00073, 2HP-31 Has Inactive, Rust-Colored Boric Acid Deposit Steam Generator (SG) Tube Inspection Activities. The inspectors reviewed the Unit 2 eddy current (EC) examination activities in SGs 2A and 2B to evaluate the inspection activities against the licensees Technical Specifications, NRC commitments, ASME Section XI, and Nuclear Energy Institute (NEI) 97-06, Steam Generator Program Guidelines. The inspectors reviewed the scope of the EC examinations to verify it included the applicable potential areas of tube degradation. The inspectors also verified that appropriate inspection scope expansion criteria were planned based on inspection results. Additionally, the inspectors reviewed EC examination status reports to ensure that all tubes with relevant indications were appropriately screened for in-situ pressure testing. Based on the EC examination results, no new degradation mechanisms were identified, no EC scope expansion was required, and none of the SG tubes examined met the criteria for in-situ pressure testing.

The inspectors reviewed the last Condition Monitoring and Operational Assessment report to assess the licensees prediction capability for maximum tube degradation. The inspectors review also included the licensees repair criteria and repair process to ensure they were consistent with plant Technical Specifications and industry guidelines.

Two tubes in SG A and ten tubes in SG B met the criteria for repair or plugging. The inspectors also reviewed the primary to secondary leakage (e.g., SG tube leakage)history for the last operating cycle. The inspectors noted that primary to secondary leakage was below the detection threshold during the previous operating cycle.

In addition, the inspectors reviewed documentation to ensure that data analysts, EC probes, and equipment configurations were qualified to detect the existing and potential SG tube degradation mechanisms. The inspectors review included a sample of site-specific Examination Technique Specification Sheets (ETSSs) to ensure that their qualification was consistent with Appendix H or I of the Electric Power Research Institute Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7.

Furthermore, the inspectors reviewed a sample of EC data with a qualified data analyst including the following tubes: SG A (R21C13, R86C121, R98C127, R147C23, and R10C7) and SG B (R8C42, R139C59, R59C1, R141C58 and R60C6). The inspectors reviewed the licensees corrective actions for indications (either from EC or secondary side visual inspections) of potential loose parts on the SG primary and secondary side, including direct observation of Foreign Object Search and Retrieval (FOSAR) activities, top of tubesheet periphery and tube bundle visual inspection activities, and visual inspection of areas of tube support plates 9 and 10.

Identification and Resolution of Problems: The inspectors performed a review of a sample of ISI- and SGISI-related problems which were identified by the licensee and entered into the CAP as PIPs. The inspectors reviewed the PIPs to confirm that the licensee had appropriately described the scope of the problem, and had initiated corrective actions. The review also included the licensees consideration and assessment of operating experience events applicable to the plant. The inspectors performed this review to ensure compliance with 10CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. Document reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification

a. Inspection Scope

Routine Operator Requalification Review: On October 1, 2013, the inspectors observed one active simulator training session to assess the performance of licensed operators during the session. The scenario involved a dropped control rod, followed by loss of main feed water, and subsequent loss of EFW. Events progressed to a point where the crew entered an Alert emergency declaration. The post-scenario critique conducted by the training instructor and the crew was also observed. Documents reviewed are listed in the Attachment.

Observation of Operator Performance: The inspectors observed operator performance in the main control room on October 12, 2013, during Unit 2 shutdown. Inspectors observed licensed operator performance to assess the following:

• Use of plant procedures

• Control board manipulations

• Communications between crew members

• Use and interpretation of instruments, indications, and alarms

• Use of human error prevention techniques

• Documentation of activities

• Management and supervision Annual Review of Licensee Requalification Examination Results: On April 4, 2013, the licensee completed the comprehensive biennial requalification written examinations and the annual requalification operating examinations required to be administered to all licensed operators in accordance with 10 CFR 55.59(a)(2). The inspectors performed an in-office review of the overall pass/fail results of the individual operating examinations and the crew simulator operating examinations in accordance with Inspection Procedure (IP) 71111.11, Licensed Operator Requalification Program. These results were compared to the thresholds established in Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Appendix I, Operator Requalification Human Performance Significance Determination Process.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the licensees effectiveness in performing the following two corrective maintenance activities. These reviews included an assessment of the licensees practices pertaining to the identification, scoping, and handling of degraded equipment conditions, as well as common cause failure evaluations. For each activity selected, the inspectors performed a detailed review of the problem history and surrounding circumstances, evaluated the extent of condition reviews as required, and reviewed the generic implications of the equipment and/or work practice problem. For those structures, systems and components (SSCs) scoped in the Maintenance Rule per 10 CFR 50.65, the inspectors verified that reliability and unavailability were properly monitored and that 10 CFR 50.65 (a)(1) and (a)(2) classifications were justified in light of the reviewed degraded equipment condition. Documents reviewed are listed in the

.

• PIP-13-03281, 3A low pressure service water (LPSW) pump tripped during pump start most likely due to silicon controlled rectifier leakage in the 50G/GR5 ground fault relay

• PIP-12-01611, 3A LPSW pump showing an unexplained trend of increasing developed head

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors evaluated the following attributes for the activity listed below: 1) the effectiveness of the risk assessments performed before maintenance activities were conducted; 2) the management of risk; 3) that, upon identification of an unforeseen situation, necessary steps were taken to plan and control the resulting emergent work activities; and 4) that maintenance risk assessments and emergent work problems were adequately identified and resolved. Documents reviewed are listed in the Attachment.

• Complex Critical Plan, Risk Mitigation for Conditions with Loops Dropped and During Hot Mid-Lop until Unit 2 RCS Loops Full and Vented.

b. Findings

No findings were identified.

1R15 Operability Evaluations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed the following four operability evaluations or functionality assessments affecting risk significant systems to assess: 1) the technical adequacy of the evaluations; 2) whether continued system operability was warranted; 3) whether other existing degraded conditions were considered; 4) if compensatory measures were involved, whether the compensatory measures were in place, would work as intended, and were appropriately controlled; and 5) where continued operability was considered unjustified, the impact on Technical Specifications (TS) limiting condition for operations.

Operating Experience Smart Sample (OpESS ) 2012/02, Technical Specification Interpretation and Operability Determination was used by the inspectors during the review.

