IR 05000424/2014005

IR 05000424/2014005, 05000425/2014005; on 10/01/2014 - 12/31/2014; Vogtle Electric Generating Plant, Units 1 and 2; Refueling and Other Outage Activities, Surveillance Testing

ML15028A375
Person / Time
Site:	Vogtle
Issue date:	01/28/2015
From:	Mark Franke NRC/RGN-II/DRP/RPB2
To:	Taber K Southern Nuclear Operating Co
References
IR 2014005
Download: ML15028A375 (38)

Text

UNITED STATES nuary 28, 2015

SUBJECT:

VOGTLE ELECTRIC GENERATING PLANT - NRC INTEGRATED INSPECTION REPORT 05000424/2014005 AND 05000425/2014005

Dear Mr. Taber:

On December 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Vogtle Electric Generating Plant, Units 1 and 2. On January 27, 2014, the NRC inspectors discussed the results of this inspection with Mr. G. Saxon and other members of your staff. The inspectors documented the results of this inspection in the enclosed inspection report.

The inspectors documented three findings of very low safety significance (Green) in this report.

All of these findings involved violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCV) consistent with Section 2.3.2 of the Enforcement Policy.

If you contest these violations or significance of 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 20555-0001; 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 Vogtle. 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 Vogtle Electric Generating Plant. In accordance with the 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosures, 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 the NRCs Agencywide Document Access and Management 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/

Mark Franke, Chief Reactor Projects Branch 2 Division of Reactor Projects Docket Nos.: 05000424, 05000425 License Nos.: NPF-68 and NPF-81

Enclosure:

IR 05000424/2014005, 05000425/2014005 w/Attachment: Supplementary Information

REGION II==

Docket Nos.: 50-424, 50-425 License Nos.: NPF-68, NPF-81 Report Nos.: 05000424/2014005 and 05000425/2014005 Licensee: Southern Nuclear Operating Company, Inc. (SNC)

Facility: Vogtle Electric Generating Plant, Units 1 and 2 Location: Waynesboro, GA 30830 Dates: October 01, 2014 through December 31, 2014 Inspectors: M. Cain, Senior Resident Inspector A. Alen, Resident Inspector B. Collins, Reactor Inspector (1R08)

A. Sengupta, Reactor Inspector (1R08)

B. Caballero, Senior Operations Engineer (1R11)

Approved by: Mark Franke, Chief Reactor Projects Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000424/2014-005, 05000425/2014-005; 10/01/2014 - 12/31/2014; Vogtle Electric

Generating Plant, Units 1 and 2; Refueling and Other Outage Activities, Surveillance Testing The report covered a three-month period of inspection by resident inspectors and three regional inspectors. There was one NRC-identified and two self-revealing violations identified and documented in this report. The significance of inspection findings are indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP) dated June 19, 2012.

The cross-cutting aspects are determined using IMC 0310, Aspects within the Cross-Cutting Areas dated December 19, 2013. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated July 9, 2013. The NRCs program for overseeing the safe operations of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, revision 5.

Cornerstone: Mitigating Systems

• Green: A self-revealing non-cited violation (NCV) of Technical Specification (TS) 5.4.1.a,

Procedures, was identified for the licensees failure to implement system operating procedure SOP 13502-2, Control Rod Drive and Position Indication System, version 42, when resetting the control rod drive system bank overlap unit (BOU). This caused an out-of-sequence control rod insertion that resulted in operators manually tripping the reactor. The licensee correctly reset the BOU prior to restarting the unit and enhanced the procedural guidance for resetting the BOU. The violation was entered into the licensees corrective action program (CAP) as condition report (CR) 879125.

The performance deficiency (PD) was more than minor because it was associated with the Configuration Control and Equipment Performance attributes of the Mitigating Systems cornerstone and adversely affected the cornerstone objective in that improper rod control system equipment lineup affected the licensees ability to control reactivity. The finding screened as Green because the finding did not affect reactor protection system trip capability or result in an unintentional positive reactivity addition. The inspectors determined the finding had a cross-cutting aspect of training in the human performance area because the organization had not provided sufficient practical or hands-on training on resetting the BOU. [H.9] (Section 1R20)

• Green: The NRC identified an NCV of TS 5.4.1.a, Procedures for the licensees failure to properly implement administrative control procedure 10019-C, Control of Safety Related Locked Valves, version 15.3. As a result, two nuclear service cooling water (NSCW)manual valves were not in their required locked-open position. The licensee restored the valves to their locked-open position. The violation was entered into the licensees corrective action program as condition report 880824.

The performance deficiency was more than minor because it was associated with the Equipment Performance and Configuration Control attributes of the Mitigating Systems cornerstone and adversely affected the cornerstone objective in that the throttled position of the valves reduced the cooling capability of the associated mitigating systems heat exchangers and the unsecured condition reduced the safety-related locked valve programs objective to control and maintain the configuration of valves required to be in a specified position. The finding screened as Green because the flow rates associated with the valves throttled position were determined to be sufficient to maintain the supported systems operability. The inspectors determined the finding had a cross-cutting aspect of documentation in the human performance area because the organization provided inaccurate documentation of the valves manipulation log sheet. [H.7] (Section 1R20)

• Green: A self-revealing NCV of TS 5.4.1.a, Procedures was identified for the licensees failure to properly implement maintenance procedures and work order instructions and inadvertently removed the 2AD1CB safety-related battery charger from service while attempting to perform routine battery surveillance on the 2CD1B battery. Upon discovery, the licensee immediately stopped the work and returned the battery charger to service. The licensee entered the condition into their corrective action program as CR 10002493.

