IR 05000400/2013005

IR 05000400-13-005 and 05000400-13-502, on October 1, 2013 - December 31, 2013; Shearon Harris Nuclear Power Plant, Unit 1; Plant Modifications and Identification and Resolution of Problems

ML14035A519
Person / Time
Site:	Harris
Issue date:	02/04/2014
From:	Hopper G NRC/RGN-II/DRP/RPB4
To:	Kapopoulos E Duke Energy Progress
References
IR-13-005, IR-13-502
Download: ML14035A519 (54)

Text

UNITED STATES ary 4, 2014

SUBJECT:

SHEARON HARRIS NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000400/2013005 AND 05000400/2013502

Dear Mr. Kapopoulos:

On December 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Shearon Harris reactor facility Unit 1. The enclosed inspection report documents the inspection results which were discussed on January 30, 2014, with you and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

One self-revealing finding and one NRC-identified finding of very low safety significance (Green)

were identified during this inspection. These findings were determined to involve a violation of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs)

consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest these non-cited violations, 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 the Shearon Harris facility.

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 Shearon Harris facility. As a result of the Safety Culture Common Language Initiative, the terminology and coding of crosscutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting aspects identified in CY 2014 will be coded under the latest revision to IMC 0310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment review.

In accordance with 10 CFR 2.390 of the NRC's Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's 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/

George T. Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket No.: 50-400 License No.: NPF-63

Enclosure:

NRC Inspection Report 05000400/2013005 and 05000400/2013502 w/Attachment: Supplemental Information

REGION II==

Docket No.: 50-400 License No.: NPF-63 Report No.: 05000400/2013005 and 05000400/2013502 Licensee: Duke Energy Progress, Inc.

Facility: Shearon Harris Nuclear Power Plant, Unit 1 Location: 5413 Shearon Harris Road New Hill, NC 27562 Dates: October 1, 2013 through December 31, 2013 Inspectors: J. Austin, Senior Resident Inspector P. Lessard, Resident Inspector M. Catts, Senior Resident Inspector (Section 1R01, 1EP6)

A. Butcavage, Reactor Inspector (Section 1R08)

M. Coursey, Reactor Inspector (Section 1R08)

A. Nielsen, Senior Health Physicist (Section 2RS8)

J. Rivera, Health Physicist (Section 2RS1, 4OA1)

J. Laughlin, Emergency Preparedness Inspector (Section 1EP4)

A. Alen, Reactor Inspector (Section 4OA5)

T. Fanelli, Reactor Inspector (Section 4OA5)

Approved by: George T. Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000400/2013-005 and 05000400/2013502: Duke Energy Progress, Inc.; on

October 1, 2013 - December 31, 2013; Shearon Harris Nuclear Power Plant, Unit 1; Plant Modifications and Identification and Resolution of Problems.

The report covered a three-month period of inspection by resident inspectors, a visiting senior resident inspector, two regional health physicists, four reactor inspectors, and one emergency preparedness inspector. One NRC-identified and one self-revealed finding of very low safety significance (Green) were identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, issued June 19, 2012, Significance Determination Process (SDP). The cross-cutting aspects were determined using IMC 0310, Components Within the Cross-Cutting Areas, issued October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated January 28, 2013. The NRCs program for overseeing the safe operations of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process revision

Cornerstone: Initiating Events

Green.

A self-revealing Green finding was identified for the licensees failure to adequately establish and implement procedure NGG-PMB-XFM-02, Equipment Reliability Template for Dry-Type Transformers, and implementing procedure PM-E0015, 480 V and 6.9 kV Transformer Electrical and Preventive Maintenance (PM)

Check, when the 1E2 transformer failed on August 8, 2013. Specifically, procedure PM-E0015 did not contain steps to identify degradation in the 1E2 transformer windings prior to failure. As corrective action, the licensee replaced the transformer and plans to revise procedure PM-E0015 to incorporate additional testing to aid in the identification of winding degradation prior to transformer failure. The licensee entered these issues into the corrective action program (CAP) as Action Request (AR) #621738.

The inspectors determined that inadequate testing prescribed by procedure NGG-PMB-XFM-02 and performed under procedure PM-E0015 was a performance deficiency. Specifically, licensee procedure ADM-NGGC-0107, Equipment Reliability Process Guideline, resulted in the determination that the 1E2 transformer was a critical component. Licensee procedure NGG-PMB-XFM-02, Equipment Reliability Template for Dry-Type Transformers, states that critical components are maintained to not allow any failure that would result in a trip, transient, or significant challenge to continued safe operation. However, implementing procedure PM-E0015, failed to contain steps to identify degradation in the 1E2 transformer windings prior to failure.

This finding was more than minor because it is associated with the procedure quality attribute of the Initiating Events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operation. Specifically, a power transient resulted from the 1E2 failure. Using IMC 0609, Significance Determination

Process, Appendix A, Exhibit 1- Initiating Events Screening Questions, the inspectors determined this finding to be of very low safety significance (Green)because the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss of feedwater). The finding had a cross-cutting aspect of Long Term Safety, as described in the Resources component of the Human Performance cross-cutting area because the licensees evaluation of the transformer PM program in March 2012 removed additional testing which might have indicated that the transformer windings had experienced insulation degradation.

H.2(a) (Section 4OA2.4)

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.49 for the failure to adequately implement the environmental qualification (EQ) program for electric equipment important to safety. Specifically, between September 2013 and November 2013, multiple EQ program deficiencies were identified including design documentation and the qualification of electric equipment installed in the plant. The licensee took corrective action to repair or schedule repair for all of the identified issues. The licensee entered these issues into the CAP as AR #663071.

