IR 05000390/2014003

IR 05000390-14-003; on 04/01/2014 - 06/30/2014; Watts Bar, Unit 1; Problem Identification and Resolution, Followup of Events

ML14213A424
Person / Time
Site:	Watts Bar
Issue date:	08/01/2014
From:	Bartley J Reactor Projects Region 2 Branch 6
To:	James Shea Tennessee Valley Authority
References
IR-14-003
Download: ML14213A424 (45)

Text

UNITED STATES August 1, 2014

SUBJECT:

WATTS BAR NUCLEAR PLANT - NRC INTEGRATED INSPECTION REPORT 05000390/2014003

Dear Mr. Shea:

On June 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Watts Bar Nuclear Plant, Unit 1. On July 9, 2014, the NRC inspectors discussed the results of this inspection with Mr. Walsh and other members of the Watts Bar staff. Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented three NRC-identified findings of very low safety significance (Green) in this report. Two of the NRC identified findings involved violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCV) consistent with Section 2.3.2.a of the NRC Enforcement Policy.

If you contest the violation or significance of this NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, D.C. 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, U.S.

Nuclear Regulatory Commission, Washington, D.C. 20555-0001; and the NRC Resident Inspector at the Watts Bar Nuclear Plant.

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 Watts Bar Nuclear Plant.

. In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, 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 System (PARS)

component of NRC's Agencywide Documents 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/

Jonathan H. Bartley, Chief Reactor Projects Branch 6 Division of Reactor Projects Docket No.: 50-390 License No.: NPF-90

Enclosure:

NRC Inspection Report 05000390/2014003 w/Attachment: Supplemental Information

REGION II==

Docket No.: 50-390 License No.: NPF-90 Report No.: 05000390/2014003 Licensee: Tennessee Valley Authority (TVA)

Facility: Watts Bar Nuclear Plant, Unit 1 Location: Spring City, TN 37381 Dates: April 1 through June 30, 2014 Inspectors: R. Monk, Senior Resident Inspector K. Miller, Resident Inspector E. Patterson, Reactor Inspector (1R04, 1R18)

P. Cooper, Reactor Inspector (1R08)

C. Kontz, Senior Project Engineer (4OA5)

T. Steadham, Reactor Inspector (1R18)

M. Magyar, Reactor Inspector, (1R20)

N. Karlovich, Reactor Inspector, (1R20)

J. Rivera-Ortiz, Senior Reactor Inspector (1R08)

C. Dykes, Health Physicist (2RS01)

W. Loo, Senior Health Physicist (2RS01, 2RS08)

Approved by: Jonathan H. Bartley, Chief Reactor Projects Branch 6 Division of Reactor Projects Enclosure

SUMMARY

IR 05000390/2014-003; 04/01/2014 - 06/30/2014; Watts Bar, Unit 1; Problem Identification and

Resolution, Followup of Events.

The report covered a three-month period of inspection by the resident inspectors. Two Green non-cited violations, one Green finding and two licensee-identified violations were identified.

The significance of most findings is indicated by their color (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, Aspects Within Cross Cutting Areas, dated December 19, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 4, dated December 2006.

Cornerstone: Initiating Events

• Green: An NRC-identified finding was documented by the inspectors for the licensees failure to comply with a design drawing during a modification resulting in a trip of Unit 1 reactor.

The inspectors determined that the licensees failure to properly implement Design Change Notice (DCN) 52295, complete bus differential wiring for main bus 2, as required by NPG-SPP-09.3, Revision 17, Plant Modifications and Engineering Change Control, was a performance deficiency. The performance deficiency was determined to be more than minor because it adversely affected the objective of the Initiating Events cornerstone to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to correctly translate design drawings to implementing work order 08-816022-006 resulted in Unit 1 experiencing a 100 percent load rejection and reactor trip. Using the screening worksheet of IMC 0609, Appendix A, Exhibit 1 - Initiating Events Screening Questions, the inspectors determined that the finding was of very low safety significance (Green)because the resulting transient was within the design basis for Unit 1 and all plant systems functioned as required to place the unit in a stable, hot standby condition. The cause of the finding was directly related to the aspect of work management in the Human Performance cross-cutting area because the licensee failed to implement a process of planning, controlling, and executing work activities such that nuclear safety was the overriding priority. [H.5] (Section 4OA3)

Cornerstone: Mitigating Systems

• Green: An NRC-identified NCV of 10 Code of Federal Regulations (CFR) 50 Appendix B, Criterion XVI, Corrective Action, was documented for the licensees failure to adequately identify a condition adverse to quality associated with the installation of 480 volt breaker 0-BKR-548-0021-S with non-conforming parts which was in service in safety-related 480 volt shutdown board 1B1. Immediate corrective action was to replace the non-conforming breaker.

The inspectors determined that the licensees failure to adequately identify a condition adverse to quality associated with the installation of non-conforming parts as required by 10 CFR 50 Appendix B, Criterion XVI, was a performance deficiency. The performance deficiency was determined to be more than minor because it adversely affected the objective of the Mitigating Systems cornerstone to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to identify the condition adverse to quality led to an additional six months that this non-conforming condition existed thus reducing the licensees ability to ensure the reliability and capability of plant safety systems. Using the screening worksheet of IMC 0609, Appendix A, Exhibit 2 - Mitigating Systems Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because the deficiency only affected the qualification of the breaker. The cause of the finding was directly related to the aspect of identification in the Problem Identification and Resolution cross-cutting area because the licensee did not identify this issue completely, accurately, and in a timely manner in accordance with the program. [P.1] (Section 4OA2.3)

• Green: A NRC-identified non-cited violation of 10 CFR 50 Appendix B, Criterion XVI,

Corrective Action, was documented for the licensees failure to adequately identify a condition adverse to quality associated with the installation of relief valve 1-RFV-67-1026D, Upper Containment Cooler 1D, an ASME Class III component. The licensee entered the issue into the corrective action program and performed an operability determination which concluded the cooler was operable.

The inspectors determined that the licensees failure to adequately identify a condition adverse to quality associated with the non-conformance of relief valve 1-RFV-67-1026D, as required by 10 CFR 50 Appendix B, Criterion XVI, was a performance deficiency.