The performance deficiency was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective in that the opening of the power supply breaker to the incorrect battery charger (2AD1CB) resulted in the charger being inoperable for a total of 30 minutes. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012.

Because the inspectors answered No to all of the Exhibit 2, Mitigating Systems Screening Questions, the inspectors concluded that the finding was (Green).The inspectors determined the finding had a cross-cutting aspect of Challenge the Unknown in the Human Performance area because the station operator proceeded in the face of uncertainty. [H.11]

(Section 1R22)

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at or near full rated thermal power (RTP). On October 2, 2014, operators reduced power to approximately 20 percent RTP due to issues with the turbine main and emergency seal oil pumps. The unit was returned to 100 percent RTP on October 6, 2014, and operated at or near full RTP for the remainder of inspection period.

Unit 2 began the inspection period shutdown for a planned refueling outage. The unit was restarted on October 12, 2014, and was manually tripped due to incorrect control rod movement. The unit was restarted on October 13, 2014, and reached 100 percent RTP on October 17, 2014. The unit operated at or near full RTP for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

Seasonal Extreme Weather Conditions: The inspectors conducted a detailed review of the stations adverse weather procedures written for extreme low temperatures. The inspectors verified that weather-related equipment deficiencies identified during the previous year had been placed into the work control process and/or corrected before the onset of seasonal extremes. The inspectors evaluated the licensees implementation of adverse weather preparation procedures and compensatory measures before the onset seasonal extreme weather conditions. Documents reviewed are listed in the

. The inspectors evaluated the following risk-significant systems.

• North and South Fire Pump Houses

• Unit 1 NSCW System Impending Adverse Weather Conditions: The inspectors reviewed the licensees preparations to protect risk-significant systems from predicted severe weather conditions of sub-freezing temperatures expected on the week of November 17, 2014. The inspectors evaluated the licensees implementation of adverse weather preparation procedures and compensatory measures, including operator staffing, before the onset of and during the adverse weather conditions. The inspectors reviewed the licensees plans to address the ramifications of potentially lasting effects that may result from the sub-freezing temperatures. The inspectors verified that operator actions specified in the licensees adverse weather procedure maintain readiness of essential systems. The inspectors verified that required surveillances were current, or were scheduled and completed, if practical, before the onset of anticipated adverse weather conditions. The inspectors also verified that the licensee implemented periodic equipment walkdowns or other measures to ensure that the condition of plant equipment met operability requirements. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R04 Equipment Alignment

a. Inspection Scope

Partial Walkdown: The inspectors verified that critical portions of the selected systems were correctly aligned by performing partial walkdowns. The inspectors selected systems for assessment because they were a redundant or backup system or train, were important for mitigating risk for the current plant conditions, had been recently realigned, or were a single-train system. The inspectors determined the correct system lineup by reviewing plant procedures and drawings. Documents reviewed are listed in the attachment. The inspectors selected the following three systems or trains to inspect:

• Unit 1 train A emergency safety feature (ESF) chilled water system while the train B ESF system was out of service (OOS) for a planned maintenance outage

• Unit 2 train B motor driven auxililary feedwater pump (MDAFW) and train C turbine driven auxiliary feedwater pump (TDAFW) while the A train MDAFW pump was OOS for a planned maintenance outage

• Unit 1 train B NSCW system while the A train NSCW pump #5 was OOS for planned motor replacement Complete Walkdown: The inspectors verified the alignment of the Unit 2 high head safety injection system. The inspectors selected this system for assessment because it is a risk-significant mitigating system. The inspectors determined the correct system lineup by reviewing plant procedures, drawings, the updated final safety analysis report, and other documents. The inspectors reviewed records related to the system outstanding design issues, maintenance work requests, and deficiencies. The inspectors verified that the selected system was correctly aligned by performing a complete walkdown of accessible components.

To verify the licensee was identifying and resolving equipment alignment discrepancies, the inspectors reviewed corrective action documents, including condition reports and outstanding work orders. The inspectors also reviewed periodic reports containing information on the status of risk-significant systems, including maintenance rule reports and system health reports. Documents reviewed are listed in the attachment.

b. Findings

No findings were identified.

1R05 Fire Protection

a. Inspection Scope

Resident Quarterly Inspection: The inspectors evaluated the adequacy of selected fire plans procedures by comparing the procedures to the defined hazards and defense-in-depth features specified in the fire protection program. In evaluating the fire plans procedures, the inspectors assessed the following:

• control of transient combustibles and ignition sources

• fire detection systems

• water-based fire suppression systems

• gaseous fire suppression systems

• manual firefighting equipment and capability

• passive fire protection features

• compensatory measures and fire watches

• issues related to fire protection contained in the licensees corrective action program The inspectors toured the following six fire areas to assess material condition and operational status of fire protection equipment. Documents reviewed are listed in the attachment.

• Unit 1, north and south main steam valve house, fire zones 45, 99, and 104

• Unit 2, trains A and B NSCW, fire zones 160A and 160B

• Unit 1, auxiliary building (AB) B level penetration area and trains A and B of the auxiliary component cooling water (ACCW) and safety injection (SI) pump rooms, fire zones 26B, 30, 31, 32 and 33

• Unit 1, AB C level pipe penetration area and trains A and B of the centrifugal charging pump rooms , fire zones 14B, 19, 20, and 21

• Unit 2, trains A, B, C, and D battery and switchgear rooms, fire zones 56A, 56B, 71, 76, 77A, 77B, 78A, 78B, 79A, 79B, 83 and 152

• Unit 2, control building level B east and west penetration areas, fire zones 60, 61, 62, 63, 64 and 82

b. Findings

No findings were identified.