The inspectors determined that the failure to completely implement the EQ program as required by 10 CFR 50.49 was a performance deficiency. Specifically, between September 2013 and November 2013, multiple EQ program deficiencies were identified including design documentation and the qualification of electric equipment installed in the plant. This finding was more than minor because, if left uncorrected, it would have the potential to lead to a more significant safety concern if the functions of other components in the EQ program are challenged. Using IMC 0609,

Significance Determination Process, Appendix A, Exhibit 2- Mitigating Systems Screening Questions, the inspectors determined this finding to be of very low safety significance (Green) because it was a deficiency affecting the design or qualification of equipment. The finding had a cross-cutting aspect of Conducts Self-Assessments, as described in the Self and Independent Assessments component of the Problem Identification and Resolution cross-cutting area because the licensee failed to identify these issues during their recent self-assessments. P.3(a) (Section 1R18)

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near rated thermal power (RTP) until it was shut down for the planned refueling outage 18 (RFO-18) on November 8, 2013. The plant was restarted on December 10, 2013 and restored to RTP on December 13,

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to verify that the plants design features and implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather. Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. Cold weather protection, such as heat tracing and area heaters, was verified to be in operation where applicable. The inspectors also reviewed corrective action program (CAP) items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures.

Documents reviewed are listed in the Attachment. The inspectors reviews focused specifically on the following plant systems due to their risk significance or susceptibility to cold weather issues:

• Emergency Service Water (ESW) System

• Compressed Air System The inspectors reviewed the following Action Requests (ARs) associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #650652, Boric Acid Batching Tank Heating Element Broken

• AR #585755, Auxiliary Reservoir Bay 8 ESW Travelling Screen Heater Causing Ground Fault

• AR #644411, Heat Trace Deenergized during Bus Outage

• AR # 652780, Low Alternate Seal Injection Room Temp Causing Main Control Board Alarm

b. Findings

No findings were identified.

.2 External Flooding

a. Inspection Scope

The inspectors evaluated the design, material condition, and procedures for coping with the design basis probable maximum flood. The evaluation included a review for deviations from the descriptions provided in the UFSAR for features intended to mitigate the potential for flooding from external factors. As part of this evaluation, the inspectors looked for obstructions that could prevent draining, ensured that the roofs did not contain obvious loose items that could clog drains in the event of heavy precipitation, and determined that barriers required to mitigate the flood were in place and operable.

Additionally, the inspectors performed a walkdown of the protected area to identify any modification to the site which would inhibit site drainage during a probable maximum precipitation event or allow water ingress past a barrier. The inspectors also reviewed the abnormal operating procedure (AOP) for mitigating the design basis flood to ensure it could be implemented as written.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #614331, Unsealed Flooding Penetrations

• AR #606017, Unsealed Hatch on Waste Processing Building Roof

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

The inspectors performed four partial system walkdowns of the following risk-significant systems:

• The B Emergency Diesel Generator (EDG) while the A EDG was inoperable for a planned maintenance outage on October 30, 2013;

• The B Switchgear Room while the A EDG was inoperable for planned maintenance on November 12, 2013;

• The B Switchgear Ventilation Room while the A EDG was inoperable for planned maintenance outage on November 14, 2013; and

• The B Component Cooling Water (CCW) system while it was protected and providing decay heat removal on December 5, 2013.

The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, applicable portions of the UFSAR, Technical Specification (TS)requirements, outstanding work orders (WO), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions.

The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

On December 20, 2013, the inspectors performed a complete system alignment inspection of the Emergency Diesel Generator Fuel Oil System to verify the functional capability of the system. This system was selected because it was considered risk significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that auxiliary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #513362, License Renewal

• AR #581384, Preventive Maintenance Extension

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Quarterly Resident Inspector Tours

a. Inspection Scope

The inspectors conducted five fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• Reactor Auxiliary Building (RAB), 190 Elevation, A Residual Heat Removal (RHR)and Containment Spray (CS) Pump Room and Floor Drain Pump Room

• RAB, 190 Elevation, B RHR and CS Pump Room and Equipment Drain Pump Room

• A Train ESW Pump Room

• B Train ESW Pump Room

• A Switchgear Ventilation Room The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and had implemented adequate compensatory measures for out-of-service (OOS), degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. The inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed, that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees corrective action program. Documents reviewed are listed in the Attachment The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #632505, Combustible Materials Located in 35' Exclusion Zone

• AR #642885, Non-Exempt Combustibles in Turbine Building Tool Storage Room

b. Findings

No findings were identified.

1R06 Flood Protection Measures

.1 Review of Areas Susceptible to Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the UFSAR, engineering calculations, and AOPs, for licensee commitments.

Documents reviewed are listed in the Attachment. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the fire suppression or the circulating water systems. The inspectors also reviewed the licensees corrective action documents with respect to past flood-related items identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following plant areas to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable, and that the licensee complied with its commitments:

• RAB 261 Elevation, Essential Services Chilled Water Area

• RAB 236 Elevation, Auxiliary Feedwater Area The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #614258, RAB 236 Wall Flood Protection Deficiencies

• AR #614331, Unsealed Penetrations

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of the B CCW heat exchanger to verify that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspectors reviewed the licensees observations as compared against acceptance criteria, the correlation of scheduled testing and the frequency of testing, and the impact of instrument inaccuracies on test results. Inspectors also verified that test acceptance criteria considered differences between test conditions, design conditions, and testing criteria.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #647486, Plugs Installed into B CCW Heat Exchanger without Direction

• AR #647497, B CCW Heat Exchanger Work Delay due to Stuck Birdies and Poor Turnover

• AR #648415, B CCW Heat Exchanger End Bell Leakage during ESW Restoration

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

.1 Non-destructive Examination Activities and Welding Activities

a. Inspection Scope

From November 18-22, 2013, the inspectors conducted an on-site review of the implementation of the licensees in-service 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 sample review of non-destructive examinations (NDEs) to evaluate compliance with the applicable edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC), Section XI, 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 or NRC approved alternative requirement.