• PIP O-13-11736 - Damage to 2-HP-25 during VIPR testing

• PIP O-13-11254 - Unit 2 Room 518 high energy line break (HELB) door left open and unattended

• PIP O-13-11955 - Unit 2 fretting of fuel during cycle 2EOC26 and the use of this fuel for cycle 2EOC27

• PIP O-13-13291 - Use of reactor building cooling units during a protected service water event. Environment (EQ) concern with use of the Adalet PLM JAG connectors and ScotchCast 9 epoxy

b. Findings

No findings were identified.

1R17 Evaluations of Changes, Tests, or Experiments, and Permanent Plant Modifications

a. Inspection Scope

Evaluations of Changes, Tests, and Experiments: The inspectors reviewed six safety evaluations listed in the Attachment to determine if the evaluations were adequate and that prior NRC approval was obtained as appropriate. The inspectors reviewed these documents to determine if:

• the changes, tests, or experiments performed were evaluated in accordance with 10 CFR 50.59 and that sufficient documentation existed to confirm that a license amendment was not required

• the safety issues requiring the changes, tests, or experiments were resolved the licensee conclusions for evaluations of changes, tests, or experiments were correct and consistent with 10 CFR 50.59

• the design and licensing basis documentation used to support the change was updated to reflect the change The inspectors used, in part, Nuclear Energy Institute (NEI) 96-07, Guidelines for 10 CFR 50.59 Implementation, Rev. 1, to determine acceptability of the completed safety evaluations. The NEI document was endorsed by the NRC in Regulatory Guide 1.187, Guidance for Implementation of 10 CFR 50.59, Changes, Tests, and Experiments, dated November 2000. The team also consulted Part 9900 of the NRC Inspection Manual, 10 CFR Guidance for 10 CFR 50.59, Changes, Tests, and Experiments, dated March 2001.

Permanent Plant Modifications: The inspectors reviewed licensee activities associated with the following two permanent plant modifications. The inspectors reviewed corrective action documentation, initiated during implementation of the modification, to evaluate the accuracy and thoroughness of the licensees investigations, conclusions, and corrective actions. Documents reviewed are listed in the Attachment.

• Tornado and High-Energy Line Break Project Modification - Emergency Power Supply for the Protected Service Water (PSW) System - The inspectors reviewed engineering change (EC) package 91875, Keowee AC Power Supply Tie-ins, Rev.

15. The inspectors reviewed the Unit 2 breaker coordination studies and one-line and control schematic diagrams to assess the effectiveness of the licensees implementation of design controls measures with respect to the design change. The review focused on Unit 2 installation and testing observed for the lockout relays 86-KPF11 located inside the Keowee Hydro Station.

• Tornado and High-Energy Line Break Project Modification - Electrical Equipment for the New PSW System - The inspectors reviewed completed test results for the initial in-service and periodic testing of the PSW battery chargers to verify that acceptance criteria for tested parameters were in accordance with the manufacturers specifications. Additionally, the inspectors assessed the adequacy and effectiveness of the licensees implementation of testing procedures.

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following temporary plant modification to verify the adequacy of the modification package and the 10 CFR 50.59 screenings and to evaluate the modification for adverse effects on system availability, reliability, and functional capability. Documents reviewed are listed in the Attachment.

• WO0108271 Provide temporary power to air handling unit 3-13

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following three post-maintenance test procedures and/or test activities to assess if: 1) the effect of testing on the plant had been adequately addressed by control room and/or engineering personnel; 2) testing was adequate for the maintenance performed; 3) acceptance criteria were clear and demonstrated operational readiness consistent with design and licensing basis documents; 4) test instrumentation had current calibrations, range, and accuracy consistent with the application; 5) tests were performed as written with applicable prerequisites satisfied; 6) jumpers installed or leads lifted were properly controlled; 7) test equipment was removed following testing; and 8) equipment was returned to the status required to perform its safety function. Documents reviewed are listed in the Attachment.

• PT/0/A/0610/024, Keowee Emergency Start for Troubleshooting and Post Maintenance Checkouts

• PT/3/A/0600/12, Turbine Driven Emergency Feedwater Pump Test after Lube PM per WO 2083359

• MP/0/A/1200/089, Main steam relief valve safety setpoint pop and stroke tests after outage maintenance per WO 02078012

b. Findings

No findings were identified.

1R20 Refueling and Outage Activities

.1 Refueling Outage

a. Inspection Scope

The inspectors evaluated licensee outage activities associated with the Unit 2 refueling outage to determine if the licensee considered risk in developing outage schedules; adhered to administrative risk reduction methodologies they developed to control plant configuration; adhered to operating license, Technical Specifications (TS) and Selected Licensee Commitment requirements and procedural guidance that maintained defense-in-depth; and developed mitigation strategies for losses of the key safety functions. The inspectors reviewed the licensees outage risk control plan to assess the adequacy of the risk assessments that had been conducted and that the licensee had implemented appropriate risk management strategies as required by 10 CFR 50.65(a)(4). The inspectors conducted portions of the following activities associated with the refueling outage. Documents reviewed are listed in the Attachment.

• Observed Just-in-Time training conducted for the shift involved in the removing the unit from service and unit cooldown which simulated bringing the unit from Mode 3 to Mode 5 at the start of the outage and the approach to criticality and placing the generator on-line at the end of the outage.

• Observed power reduction process, removing the reactor from service and portions of the cooldown from normal operating pressure and temperature to ensure that the requirements in the TS and Selected Licensee Commitments were followed.

• Conducted a containment entry once Mode 3 had been reached to observe the condition of major, normally-inaccessible equipment and check for indications of previously unidentified leakage from the reactor coolant system including the reactor vessel upper and bottom head penetrations.

• Reviewed the licensees responses to emergent work and unexpected conditions to verify that resulting configuration changes were controlled in accordance with the outage risk control plan.

• Observed the removal and reinstallation of the reactor vessel head and plenum assembly to ensure the lift was conducted in accordance the station procedures and heavy lift guidance.

• Periodically reviewed the setting and maintenance of containment integrity, to establish that the RCS and containment boundaries were in place and had integrity when necessary.

• Observed fuel handling operations during new fuel receipt, movement into the spent fuel pool, reactor core offload and reload to verify that those operations and activities were being performed in accordance with TS and procedural guidance. Reviewed the videotape core loading verification and alignment with Reactor Engineering personnel.