1R06 Flood Protection Measures

a. Inspection Scope

Internal Flooding The inspectors reviewed related flood analysis documents and walked down the area(s) listed below containing risk-significant structures, systems, and components susceptible to flooding. The inspectors verified that plant design features and plant procedures for flood mitigation were consistent with design requirements and internal flooding analysis assumptions. The inspectors also assessed the condition of flood protection barriers and drain systems. In addition, the inspectors verified the licensee was identifying and properly addressing issues using the corrective action program. Documents reviewed are listed in the attachment.

• Unit 1, normal and centrifugal charging pump rooms: C-111, C-113, and C-118

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

Annual Review: The inspectors verified the readiness and availability of the Unit 2 A train jacket water heat exchanger of the emergency diesel generator to perform its design function by observing performance tests or reviewing reports of those tests, verifying the licensee uses the periodic maintenance method outlined in Generic Letter (GL) 89-13, Service Water System Problems Affecting Safety Related Equipment, observing the licensees heat exchanger inspections, and verifying critical operating parameters through direct observation or by reviewing operating data. Additionally, the inspectors verified that the licensee had entered any significant heat exchanger performance problems into the corrective action program and that the licensees corrective actions were appropriate. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

a. InspectionAScope Non-Destructive Examination Activities and Welding Activities: The inspectors conducted an onsite review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system (RCS),emergency feedwater systems, risk-significant piping and components, and containment systems in Unit 2. The inspectors activities included a review of non-destructive examinations (NDE) 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 with 2000 Addenda), and to verify that indications and defects were appropriately evaluated and dispositioned, in accordance with the requirements of the ASME Code,Section XI, acceptance standards.

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

• Ultrasonic Testing (UT) of pipe-to-elbow weld 21204-043-9-RB, Low Pressure Safety Injection System (LPSI), 6, ASME Class 1

• UT of elbow-to-pipe weld 21204-043-10-RB, Low Pressure Safety Injection System (LPSI), 6, ASME Class 1

• UT of Reactor Vessel Hot Leg nozzle-to-safe end weld (22° azimuth), RCS, 24, ASME Class 1 The inspectors reviewed records of the following NDE mandated by the ASME Code Section XI to evaluate compliance with the ASME Code Section XI and Section V requirements, and if any indications and defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

• Visual Inspection (VT) of control rod drive mechanism (CRDM) restraints, ASME Class 3 The inspectors observed the welding activities referenced below and reviewed associated documents in order to evaluate compliance with procedures and the ASME Code. The inspectors reviewed the work order (WO), repair and replacement plan, weld data sheets, welding procedures, procedure qualification records, welder performance qualification records, and NDE reports.

• WO # SNC551283, Turbine-Driven Auxiliary Feedwater Pump Discharge Line Tie-In, 1/4 support plate weld, AWS D1.1

• WO # SNC551283, Turbine-Driven Auxiliary Feedwater Pump Discharge Line Tie-In, 4 weldolet-to-pipe weld, ASME Class 3 During non-destructive surface and volumetric examinations performed since the previous refueling outage, the licensee did not identify any relevant indications that were analytically evaluated and accepted for continued service. Therefore, no NRC review was completed for this inspection procedure attribute.

Pressurized Water Reactor Vessel Upper Head Penetration Inspection Activities: For the Unit 2 vessel head, a bare metal visual and volumetric examinations of the penetration nozzles were not required this outage pursuant to 10 CFR 50.55a, as both examination techniques were performed during the last refueling outage. Therefore, no NRC review was done for this inspection procedure attribute.

Boric Acid Corrosion Control Inspection Activities: The inspectors reviewed the licensees boric acid corrosion control (BACC) program activities to ensure implementation with commitments made in response to NRC GL 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary, and applicable industry guidance documents. Specifically, the inspectors performed an onsite record review of procedures, and the results of the licensees containment walkdown inspections performed during the current spring 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 CRs 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.

• 642858, Moderate Dry White Residue on Pipe Cap Downstream of Valve 21205X4028

• 658459, Heavy Boron Buildup on Valve 2-1208-U4-287

• 741269, Minor-to-Moderate Dry White Residue from Pipe Cap Downstream of Valve 21208X4018

• 785964, Moderate Dry White Residue from Packing of Valve 2FV0110A The inspectors reviewed the following engineering evaluations completed for evidence of boric acid leakage to determine if degraded components were documented in the CAP.

The inspectors also evaluated corrective actions for any degraded components to determine if they met the ASME Section XI Code.

• 648124, Boric Acid Leak on Seal Injection Filter #4

• 650720, Filter 2-1208-F4-005 Anchor Bolt Degraded Due To Boric Acid Leak

• 854077, Heavy Moist Discolored Boric Acid Residue below Valve 21208X4477 Steam Generator Tube Inspection Activities: The inspectors reviewed the eddy current (EC) examination activities performed in Unit 2 steam generators (SGs) 1, 2, 3, and 4 during the end-of-cycle 17 refueling outage, to verify compliance with the licensees Technical Specifications, ASME BPVC Section XI, and Nuclear Energy Institute (NEI)97-06, Steam Generator Program Guidelines. The inspectors interviewed licensee personnel and vendor staff responsible for the SG inspection project, and reviewed documentation associated with the SG inspections and integrity assessments, as described in this report section. The inspectors reviewed the scope of the EC examinations to verify that known and potential areas of tube degradation were inspected. The inspectors also verified that inspection scope expansion criteria were implemented based on inspection results, as directed by the Electric Power Research Institute (EPRI) Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7.