The inspectors directly observed or reviewed records of 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. Inspectors also reviewed evaluations of results that were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

• Directly observed:

o Remote ultrasonic testing (UT) examinations of the RPV closure head penetrations to the reactor closure head o Penetrant testing (PT) examinations of the integral lug attachments associated with service water piping supports inside the containment building o Visual examination (VT) associated with a service water pipe support inside containment

• Reviewed records:

o UT examinations of reactor coolant pipe welds associated with the augmented industry examinations performed in response to MRP-146, Management of Thermal Fatigue in Normally Stagnant Non- Isolable Reactor Coolant System Branch Lines o VT examination results of inspections on reactor vessel supports required by ASME Section XI, Table IWF-2500-1 o VT-3 examination of accessible portions of the containment moisture barrier on the lower level of the containment structure The inspectors reviewed documentation for the repair/replacement of the following pressure boundary welds:

• Repair Welds associated with the Reactor Vessel Closure Head (RVCH)

Penetrations Specific inspector activities associated with RVCH repair welds are documented in the next section.

b. Findings

No findings were identified.

.2 Pressurized-Water Reactor Vessel Upper Head Penetration (VUHP) Inspection Activities

a. Inspection Scope

For the Unit 1 vessel head, a bare metal visual (BMV) examination and a volumetric examination were required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D). The inspectors observed and reviewed records of the Unit 1 BMV examination for penetrations 20, 22, 26, 27, 34, 37, 54, and 56. The inspectors also observed and reviewed records of UT examination for penetration 1, 6, 7, 28, 31, 33, 34, 37, 40, 42, 45, and 53, to evaluate if the activities were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). In particular, the inspectors evaluated if the required BMV and UT examination scopes/coverage were achieved and limitations (if applicable) were recorded in accordance with the licensees procedures. Additionally, the inspectors evaluated if the licensees criteria for visual and UT examination quality and instructions for resolving interference and masking issues were consistent with 10 CFR 50.55a.

The inspectors reviewed records of welded repairs on the upper head penetration 37, completed during the current outage, to evaluate if the licensee applied the pre-service nondestructive examinations and acceptance criteria required by the NRC-approved ASME Code relief request, and the ASME Code Section XI. In addition, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to evaluate if the weld procedures used were validated in accordance with the Construction Code and the ASME Code Section IX requirements.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control (BACC) Inspection Activities

a. Inspection Scope

The inspectors reviewed the licensees BACC program activities to ensure implementation with commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary, and applicable industry guidance documents. Specifically, the inspectors performed an on-site record review of procedures and the results of the licensees containment walkdown inspections performed during the current refueling outage.

The inspectors also interviewed the BACC program owner, conducted an independent walk-down of three levels of the 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.

Several cases of boric acid deposition on containment equipment were noted by inspectors during the containment walk-down and were entered into the corrective action process by the licensee. Specifically, the inspectors noted stalactite formation on the bottom of a HVAC duct located below a section of piping containing boric acid. This condition was entered into the corrective action process. As a second example, the inspectors noted that boric acid spray associated with a leak on a fill valve for one of the safety injection accumulators, had deposited overspray on the cooling coil fins of one of the containment air handling units. An action report was initiated to assess the impact of the boric acid on the coil performance and assess the impact, if any, on previous conclusions reached in Operational Decision Making conclusions that were associated with the leaking valve.

The inspectors also interviewed the inspector associated with the examination performed on the lower reactor vessel head penetration area to fulfill the intent of ASME Code Case N-722-1 and 10 CFR 50.55a. This inspection examines the annulus interface between the penetration and the lower reactor head for evidence of boric acid leakage. Discussions centered on the initial documentation presented to the inspector that documented the examination and any conditions that could mask the penetration annulus areas thereby inhibiting boric acid detection. Additional photographs and documentation presented to the inspector combined with assurances from the level III examiner provided reasonable assurance that the lower head annulus areas were open on all 50 penetrations. Documentation was presented that documented 100 percent coverage was achieved with an unobstructed view of the annulus regions of all 50 penetrations with no evidence of boric acid leakage. Additional discussions and observations were provided on operating experience associated with refuel cavity seal leakage and documentation.

The inspectors also reviewed a sample of evaluations and 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.

b. Findings

No findings were identified.

.4 Steam Generator (SG) Tube Inspection Activities

a. Inspection Scope

The licensee did not perform SG tube inspection activities during this outage. The inspectors reviewed the licensees RFO-18 Degradation Assessment to verify that the licensee met the requirements for maximum operating time without inspection for this refueling maintenance cycle, based on the licensees TSs, NRC commitments, ASME Code Section XI, and Nuclear Energy Institute (NEI) 97-06, Steam Generator Program Guidelines.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of a sample of ISI-related problems that were identified by the licensee and entered into the corrective action program as condition reports (CRs). The inspectors reviewed the 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. The corrective action documents reviewed by the inspectors are listed in the report attachment.

The inspectors also interviewed the ISI program owner to review and discuss the current status of ISI program examinations. A potential discrepancy was noted in the total number of completed examinations at the site as compared to the tables in the information provided to the NRC in preparation for the inspection. An additional discussion also surfaced on reactor vessel support required examinations in accordance with ASME Code Section XI, Table IWB-2500-1 and the use of the exemption provided for by Note

(1) of the table based on compressive normal loading conditions. The licensee performed the ASME Code Section XI, Table IWF-2500-1, VT-3 requirements and applied Note

(1) of IWB-2500-1 to justify not performing the surface examination on the welded attachment portion of the support. The NRC is currently pursuing a formal ASME Code interpretation for this welded area at another licensee facility in order to provide a consistent interpretation of the ASME Code. Since the reactor support inspection was not part of the current refueling outage scope of work, the NRC will address this area following the ASME Code Interpretation and NRC review. The licensee entered this concern into the corrective action program as AR #647849, RPV Support Inclusion in the ISI Program.

Inspectors also identified an abandoned pipe clamp on a service water line inside containment. This condition was entered in to the corrective action process through AR #647857.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review

a. Inspection Scope

On October 14, 2013, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems and training was being conducted in accordance with licensee procedures. The scenario tested the crews ability to respond to a steam generator tube leak, loss of the A emergency bus, and the failure of the turbine to automatically trip.