The performance deficiency was determined to be more than minor because it adversely affected the objective of the Mitigating Systems cornerstone to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to correct the condition adverse to quality in a timely manner led to an additional 4 years that this non-conforming condition existed prior to evaluation thus reducing the licensees ability to ensure the reliability and capability of plant safety systems. Using the screening worksheet of IMC 0609,

Appendix A, Exhibit 2 - Mitigating Systems Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because there existed an additional relief valve in the IST program that could protect the piping and cooler from over pressurization with appropriate compensatory measures. The cause of the finding was directly related to the aspect of evaluation in the Problem Identification and Resolution cross-cutting area because the licensee did not adequately evaluate this issue to ensure that an adequate resolution addressed the condition commensurate with its safety significance. [P.2] (Section 4OA2.4)

Licensee-Identified Violations

Two 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 into the licensees corrective action program (CAP). The violations and corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began this reporting period shutdown for refueling outage 1R12. The unit was returned to service May 2, 2014, and remained at essentially 100 percent power through the end of the reporting period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Review of Offsite and Alternate AC Power System Readiness

a. Inspection Scope

Inspectors verified plant features, interviewed control room personnel, and reviewed procedures for operation and continued availability of offsite and alternate AC power systems and determined they were appropriate. Inspectors reviewed the licensees procedures and interface agreements affecting these areas and the communications protocols between the northeast area dispatcher and the control room to verify that the appropriate information is exchanged when issues arise that could impact the offsite power system and the alternate AC power system. This activity constituted one Adverse Weather Protection inspection sample. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial System Walkdowns

a. Inspection Scope

The inspectors conducted the equipment alignment partial walkdowns, listed below, to evaluate the operability of selected redundant trains or backup systems with the other train or system inoperable or out of service (OOS). This also included that redundant trains were returned to service properly. The inspectors reviewed the functional system descriptions, the Updated Final Safety Analysis Report (UFSAR), system operating procedures, and Technical Specifications (TS) to determine correct system lineups for the current plant conditions. The inspectors performed walkdowns of the systems to verify that critical components were properly aligned and to identify any discrepancies which could affect operability of the redundant train or backup system. This activity constituted three inspection samples. Documents reviewed are listed in the Attachment.

• Partial walkdown of 1A and 1B motor-driven auxiliary feedwater (MDAFW) pumps while turbine-driven auxiliary feedwater (TDAFW) pumps OOS for preventive maintenance (PM)

• Partial walkdown of 1A residual heat removal (RHR) pump while 1B OOS for testing

• Partial walkdown of 1A emergency diesel generator (EDG) with 1B EDG OOS for modifications and PM

b. Findings

No findings were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors conducted a detailed walkdown/review of the alignment and condition of the safety injection system to verify proper equipment alignment and to identify any discrepancies that could impact the function of the system and increase risk. The inspectors utilized licensee procedures, as well as licensing and design documents, when verifying that the system alignment was correct. During the walkdown, the inspectors also verified, as appropriate, that: 1) valves were correctly positioned and did not exhibit leakage that would impact the function(s) of any valve; 2) electrical power was available as required; 3) major portions of the system and components were correctly labeled, cooled, ventilated, etc.; 4) hangers and supports were correctly installed and functional; 5) essential support systems were operational; 6) ancillary equipment or debris did not interfere with system performance; 7) tagging clearances were appropriate; and 8) valves were locked as required by the licensees locked valve program. Pending design and equipment issues were reviewed to determine if the identified deficiencies significantly impacted the systems functions. Items included in this review were the operator workaround list, the temporary modification list, system health reports, and outstanding maintenance work requests/work orders (WOs). In addition, the inspectors reviewed the licensees corrective action program (CAP) to ensure that the licensee was identifying equipment alignment problems and to ensure they were properly addressed for resolution. This activity constituted one complete walkdown inspection sample.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Fire Protection Tours

a. Inspection Scope

The inspectors conducted tours of the areas important to reactor safety, listed below, to verify the licensees implementation of fire protection requirements as described in: the Fire Protection Program, Nuclear Power Group Standard Programs and Processes (NPG-SPP)-18.4.6, Control of Fire Protection Impairments; NPG-SPP-18.4.7, Control of Transient Combustibles; and NPG-SPP-18.4.8, Control of Ignition Sources (Hot Work).

The inspectors evaluated, as appropriate, conditions related to: 1) licensee control of transient combustibles and ignition sources; 2) the material condition, operational status, and operational lineup of fire protection systems, equipment, and features; and 3) the fire barriers used to prevent fire damage or fire propagation. This activity constituted nine inspection samples.

• 1A RHR pump room

• 1B RHR pump room

• 1A containment spray (CS) pump room

• 1B CS pump room

• TDAFW room

• 1A centrifugal coolant charging pump (CCP) room

• 1B CCP room

• 1A safety injection pump (SIP) room

• 1B SIP room

b. Findings

No findings were identified.

.2 Annual Drill Observations

a. Inspection Scope

On May 14, 2014, the inspectors observed an unannounced fire drill for a simulated fire on the 729-foot elevation on the Unit 2 side of the turbine building. The drill was observed to evaluate the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies; openly discussed them in a self-critical manner at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated were: 1) specified number of individuals responding; 2) proper wearing of turnout gear; 3) self-contained breathing apparatus available and properly worn and used; 4) control room personnel followed procedures for initiation and verification of response; 5) fire brigade leader exhibited command and had a copy of the pre-fire plan; 6) fire brigade leader maintained control starting at the dress-out area; 7) fire brigade response was timely and followed the appropriate access route; 8) command/control set up near the location and communications were established; 9) proper use and layout of fire hoses; 10) fire area entered in a controlled manner; 11) sufficient firefighting equipment brought to the scene; 12) search for victims and propagation of the fire into other plant areas; 13) utilization of pre-planned strategies; 14) adherence to the pre-planned drill scenario and drill objectives acceptance criteria were met; and 15) firefighting equipment returned to a condition of readiness to respond to an actual fire. This activity constituted one inspection sample.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

.1 Intake Pumping Station

a. Inspection Scope

The inspectors reviewed internal flood protection measures for the intake pumping station flood protection features. The features were examined to verify that they were installed and maintained consistent with the plant design basis. The inspectors also reviewed the licensees flooding study calculation for determining maximum flood level in all building rooms for piping failures in both the essential raw cooling water (ERCW)system and the fire protection system. The inspectors confirmed that flood mitigation features such as drains, curbs and door seals were not degraded in such a manner as to adversely impact the conclusions of the study. Documents reviewed are listed in the

. This inspection constituted one inspection sample.

b. Findings

No findings were identified.

.2 Cables in Underground Manholes

a. Inspection Scope

Inspectors directly observed one underground bunker/manholes subject to flooding that contained cables whose failure could disable risk-significant equipment. Specific attributes evaluated were: 1) the cables were not submerged in water; 2) the cables and/or splices appeared intact and the material condition of cable support structures was acceptable; and 3) dewatering devices (sump pump) operation and level alarm circuits were set appropriately to ensure that the cables would not be submerged or were in an environment for which they were qualified. Below are the bunker/manholes that were inspected.

• Manhole 22

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors performed two heat sink performance reviews. The inspectors reviewed the licensees program for maintenance and testing of the 1B-1 emergency diesel generator (EDG) heat exchangers. Specifically, the review included the performance testing and analysis of the 1B1 and 1B2 EDG jacket water heat exchangers. The inspectors reviewed the ERCW system description, the heat exchanger performance, and the eddy current testing program document as well as completed WOs documenting the testing and visual inspection and associated corrective actions to verify that corrosion or fouling did not impact the heat exchanger from achieving its design basis heat removal capacity. The inspectors reviewed periodic test data of ERCW flow rates as well as inlet and outlet temperatures to determine whether potential degradation was being monitored and/or prevented. The inspectors also reviewed eddy current inspection results to determine whether wall loss indications and tube plugging requirements were being identified. The inspectors reviewed the fouling factor calculation. Documents reviewed are listed in the Attachment. This inspection constituted two annual inspection samples.

b. Findings

No findings of significance were identified.