The inspectors reviewed documentation for a sample of EC data analysts, EC probes, and EC testers to verify that personnel and equipment were qualified to detect the existing and potential degradation mechanisms applicable to Vogtles SG tubes, in accordance with the EPRI Examination Guidelines. This review included a sample of site-specific Examination Technique Specification Sheets (ETSSs) that were selected based on plant-specific and industry operating experience, to ensure that their qualification and site-specific implementation were consistent with Appendix H or I of the EPRI Examination Guidelines. The selected ETSSs for review consisted of bobbin and rotating pancake coil (RPC) probe techniques that were used to detect wear as well as outside diameter stress corrosion cracking.

The inspectors also reviewed a sample of EC data with a qualified data analyst to confirm that data analysis was performed in accordance with the applicable ETSSs, and site-specific analysis guidelines. The inspectors verified that the equipment configuration was consistent with the essential parameters of the applicable technique.

The inspectors also verified that recordable indications were detected and sized in accordance with vendor procedures. As part of the EC data review, the inspectors verified that the EC indications on each selected tube were consistent with historical data relative to the number of indications, location, and size. The sample of EC data selected for review is listed below:

Steam Generator Tube Row/Column Eddy Current Probe 01/42 Bobbin, RPC 43/55 Bobbin, RPC 47/84 RPC 32/49 RPC 44/42 Bobbin The inspectors selected a sample of wear degradation mechanisms from the Steam Generator Degradation Assessment, and verified that the in-situ pressure testing criteria were determined in accordance with the EPRI Tube Integrity Guidelines. Additionally, the inspectors reviewed EC indication reports to determine whether tubes with relevant indications were appropriately screened for in-situ pressure testing.

The inspectors compared the recent EC examination results with the last Operational Assessment report for the SGs to assess the licensees prediction capability for maximum tube degradation. The inspectors verified that the licensees evaluation was conservative, and that current examination results were bound by the Operational Assessment projections. The inspectors also compared past examination results discussed in the latest Degradation Assessment with the recent EC examination results to verify that new degradation mechanisms, if any, were identified and evaluated before plant startup.

The review of EC examination results included the disposition of potential loose part indications on the SG secondary side, to verify that corrective actions for evaluating and retrieving loose parts were consistent with the EPRI guidelines. The inspectors also reviewed a sample of primary-to-secondary leakage data for Unit 2 to confirm that operational leakage in all SGs remained below the action level threshold during the previous operating cycle.

Based on the review of the final EC examination results and interviews with the licensee, the inspectors confirmed that no EC scope expansion was required and none of the SG tubes examined met the criteria for plugging or in-situ pressure testing. The inspectors also interviewed licensee staff about any planned secondary side visual inspection activities to verify that potential areas of degradation (e.g. loose part wear) were inspected based on recent EC examination results. The inspectors confirmed that no secondary side inspections and Foreign Object Search and Retrieval (FOSAR) activities were performed based on the latest results of EC examination activities.

Identification and Resolution of Problems: The inspectors reviewed a sample of ISI related problems that were identified by the licensee and entered into the CAP as CRs to confirm 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 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

Resident Inspector Quarterly Review of Licensed Operator Requalification: The inspectors observed an evaluated simulator scenario administered to an operating crew as part of the biennial requalification operating test required by 10 CFR 55.59, Requalification. The inspectors assessed the following. Documents reviewed are listed in the Attachment.

• licensed operator performance

• the ability of the licensee to administer the scenario and evaluate the operators

• the quality of the post-scenario critique

• simulator performance Resident Inspector Quarterly Review of Licensed Operator Performance: The inspectors observed licensed operator performance in the Unit 1 main control room on October 2, 2014 during a rapid power reduction to approximately 17 percent and subsequent tripping of the main turbine due to issues with the main and emergency hydrogen seal oil pumps. The inspectors assessed the following. Documents reviewed are listed in the Attachment.

• 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 September 2, 2014, the licensee completed the annual requalification operating examinations and on December 3, 2014, the licensee completed the comprehensive biennial requalification written examinations, which are required to be administered to all licensed operators in accordance with Title 10 of the Code of Federal Regulations 55.59(a)(2), Requalification Requirements, of the NRCs Operators Licenses. 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 and Licensed Operator Performance, dated October 1, 2012. These results were compared to the thresholds established in Section 3.02, Requalification Examination Results, of IP 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors assessed the licensees treatment of the two issues listed below to verify the licensee appropriately addressed equipment problems within the scope of the maintenance rule (10 CFR 50.65, Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants). The inspectors reviewed procedures and records to evaluate the licensees identification, assessment, and characterization of the problems as well as their corrective actions for returning the equipment to a satisfactory condition. The inspectors also interviewed system engineers and the maintenance rule coordinator to assess the accuracy of performance deficiencies and extent of condition.

Documents reviewed are listed in the attachment.