The inspectors evaluated the following areas:

• Licensed operator performance

• Crews clarity and formality of communications

• Ability to take timely and conservative actions

• Prioritization, interpretation, and verification of annunciator alarms

• Correct use and implementation of abnormal and emergency procedures

• Control board manipulations

• Oversight and direction from supervisors

• Ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements.

The inspectors reviewed the following AR associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #642220, Unsatisfactory NRC Exam Submittal per NUREG-1021

b. Findings

No findings were identified.

.2 Licensed Operator Performance in the Actual Plant/Main Control Room

a. Inspection Scope

On November 8-9, 2013, the inspectors observed operators in the plants main control room (MCR) during a planned reactor shutdown in preparation for RFO-18. Additionally, the inspectors observed operators in the MCR during the reactor startup on December 10, 2013. The inspectors evaluated the following areas:

• Operator compliance and use of plant procedures, including procedure entry and exit, performing procedure steps in the proper sequence, procedure place-keeping, and TS entry and exit;

• Control board/in-plant component manipulations;

• Communications between crew members;

• Use and interpretation of plant instruments, indications, and alarms; diagnosis of plant conditions based on instruments, indications, and alarms;

• Use of human error prevention techniques, such as pre-job briefs and peer checking;

• Documentation of activities, including initials and sign-offs in procedures, control room logs, TS entry and exit, entry into OOS logs; and

• Management and supervision of activities, including risk management and reactivity management.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #643444, A and B Steam Generator Power Operated Relief Valves (PORVs)

Lifted Prior to Setpoint

• AR #645594, Lowering Volume Control Tank Level

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment. The inspectors evaluated degraded performance issues involving the following risk significant components:

• AR #629641, Replace Control Room Heating and Ventilation Temperature Switch due to Faulty Auxiliary Relay

• AR #651425, Loss of 7.5 kVA Inverter The inspectors focused on the following attributes:

• Implementing appropriate work practices;

• Identifying and addressing common cause failures;

• Scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;

• Characterizing system reliability issues for performance;

• Counting unavailability time during performance of maintenance;

• Trending key parameters for condition monitoring;

• Ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

• Verifying appropriate performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2) are appropriate and adequate goals and corrective actions for systems classified as (a)(1).

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #642651, Corrosion on top of Battery

• AR #651350, C Steam Generator PORV Hydraulic Leak

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• Elevated Green risk condition while the A EDG was inoperable for a planned maintenance outage on October 30, 2013;

• Yellow risk condition due to planned reactor shutdown for RFO-18 on November 8, 2013;

• Yellow risk condition due to planned lower inventory conditions while placing the head on the reactor vessel on December 2, 2013;

• Yellow risk condition due to planned plant heat up following refueling outage on December 9, 2013; and

• Yellow risk condition due to plant start-up on December 10, 2013.

These activities were selected based on their potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors selected the following four potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and UFSAR to the licensees evaluations, to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the Attachment.

• AR #634320, Increased Frequency of Filling A EDG Jacket Water System

• AR #653185, OST-1044, A Engineered Safeguard Features Actuation System (ESFAS) Slave Relay Test Quarterly Interval Modes 1 - 4, Unable to be Completed as Scheduled

• AR #633925, B EDG Overspeed Trip Device Difficult to Reset

• AR #636488, C Cold Leg Accumulator Level and Pressure are Slowly Lowering The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #638073, Incorrect Mission Times in Operability Evaluations

• AR #643298, TE-412D, Reactor Coolant System (RCS) A Cold Leg Temperature Element) Response is Approaching Technical Specification Limit

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The following engineering design package was reviewed and selected aspects were discussed with engineering personnel:

• Engineering Change (EC) #94713, Drain Holes for Environmental Qualification (EQ)of Electrical Penetration Enclosures inside Containment This document and related documentation were reviewed for adequacy of the associated 10 CFR 50.59 safety evaluation screening, consideration of design parameters, implementation of the modification, post-modification testing, and relevant procedures, design, and to ensure licensing documents were properly updated. The inspectors observed ongoing and completed work activities to verify that installation was consistent with the design control documents. The purpose of this modification was to install drain holes as required to ensure adequate drainage in the bottom of all the safety and non-safety related EQ electrical penetration enclosures inside containment.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #643178, Rosemount Transmitter in Field with Plastic Shipping Plug

• AR #650321, Safety-Related MOVS with Non-Safety Power/Control Circuitry

• AR #631082, Incorrect Immediate Operability Assessment on MS-58

b. Findings

Introduction:

The inspectors identified a Green NCV of 10 CFR 50.49 for the failure to adequately implement the environmental qualification (EQ) program for electric equipment important to safety. Specifically, between September 2013 and November 2013, multiple EQ program deficiencies were identified including design documentation and the qualification of electric equipment installed in the plant.

Description:

During the period between September 2013 and November 2013, the inspectors identified several examples of electric equipment important to safety for which the EQ program did not adequately implement requirements for humidity and submergence. These examples are outlined below.

The SG PORVs are located in the steam tunnel, which the licensee determined could be subjected to a harsh environment during a design basis accident (DBA). For this reason, the licensee included the SG PORVs in their EQ program. After the licensee reviewed a work request for a disconnected motor lead conduit for the A SG PORV (1MS-58) on September 23, 2013, the inspectors identified that the licensee had not accounted for the EQ status of the motor. As a result of the inspectors questions, the licensee determined the configuration of all three SG PORVs (1MS-58, 1MS-60, and 1MS-62) did not match the EQ tested configuration because they were missing conduit seals. The function of the conduit seals is to prevent humidity intrusion into the junction boxes, potentially causing erratic operation of the motor operators for the valves.

Additionally, the licensee determined that all three SG PORVs were operable but nonconforming because they did not meet the EQ requirement for humidity outlined in 10 CFR 50.49(e)(2). These issues were entered into the CAP as AR #630582, AR #631082 and AR #631497. The motor lead conduit for 1MS-58 was reconnected on October 26, 2013. The nonconforming condition for the SG PORVs is scheduled to be corrected by June 30, 2014.