1R08 Inservice Inspection Activities

a. Inspection Scope

Non-Destructive Examination Activities and Welding Activities: From March 31, 2014, through April 4, 2014, the inspectors conducted an onsite review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, emergency feedwater systems, risk-significant piping and components, and containment systems in Unit 1. 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 (ASME BPVC),Section XI (Code of record: 2001 Edition with 2003 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 directly 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 (UT) examination of reactor vessel upper head penetrations 32, 54, and

• UT examination of System 062 - Chemical & Volume Control System Elbow-Pipe Weld CVCS-253, ASME Class 2 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.

• Radiographic (RT) examination of auxiliary feedwater open butt weld WBN-1-PIPE-003-B

• Visual examination of containment liner The inspectors reviewed associated documents of the welding activity listed below in order to evaluate compliance with procedures and the ASME Code. The inspectors reviewed the WO, repair and replacement plan, weld data sheets, welding procedures, procedure qualification records, welder performance qualification records, and NDE reports.

• Weld 0-032E-T043-1B, Essential Control Air System, SK 600-206, 3/16x3/8 pipe socket, 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: The inspectors reviewed a sample of ultrasonic NDE of the reactor vessel upper head penetrations (VUHPs) to verify these activities were implemented in accordance with the ASME Code Case N-729-1, as incorporated by reference in 10 CFR 50.55a(g)(6)(ii)(D).

The inspectors reviewed the plant-specific scan plan and vendor examination procedures to verify the ultrasonic examination method met the requirements in Code Case N-729-1. The inspectors also reviewed personnel and procedure qualification records to verify that they were qualified through a blind demonstration process as required by 10 CFR 50.55a(g)(6)(ii)(D)(4).

The inspectors directly observed ultrasonic data acquisition of reactor VUHP. The inspectors reviewed ultrasonic data examination results for reactor VUHP numbers 32, 54, and 66. The inspectors interviewed vendor and licensee staff to verify that the disposition of indications was consistent with Code Case N-729-1, as modified by 10 CFR 50.55a. For penetrations 32, 54, and 66, the inspectors verified that 100 percent of the required examination volume was examined and that the ultrasonic examination included a leak path assessment through the J-groove welds. The inspections also verified that ultrasonic equipment settings and calibration for penetrations 32, 54, and 66 were consistent with the essential variables described in the demonstrated procedures.

The inspectors review of ultrasonic data also included a comparison of current results with recorded ultrasonic data for the same penetrations from the previous non-visual examination performed in 2008.

The licensee did not perform a bare metal visual examination of the vessel upper head area during the spring 2014 refueling outage. Therefore, the inspectors reviewed the licensees evaluation of effective degradation years and re-inspection years to verify that the inspection frequency for the volumetric and bare metal examinations were consistent with ASME Code Case N-729-1. The inspectors also reviewed visual examination system leakage (VT-2) records for the current outage to verify that a visual examination of the head was performed in accordance with Code Case N-729-1 and ASME BPVC,Section XI, paragraph IWA-2212.

The inspectors also interviewed the licensee and vendor staff about the disposition of any relevant indications (visual or volumetric) that were going to be accepted for continuous service in order to verify that the licensees acceptance was in accordance with ASME Code Case requirements and 10 CFR 50.55a(g)(6)(ii)(D), or an NRC approved alternative. The inspectors were informed that the licensee did not identify any relevant indications that required further evaluation for continuous service.

The inspectors followed up on any weld repairs to verify that the welding process and welding examinations were performed in accordance with ASME Code requirements and 10 CFR 50.55a(g)(6)(ii)(D), or an NRC-approved alternative. The inspectors were informed that no welding repairs were required based on the examination results.

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 Generic Letter 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 (U1R12). 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 program and CAP.

The inspectors reviewed the following PERs, 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.

• PER 613006; Leakage on Reactor Coolant Pump (RCP) #1 Flange and Bolting WBN-1-PMP-068-0008

• PER 692454; Boric Acid Leak located on the seal table WBN-1-ISV-094-E011

• PER 662895; Boric Acid leakage from Spent Fuel Pit Circulating Pump WBN-0-PMP-078-0035-S The inspectors reviewed the following engineering evaluations completed for evidence of boric acid leakage to determine if degraded components were documented in the corrective action program. The inspectors also evaluated corrective actions for any degraded components to determine if they met the ASME Section XI Code and/or NRC approved alternative.

• PER 613006; Leakage on RCP #1 Flange and Bolting WBN-1-PMP-068-0008

• PER 662895; Boric Acid leakage from Spent Fuel Pit Circulating Pump WBN-0-PMP-078-0035-S Steam Generator Tube Inspection Activities: The licensee did not perform steam generator tube inspection activities during the Spring 2014 refueling outage (U1R12).

Therefore, the inspectors did not implement the IP attributes applicable to tube examination and repair activities. However, the inspectors reviewed the latest Condition Monitoring and Operational Assessment Report for Unit 1 (dated December 21, 2012) to verify that the licensees evaluation of inspection results on the primary and secondary sides provided reasonable assurance that the tube integrity performance criteria would be met until the next scheduled inspection. The inspectors also verified that the planned tube inspection schedule was in accordance with the plants TS.

Identification and Resolution of Problems: The inspectors reviewed a sample of ISI-related problems, which were identified by the licensee, and entered into the CAP as PERs. The inspectors reviewed the PERs to confirm the licensee had appropriately described the scope of the problem, and had initiated corrective actions. 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

.1 Licensed Operator Requalification Review

a. Inspection Scope

On June 6, 2014, the inspectors observed the simulator evaluation for an Operations Crew 3 per A28.46.33E0.3S98 Revision (Rev.) 0, reactor coolant system (RCS) fuel failure with a steam generator leak leading to a steam generator tube rupture with a stuck open PORV on the ruptured steam generator. The plant conditions led to a Notification of Unusual Event, Alert and Site Area Emergency. Performance indicator credit was taken.

The inspectors specifically evaluated the following attributes related to the operating crews performance:

• Clarity and formality of communication

• Ability to take timely action to safely control the unit

• Prioritization, interpretation, and verification of alarms

• Correct use and implementation of abnormal operating instructions and emergency operating instructions

• Timely and appropriate Emergency Action Level declarations per emergency plan implementing procedures

• Control board operation and manipulation, including high-risk operator actions

• Command and Control provided by the unit supervisor and shift manager The inspectors also attended the critique to assess the effectiveness of the licensee evaluators and to verify that licensee-identified issues were comparable to issues identified by the inspector. This activity constituted one inspection sample.

b. Findings

No findings were identified

.2 Observation of Operator Performance

a. Inspection Scope

Inspectors observed and assessed licensed operator performance in the plant and main control room, particularly during periods of heightened activity or risk and where the activities could affect plant safety. Inspectors reviewed various licensee policies and procedures such as procedures OPDP-1, Conduct of Operations; NPG-SPP-10.0, Plant Operations; and GO-4, Normal Power Operation.

Inspectors utilized activities such as post maintenance testing, surveillance testing and refueling, and other outage activities to focus on the following conduct of operations as appropriate: This activity constituted one inspection sample.