• Reviewed system lineups and/or control board indications to substantiate TS, license conditions, and other requirements, commitments, and administrative procedure prerequisites for mode changes were met prior to changing modes or plant configurations.

• Conducted containment walkdown to inspect for overall cleanliness and material condition of plant equipment after the licensee completed their closeout inspection prior to restart.

• Observed the approach to criticality, placing the main generator on-line, and portions of the power ascension activities.

• Reviewed the items that had been entered into the CAP to verify that the licensee had identified outage related problems at an appropriate threshold.

• Reviewed the licensees processing of workers as they transitioned from on-line to outage work hour restrictions and then back to on-line schedules at the completion of the Unit 2 refueling outage.

• Observed activities to verify that the licensee maintained defense-in-depth commensurate with the outage risk control plan for key safety functions and applicable TS when taking equipment out of service.

b. Findings

No findings were identified

.2 Forced Outage

a. Inspection Scope

The inspectors evaluated licensee outage activities associated with the Unit 1 forced outage due to pressure boundary leakage associated with 1B2 high pressure injection (HPI) nozzle. The inspectors evaluated the licensees consideration of risk and risk reduction methodologies in developing a repair schedule; adherence to the operating license, TS and Selected Licensee Commitment requirements and procedural guidance that maintained defense-in-depth; and developed mitigation strategies for losses of the key safety functions. The inspectors conducted portions of the following activities associated with the forced outage. Documents reviewed are listed in the Attachment.

• Observed power reduction process, removing the reactor from service and portions of the cooldown from normal operating pressure and temperature to ensure that the requirements in the TS and Selected Licensee Commitments were followed.

• Conducted a containment entry once Mode 3 had been reached to observe the condition of major, normally-inaccessible equipment and check for indications of previously unidentified leakage from the reactor coolant system including the reactor vessel upper head penetrations.

• Reviewed the licensees plans for inclusion of work related previously identified conditions adverse to quality to ensure timely resolution of emergent issues and these activities were controlled in accordance with the forced outage risk control plan.

• Reviewed system lineups and/or control board indications to substantiate that TS, license conditions, and other requirements, commitments, and administrative procedure prerequisites for mode changes were met prior to changing modes or plant configurations.

• Conducted containment walkdown to inspect for overall cleanliness and material condition of plant equipment after the licensee completed their closeout inspection prior to restart.

• Observed the approach to criticality, placing the main generator on-line which completed the forced outage and portions of the power ascension activities.

• Reviewed the items that had been entered into the CAP to verify that the licensee had identified outage related problems at an appropriate threshold.

• Observed activities to verify that the licensee maintained defense-in-depth commensurate with the outage risk control plan for key safety functions and applicable TS when taking equipment out of service.

• Observed the licensees control of work activities to ensure that refueling outage activities of Unit 2 did not interfere with Unit 1 force outage activities and risk.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors either witnessed and/or reviewed test data for the five surveillance tests listed below to assess if the SSCs met TS, Updated Final Safety Analysis Report (UFSAR), and licensee procedure requirements. In addition, the inspectors determined if the testing effectively demonstrated that the SSCs were ready and capable of performing their intended safety functions. Documents reviewed are listed in the

.

Routine Surveillances

• WO 02117463, 3C Essential syphon vacuum pump test

• PT/2/A/0610/001 J, Emergency Power Switching Logic Functional Test

• PT/3/A/0203/06 AC, 3C Low Pressure Injection pump test Containment Isolation Valve Tests

• WO 02078460, local leak rate test of penetration 56 which includes valves 2SF-61, 81, 87, and 127

• WO 0202849, local leak rate test of penetration 45 which includes valves 2LRT-24, 25, 36, 37, 38, and 39

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The NSIR headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures (EPIPs) and the Emergency Plan located under ADAMS accession numbers ML12352A125, ML123630268, ML13074A525, ML13105A009, and ML13323A764, as listed in the Attachment.

The licensee determined that in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, these revisions are subject to future inspection. Documents reviewed are listed in the Attachment. This inspection activity satisfied one inspection sample for the emergency action level and emergency plan changes on an annual basis.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors evaluated the licensees performance in the Unit 1 simulator and the Technical Support Center on December 10, 2013. The drill involved an HPI pump trip, a total loss of feedwater, and loss of reactor sub-cooling margin. The NRC assessment focused on the timeliness and location of classification, offsite agency notification, and the licensees expectations of response. The performance of emergency response organization was evaluated against applicable licensee procedures and regulatory requirements. The inspectors attended the post-exercise critique for the drill to evaluate the licensees self-assessment process for identifying potential deficiencies relating to failures in classification and notification. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones; Occupational Radiation Safety and Public Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

Hazard Assessment and Instructions to Workers: During facility tours of Units 1, 2, and 3, the inspectors observed labeling of radioactive material and postings for radiation areas (RAs), high RAs (HRAs), and very HRAs (VHRAs) in the radiologically controlled areas (RCAs), Independent Spent Fuel Storage Installations (ISFSIs), and selected radioactive waste (radwaste) processing and storage locations to include Warehouse No. 10. Inspectors also observed and evaluated labels on selected containers in those selected locations. The inspectors reviewed survey records for several plant areas to include surveys for:

• alpha emitters

• hot particles

• airborne radioactivity

• gamma surveys within areas of high dose rate gradients

• pre-job surveys for upcoming tasks Inspectors independently surveyed areas in the plant and compared results to radiological conditions and postings in the plant. Inspectors also reviewed air sample records and observed work in potential airborne areas to assess the location of air monitors to include the core barrel move and Unit 2 letdown storage tank valve cutout.

The inspectors discussed changes to plant operations that could contribute to changing radiological conditions since the last inspection. For selected Unit 2 refueling outage jobs, the inspectors attended pre-job briefings and reviewed radiation work permit (RWP) details to assess communication of radiological control requirements and current radiological conditions to workers.