During an extent of condition review on October 3, 2013, the licensee identified two additional issues affecting the EQ status of two of the SG PORVs. First on 1MS-58, the licensee identified that a piece of red tape was covering a hole on a junction box. Next on 1MS-60, the licensee identified a similar hole on another junction box which remained totally open. The licensee concluded that both of the holes should have been filled by a metal plug to prevent humidity intrusion into the junction box as required by 10 CFR 50.49(e)(2). These issues were entered into the CAP as AR #632974 and AR #632975. The licensee corrected these conditions on October 7, 2013.

On October 8, 2013, the inspectors identified that the auxiliary feedwater (AFW) flow transmitters were not included in the EQ program even though they were located in a harsh environment as determined by the licensees EQ Design Basis Document (DBD-1000-V02). Section 50.49(d) of 10 CFR requires, in part, that the licensee prepare a list of electric equipment important to safety covered by the EQ program. However, by not including these instruments in the EQ program, their EQ status was not maintained.

This issue was entered into the CAP as AR #633822. After further evaluation, the licensee determined that DBD-1000-V02 was inaccurate in that the area of concern was actually not a harsh environment and revised the document. As a result, the licensee determined these instruments were not required to be included in the EQ program.

During a containment walkdown on November 21, 2013, the inspectors identified that the electrical penetration enclosures had pathways to allow water intrusion during a DBA, but did not have a path to allow accumulated water to drain. The inspectors challenged the EQ status of the cables inside the enclosures, based upon the fact that they could be exposed to submergence. The licensee determined that 22 of these electrical penetrations were nonconforming because they did not meet the EQ requirement for submergence outlined in 10 CFR 50.49(e)(6). This issue was entered into the CAP as AR #648426. EC #94713 was completed on the 22 enclosures on December 7, 2013.

Also during this containment walkdown, the inspectors identified RCS flow transmitters which did not have conduit seals and therefore were not consistent with their EQ test configuration. Section 50.49(d) of 10 CFR requires, in part, that the licensee prepare a list of electric equipment important to safety covered by the EQ program. However, even though these instruments were listed in the EQ program, their EQ status was not maintained. This issue was entered into the CAP as AR #648249. The licensees evaluation of this issue concluded that the instruments were not required to be in the EQ program. As a result, the instruments were removed from the EQ program.

The licensee performed a formal self-assessment of the EQ program in October 2012 using AR #505333. The intent of this assessment, in part, was to evaluate the EQ program to ensure performance was technically sound and satisfied the requirements of 10 CFR 50.49. Additionally, in response to the issues identified with the PORVs, the licensee performed a self-assessment of their EQ program under AR #635626 during October 16-31, 2013. These self-assessments identified several recommendations and deficiencies, including instruments that needed to be incorporated into the EQ program.

However, neither of these self-assessments uncovered the issues that the inspectors identified. This represented a missed opportunity for the licensee to identify and correct these deficiencies.

Analysis:

The inspectors determined that the failure to completely implement the EQ program as required by 10 CFR 50.49 was a performance deficiency. Specifically, between September 2013 and November 2013, multiple EQ program deficiencies were identified including design documentation and the qualification of electric equipment installed in the plant. This finding was more than minor because, if left uncorrected, it would have the potential to lead to a more significant safety concern if the functions of other components in the EQ program are challenged. Using IMC 0609, Significance Determination Process, Appendix A, Exhibit 2- Mitigating Systems Screening Questions, the inspectors determined this finding to be of very low safety significance (Green)because it was a deficiency affecting the design or qualification of equipment. The finding had a cross-cutting aspect of Conducts Self-Assessments, as described in the Self and Independent Assessments component of the Problem Identification and Resolution cross-cutting area because the licensee failed to identify these issues during their recent self-assessments. P.3(a)

Enforcement:

Section 50.49(d) of 10 CFR requires, in part, that the licensee establish a program for the environmental qualification of electric equipment important to safety.

10 CFR 50.49(e)(2) and 10 CFR 50.49(e)(6) require that the EQ program must include and be based on humidity and submergence, respectively. Additionally, 10 CFR 50.49(d) requires, in part, that the licensee prepare a list of electric equipment important to safety covered by the EQ program. Contrary to the above, between September 2013 and November 2013, multiple EQ program deficiencies were identified including design documentation and the qualification of electric equipment installed in the plant. Because this finding is of very low safety significance and was entered into the licensees CAP as AR #663071, this violation is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy and designated as NCV 05000400/2013005-01, Failure to Maintain Environmental Qualification for Electric Equipment.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following five post-maintenance test (PMT) activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

Procedure Title Related Maintenance Activity Date OWP- Essential Services Chilled Work Order (WO) #2293632, October 22, 2013 ECW-01 Water Temperature Module Tuning PIC-I407 Refueling Machine WO #2079699, Generic November 13, 2013 (Manipulator) Load Cell Support for Polar, Manipulator and Limiting Circuit and Spent Fuel Crane Calibration OPT-1537 A Emergency WO #13316417, A November 14, 2013 Safeguards Sequencer Sequencer Failed OPT-1537 System Test - Quarterly due to Relay Failure Interval Modes 1-6 OST-1858 Remote Shutdown System Engineering Change (EC) November 16, 2013 Operability #94512, Relocate Contacts on Relay 43T-5/SA OST-1077 Auxiliary Feedwater WO #1832572, Rebuild December 5, 2013 (AFW) Valves Operability Hydramotor Actuator and Test Quarterly Interval Replace Starting Capacitor for Mode 4-5-6 1AF-51, B AFW Regulator These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following: the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing, and test documentation was properly evaluated. The inspectors evaluated the activities against TS and the UFSAR to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #646917, Joy Cable Failure on Reactor Building Manipulator Crane

• AR # 649217, 1AF-51 (B AFW Regulator) and 1AF-49 (A AFW Flow Control Valve to A Steam Generator) Incorrect Hydramotor Installed

• AR #648703, 1AF-51 Failed Stroke Open as PMT

b. Findings

No findings were identified.