• Operator compliance and use of procedures

• Control board manipulations

• Communication between crew members

• Use and interpretation of plant instruments, indications and alarms

• Use of human error prevention techniques

• Documentation of activities, including initials and sign-offs in procedures

• Supervision of activities, including risk and reactivity management

• Pre-job briefs

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the performance-based problems listed below. A review was performed to assess the effectiveness of maintenance efforts that apply to scoped structures, systems, or components (SSCs) and to verify that the licensee was following the requirements of TI-119, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting 10 CFR 50.65, and NPG-SPP-03.4, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting 10 CFR 50.65. Reviews focused, as appropriate, on: 1) appropriate work practices; 2) identification and resolution of common cause failures; 3) scoping in accordance with 10 CFR 50.65; 4) characterization of reliability issues; 5) charging unavailability time; 6) trending key parameters; 7) 10 CFR 50.65 (a)(1) or (a)(2) classification and reclassification; and 8) the appropriateness of performance criteria for SSCs classified as (a)(2) or goals and corrective actions for SSCs classified as (a)(1). This activity constituted two inspection samples.

• Reviewed expert panel decision to return south main steam valve vault ventilation system from a(2) to a(1)

• Reviewed station air compressor a(1) corrective action plan revision to change the monitoring period for the new replacement compressors

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors evaluated, as appropriate, for the work activities 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. The inspectors verified that the licensee was complying with the requirements of 10 CFR 50.65 (a)(4); NPG-SPP-07.0, Work Control and Outage Management; NPG-SPP-07.1, On Line Work Management; and TI-124, Equipment to Plant Risk Matrix. This activity constituted four inspection samples.

• Risk assessment for work week 512 with 1A EDG OOS for modifications and PMs and A and C essential raw cooling water (ERCW) testing

• Risk assessment for work week 519 with C-S component cooling system (CCS)pump OOS for testing and H ERCW pump OOS

• Risk assessment for work week 609 with 1A EDG and B ERCW pump OOS

• Emergent risk assessment for F-B ERCW pump failing to trip from main control room (MCR) while 1B EDG OOS for maintenance

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the operability evaluations affecting risk-significant mitigating systems listed below, to assess, as appropriate: 1) the technical adequacy of the evaluations; 2) whether continued system operability was warranted; 3) whether the compensatory measures, if involved, were in place, would work as intended, and were appropriately controlled; 4) where continued operability was considered unjustified, the impact on TS Limiting Conditions for Operation (LCO) and the risk significance in accordance with the SDP. The inspectors verified that the operability evaluations were performed in accordance with NPG-SPP-03.1, Corrective Action Program. This activity constituted four inspection samples.

• Prompt determination of operability (PDO) for PER 866130, Ice condenser baskets found with previously unidentified damage

• PDO for PER 871078, Component cooling system train separation

• PDO for PER 885414, QA-3 grade contactors installed in safety-related breaker for 480V shutdown board 1B-B

• PDO for PER 901154, Untested ASME code relief valve installed for 1D upper containment cooler

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 Ice Basket Design Change

a. Inspection Scope

The inspectors reviewed the permanent plant modifications listed below against the requirements of NPG-SPP-09.3, Plant Modifications and Engineering Change Control, and NPG-SPP-09.4, 10 CFR 50.59 Evaluation of Changes, Tests, and Experiments, and verified that the modification did not affect system operability or availability as described by the TS or the UFSAR. In addition, the inspectors determined whether: 1) the installation of the permanent modification was in accordance with the work package; 2)adequate configuration control was in place; 3) procedures and drawings were updated; and 4) post-installation tests verified operability of the affected systems. This activity constituted one inspection sample. Documents reviewed are listed in the Attachment.

• DCN 51437, Revision A, Modify additional ice baskets with finger supports

b. Findings

No findings were identified.

.2 Fukushima Modification

a. Inspection Scope

The inspectors reviewed DCN 60683, Install New Connections for Fukushima Modifications - Stages 4 and 5 and related documentation for adequacy of the associated 10 CFR 50.59 safety evaluation screening, consideration of design parameters, compliance with the UFSAR and applicable design specifications, and implementation of the modification. The inspectors observed completed work activities to verify that the fabricated spool pieces were consistent with the design control documents. The inspectors reviewed procurement documents, receiving inspection reports, ASME valve data sheets, certified material test reports, and certificates of conformance to determine if the materials used to fabricate the spool pieces complied with the requirements of the ASME Boiler and Pressure Vessel Code, 1971 with 1973 addenda,Section III, Subsection NC and Section II.

The modification installed a new 2-inch branch line for a new hose connection in the discharge line from the A-train safety injection pump (Stage 4) and the B-train safety injection pump (Stage 5). Documents reviewed are listed in the Attachment. This inspection constituted one permanent plant modification sample.

• DCN 60683, Install New Connections for Fukushima Modifications - Stages 4 and 5, dated June 24, 2013

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the post-maintenance test procedures and/or test activities, (listed below) as appropriate, for selected risk-significant mitigating systems to assess whether: 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 adequately 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. The inspectors verified that these activities were performed in accordance with NPG-SPP-06.9, Testing Programs; NPG-SPP-06.3, Pre-/Post-Maintenance Testing; and NPG-SPP-07.1, On Line Work Management. This activity constituted six inspection samples.

• WO 114691460, 1-SI-74-63B, 18-month channel calibration of remote shutdown control RHR heat exchanger B outlet flow control loop 1-LPF-74-28

• WO 114472266, 0-SI-82-6, 18-month loss of offsite power - DG 2B-B

• WO 114561181, IMI-46.002, Auxiliary feedwater turbine 1A-S overspeed trip test

• WO 115756152, 1-SI-1-904, Full stroke exercising of MSIVs

• WO 114560112, Replace pressurizer power operated relief valve (PORV) 1-PCV-08-0349A-A

• WO 115721913, Motor-driven auxiliary feedwater pump 1A-A, steam generator 2 level control valve 1-LCV-003-0156-A positioner calibration and testing

b. Findings

No findings were identified.

1R20 Refueling and Outage (RFO) Activities

a. Inspection Scope

The licensee continued its U1C12 RFO from the beginning of the reporting period until the unit was returned to 100 percent power on May 2, 2014. The inspectors observed mode changes, portions of the plant heatup, reactor startup and power ascension.

The inspectors monitored licensee controls over the outage activities listed below. In addition, the inspectors reviewed the licensees CAP to ensure that the licensee was identifying equipment alignment problems and that they were properly addressed for resolution.

• Controls to ensure that outage work was not impacting the ability to operate the SFP cooling system during and after core offload

• Refueling activities for compliance with TS to verify proper tracking of fuel assemblies from the SFP to the core and to verify foreign material exclusion was maintained

• Heatup and startup activities to verify that TS, license conditions, and other requirements, commitments, and administrative procedure prerequisites for mode changes were met prior to changing modes or plant conditions; RCS integrity verified by reviewing RCS leakage calculations; and containment integrity verified by reviewing the status of containment penetrations and containment isolation valves

• Containment closure activities, including a detailed containment walkdown prior to startup, to verify no evidence of leakage and that debris had not been left which could affect the performance of the containment sump or ice condenser

• Licensee management of fatigue by reviewing schedules, time sheets, and waivers to manage fatigue and associated administrative controls.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors witnessed the surveillance tests and/or reviewed test data of selected risk-significant SSCs listed below, to assess, as appropriate, whether the SSCs met the requirements of the TS; the UFSAR; NPG-SPP-06.9, Testing Programs; NPG-SPP-06.9.2, Surveillance Test Program; and NPG-SPP-09.1, ASME Section XI. The inspectors also determined whether the testing effectively demonstrated that the SSCs were operationally ready and capable of performing their intended safety functions. This activity constituted eight inspection samples.