• Unit 2 train B centrifugal charging pump failed to start from main control board

• Unit 2, charging flow control valve 2FV-121, controller down pushbutton stuck fully depressed

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the five maintenance activities listed below to verify that the licensee assessed and managed plant risk as required by 10 CFR 50.65(a)(4) and licensee procedures. The inspectors assessed the adequacy of the licensees risk assessments and implementation of risk management actions. The inspectors also verified that the licensee was identifying and resolving problems with assessing and managing maintenance-related risk using the corrective action program. Additionally, for maintenance resulting from unforeseen situations, the inspectors assessed the effectiveness of the licensees planning and control of emergent work activities.

Documents reviewed are listed in the attachment.

• Unit 2, October 5, 2014 ORANGE Outage Risk Assessment Monitor (ORAM) risk condition due to midloop operation

• Unit 2, November 10, 2014, GREEN equipment out of service (EOOS) risk due to planned maintenance on the B train of the MDAFW pumps

• Unit 2, November 17, 2014, YELLOW EOOS risk due to planned maintenance on the train A NSCW fan #2

• Unit 1, December 01, 2014, YELLOW EOOS risk due to planned maintenance on the train A NSCW pump #5 motor replacement

• Unit 1, December 10, 2014, YELLOW EOOS risk due to planned maintenance on the train A NSCW pump #5 motor replacement and planned maintenance on the train B of containment spray system

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors selected the five operability determinations or functionality evaluations listed below for review based on the risk-significance of the associated components and systems. The inspectors reviewed the technical adequacy of the determinations to ensure that technical specification operability was properly justified and the components or systems remained capable of performing their design functions. To verify whether components or systems were operable, the inspectors compared the operability and design criteria in the appropriate sections of the technical specification and updated final safety analysis report to the licensees evaluations. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. Additionally, the inspectors reviewed a sample of corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with operability evaluations.

Documents reviewed are listed in the attachment.

• Unit 2, Immediate determination of operability (IDO) for component cooling water pump number three (2-1203-P4-003) due to mechanical seal leakage, corrective action report (CAR) 212988

• Unit 1, IDO for the train B emergency diesel generator (EDG) due to a lube oil cooler leak identified during EDG test run, CAR 213187

• Units 1 and 2, Part 21 C&D Technologies for safety related batteries, 9/22/14

• Units 1 and 2 train A EDG turbocharger bolting prompt determination of operability 1-14-002

• Unit 1, IDOs for the train B EDG broken/missing bolts on the exhaust manifold assembly support and clover leaf connection to the turbocharger, CARs 212315 and 212327

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The inspectors verified that the plant modification listed below did not affect the safety functions of important safety systems. The inspectors confirmed the modifications did not degrade the design bases, licensing bases, and performance capability of risk significant structures, systems and components. The inspectors also verified modifications performed during plant configurations involving increased risk did not place the plant in an unsafe condition. Additionally, the inspectors evaluated whether system operability and availability, configuration control, post-installation test activities, and changes to documents, such as drawings, procedures, and operator training materials, complied with licensee standards and NRC requirements. In addition, the inspectors reviewed a sample of related corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with modifications. Documents reviewed are listed in the Attachment.

• SNC137321, Unit 2 main feed isolation valve accumulator gas pressure switch setpoint, Ver. 2.0

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors either observed post-maintenance testing or reviewed the test results for the six maintenance activities listed below to verify the work performed was completed correctly and the test activities were adequate to verify system operability and functional capability.

• SNC 607280, Unit 2 pressure relief valve (PSV-11825) replacement, 10/7/14

• SNC 407964, Unit 1 train A containment spray pump sump suction motor-operated valve preventive maintenance, 10/23/2014

• SNC 136712, Unit 2 train B NSCW tower level indication

• SNC 610460, Unit 2 train B NSCW - EDG supply header flow indicator calibration

• SNC 408761, Unit 1 train A component cooling water (CCW) pump 5 check valve inspection

• SNC 620434, Unit 1 loop 1 RCS temperature instrument loop failure The inspectors evaluated these activities for the following:

• Acceptance criteria were clear and demonstrated operational readiness.

• Effects of testing on the plant were adequately addressed.

• Test instrumentation was appropriate.

• Tests were performed in accordance with approved procedures.

• Equipment was returned to its operational status following testing.

• Test documentation was properly evaluated.

Additionally, the inspectors reviewed a sample of corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with post-maintenance testing. Documents reviewed are listed in the attachment.

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors evaluated the following Unit 2 outage activities:

• refueling, heatup, and startup

• reactor coolant system instrumentation and electrical power configuration

• reactivity and inventory control

• decay heat removal and spent fuel pool cooling system operation

• containment closure The inspectors verified that the licensee:

• controlled plant configuration in accordance with administrative risk reduction methodologies

• developed work schedules to manage fatigue

• developed mitigation strategies for loss of key safety functions

• adhered to operating license and technical specification requirements Inspectors verified that safety-related and risk-significant structures, systems, and components not accessible during power operations were maintained in an operable condition. The inspectors also reviewed a sample of related corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with outage activities. Documents reviewed are listed in the Attachment.

.1 Failure to Correctly Implement Control Rod Drive System Procedure During Reactor

Startup Activities

Introduction:

A Green self-revealing NCV of TS 5.4.1.a, Procedures, was identified for failure to implement operating procedure SOP 13502-2, Control Rod Drive and Position Indication System, version 42. The licensee failed to follow procedural steps when resetting the control rod drive system BOU. As a result, control rods moved out-of-sequence when manually inserted by the operator at the controls (OATC).