1R20 Refueling and Outage Activities

For the outage that began on November 8, 2013, and ended on December 11, 2013, the inspectors evaluated licensee outage activities as described below to verify that licensees considered risk in developing outage schedules, adhered to administrative risk reduction methodologies they developed to control plant configuration, and adhered to operating license and TS requirements that maintained defense-in-depth. The inspectors also verified that the licensee developed mitigation strategies for losses of the following key safety functions:

• Decay heat removal

• Inventory control

• Power availability

• Reactivity control

• Containment integrity Documents reviewed are listed in the Attachment.

.1 Review of Outage Plan

a. Inspection Scope

Prior to the outage, the inspectors reviewed the outage risk control plan to verify that the licensee had performed adequate risk assessments, and had implemented appropriate risk-management strategies when required by 10 CFR 50.65(a)(4).

b. Findings

No findings were identified.

.2 Monitoring of Shutdown Activities

a. Inspection Scope

The inspectors observed portions of the cooldown process to verify that TS cooldown restrictions were followed.

The inspectors reviewed the following AR associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #643444, 1MS-58 and 1MS-60 Lifted before Setpoint

b. Findings

No findings were identified.

.3 Licensee Control of Outage Activities

a. Inspection Scope

During the outage, the inspectors observed the items or activities described below to verify that the licensee maintained defense-in-depth commensurate with the outage risk-control plan for key safety functions and applicable TS when taking equipment OOS.

• Clearance Activities

• Reactor Coolant System Instrumentation

• Electrical Power

• Decay Heat Removal

• Spent Fuel Pool Cooling

• Inventory Control

• Reactivity Control

• Containment Closure The inspectors also reviewed responses to emergent work and unexpected conditions to verify that resulting configuration changes were controlled in accordance with the outage risk control plan, and to verify that control-room operators were kept cognizant of the plant configuration.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #649689, Material Installed in Containment without Receipt Inspection

• AR #649594, Lowering Volume Control Tank Level

b. Findings

No findings were identified.

.4 Reduced-Inventory Conditions

a. Inspection Scope

The inspectors reviewed commitments from Generic Letter 88-17, Loss of Decay Heat Removal, and confirmed by sampling, that those commitments are still in place and adequate. Periodically, during the lower inventory conditions, the inspectors reviewed system lineups to verify that the configuration of the plant systems are in accordance with those commitments. During lower inventory operations, the inspectors observed operator activities to verify that unexpected conditions or emergent activities did not degrade the operators ability to maintain required reactor vessel level.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #644904, Avoidable Delays Encountered while in Lower Inventory

• AR #649801, Delays on Exiting from Lower Inventory

b. Findings

No findings were identified.

.5 Refueling Activities

a. Inspection Scope

The inspectors observed fuel handling operations (removal, inspection, and insertion)and other ongoing activities to verify that those operations and activities were being performed in accordance with technical specifications and approved procedures. Also, the inspectors observed refueling activities to verify that the location of the fuel assemblies, including new fuel, was tracked from core offload through core reload.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #649270, Radial Arm Hoist Contacted Guide Stud during Vessel Head Set

• AR #647352, Outage Delay Due to Joy Cable/Reel Replacement

• AR #648295, Wrong Manipulator Crane Set Point for Core Reload

b. Findings

No findings were identified.

.6 Monitoring of Heatup and Startup Activities

a. Inspection Scope

Prior to mode changes and on a sampling basis, the inspectors reviewed system lineups and/or control board indications 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 configurations. Also, the inspectors periodically reviewed RCS boundary leakage data, and observed the setting of containment integrity to verify that the RCS and containment boundaries were in place and had integrity when necessary. Prior to reactor startup, the inspectors walked down containment to verify that debris had not been left which could affect performance of the containment sumps. The inspectors reviewed reactor physics testing results to verify that core operating limit parameters were consistent with the design.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #650517, A Reactor Coolant System Cold Leg Temperature Element Failed

• AR #650421, Items Found in Containment After Closeout

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 Routine Surveillance Testing

a. Inspection Scope

For the three surveillance tests below, the inspectors observed the surveillance tests and/or reviewed the test results for the following activities to verify the tests met TS surveillance requirements, UFSAR commitments, inservice testing requirements, and licensee procedural requirements. The inspectors assessed the effectiveness of the tests in demonstrating that the SSCs were operationally capable of performing their intended safety functions.

• OST-1116, Administrative Controls to Prevent Dilution During Refueling Monthly Interval Mode 6 on November 11, 2013

• OST-1823, Emergency Diesel Generator Operability 18 Month Interval

• OST-1859, Remote Shutdown System Operability Bus Drops Train B 18 Month Interval

b. Findings

No findings were identified.

.2 In service Testing (IST) Surveillance

a. Inspection Scope

The inspectors reviewed the performance of OST-1011, Auxiliary Feedwater System Operability Test Monthly Interval, on December 17, 2013, to evaluate the effectiveness of the licensees ASME Section XI testing program for determining equipment availability and reliability. This surveillance satisfies the IST requirements for 1AF-49 (Auxiliary Feedwater Flow Control Valve to the A Steam Generator). The inspectors evaluated selected portions of the following areas:

• Testing procedures and methods

• Acceptance criteria

• Compliance with the licensees IST program, TS, selected licensee commitments, and code requirements

• Range and accuracy of test instruments

• Required corrective actions The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #652226, 1AF-49 Dual Indication with the Valve Full Open

• AR #648704, 1AF-49 Failed Stroke Open Time for PMT

b. Findings

No findings were identified.

.3 Containment Isolation Valve Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

• EST-212, Type C Local Leak Rate Test (LLRT), Attachment 3 Penetration M-9 (A

[Reactor Coolant Pump] RCP Seal Injection) LLRT for 1CS-341 (outside containment) and 1CS-344 (inside) on November 13, 2013

• EST-212, Type C Local Leak Rate Test (LLRT), Attachment 44 Penetration M-92 (Service Water Supply to Containment Fan Coil AH-37, AH-38, and AH-39) LLRT for 1SW-231 (outside) and 1SW-233 (inside) on November 13, 2013.