In-Service Test:

• WO 114471607, 1-SI-3-923-5, Auxilairy feedwater pump 1A-S comprehensive pump test Containment Isolation Valve:

• WO 114472587, 1-SI-67-701-C, Containment isolation valve local leak rate test lower compartment ERCW Ice Condenser:

• WO 114472149, 1-SI-61-5, 18 month ice condenser lower inlet doors inspection Other Surveillances:

• WO 114472748, 1-SI-99-633-A, Response time test - auxiliary feedwater slave relay K633-Train A

• WO 114472264, 0-SI-82-4, 18 month loss of offsite power with safety injection test -

DG 1B-B

• WO 114472594, 1-SI-0-904, Primary pressure boundary isolation valve leak test (RHR cold leg injection check valves)

• WO 114472596, 1-SI-0-905, Primary pressure boundary isolation valve leak test (residual heat removal return valves)

• WO 115253334, 0-SI-82-11-B, Monthly diesel generator start end load test DG 1B-B

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

a. Inspection Scope

On May 14, 2014, the inspectors observed a licensee-evaluated emergency preparedness drill, listed below, to verify that the emergency response organization was properly classifying the event in accordance with procedure EPIP-1, Emergency Plan Classification Flowchart, and making accurate and timely notifications and protective action recommendations in accordance with EPIP-2, Notification of Unusual Event; EPIP-3, Alert; EPIP-4, Site Area Emergency; EPIP-5, General Emergency; and the Radiological Emergency Plan. In addition, the inspectors verified that licensee evaluators were identifying deficiencies and properly dispositioning performance against the performance indicator criteria in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline.

• Fire on Unit 2 main turbine oil tank and trip of 2A main feed pump resulting in Alert level classification

• Unit 1 turbine trips on load rejection from loss of 500 kV switchyard resulting in a loss of flow reactor trip signal without an actual trip

• Unit 1 entered E-0, Reactor Trip or Safety Injection

• A break occured on the #3 RCP seal return line which eventually led to a 300 gpm leak

• The RCS break along with leakage from the Unit 1 containment personnel hatch resulted in a Site Area Emergency due to the loss of the RCS barrier and potential loss of the containment barrier

• Appropriate protective action recommendations made

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

Hazard Assessment and Instructions to Workers: The inspectors discussed possible changes to plant operations since the last inspection that could contribute to significant new radiological conditions. The inspectors independently measured radiation dose rates or directly observed conduct of licensee radiation surveys for selected radiologically controlled area (RCA) areas during plant walkdowns. The inspectors reviewed survey records for several plant areas in the auxilary building, lower and upper containment and including surveys for alpha emitters, airborne radioactivity, gamma surveys with a range of dose rate gradients, and pre-job and some post-job surveys for tasks. During facility tours, the inspectors directly observed labeling of radioactive material and postings for radiation areas, high radiation areas (HRAs) within the RCA of the Unit 1 (U1) auxiliary building and radioactive waste (radwaste) processing and storage locations. 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 for select jobs in HRAs.

Control of Radioactive Material: The inspectors observed surveys of material and personnel being released from the RCA using small article monitor, personnel contamination monitor, and portal monitor instruments, in accordance with procedures.

Inspectors also observed instrument calibration stickers and observed and discussed.

set points for some instrumentation. The inspectors reviewed records of inventory and leak tests on selected sealed sources and discussed nationally tracked source transactions with licensee staff.

Risk-Significant Radiation Areas, Hazard Control, and Work Practices: The inspectors evaluated access barrier effectiveness for selected locked high radiation area (LHRA)locations and discussed procedural guidance and adherence for LHRA and very high radiation area (VHRA) controls with health physics (HP) supervisors. The inspectors observed and evaluated controls for the storage of irradiated material within the SFP.

Established radiological controls (including airborne controls) were evaluated for selected at-power entries into containment and for maintenance work in the SFP transfer canal. In addition, the inspectors reviewed and discussed licensee controls for areas where dose rates could change significantly as a result of incore drive maintenance.

Through direct observations and interviews with licensee staff, the inspectors evaluated occupational workers adherence to selected RWPs and HP technician (HPT) proficiency in providing job coverage. Electronic dosimeter (ED) alarm set points and worker stay times were evaluated against area radiation survey results for selected entries into upper and lower containment. The inspectors discussed the use of personnel dosimetry for multibadging work and areas with high dose gradients. The inspectors also evaluated worker response to dose and dose rate alarms during selected work activities.

Inspectors reviewed RWPs for airborne radioactivity areas.

Problem Identification and Resolution: The inspectors reviewed CAP documents associated with radiological hazard assessment and exposure control. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with licensee procedures. The inspectors also reviewed recent self-assessment results.

The inspectors evaluated radiation protection activities against the requirements and guidance of UFSAR Section 12; TS Section 5.11; 10 CFR 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. Licensee programs for monitoring materials and personnel released from the RCA were evaluated against 10 CFR Part 20 and IE Circular 81-07, Control of Radioactively Contaminated Material. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and

Transportation

a. Inspection Scope

Waste Processing System Program Review: The inspectors reviewed and discussed the status and proposed changes to the radioactive waste processing systems relative to the current UFSAR and Process Control Program (PCP) documents. The inspectors discussed component function, processing system changes, and radwaste program implementation with licensee staff.

For primary resin, filters, and dry active waste (DAW) the inspectors evaluated analyses for hard-to-detect nuclides, reviewed the use of scaling factors, and examined quality assurance comparison results between licensee waste stream characterizations and outside laboratory data. Waste stream sampling methodologies for resins, filters and DAW were evaluated and discussed with responsible radwaste staff.

Radioactive Material Storage: During walkdowns of radioactive material and radioactive waste storage areas, the inspectors observed the physical condition and labeling of storage containers and the posting of radioactive material areas. The inspectors also reviewed licensee procedural guidance for storage and monitoring of radioactive material. RCA storage areas evaluated included select U1 auxiliary building locations and remote facilities within owner controlled area including the steam generator mausoleum and decontamination building.

Radioactive Waste System and Radioactive Material Storage Area Walkdowns:

During inspector walkdowns, accessible sections of the liquid and solid radioactive waste (radwaste) processing systems were assessed for material condition and conformance with system design diagrams. Inspected equipment included radwaste processing and holdup tanks; radwaste system transfer piping, resin and filter components; and dewatering system equipment.

Transportation: During the onsite inspection, training provided to radioactive waste staff responsible for preparing shipments to meet Department of Transportation (DOT)regulations was evaluated. Selected shipping records were reviewed for consistency with licensee procedures and compliance with NRC and DOT regulations. The inspectors reviewed emergency response information, DOT shipping package classification, waste classification, radiation survey results. Licensee procedures for opening and closing shipping containers were compared to package manufacturers requirements. In addition, status of training for selected individuals currently qualified to ship radioactive material was reviewed. The inspectors observed HPTs prepare and survey several shipments that had been received or were being shipped.