Description:

On October 12, 2014, operators were conducting an infrequent evolution of Unit 2 reactor startup by boron dilution with all control rods fully withdrawn to support low power physics testing (LPPT). Following unit criticality, the OATC was directed to manually insert control rods to stabilize reactor power in the intermediate nuclear instrumentation range for LPPT data collection. The OATC manually inserted control rods about three steps and noticed control rod bank A was inserting instead of the expected control rod bank D. The OATC was unsure if the control rods should be withdrawn to the original position. Following discussion of the incorrect operation and unknown operational state of the rod control system between the OATC and the Shift Manager, it was decided to manually initiate a reactor trip.

Control rod banks are moved in a pre-determined sequence and overlap because each bank has a different amount of rods, different insert location, and different neutron absorption worth that is taken into account when evaluating the expected core response during control rod movement. The BOU is the rod control system component that determined the movement sequence and overlap of the control rod banks. The licensee determined the erratic rod control system operation was due to an improper resetting of the BOU. Prior to inserting control rods for data collection, the BOU was reset using operating procedure 13502-2, Control Rod Drive and Position Indication, version 42.

The procedure specified resetting of the BOU by pushing the BO+1 pushbutton (i.e.

upward direction) to set the BOU counter at 573 from 000. To perform the step quicker, the BO-1 pushbutton (i.e. downward direction) was used to set the BOU counter. Due to the equipment control logic, the BOU sequence function was not properly reset when the BO-1 pushbutton was used and resulted in the out-of-sequence control rod operation. Licensee corrective actions included crew stand downs, a human performance review board, and a note to procedure 13502-1/2, prior to the step for resetting the BOU to highlight the importance of using the BO+1 pushbutton.

Analysis:

The failure to properly implement SOP 13502-2 for resetting the rod control system BOU counter was a PD. The PD was more than minor because it was associated with the Configuration Control and Equipment Performance attributes of the Mitigating Systems cornerstone and adversely affected the cornerstone objective in that improper rod control system equipment lineup affected the licensees ability to control reactivity. The inspectors evaluated the finding using Section C of Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012. The finding was determined to be Green because while the ability anticipate and control reactivity changes was reduced, it did not result in an inability to control reactivity in that boration capability and reactor trip functions remained available. The inspectors determined the finding had a cross-cutting aspect of training in the human performance area because the licensee had not provided sufficient practical training on the infrequent evolution of resetting the BOU.[H.9]

Enforcement:

Technical Specification 5.4.1.a, Procedures, required, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A to Regulatory Guide 1.33, Quality Assurance Program Requirements, of February 1978. Appendix A, Item 3.b, required procedures for startup and operation of the control rod drive system. Procedure SOP 13502-2, Control Rod Drive and Position Indication System, version 42, provided steps to adjust the BOU counter using the BO+1 pushbutton. Contrary to the above, on October 12, 2014, the operators failed to correctly implement procedure SOP 13502-2 to reset the BOU counter using the BO+1 pushbutton. As a result, control rod banks inserted out-of-sequence when manually inserted by the OATC during Unit 2 reactor startup activities which resulted in operators manually tripped the reactor. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy.

The violation was entered into the licensees corrective action program as CR 879125.

(NCV 05000425/2014005-01, Failure to Correctly Implement Control Rod Drive System Procedure During Reactor Startup Activities)

.2 Failure To Restore Nuclear Service Cooling Water Manual Valves

Introduction:

A Green NRC-identified NCV of TS 5.4.1.a, Procedures, was identified for the licensees failure to properly implement administrative control procedure 10019-C, Control of Safety Related Locked Valves, version 15.3. Two NSCW manual valves were not returned to their required locked-open position after being throttled in support of outage activities.

Description:

On October 15, 2014, two days after Unit 2 had been returned to power operations, the inspectors identified that manual valve 2HV-11620, NSCW supply to the Unit 2 B train of the EDG jacket water (JW) heat exchanger (HX), was unlocked and throttled. The NSCW was considered to be in its standby alignment with the valve required to be locked-open. The inspectors notified the licensee who proceeded to restore the valve to its fully open position and conducted an extent of condition that identified that valve 2HV-1836, ESF chiller condenser HX B train outlet valve, was also unlocked and throttled. The licensee determined the valves had been manipulated to support outage activities. Procedure 10019-C required manipulation and restoration of SR locked valves (SRLV) to be logged/tracked using procedure 11888-C, Safety Related Locked Valve Manipulation Log, revision 10. The SRLV manipulation log records for these valves showed their initial manipulation had been logged per 11888-C on October 6, 2014; however, the valve restoration section had been improperly documented as N/A. As a result, when operators reviewed the SRLV manipulation log, as part of returning the unit to power operations, the affected valves were not identified as requiring restoration.

The NSCW system removes heat from safety-related equipment during emergency operating conditions including the EDG JW HX and the ESF chiller condenser HX.

These HXs have manual inlet and outlet isolation valves that were required to be secured (i.e. chained and locked) in the open position to provide constant cooling water supply from the NSCW system. The licensee evaluated the throttled condition and determined there was adequate cooling water supply for these HXs to perform their safety function.