Hazard Control and Work Practices The inspectors evaluated access barrier effectiveness for locked high radiation area (LHRA) and VHRA locations. Procedures for LHRA and VHRA access controls were discussed with cognizant health physics (HP)supervisors and staff, and Operations personnel. Controls and their implementation for storage of irradiated material within the spent fuel pool (SFP) were reviewed and discussed with cognizant radiation protection (RP) and reactor engineering (RE)personnel. Areas where dose rates could change significantly as a result of plant shutdown and refueling operations were also discussed. Radiological controls were evaluated for selected refueling outage tasks to include:

• core barrel move

• letdown storage tank valve cutout

• annulus inspections

• containment at power entry Occupational workers adherence to selected RWPs and HP technician (HPT)proficiency in providing job coverage was evaluated through direct observations and interviews with selected licensee staff of selected refueling outage activities. Electronic dosimeter alarm set points and worker stay times were evaluated against area radiation survey results for selected refueling outage work activities in the reactor, auxiliary and turbine buildings. Worker response to dose and dose rate alarms during selected work activities was evaluated. HPT coverage and actions at the Unit 2 containment access point, remote monitoring area, and RCA Single Point of Access (SPA) were reviewed.

Control of Radioactive Material The inspectors observed the use of small article monitors, personnel contamination monitors, and portal monitors to survey material and personnel being released from the:

• RCA SPA

• turbine deck

• radwaste facility

• Warehouse No. 10 The inspectors also walked-down portions of the ISFSI, auxiliary building, turbine deck, and radwaste storage areas. The inspectors compared recent 10 CFR Part 61 results for the dry active waste radwaste stream with radionuclides used in calibration sources to evaluate the appropriateness and accuracy of release survey instrumentation. The inspectors also reviewed source inventory and discussed leak tests for selected sealed sources and discussed nationally tracked source transactions with cognizant RP staff.

This included a walk down of storage locations for sealed sources to include Room Nos.

220, 332 and 362 in the auxiliary building.

Problem Identification and Resolution Problem Investigation Program (PIP) Reports associated with radiological hazard assessment and control were reviewed and assessed. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with NSD-208, Problem Investigation Program, Rev. 39.

RP activities were evaluated against the requirements and guidance of Updated Final Safety Analysis Report (UFSAR) Section 12; 10 Code of Federal Regulations Parts 19 and 20; Regulatory Guide 8.38, Control of Access to High and Very High Radiation Areas in Nuclear Power Plants, and approved licensee procedures. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

As Low As Reasonably Achievable (ALARA) Program Status The inspectors reviewed and discussed plant exposure history and current trends including the sites three-year rolling average (TYRA) collective exposure history for calendar year (CY) 2010 through CY 2012. Current and proposed activities to manage site collective exposure and trends regarding collective exposure were evaluated through review of previous TYRA collective exposure data and review of the licensees ALARA dose and source term reduction initiatives. Current ALARA program guidance and recent changes, as applicable, regarding estimating and tracking exposure were discussed and evaluated.

Radiological Work Planning Refueling outage work activities, exposure estimates, and mitigation activities were reviewed for the following high collective exposure tasks:

• Low Pressure Service Water (LPSW) piping replacement

• High Pressure Injection (HPI) HP 1 and 2 inlet isolation valves replacement

• Reactor vessel robotic inspections For the selected tasks, the inspectors reviewed dose mitigation actions and established dose goals. During the inspection, use of remote technologies including teledosimetry and remote visual monitoring as specified in RWP or procedural guidance were evaluated. Current collective dose data for selected tasks were compared with established estimates and, where applicable, changes to established estimates were discussed with responsible licensee ALARA planning representatives. The inspectors also reviewed and evaluated selected post-job reviews conducted for previous refueling outage work.

Verification of Dose Estimates and Exposure Tracking Systems The inspectors reviewed ALARA work packages and discussed assumptions with responsible planning personnel regarding the bases for the current estimates. The licensees on-line RWP cumulative dose databases used to track and trend current personal and cumulative exposure data and/or to trigger additional ALARA planning activities in accordance with current procedures were reviewed and discussed. Select work-in-progress reviews and adjustments to cumulative exposure estimate data were evaluated against work scope changes or unanticipated elevated dose rates.

Source Term Reduction and Control The inspectors reviewed historical dose rate trends for shutdown chemistry, cleanup, and resultant chemistry and radiation protection trend-point data against the current refueling outage data. The licensees chemistry control and source term reduction initiative was reviewed and discussed with pertinent personnel.

Problem Identification and Resolution The inspectors reviewed and discussed selected PIPs associated with ALARA program implementation. The reviewed items included PIPs, self-assessments, and quality assurance audit documents. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with licensee procedure Nuclear Policy Manual, NSD-208, Rev. 39.

The licensees ALARA program activities and results were evaluated against the requirements of UFSAR Section 12; Technical Specifications (TS) Sections 5.4 and 5.5; 10 CFR Parts 19 and 20; and approved licensee procedures. Records reviewed are listed in the Attachment. Radiation worker performance was reviewed as part of observations conducted for IP 71124.01 and is documented in section 2RS1.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

Engineering Controls The inspectors reviewed the use of temporary and permanent engineering controls to mitigate airborne radioactivity during the refueling outage. In addition, during observations of jobs in-progress and containment walk-downs, inspectors observed the placement and use of High Efficiency Particulate Air (HEPA)negative pressure units, and air sampling equipment. The inspectors evaluated the effectiveness of continuous air monitors and air samplers placed in work areas to provide indication of increasing airborne levels. The inspectors also reviewed procedural guidance for alpha emitter airborne monitoring.

Use of Respiratory Protection Devices Inspectors reviewed the use of respiratory protection devices to limit the intake of radioactive material, including devices used for routine tasks and devices stored for use in emergency situations.

The inspectors evaluated self-contained breathing apparatus (SCBA) and negative pressure respirator (NPR) compliance with National Institute for Occupational Safety and Health certification requirements. The inspectors also reviewed records of Grade D (or better) air quality testing for supplied-air devices and SCBA bottles. In addition, the inspectors walked-down the compressor used for filling SCBA bottles. The inspectors discussed the process for issuing respirators, and evaluated whether selected individuals qualified for respirator and/or SCBA use had completed the required training, fit-test, and medical evaluation. Inspectors interviewed personnel qualified for use of respiratory protection devices and tested their knowledge of donning and doffing of the equipment. Inspectors observed the physical condition of SCBA units, NPRs, air purifying respirators and device components staged for routine and emergency use throughout the plant. SCBA bottle air pressure, the number of units, and the number of spare masks and air bottles available were also evaluated by the inspectors.