Problem Identification and Resolution: The inspectors reviewed selected CAP documentation in the areas of radwaste processing and radwaste/radioactive material shipping. The inspectors evaluated the licensees ability to identify and resolve identified issues in accordance with licensee procedures. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Radwaste processing activities and equipment configuration were reviewed for compliance with the licensees PCP, UFSAR Chapter 11; TS 5.7, Procedures, Programs and Manuals and approved procedures. Waste stream characterization analyses were reviewed against regulations detailed in 10 CFR Part 20, 10 CFR Part 61, and guidance provided in the Branch Technical Position on Waste Classification (1983).

Transportation program implementation was reviewed against regulations detailed in 10 CFR Part 20, 10 CFR Part 71, 49 CFR Parts 172-178, as well as the guidance provided in NUREG-1608. Training activities were assessed against 49 CFR Part 172 Subpart H.

Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

.1 Reactor Safety Cornerstones

a. Inspection Scope

The inspectors sampled licensee submittals for the two PIs listed below. To verify the accuracy of the PI data reported from July 1, 2013, through June 30, 2014, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Indicator Guideline, Rev.

6, were used to verify the basis in reporting for each data element.

• RCS leakage

• Safety system functional failures

b. Findings

No findings were identified.

.2 Radiations Safety Cornerstones

a. Inspection Scope

Occupational Radiation Safety Cornerstone: The inspectors reviewed the Occupational Exposure Control Effectiveness PI results for the Occupational Radiation Safety Cornerstone from April through December 2013. For the assessment period, the inspectors reviewed ED alarm logs and selected CAPs documents related to controls for exposure significant areas. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents reviewed are listed in the

.

Public Radiation Safety Cornerstone The inspectors reviewed the Radiological Control Effluent Release Occurrences PI results for the Public Radiation Safety Cornerstone from April through December 2013. For the assessment period, the inspectors reviewed cumulative and projected doses to the public contained in liquid and gaseous release permits and CAPs documents related to Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual issues. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Review of Items Entered into the Corrective Action Program (CAP)

a. Inspection Scope

As required by 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 a daily screening of items entered into the licensees CAP. This review was accomplished by reviewing daily PER summary reports and attending daily PER review meetings

.2 Semi-Annual Review to Identify Trends

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 human performance trends, licensee trending efforts, and repetitive equipment and corrective maintenance issues. The inspectors also considered the results of the daily inspector CAP item screening discussed in Section 4OA2.1. The inspectors review nominally considered the six-month period of January 2013 through June 2013, although some examples expanded beyond those dates when the scope of the trend warranted.

b. Observations No findings were identified. Some long-standing equipment issues remain. The ice condenser is challenged to maintain temperatures below the administrative limit of 20º F.

RCS leakage rates have been elevated since the unit was returned to service from the spring 2014 outage. The inspectors have engaged the licensee on the long-standing equipment issues a number of times. There has been an upward trend in human performance issues related to procedure adherance. Also, the inspectors have noted the licensee struggles with the parts qualification process. The screening committee (PSC) for incoming CAP documents struggles with recognizing issues related to Codes and Standards and how they affect the conformance or operability of equipment. For examples, see part 3 and 4 of this section.

.3 Annual Sample: Review of Problem Identification and Resolution for PER 810826

a. Inspection Scope

The inspectors reviewed the plan and implementation of corrective actions for a non- conformance issue, which was documented in PER 810826.

b. Findings and Observations

Introduction:

A Green NRC-identified NCV of 10 Code of Federal Regulations (CFR) 50 Appendix B, Criterion XVI, Corrective Action, was documented for the licensees failure to adequately identify a condition adverse to quality associated with the installation of non-conforming parts in 480 volt breaker 0-BKR-548-0021-S, which was in service in safety-related 480 volt shutdown board 1B1.

Description:

On January 22, 2013, licensee maintenance personnel obtained non-conforming main contactors and installed them in breaker 0-BKR-548-0021-S and subsequently installed this breaker into safety-related 480 volt shutdown board 1B1.

The materials department determined on November 19, 2013, that this safety-related breaker had non-conforming parts issued to it and requested that the engineering department ensure that this was the correct part for this breaker. This was captured in PER 810826. The corrective action screening process for all PERs is performed by a committee composed of plant staff members from the plant departments. This committed failed to recognize that this breaker was installed with non-conforming parts.

As a result, this breaker remained in service until May 20, 2014. Inspectors review of the apparent cause analysis determined that the licensee had categorized the failure to identify the installed non-conforming breaker as a corrective action for the original PER not as a new condition adverse to quality. Because of this the licensee did not generate a PER in February 2014 and perform an operability evaluation when the non-conforming condition on the breaker installed in January 2013 was identified. The licensee generated PER 885414 to address the failure to generate a PER and review the non-conforming breaker for operability.

Analysis:

The inspectors determined that the licensees failure to adequately identify a condition adverse to quality associated with the installation of non-conforming parts as required by 10 CFR 50 Appendix B, Criterion XVI, was a performance deficiency. The performance deficiency was determined to be more than minor because it adversely affected the objective of the Mitigating Systems cornerstone to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to identify the condition adverse to quality led to an additional six months that this non-conforming condition existed thus reducing the licensees ability to ensure the reliability and capability of plant safety systems. Using the screening worksheet of IMC 0609, Appendix A, Exhibit 2 -

Mitigating Systems Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because the deficiency only affected the qualification of the breaker. The cause of the finding was directly related to the aspect of identification in the Problem Identification and Resolution cross-cutting area because the licensee did not identify this issue completely, accurately, and in a timely manner in accordance with the program. [P.1]

Enforcement:

10 CFR 50 Appendix B, Criterion XVI, Corrective Action, states in part, that measures shall be established to assure that conditions adverse to quality such as non-conformances are promptly identified and corrected. Contrary to the above, from November 19, 2013, until May 15, 2014, the licensee failed to identify a condition adverse to quality associated with 480 volt breaker 0-BKR-548-0021-S. Because this finding was of low safety significance (Green) and was entered into the licensees corrective action program as PER 885414, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy. This finding is identified as NCV 05000390/2014003-01, Failure to Identify a Condition Adverse to Quality.

.4 Annual Sample: Review of Problem Identification and Resolution for PER 901154

a. Inspection Scope

The inspectors reviewed the plan and implementation of corrective actions for a non- conformance issue, which was documented in PER 901154.

b. Findings and Observations

Introduction:

A Green NRC-identified NCV of 10 Code of Federal Regulations (CFR) 50 Appendix B, Criterion XVI, Corrective Action, was documented for the licensees failure to adequately identify a condition adverse to quality associated with the installation of relief valve 1-RFV-67-1026D, Upper Containment Cooler 1D, an ASME Class III component.

Description:

On July 21, 2010, licensee engineering personnel determined that an relief valve that was assumed to be rebuilt was installed in the ERCW system; The relief valve had no test data to support operability. PER 241082 was submitted into the screening process and was initially identified as a potential operability issue.