Analysis:

The licensees failure to restore two NSCW manual valves to their required locked-open position, as required by administrative procedure 10019-C, was a PD. The PD was more than minor because it was associated with the Equipment Performance and Configuration Control attributes of the Mitigating Systems cornerstone and adversely affected the cornerstone objective in that the valves throttled condition reduced the cooling capability of the associated mitigating systems HXs and the unsecured condition reduced the SRLV programs ability to control and maintain the configuration of valves required to be in a specified position. The inspectors evaluated the finding using Exhibit 2, Mitigating Systems Screening Questions, of IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012. The finding screened as Green because it was a deficiency that affected the heat removal design capability of the associated HXs, however; the flow rates associated with the valves throttled condition were determined to be sufficient to maintain the supported systems (EDG and ESF chiller) operability. The inspectors determined the finding had a cross-cutting aspect of documentation in the human performance area because the organization provided inaccurate documentation of manipulation log sheet (11888-C) such that the individual reviewing the log sheet could not identify and take actions to restore the valves to their required position. [H.7]

Enforcement:

Technical Specification 5.4.1.a, Procedures, required, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A to Regulatory Guide 1.33, Quality Assurance Program Requirements, of February 1978. Appendix A, Item 1.c, required administrative procedures for equipment control (e.g. locking and tagging). Procedure 10019-C, Control of Safety Related locked Valves, version 15.3, provided instructions to control manipulation and restoration of SRLV. Contrary to the above, the licensee failed to implement administrative procedures for equipment control. Between October 6, 2014, and October 15, 2014, the licensee failed to control two NSCW manual valves and restore these valves to their required locked-open position. The licensee took immediate actions to restore the valves to their required locked-open position. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. The violation was entered into the licensees corrective action program as condition report 880824. (NCV 05000425/2014005-02, Failure to restore nuclear service cooling water manual valves to their required locked-open position).

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the seven surveillance tests listed below and either observed the test or reviewed test results to verify testing adequately demonstrated equipment operability and met technical specification and licensee procedural requirements. The inspectors evaluated the test activities to assess for preconditioning of equipment, procedure adherence, and equipment alignment following completion of the surveillance.

Additionally, the inspectors reviewed a sample of related corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with surveillance testing. Documents reviewed are listed in the Attachment.

Routine Surveillance Tests

• 14228-1 Ver. 35.3, Operations monthly surveillance logs

• 14805B-2 Ver. 4, Train B residual heat removal pump IST and response time test

• 14510A-1 Ver. 6.2, Train A control room emergency filtration system operability test

• 14667-2 Ver. 34.2, Train B Diesel Generator and ESFAS Test

• 28912-C Ver. 66, 92-Day Battery and Charger Inspection and Maintenance In-Service Tests

• 14801A-2 Ver. 4.2, Train A NSCW Transfer Pump Inservice Test Reactor Coolant System Leak Detection

• 14905 Ver. 69, RCS Leakage Calculation (Inventory Balance)

b. Findings

Introduction:

A Green self-revealing NCV of TS 5.4.1.a, Procedures, was identified for the licensees failure to properly implement maintenance procedures and work order instructions. Station personnel inadvertently removed the 2AD1CB safety-related battery charger from service while attempting to perform routine battery surveillance on the 2CD1B battery.

Description:

On December 17, 2014, the licensee had commenced a routine quarterly battery surveillance for the 2CD1B (C train) safety-related battery. After making initial battery checks in the 2CD1B battery room, electricians left the 2CD1B battery room and proceeded to notify main control room (MCR) operators, in accordance with procedure 28912-C, 92-Day Battery and Charger Inspection and Maintenance, version 66, prior to starting work. Following notification of the MCR, electricians and a station operator entered the 2AD1CB (A train) battery charger room and opened the supply power breaker for the 2AD1CB battery charger. Opening of the breaker actuated a trouble alarm, 2AD1CA/2AD1CB Trouble, in the MCR, which prompted MCR operators to stop the work. As a result, the 2AD1CB battery charger was rendered inoperable for approximately 30 minutes while restoration activities were being performed. The licensee concluded that because the 2AD1CA battery charger was never removed from service while the 2AD1CB was out of service, no loss of safety function occurred.

Analysis:

The licensees failure to implement maintenance instructions to remove the correct and identified battery charger (2CD1CB) was a performance deficiency. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the mitigating systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the opening of the power supply breaker to the incorrect battery charger (2AD1CB) resulted in the charger being inoperable for a total of 30 minutes. The inspectors evaluated the finding using IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, issued June 19, 2012. Because the inspectors answered No to all of the Exhibit 2, Mitigating Systems Screening Questions, the inspectors concluded that the finding was Green. The inspectors determined the finding had a cross-cutting aspect of Challenge the Unknown in the Human Performance area because the station operator proceeded in the face of uncertainty because the operator, which had been briefed on the correct battery charger to be removed from service (2CD1CB), did not question why electricians had directed him to the 2AD1CB battery charger. [H.11]

Enforcement:

Technical Specification 5.4.1.a, Procedures, required, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Appendix A to Regulatory Guide 1.33, Quality Assurance Program Requirements, of February 1978. Appendix A, Item 9 required, in part, that maintenance activities that can affect the performance of safety-related equipment should be performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances. Contrary to the above, the licensee failed to perform safety-related station battery maintenance activities in accordance with written procedures and maintenance instructions. As a result, the 2AD1CB safety-related battery charger was rendered inoperable for a total of 30 minutes. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. This violation was entered into the licensees corrective action program as CR 10002493. (NCV 05000425/2014005-03, Failure to Follow Procedures Renders Safety Related Battery Charger Inoperable)

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors observed the emergency preparedness drill conducted on November 5, 2014. The inspectors observed licensee activities in the simulator to evaluate implementation of the emergency plan, including event classification, notification, and protective action recommendations. The inspectors evaluated the licensees performance against criteria established in the licensees procedures. Additionally, the inspectors attended the post-exercise critique to assess the licensees effectiveness in identifying emergency preparedness weaknesses and verified the identified weaknesses were entered in the corrective action program. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 The inspectors reviewed a sample of the performance indicator (PI) data, submitted by

the licensee, for the Unit 1 and Unit 2 PIs listed below. The inspectors reviewed plant records compiled between October 1, 2013, and September 30, 2014 to verify the accuracy and completeness of the data reported for the station. The inspectors verified that the PI data complied with guidance contained in Nuclear Energy Institute 99-02, Regulatory Assessment Performance Indicator Guideline, and licensee procedures.