Self-Contained Breathing Apparatus for Emergency Use Control room operators were interviewed on the use of the devices including SCBA bottle change-out and use of corrective lens inserts. Respirator qualification records and medical fitness records were reviewed and cross checked against several Main Control Room operators. In addition, qualifications for individuals responsible for testing and repairing SCBA vital components were evaluated through review of training records.

The inspectors walked-down the respirator issue and storage locations and evaluated whether the equipment was appropriately stored and maintained. Records of monthly and quarterly inventory and inspection of the equipment were also reviewed by the inspectors.

Problem Identification and Resolution Licensee CAP documents associated with the control and mitigation of in-plant radioactivity were reviewed and assessed. This included review of selected PIPS related to use of respiratory protection devices including SCBAs. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with NSD-208, Rev. 39. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Radiation protection activities were evaluated against the requirements UFSAR Section 12; 10 CFR Parts 19 and 20; and approved licensee procedures. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

External Dosimetry: Inspectors reviewed and discussed the licensees National Voluntary Accreditation Program (NVLAP) certification data for accreditation years April 2013 through March 2014 for Ionizing Radiation Dosimetry. Program procedures were reviewed for processing active personnel dosimeters and onsite storage of dosimeters were discussed. Comparisons between ED and personnel dosimeters were discussed in detail as part of the PI dosimetry corrective action program documents were reviewed.

Internal Dosimetry: Inspectors reviewed and discussed the in vivo bioassay program with the licensee. Inspectors reviewed procedures that addressed methods for determining internal or external contamination, releasing contaminated individuals, the assignment of dose and the frequency of measurements depending on the nuclides.

Inspectors reviewed and evaluated Whole Body Count records selected from January 2012 to October 2013. The licensees program for in vitro monitoring was reviewed and discussed in detail however, there were no dose assessments available for review by inspectors.

Special Dosimetric Situations: Inspectors reviewed records of monitored declared pregnant women (DPWs) since January 2012 and discussed guidance for monitoring and informing DPWs. Inspectors reviewed the licensees practice for monitoring external dose in areas if expected dose gradients. There were no available multi-badging dose assessments to review for the inspection time period. Inspectors reviewed the licensees neutron dosimetry and survey program. Inspectors reviewed neutron surveys related with ISFSI loading and monitoring.

Problem Identification and Resolution: Inspectors reviewed and discussed licensee CAP documents associated with occupational dose assessment. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with NSD-208, Rev. 39. The inspectors also discussed the scope of the licensees internal audit program and reviewed recent assessment results.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

Radiation Monitoring Instrumentation During tours of the auxiliary building and spent fuel pool areas, the inspectors observed various types of installed radiation detection equipment. The inspectors observed the physical location of the components, noted the material condition, and compared sensitivity ranges with UFSAR requirements. The inspected components included:

• Area radiation monitors (ARM)s

• Auxiliary building air monitors

• Liquid and gaseous effluent monitors In addition to equipment walk-downs, the inspectors observed alarm setpoint testing and reviewed calibration records for various portable and fixed detection instruments, including:

• Ion chambers

• Telepoles

• Personnel contamination monitors

• Small article monitors

• Portal monitors

• Whole body counters

• Containment high-range post-accident ARMs

• Portable Air Samplers For the portable survey instruments, the inspectors observed the use of a high-range calibrator and discussed periodic output value testing with HPTs. Radioactive sources used to calibrate selected ARMs and effluent monitors were evaluated for traceability to national standards. Calibration stickers on portable survey instruments and air samplers were noted during inspection of storage areas for ready-to-use equipment. The most recent 10 CFR Part 61 analysis for dry active waste was reviewed to determine if calibration and check sources are representative of the plant source term. The inspectors also reviewed countroom quality assurance records for gamma ray spectrometry equipment and liquid scintillation detectors.

Problem Identification and Resolution The inspectors reviewed CAP documents in the area of radiation detection instruments. The inspectors evaluated the licensees ability to identify and resolve the identified issues. The inspectors also reviewed recent self-assessment results.

Effectiveness and reliability of selected radiation detection instruments were reviewed against details documented in the following: 10 CFR Part 20; NUREG-0737, Clarification of TMI Action Plan Requirements; TS Section 3.3.8; UFSAR Chapters 11 and 12; and applicable licensee procedures. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors sampled licensee data to confirm the accuracy of reported PI data for the following eight PIs. To determine the accuracy of the report PI elements, the reviewed data was assessed against PI definitions and guidance contained in Nuclear Energy Institute 99-02, Regulatory Assessment Indicator Guideline, Revision 6. Documents reviewed are listed in the Attachment.

Cornerstone: Mitigating Systems

• MSPI Emergency AC (3 units)

• MSPI Residual Heat Removal (3 units)

For the period of December 20, 2012, through December 30, 2013, the inspectors reviewed Operating Logs, Train Unavailability Data, Maintenance Records, Maintenance Rule Data, PIPs, Consolidated Derivation Entry Reports, and System Health Reports to verify the accuracy of the PI data reported for each PI.

Occupational Radiation Safety Cornerstone

• Occupational Exposure Control Effectiveness The inspectors reviewed PI data collected from August 2012 through October 2013. The inspectors assessed CAP records to determine if HRA, VHRA or unplanned exposures, resulting in TS or 10 CFR 20 non-conformances, had occurred during the review period.

In addition, the inspectors reviewed selected personnel contamination event data, internal dose assessment results, and electronic dosimeter alarms for cumulative doses and/or dose rates exceeding established set-points.

Public Radiation Safety Cornerstone

• Radiological Control Effluent Release Occurrences The inspectors reviewed the PI results from August 2012 through October 2013. The inspectors reviewed cumulative and projected doses to the public and PIP documents related to Radiological Effluent TS/ODCM issues. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Daily Screening of Corrective Action Reports

a. Inspection Scope

In accordance with Inspection Procedure (IP) 71152, Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed daily screening of items entered into the licensees CAP. This review was accomplished by reviewing copies of PIPs, attending daily screening meetings, and accessing the licensees computerized database.

b. Findings

No findings were identified.