Subsequently, it was incorrectly determine by Operations personnel that the valve was operable and that the Inservice Testing requirements of ASME section 11 were only administrative or programmatic issues. Following review by the PER screening committee which concluded no operability concerns, this PER was closed to a work order to replace the relief valve. The work order was not scheduled to be worked for approximately four years.

During the spring 2014 outage, maintenance management canceled the WO which effectively canceled the corrective action. The cognitive engineer recognized this issue and submitted PER 874223 on April 19, 2014, and this PER was also closed to a work order to replace the valve. This PER was marked that potential operability was not affected, the PER screening committee concurred and it received no further operability evaluation. Inspectors became aware through the normal process of daily PER review and challenged the licensee as to the basis of considering this condition as conforming.

This issue was discussed with site management as a part of a normal periodic meeting on June 4, 2014.

On June 20, 2014, a third PER, PER 901154 was written by the Inservice Test Program engineer with the words, non-conforming to ASME OM Code requirements and the PER was screened by the PER screening committee as not an operability concern.

Inspectors re-engaged the licensee and the PER was re-evaluated on June 24, 2014, as a non-conforming issue. Engineering performed a Prompt Operability Determination on June 27, 2014, and determined that due to a second relief valve in this piping section, that as long as there were no valves closed separating the sections that the 1D Containment Cooler sub-system was operable.

Analysis:

The inspectors determined that the licensees failure to adequately identify a condition adverse to quality associated with the non-conformance of relief valve 1-RFV-67-1026D, as required by 10 CFR 50 Appendix B, Criterion XVI, was a performance deficiency. The performance deficiency was determined to be more than minor because it adversely affected the objective of the Mitigating Systems cornerstone to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to correct the condition adverse to quality in a timely manner led to an additional four years that this non-conforming condition existed prior to evaluation, thus reducing the licensees ability to ensure the reliability and capability of plant safety systems. Using the screening worksheet of IMC 0609, Appendix A, Exhibit 2 - Mitigating Systems Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because there existed an additional relief valve in the IST program that could protect the piping and cooler from over pressurization with appropriate compensatory measures. The cause of the finding was directly related to the aspect of evaluation in the Problem Identification and Resolution cross-cutting area because the licensee did not adequately identify this issue to ensure that an adequate resolution addressed the condition commensurate with its safety significance. [P.2]

Enforcement:

10CFR50 Appendix B, Criterion XVI, Corrective Action states, in part, that measures shall be established to assure that conditions adverse to quality such as non-conformances are promptly identified and corrected. Contrary to the above, from July 21, 2010, until June 27, 2014, the licensee failed to identify a condition adverse to quality associated with relief valve 1-RFV-67-1026D. Because this finding was of low safety significance (Green) and was entered into the licensees corrective action program as PER 901154, this violation is being treated as an NCV consistent with Section 2.3.2 of the NRC Enforcement Policy. This issue is identified as NCV 05000390/2014003-02, Failure to Identify a Condition Adverse to Quality.

4OA3 Followup of Events

Unit 1 Reactor Trip - June 28, 2013

a. Inspection Scope

The inspectors monitored troubleshooting activities supporting the completion of the licensee root cause analysis for the reactor trip of June 28, 2013, conducted to resolve URI 050000390/2013004-01, Contribution of Potential Current Transformer Imbalance to Reactor Trip.

b. Findings and Observations

Introduction:

A Green NRC-identified finding was documented by the inspectors for the licensees failure to comply with a design drawing during a modification resulting in a trip of Unit 1 reactor.

Description:

On June 28, 2013, an A-phase high impedance ground fault occurred on the Roane 500kV transmission line approximately 22 miles from Watts Bar Nuclear Unit 1. Concurrently, the licensee experienced a reactor trip due to the actuation of the 1A Main Bank Transformer Feeder Differential Relay 187TF. The 500kV transmission line fault was caused by a tree that fell onto the A phase of the transmission line.

Per design, a differential relay, such as the 187TF relay, should not trip due to an event occurring outside of the relays zone of protection because the input amperage subtracts from the output amperage equaling zero so no amperage is available to trip the relay.

Specifically, the 187TF relay zone of protection covers the bus network between the two main generator output breakers and the 1A main bank transformer, which is within the plants switch yard, whereas the fault was 22 miles from the plant site. The root cause team determined that a loose connection was the cause of the relay trip even though subsequent bench testing could not support it. The inspectors concluded that the loose connection was not the root cause because the connection had passed approximately 2 amps, during previous troubleshooting. This would have detected a loose connection.

.In response to inspector questions, the licensee hired a third party consultant, which also discounted the connector as an obvious cause of the 187TF relay trip. Both the inspectors and the third party consultant believed that neither of the licensees troubleshooting techniques nor their root cause analysis had adequately addressed the cause of the 187TF relay trip, which could continue to challenge the reactor protection system on subsequent high impedance ground faults outside of the plant.

Extensive follow-up testing by the licensee during the spring 2014 outage determined that a portion of the neutral circuit had been inappropriately left disconnected due to a llead that was lifted during a previous modification. This lifted lead unbalanced the circuit, causing 1A Main Bank Transformer Feeder Differential Relay 187TF to actuate when the tree fell on the transmission line. .

Analysis:

The inspectors determined that the licensees failure to properly implement DCN 52295, complete bus differential wiring for main bus 2, as required by NPG-SPP-09.3, Rev 17, Plant Modifications and Engineering Change Control, was a performance deficiency. The performance deficiency was determined to be more than minor because it adversely affected the objective of the Initiating Events cornerstone to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to correctly translate design drawings to implementing WO 08-816022-006 resulted in Unit 1 experiencing a 100 percent load rejection and reactor trip. Using the screening worksheet of IMC 0609, Appendix A, Exhibit 1 - Initiating Events Screening Questions, the inspectors determined that the finding was of very low safety significance (Green) because the resulting transient was within the design basis for Unit 1 and all plant systems functioned as required to place the unit in a stable, hot standby condition. The cause of the finding was directly related to the aspect of work management in the Human Performance cross-cutting area because the licensee failed to implement a process of planning, controlling, and executing work activities such that nuclear safety was the overriding priority. [H.5]

Enforcement:

No violation of NRC regulatory requirements occurred. The inspectors determined that the finding did not represent a noncompliance because the performance deficiency involved non-safety related equipment. This finding was determined to be of very low safety significance (Green) and was entered into the licensees CAP as PER 747048. This finding is identified as FIN 050000390/2014003-03, Failure to Comply with Design Drawing Results in a Reactor Trip. This finding closes URI 050000390/2013004-01, Contribution of Potential Current Transformer Imbalance to Reactor Trip.

4OA5 Other Activities

.1 Follow-up on Confirmatory Action Letter (IP 92702)

a. Inspection Scope

The inspector reviewed the progress TVA has made in the implementation of commitments associated with the Confirmatory Action Letter - Watts Bar Nuclear Plant Unit 1, And Sequoyah Nuclear Plant, Units 1 and 2, Commitments to Address External Flooding Concerns (CAL no. NRR-12-001)( ADAMS Accession No. ML12165A527).

Using the guidance of IP 92702, this inspector verified the following for selected actions of the licensee's commitments 1, 3, 6, 8, 9, and 12:

• Ensured required actions were completed.

• Verified the adequacy of implementation of required actions.