The inspectors verified the accuracy of reported data that were used to calculate the value of each PI. In addition, the inspectors reviewed a sample of related corrective action documents to verify the licensee was identifying and correcting any deficiencies associated with PI data. Documents reviewed are listed in the Attachment.

Cornerstone: Mitigating Systems

• safety system functional failures

• emergency AC power system

• cooling water system

b. Findings

No findings identified.

4OA2 Problem Identification and Resolution

.1 Routine Review

The inspectors screened items entered into the licensees corrective action program in order to identify repetitive equipment failures or specific human performance issues for followup. The inspectors reviewed condition reports, attended screening meetings, or accessed the licensees computerized corrective action database.

.2 Annual Follow-up of Selected Issues

The inspectors conducted a detailed review of condition report CR 877475, Broken mounting bolt for the Unit 1 B train EDG, 10/8/2014. The inspectors evaluated the following attributes of the licensees actions. Documents reviewed are listed in the

.

• complete and accurate identification of the problem in a timely manner

• evaluation and disposition of operability and reportability issues

• consideration of extent of condition, generic implications, common cause, and previous occurrences

• classification and prioritization of the problem

• identification of root and contributing causes of the problem

• identification of any additional condition reports

• completion of corrective actions in a timely manner

.3 Semi-Annual Trend Review

The inspectors reviewed issues entered in the licensees corrective action program and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors focused their review on human performance trends, but also considered the results of inspector daily condition report screenings, licensee trending efforts, and licensee human performance results. The review nominally considered the six-month period of July 2014 thru December 2014 although some examples extended beyond those dates when the scope of the trend warranted.

The inspectors compared their results with the licensees analysis of trends.

Additionally, the inspectors reviewed the adequacy of corrective actions associated with a sample of the issues identified in the licensees trend reports. The inspectors also reviewed corrective action documents that were processed by the licensee to identify potential adverse trends in the condition of structures, systems, and/or components as evidenced by acceptance of long-standing non-conforming or degraded conditions.

Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA3 Event Follow-up

.1 (Closed) Licensee Event Report (LER) 05000425/2014-003-00: Unit 2 Manual Reactor

Trip due to Out of Sequence Control Rod Movement

a. Inspection Scope

At approximately 0944 EST on October 12, 2014, while performing Unit 2 reactor startup, control rods were being manually inserted to stabilize reactor power for LPPT.

With the rod bank selector switch in Manual, operators observed control bank A insert instead of the expected D bank. Operators took action to trip the reactor and stabilize the plant. Upon tripping the reactor, safety systems responded per design and the unit was stabilized in Mode 3. The cause of this event was incorrectly resetting of the rod control system BOU. The inspectors reviewed the LER, the associated condition report, apparent cause determination report, and subsequent action items.

b. Findings

The enforcement aspects of this finding are discussed in Section 1R20 of this report. No other findings were identified.

4OA6 Meetings, Including Exit

a. Exit Meeting On January 27, 2014, the resident inspectors presented the inspection results to Mr. G.

Saxon and other members of plant staff. The inspectors confirmed that proprietary information was destroyed or returned following the completion of the inspection period.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

T. Baker, Security Manager

R. Collins, Chemistry Manager

G. Gunn, Licensing Manager (interim)

C. Nesbitt, Training Manager

M. Johnson, Health Physics Manager

F. Pournia, Engineering Director

D. Myers, Maintenance Director

J. Klecha, Operations Director

J. Robinson, Engineering Programs Manager

G. Saxon, Plant Manager

J. Thomas, Work Management Director

T. Thompson, Systems Engineering Manager

K. Taber, Site Vice-President

K. Walden, Licensing Engineer

K. Morrow, Licensing Engineer

D. Cordes, SNC Corporate ISI Examinations Coordinator

G. Fechter, Site Welding Engineer

A. Gordon, Oconee ISI Engineer

E. Groves, Oconee ISI Examinations Coordinator

V. Looper, IQDA

A. Martin, SNC Corporate Steam Generator Engineer

T. Smith, Site NDE Coordinator

K. Walden, Site Licensing Engineer

LIST OF REPORT ITEMS

OPEN AND CLOSED NCV

05000425/2014005-01 Failure to Correctly Implement Control Rod Drive System Procedure During Reactor Startup Activities (1R20)

NCV

05000425/2014005-02 Failure to Restore Nuclear Service Cooling Water Manual Valves to their Required Locked-Open Position (1R20)

NCV

05000425/2014005-03 Failure to Follow Procedures Renders Safety Related Battery Charger Inoperable (1R22)

CLOSED LER

05000425/2014-003-00 Unit 2 Manual Reactor Trip due to Out of Sequence Control Rod Movement (4OA3.1)