.2 Annual Sample

a. Inspection Scope

As required by IP 71152, Identification and Resolution of Problems, the inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive close out of E1 work requests, but also considered the results of daily inspector CAP item screenings discussed in section 4OA2.1 above, licensee trending efforts, licensee human performance results and inspector observations made during in-plant inspections and walk-downs. The inspectors review primarily considered the ten-month period of January 2013 through October 2013, although some examples expanded beyond those dates when the scope of the trend warranted. The review also included issues documented outside the normal CAP in major equipment problem lists, plant health reports, Independent Nuclear Oversight reports, self-assessment reports, and maintenance rule reports. The inspectors compared and contrasted their results with the results contained in the licensees latest quarterly trend reports. Corrective actions associated with a sample of the issues identified in the licensees trend report were reviewed for adequacy.

b. Observations and Findings

No findings were identified. In general, the licensee performs adequate monitoring of their programs for adverse trends. The inspectors reviewed corrective actions associated with problem identification reports for potential trends and observed the corrective actions were adequate to address the trends. The E1 work requests that were closed out without work orders were addressed by incorporating the issues in existing related work orders.

.3 Annual Sample

Unsealed Penetration

a. Inspection Scope

In addition to the routine review, the inspectors reviewed the circumstances surrounding identification of an unsealed conduit penetrating the Unit 1 north control room fire barrier for a more in-depth review. The inspectors considered the following during the review of the licensees actions: 1) complete and accurate identification of the problem in a timely manner; 2) evaluation and disposition of operability/reportability issues; 3) consideration of extent of condition, generic implications, common cause, and previous occurrences; 4) classification and prioritization of the resolution of the problem; 5) identification of root and contributing causes of the problem; and 6) completion of corrective actions in a timely manner.

b. Observations and Findings

Introduction:

An NRC-identified non-cited violation (NCV) of 10 CFR 50.48(c) and National Fire Protection Association Standard 805 (NFPA 805), Section 3.11.4, was identified for the licensees failure to comply with the fire barrier penetration sealing and inspection requirements of the approved fire protection program (FPP). The annular space between the fire barrier opening and the 2 inch conduit was not properly sealed.

Description:

On August 20, 2013, the licensee discovered a 2 inch conduit penetrating the fire barrier above the Unit 1 control room (CR) north door that was missing a portion of the foam fire stop sealant around the outer annular space of the conduit. There was also evidence of air flow through the degraded seal. The licensee entered the issue in their CAP as PIP O-13-09104, initiated a work order to repair the seal, and implemented an hourly fire watch as required by Oconee Selected Licensee Commitment (SLC)16.9.5. The licensee also performed an immediate determination of operability (IDO) for the control room pressure boundary. The inspectors reviewed the IDO and determined the licensee had not evaluated the impact of the degraded seal on the fire barrier.

The Unit 1 north CR door is located along the unit 1 CR north wall, which is denoted as a required fire barrier on plant drawings and functions as a fire barrier between the shared unit 1 and unit 2 CR and the unit 1 lobby area. A fire on the turbine deck could propagate into the lobby area as there are no rated fire doors between the turbine deck and the lobby area. Further, the lobby area does not have fire detection or automatic fire suppression; therefore, a fire could spread throughout the lobby area for some period of time before manual action could be taken.

SLC Surveillance Requirement (SR) 16.9.5.3 required the Unit 1 fire barrier penetrations to be periodically inspected on a sampling basis. The inspectors reviewed maintenance inspection procedure MP/1/A/1705/018, Fire Protection-Penetration-Fire & Flood Barrier-Inspection and Minor Repair, and determined that the procedure was not sufficient for inspection of the area above the Unit 1 north CR door; the degraded penetration and other penetrations were not specifically listed in the procedure. The lack of periodic inspection directly contributed to the degraded seal not being identified earlier.

Although the degraded penetration was initially identified by the licensee, this issue is considered to be NRC-identified due to the value added due to subsequent observations of the NRC inspectors. The inspectors were concerned that the initial PIP (PIP O-13-09104) was closed within three days of initiation with the only corrective actions being implementation of an hourly fire watch at the Unit 1 CR door and a work order to repair the degraded seal. In addition, the inspectors determined that the IDO failed to address the impact of the degraded seal on the fire barrier. The inspectors engaged in multiple conversations with the licensee to determine what, if any, additional evaluations or corrective actions the licensee had planned. The NRC inspectors engagement prompted the licensee to take the additional actions which included the following:

1) Extent of condition inspections which identified undesirable seals at the Unit 1, 2, and 3 CR doors (documented in PIP O-13-12613); 2) Implementation of additional fire watches at the Unit 2 and Unit 3 CR doors; and 3) Initiation of work orders 2124527, 2124528, and 2124529 to replace the undesirable seals with more robust seals.

Analysis:

The licensees failure to comply with the fire barrier penetration sealing and inspection requirements of the approved fire protection program was a performance deficiency. The duration this condition existed could not be determined. This performance deficiency was determined to be more than minor because it was associated with the Mitigating Systems cornerstone attribute of protection against external factors (i.e., fire), and adversely affected the cornerstone in that the fire barrier could not be relied upon to fully perform its function. The finding was screened using NRC IMC 0609, Appendix F, Fire Protection Significance Determination Process, dated September 20, 2013, because the finding affected the ability to confine a fire. Using IMC 0609, Appendix F, Attachment 1, Fire Protection SDP Phase 1 Worksheet, dated September 20, 2013, the finding was assigned to the Fire Confinement category because the degraded penetration was located in a fire barrier that separated two fire areas. Proceeding to Task 1.3.1 of IMC 0609, Appendix F, Attachment 1, the inspectors determined finding was of very low safety significance (Green) because safety significant equipment was located a sufficient distance from the degraded penetration and the reactors ability to reach and maintain a safe shutdown condition was not impacted.

The cause of this finding was determined to have a cross-cutting aspect of H.2(c) in the Resources component of the Human Performance area because the licensee did not ensure that complete, accurate, and up-to-date design documentation and procedures were available because adequate guidance was not included in the maintenance inspection procedures to allow personnel to identify a degraded condition.