The inspectors observed in-plant activities and reviewed procedures and associated records to determine whether: any preconditioning occurred; effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing; acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis; plant equipment calibration was correct, accurate, and properly documented; as left setpoints were within required ranges; and the calibration frequency were in accordance with TS, the UFSAR, procedures, and applicable commitments; measuring and test equipment calibration was current; test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied; test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used; test data and results were accurate, within limits, and valid; test equipment was removed after testing; where applicable, test results not meeting acceptance criteria were addressed or the system or component was declared inoperable; where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure; equipment was returned to a position or status required to support the performance of its safety functions; and all problems identified during the testing were appropriately documented and dispositioned in the CAP.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #644875, Potential for Clogged Service Water Drains to Affect LLRT

• AR #647788, 1CS-344 Failed LLRT

• AR #644875, Potential for Clogged Drains Affecting LLRT Test Boundaries

• AR #649335, M-9, 1CS-344, Failed LLRT due to Excessive Leakage

• AR #651009, RFO-18 LLRT Total Leak Rate is Satisfactory but Elevated

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

Hazard Assessment and Instructions to Workers: During facility tours, the inspectors directly observed labeling of radioactive material and postings for radiation areas, High Radiation Areas (HRAs), and Locked High Radiation Areas (LHRAs) established within the Radiologically Controlled Area (RCA) of the auxiliary building, reactor containment building, and radioactive waste (radwaste) processing and storage locations. The inspectors independently measured radiation dose rates or directly observed conduct of licensee radiation surveys for selected RCA areas. The inspectors reviewed survey records for several plant areas, including pre-job surveys for refueling outage tasks. The inspectors also discussed changes to plant operations that could contribute to changing radiological conditions since the last inspection. The inspectors attended HRA briefings and reviewed Radiation Work Permit (RWP) details for selected jobs to assess communication of radiological control requirements and current radiological conditions to workers.

Hazard Control and Work Practices: The inspectors evaluated access barrier effectiveness for selected LHRA locations. Changes to procedural guidance for LHRA and Very High Radiation Area controls were discussed with Health Physics (HP)supervisors. Controls and their implementation for storage of irradiated material within the spent fuel pool were reviewed and discussed. Established radiological controls (including airborne controls) were evaluated for selected refueling outage tasks, including reactor head inspection/repair and installation/removal of reactor internals. In addition, licensee controls for areas where dose rates could change significantly as a result of plant shutdown and refueling operations were reviewed and discussed.

Occupational workers adherence to selected RWPs and HP technician proficiency in providing job coverage were evaluated through direct observations and interviews with licensee staff. Electronic dosimeter (ED) alarm set points and worker stay times were evaluated against area radiation survey results for selected work activities. The use of personnel dosimetry in high dose rate gradients was reviewed and discussed. Worker response to dose and dose rate alarms during selected work activities was also evaluated.

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. The inspectors discussed equipment sensitivity, alarm setpoints, and release program guidance with licensee staff.

The inspectors also reviewed records of leak tests on selected sealed sources and discussed nationally tracked source transactions with licensee staff.

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

Radiation protection activities were evaluated against the guidance and requirements of UFSAR Section 12; Technical Specifications Section 6; 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 report Attachment.

b. Findings

No findings were identified.

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

Transportation

a. Inspection Scope

Waste Processing and Characterization: During inspector walk-downs, accessible sections of the liquid and solid radwaste processing systems were assessed for material condition and conformance with system design diagrams. Inspected equipment included radwaste storage tanks, resin transfer piping, resin and filter packaging components, and abandoned reverse osmosis equipment. The inspectors discussed component function, processing system changes, and radwaste program implementation with licensee staff.

The 2012 Radioactive Effluent Report and radionuclide characterizations from 2011-2013 for each major waste stream were reviewed and discussed with radwaste staff. For primary resin 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 mixing and concentrations averaging methodology for resin and filter waste streams were evaluated and discussed with radwaste staff. The inspectors also reviewed the licensees procedural guidance for monitoring changes in waste stream isotopic mixtures.

Radioactive Material Storage: During walk-downs of indoor and outdoor radioactive material 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.

Transportation: The inspectors directly observed preparation activities for a shipment of contaminated trash. The inspectors noted package markings, observed dose rate measurements, and interviewed shipping technicians regarding Department of Transportation (DOT) regulations. 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, and radiation survey results. Licensee procedures for opening and closing Type B shipping casks were compared to Certificate of Compliance requirements.

Problem Identification and Resolution: The inspectors reviewed NCRs in the areas of shipping and radwaste processing. The inspectors evaluated the licensees ability to identify and resolve the identified issues. The inspectors also reviewed recent self-assessment results.

Radwaste processing, radioactive material handling, and transportation activities were reviewed against the requirements contained in the licensees Process Control Program, UFSAR Chapter 11, 10 CFR Part 20, 10 CFR Part 61, 10 CFR Part 71, and 49 CFR Parts 172-178. Licensee activities were also evaluated against guidance provided in the Branch Technical Position on Waste Classification (1983) and NUREG-1608.

Documents are listed in the Attachment.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The NSIR headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures and the Emergency Plan located under ADAMS accession numbers ML13023A239, ML13161A205, ML123630578, ML13280A344, ML13346A310, and ML13137A322, as listed in the Attachment.

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

b. Findings

No findings were identified.