• Confirmed that the licensee instituted appropriate corrective and preventive measures.

1. By July 20, 2012, TVA will submit a License Amendment Request to update the

WBN, Unit 1 UFSAR to reflect the updated hydrologic analysis methods and results, including the analysis of the rim leakage paths discussed at the May 31, 2012, public meeting between TVA and NRC staff.

3. By August 31, 2012, TVA will issue and initially perform a procedure for a semi-

annual inspection of the compensatory measure for flood protection of the WBN, Unit 1 Thermal Barrier Booster pumps and motors. The inspection will verify:

a. The condition of the permanent building attachments; and b. The inventory, storage, physical protection, and condition of the materials and consumables required for erection of the temporary flood protection panels during a postulated PMF [probable maximum flood] event.

Inspections will continue until the compensatory measure is replaced by a permanent plant modification.

6. By August 31, 2012, TVA will perform an analysis of the Design Basis Flood for

SQN, Units 1 and 2, and WBN, Unit 1 that assumes a failure of a section of the HESCO flood barriers [sand baskets] and earthen embankments at Fort Loudon, Cherokee, Tellico, and Watts Bar dams.

8. By March 31, 2013, TVA will install a permanent plant modification to provide flood

protection with respect to the Design Basis Flood level for WBN, Unit 1 Thermal Barrier Booster pumps and motors.

9. By March 31, 2013, TVA will install a permanent plant modification to provide flood

protection with respect to the Design Basis Flood level for WBN, Unit 1 Spent Fuel Pit Cooling pumps and motors.

12. By April 30, 2013, TVA will provide the results of the evaluation conducted in compliance with the National Environmental Policy Act (NEPA) Environmental Impact Statement (EIS) Status to define the permanent modifications to prevent overtopping the embankments of the Cherokee, Fort Loudon, Tellico, and Watts Bar dams.

Additionally, this inspection reviewed plans and progress of open commitments 7, 13, 14, 15, and 16, to ensure current understanding and scheduled completion were consistent between the NRC and TVA.

b. Findings

No findings were identified.

.2 (Closed) Temporary Instruction 2515/182 - Review of the Industry Initiative to Control

Degradation of Underground Piping and Tanks

a. Inspection Scope

The inspectors reviewed records and procedures related to the licensees program for buried piping and underground piping and tanks, in accordance with Phase II of Temporary Instruction (TI) 2515/182 to confirm that the licensees program contained attributes consistent with Sections 3.3.A and 3.3.B of Nuclear Energy Institute (NEI)09-14, Guideline for the Management of Buried Piping Integrity, Revision 3, and to confirm that these attributes were scheduled and/or completed by the NEI 09-14 deadlines. The inspectors interviewed licensee staff responsible for the buried piping program, and reviewed program related activities, to determine if the program attributes were accomplished in a manner that reflected acceptable practices in program management.

The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.a of the TI, and it was confirmed that activities which correspond to completion dates specified in the program, which had passed since the Phase I inspection was conducted, have been completed. The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.b of the TI, and responses to specific questions found in http://www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-phase-2-insp-req-2011-11-16.pdf were submitted to the NRC Headquarters staff. Additionally, the inspectors reviewed the licensees risk ranking process and implementation of the inspection plan, using the guidance of paragraph 03.04 and 03.05 of the TI.

b. Findings

No findings were identified. Based on the scope of the review described above, Phase II of TI-2515/182 was completed.

4OA6 Meetings, including Exit

On July 9, 2014, the resident inspectors presented the quarterly inspection results to members of the licensee staff. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

On April 4, 2014, the inspectors presented the inspection results to members of the licensee management staff. The licensee acknowledged the inspection results. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

On April 18, 2014, the inspectors discussed the results of the onsite inspection with Mr.

Chris Church, Site Vice President, and other responsible staff. The inspectors noted that proprietary and sensitive information was reviewed during the course of the inspection and it would not be included in the documented report.

4OA7 Licensee-Identified Violations

The following violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which met the criteria of the NRC Enforcement Policy for being dispositioned as Non-Cited Violations.

• 10 CFR 50 Appendix B, Criterion XV, Nonconforming Materials, Parts, or Components, states, in part, that measures shall be established to control materials, parts, or components which do not conform to requirements in order to prevent their inadvertent use or installation. Contrary to this requirement, the licensee did not ensure that a non-conforming component was properly identified and segregated as non-conforming to prevent possible use in a safety-related application.

On March 22, 2014, during receipt inspection of a refurbished 6.9 kV circuit breaker per WO 115282290, breaker maintenance personnel determined that it was not in serviceable condition and initiated service requests 862089 and 862145 to document the non-conforming conditions. On March 31, 2014, the non-conforming circuit breaker was returned to inventory with two serviceable circuit breakers and made available for issue, rather than being identified and segregated as non-conforming, as required by procedure NPG-SPP-6.11. On April 4, 2014, discussions between warehouse personnel and maintenance personnel revealed that one of three 6.9 kV circuit breakers recently placed in inventory was unusable. All three circuit breakers were placed on hold and tagged as non-conforming. Once further investigation determined which circuit breaker was non-conforming, it was removed from inventory. This low safety significant adverse condition was captured in the licensees corrective action program as PER 872906.

• 10 CFR 50 Appendix B, Criterion XV, Nonconforming Materials, Parts, or Components, states, in part, that measures shall be established to control materials, parts, or components which do not conform to requirements in order to prevent their inadvertent use or installation. Contrary to this requirement, the licensee did not ensure that a non-conforming part was properly controlled to prevent its use in a safety-related application.

On January 22, 2013, non-conforming main contactors were installed in a safety-related 480 volt breaker which was then installed in the plant on January 25, 2013.

The breaker remained in service until May 20, 2014, when it was replaced. This low safety significant adverse condition was captured in the licensees corrective action program as PER 810826. (See Section 4OA2 for additional details)

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

G. Arent, Licensing Manager

R. Bankes, Chemistry/Environmental Manager

L. Belvin, QA Manager

M. Bottorff, Operations Superintendent

M. Casner, Site Engineering Director

S. Connors, Plant Manager

K. Dietrich, Manager Engineering Programs

T. Detchemende, Emergency Preparedness Manager

S. Fisher, Security Manager

W. Hooks, Radiation Protection Manager

J. James, Maintenance Manager

T. Morgan, Licensing Engineer

J. ODell, Site Licensing Supervisor

A. Pirkle, Engineering Programs

J. Reidy, Operations Manager

D. Shutt, Licensing

R. Stroud, Site Licensing

M. Thaggart, Work Control Manager

K. Walsh, Site Vice President

ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000390/2014003-01 NCV Failure to Identify a Condition Adverse to Quality (Section 4OA2.3)

05000390/2014003-02 NCV Failure to Identify a Condition Adverse to Quality (Section 4OA2.4)

050000390/2014003-03 FIN Failure to Comply with Design Drawing Results in a Reactor Trip (Section 4OA3)

Closed

050000390/2013004-01 URI Contribution of Potential Current Transformer Imbalance to Reactor Trip (Section 4OA3)

2515/182 TI Review of the Industry Initiative to Control Degradation of Underground Piping and Tanks, Phase II (Section 4OA5.2)