Enforcement:

Oconee Nuclear Station, Unit 1 Renewed Facility Operating License Condition 3.D required the licensee to implement and maintain in effect all provisions of the approved FPP that comply with 10 CFR 50.48 (c), National Fire Protection Association Standard NFPA 805, as specified in the NRC Safety Evaluation Report (SER) dated December 29, 2010. The Oconee Fire Protection Program was defined in Oconee Nuclear Station Design Basis Specification, OSS-0254.00-00-4008, Fire Protection. OSS-0254.00-00-4008, Appendix A, NFPA 805 Ch. 3 Compliance (NEI 04-02 Table B-1), indicated that Oconee Nuclear Station complies with NFPA 805 Section 3.11.4, 2001 Edition.

NFPA 805 Section 3.11.4 stated in part that the annular space between the penetrating item and the through opening in the fire barrier shall be filled with a qualified fire-resistive penetration seal assembly capable of maintaining the fire resistance of the fire barrier.

OSS-0254.00-00-4008, Section 3.9.1, Selected Licensee Commitments, stated in part that selected licensee commitments included inspection and testing requirements for those fire protection systems and features which were committed to be functional to the NRC. SLC 16.9.5.3 stated that at least 10% of each type of sealed penetration should be visually inspected every 24 months and samples shall be selected such that each penetration seal will be inspected at least once every 15 years.

Contrary to the above, the licensee failed to periodically inspect and maintain the seals of all items penetrating the Unit 1 north control room wall (a required fire barrier). The licensee entered this issue into the corrective action program as PIPs O-13-09104, PIP O-13-09438, and PIP O-13-12613. A corrective action has been initiated to revise the maintenance inspection procedures. Additionally, work orders 2124527, 2124528, and 2124529 have been initiated to restore the degraded penetration as well as undesirable penetrations identified during extent of condition walkdowns. Until the work orders are completed, fire watches have been implemented at the Unit 1, Unit 2, and Unit 3 Control Room doors. Because of the very low safety significance, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy and is identified as NCV 05000269/2013005-01: Failure to properly maintain a fire barrier penetration seal.

.4 Annual Sample

Reactor Building Coatings

a. Inspection Scope

The inspectors performed an in-depth review of the units 1, 2, and 3 reactor building (RB) coatings inspection and maintenance program and the licensee's efforts to mitigate degraded reactor building coatings. During accident conditions, degraded coatings could be released and transported to the reactor building emergency sump (RBES) and potentially impact the safety function of the RBES during accident scenarios that require sump recirculation. Degraded reactor building coatings has been an ongoing issue at the Oconee nuclear station since at least the 2002 timeframe. Numerous corrective actions and revisions to the program have been implemented over the years. The inspectors reviewed the corrective actions taken as well as the health of the current program to determine if the licensee was adequately addressing the following attributes:

• Prioritization and resolution of the issue commensurate with safety significance.

• Corrective actions appropriately focused to correct the problem.

• Interim corrective actions and/or compensatory measures identified and implemented to minimize the problem.

b. Observations and Findings

During the Unit 2 refueling outage, the inspectors performed a post-shutdown walkdown of the unit 2 reactor building and noted numerous paint chips from delaminated reactor building coatings throughout the reactor building (e.g., on the floors and in air handling unit intakes). The inspectors reviewed historical PIPs, dating back to 2002, and also engaged in several discussions with the licensee to determine the history of the issue and if appropriate corrective actions had been taken.

The inspectors reviewed the Oconee RB coatings inspection and maintenance program documents and discussed the program with the licensee. Each refueling outage, the licensee performed a visual inspection of the reactor building coated surfaces and documented the condition of the coatings. A PIP was written to document the inspection and assessment of the degraded coatings. The licensee had an ongoing project to abate/recoat accessible degraded coatings during each outage. The inspectors determined that the inspection and maintenance program was consistent with program guidance endorsed by USNRC Regulatory Guide 1.54, Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants, Revision 1.

The inspectors reviewed calculations provided by the licensee and confirmed that degraded coatings (paint chips) had been considered in their RBES downstream effects analysis and determined to have a negligible effect. The inspectors also confirmed, through review of calculations and PIPs and discussions with the licensee, that there were no significant impacts associated with loose paint entering the refueling canal during outages or with loose paint adversely impacting equipment in containment during unit operation. The NRC inspectors concluded that the issue was minor because the operability of the RBES and other equipment inside the RB was not challenged. The licensees inspection and assessment of Unit 2 reactor building coatings was documented in PIP O-13-13971.

.5 Semi-annual Trend Review

a. Inspection Scope

As required by IP 71152, Identification and Resolution of Problems, the inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screenings discussed in section 4OA2.1 above, licensee trending efforts, licensee human performance results and inspector observations made during in-plant inspections and walk-downs. The inspectors review primarily considered the six-month period of July 2013 through December 2013, although some examples expanded beyond those dates when the scope of the trend warranted. The review also included issues documented outside the normal CAP in major equipment problem lists, plant health reports, Independent Nuclear Oversight reports, self-assessment reports, and maintenance rule reports. The inspectors compared and contrasted their results with the results contained in the licensees latest quarterly trend reports. Corrective actions associated with a sample of the issues identified in the licensees trend report were reviewed for adequacy.

b. Observations and Findings

No findings were identified. The inspectors reviewed corrective actions associated with problem identification reports for potential trends and observed the corrective actions were generally adequate. The inspectors did observe an abnormal number of PIPs associated with the implementation of NFPA 805 and control of transient combustibles.

The PIPs listed below are instances where transient combustibles were allowed in sensitive areas and were discovered after the fact:

• 13-07292 - wooden dowel wedged into rail of sliding fire door of Unit 2 control room

• 13-07916 - Protected Service Water (PSW) deficiencies which included wooden stanchion at north entrance

• 13-08764 - unknown quantities of transient fire retardant wood installed in Unit 1 and Unit 2 control battery rooms

• 13-09257 - plant walkdown deficiencies which included 23 areas with wood, overflowing trash cans, plastic drums, and cardboard in the auxiliary building

• 13-10195 - wooden planking/flooring located in the turbine building

• 13-10300 - housekeeping tour discovered untreated wood, scaffold building material, and loose debris and trash in turbine and auxiliary buildings

• 13-11136 - wood planks left on turbine building roof

• 13-11500 - wood boards discovered in Unit 2 turbine building

• 13-11877 - untreated wood brought into Unit 2 reactor building for specialized platforms

• 13-12502 - untreated wood found in security fence within 30 foot of building

• 13-13031 - untreated wood and cardboard box containing griffon in turbine building

• 13-14921 - untreated wood found in turbine building In addition, the inspectors found the following licensee self-assessments where weaknesses in the licensees control of transient combustibles were also identified.

• 13-05894 readiness assessment for NRC triennial fire protection audit

• 13-10373 NFP 805 Quick Hitter Benchmark

• 13-12690 Oconee Nuclear Safety Review Board Meeting for October 3, 2013

• 13-14651 maintenance identifies gap to excellence in wood use on scaffolds PIP 13-03138 tracks a NEIL inspection performed on March 20, 2013. The inspection also identified uncontrolled transient combustibles in sensitive areas.

The NRC triennial fire inspection also identified similar issues which were entered into the licensees corrective action program as PIPs 13-08072 and 13-08584. In addition, the NRC triennial fire protection inspection team identified two Green NCVs in inspection report 05000269/270/287/2013007 associated with control of transient combustibles.

The above items lead the inspectors to conclude an adverse trend exists in the licensees program for control of transient combustibles.

4OA3 Follow-up on Plant Events

.1 Unit 1 HPI leak and Shut down

On November 12, Unit 1 was shut down and Mode 5 entered to repair a leak on high pressure injection (HPI) piping inside containment. The inspectors monitored control room activities to ensure plant equipment operated as designed and that plant operators controlled the unit in accordance with technical specification and station procedures.

The inspectors monitored the RCS parameters (i.e. temperature and pressure) to ensure that no limitations on plant cooldown were exceeded and that the secondary plant was placed in a stable condition.

.2 Unit 3 Reactor Trip

On October 24, Unit 3 was manually tripped due to feed water oscillations. The inspectors monitored control room activities to ensure plant equipment operated as designed and that plant operators controlled the unit in accordance with technical specification and station procedures. The inspectors monitored the RCS parameters (i.e. temperature and pressure) to ensure that no limitations on plant cooldown were exceeded and that the secondary plant was placed in a stable condition.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period the inspectors conducted observations of security force personnel and activities to ensure that the activities were consistent with licensee security procedures and regulatory requirements relating to nuclear plant security.

These observations took place during both normal and off-normal plant working hours.

These quarterly resident inspector observations of security force personnel and activities did not constitute any additional inspection samples. Rather, they were considered an integral part of the inspectors' normal plant status reviews and inspection activities.

b. Findings

No findings were identified.

.2 Verification of Completion of Milestone 2 of Protected Service Water Major Plant

Modification

a. Inspection Scope

The inspectors reviewed licensee procedures and training activities related to installation and testing of permanent equipment necessary to power the PSW electrical bus from the Keowee Hydro Units. The inspectors verified that station procedures were adequate for station operators to accomplish the energization of the PSW electrical bus. The inspectors also verified that adequate training was provided to personnel to accomplish the above task. Final verification of completion of milestone 2 is pending a review of the design and installation of the modification itself.

b. Findings

No findings were identified.

.3 Review of Comprehensive Standby Shutdown Facility (SSF) Design Review Activities

(CAL 2-12-001)

a. Inspection Scope

In a Confirmatory Action Letter (CAL) dated March 6, 2012, the NRC confirmed that the licensee would complete a comprehensive design, licensing, and operational review of the SSF to verify the SSF structures, systems, and components were capable of performing their design functions by March 30, 2012. The licensee completed this review on March 28, 2013. The inspectors reviewed the scope of the comprehensive review team to ensure the appropriate design and license bases elements were considered during the licensees review. Additionally, the inspectors reviewed a sampling of issues identified and the resulting completed and planned corrective actions to verify the corrective actions were appropriate and timely.

Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA6 Management Meetings (Including Exit Meeting)

Exit Meeting Summary

On January 13, 2014, the resident inspectors presented the inspection results to Mr. S. Batson and other members of licensee management. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

4OA7 Licensee Identified Violations

The following violation(s) of very low safety significance (Green) or Severity Level IV was identified by the licensee and is a violation of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as a Non-Cited Violation.

• 10 CFR 50, App. B, Criterion XVI, required in part that conditions adverse to quality, such as non-conformances, are promptly identified and corrected. NSD-203, Operability/Functionality, required entry into the operability determination process (ODP) upon the discovery of circumstances that call into question the operability of any TS SSC including degraded/non-conforming conditions. NSD-203 also requires that actions to confirm if the SSC is degraded or non-conforming should be completed in a timeframe that is commensurate with its safety significance. Contrary to the above, a potential non-conforming condition was identified on December 30, 2012; however, the ODP was not entered until November 26, 2013, and corrective actions generated to correct the non-conforming condition. The finding was not greater than Green because it did not represent an actual open pathway in the physical integrity of reactor containment, containment isolation system, or heat removal components and did not involve an actual reduction of hydrogen igniters in containment. This violation was entered into the CAP as PIP O-13-14547.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee

L. Azzarello, Fleet Design Engineering Manager

S. Batson, Site Vice President

A. Best, Site BACCP Owner

S. Boggs, Emergency Services Coordinator

E. Burchfield, Engineering Manager

T. Cheslak; Oconee Fire Protection Engineer

P. Downing, Duke Steam Generator Integrity

J. Eaton, Oconee ISI Coordinator

P. Fisk; Superintendent of Operations

M. Ginn, Engineer 3, Systems Engineering

T. Grant, Nuclear Engineering Manager

K. Grayson, Principal Engineer, Design Engineering

R. Guy, Organization Effectiveness Manager

E. Hurley, Duke Qualified Data Analyst, Level III

E. Lampe, RP Supervising Scientist

A. Lotfi, Duke - Construction

M. McNeely, Security Manager

P. North, Manager, Nuclear Engineering Section

T. Patterson, Safety Assurance Manager

J. Pounds, OMP Tornado/HELB QA Oversight

T. Ray, Station Manager

F. Rickenbaker, OMP Manager

D. Robinson, Radiation Protection Manager

J. Smith, Regulatory Compliance

L. Stauffer, Principal UT & VT Level III

P. Street, Emergency Planning Manager

C. Vickery, Site Welding

C. Wasik, Regulatory Compliance Manager

LIST OF REPORT ITEMS

Closed

05000269, 270/2013005-01 NCV Failure to properly maintain a fire barrier penetration seal (Section 4OA2.3)