1EP6 Emergency Planning Drill Evaluation

a. Inspection Scope

The inspectors observed an emergency preparedness (EP) drill conducted on December 18, 2013, to verify licensee self-assessment of classification and notifications in accordance with 10 CFR Part 50, Appendix E. The drill was conducted in two parts each starting with a train derailment near the site that resulted in a chlorine release. The first drill then tested the licensees ability to manage a vehicle crashing into the switchyard, and the second drill, a hostile action at the owner controlled area.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #652716, EP Drill 13-12, Toxic Atmosphere Emergency Action Level Declaration

• AR #652710, EP Drill 13-12, State and County Communications

• AR #652470, EP Drill 13-12, ERFIS Met Data Not Tracking in Emergency Operations Facility

• AR #652463, EP Drill 13-12, Incorrect Fax Numbers in PEP-270, Attachment 19

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

To verify the accuracy of the PI data reported to the NRC, the inspectors compared the licensees basis in reporting each data element to the PI definitions and guidance contained in NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline.

Mitigating Systems Cornerstone

• Mitigating Systems Performance Index (MSPI), Residual Heat Removal

• MSPI, Cooling Water Systems The inspectors sampled licensee submittals for the MSPI performance indicators listed above for the period from the fourth quarter 2012 through the third quarter 2013. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection reports for the period to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the

.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #580104, Electric Unit Heater Thermostats Set Greater than Required

• AR #581044, A ESW Pump Seal Water Indicates Low Causing Control Board Alarm

• AR #618756, A ESW Pump High Winding Temp Alarm in MCR

• AR #582477, Pressure Rise in A RHR during Testing

• AR #595147, 1SI-311 (B Train Sump Isolation Valve) High Maximum Final Closing Thrust

• AR #599763, B RHR Seal Cooler Needed to be Adjusted During Testing

• AR #577166, 1CC-147 (A RHR Heat Exchanger Throttle Valve) Test Results did not meet Acceptance Criteria

• AR #617345, 1CC-147 has too much Grease and has an Oil Leak

• AR #602921, B CCW Pump has Oil Leak on Inboard Bearing Housing

• AR #617350, A CCW Pump is Cavitating Occupational Radiation Safety Cornerstone The inspectors reviewed the Occupational Exposure Control Effectiveness PI results for the Occupational Radiation Safety Cornerstone from June 2012 through October 2013.

For the assessment period, the inspectors reviewed ED alarm logs and selected NCRs 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 Attachment.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Review of Items Entered Into the Corrective Action Program

a. Inspection Scope

To aid in the identification of repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed frequent screenings of items entered into the licensees CAP. The review was accomplished by reviewing daily action request reports.

b. Findings

No findings were identified.

.2 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.1 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the six month period of July 1, 2013, through December 31, 2013, although some examples expanded beyond those dates where the scope of the trend warranted. Additionally, the inspectors reviewed the adverse trend that was identified in Inspection Report 05000400/2012005. This trend was associated with inadequate determinations of operability and was entered into CAP as AR #584473.

The inspectors continue to monitor the progress that the licensee has made toward closing this adverse trend.

This review also included issues documented outside the normal CAP in the major equipment problem lists, repetitive and/or reworks maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #605326 Inadequate Causal Analysis involving operability determinations

• AR #613675 NRC NCV with crosscutting aspect P.1(d)

b. Findings

No findings were identified.

.3 Selected Issue Follow-up Inspection: High Oxygen Concentration in the C Waste Gas

Decay Tank

a. Inspection Scope

The inspectors selected AR #647917, High Oxygen Concentration in the C Waste Gas Decay Tank (WGDT), for detailed review. The inspectors reviewed this report to verify that the licensee identified the full extent of the issue, performed an appropriate evaluation, and specified and prioritized appropriate corrective actions. The inspectors evaluated the report against the requirements of the licensees CAP as delineated in corporate procedure CAP-NGGC-0200, Condition Identification and Screening Process, and 10 CFR Part 50, Appendix B.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #647120, Operating Procedure 120, Precaution and Limitation not Referenced by OST-2044 (Radwaste Daily Operations Surveillance Test Modes at all times)

• AR #647129, WGDT Sample Results not in Chemistry Data Management System

• AR #651188, Waste Gas Issues

• AR #650407, OARC-1119B (Oxygen Analyzer) not Indicating Properly, Repels High

b. Findings

(Opened) Unresolved item (URI): Operation of the Waste Gas System with Oxygen Concentrations Greater than the Technical Specification Limits.

Introduction.

The inspectors identified an URI associated with procedural noncompliance related to TS, while operating the Waste Gas System on November 11, 2013. This item is unresolved pending review and evaluation of the licensees root cause evaluation to determine if a performance deficiency exists.

Description:

On November 11, 2013, the licensee was performing a degassing evolution to the waste gas system while the oxygen and hydrogen analyzers were inoperable and the hydrogen recombiner was not functional. The inspectors identified that the licensees procedures and compensatory measures for degassing without all equipment in service may have been inadequate to properly control the oxygen concentration in the waste gas system. The inspectors are awaiting the completion of the licensees root cause evaluation to determine the licensees compliance with applicable procedures and TS 3.11.2.5, which limits oxygen concentration in the waste gas system.

Additional inspection activities are needed to determine the extent of condition, relative to procedural and TS compliance during operation of the waste gas system. Pending the results of this additional inspection, an URI will be opened and designated as URI 05000400/2013005-02, Potential Performance Deficiency Associated with Oxygen Concentration in the Waste Gas System.

.4 Selected Issue Follow-up Inspection: Inadequate Transformer Preventive Maintenance

a. Inspection Scope

The inspectors selected AR #621738, 1E2 Transformer Failure for detailed review. The inspectors reviewed this report to verify that the licensee identified the full extent of the issue, performed an appropriate evaluation, and specified and prioritized appropriate corrective actions. The inspectors evaluated the report against the requirements of the licensees CAP as delineated in corporate procedure CAP-NGGC-0200, Condition Identification and Screening Process, and 10 CFR Part 50, Appendix B.

b. Findings

Introduction:

A self-revealing Green finding was identified for the licensees failure to adequately establish and implement procedure NGG-PMB-XFM-02, Equipment Reliability Template for Dry-Type Transformers, and implementing procedure PM-E0015, 480 V and 6.9 kV Transformer Electrical and Preventive Maintenance (PM)

Check, when the 1E2 transformer failed on August 8, 2013. Specifically, procedure PM-E0015 did not contain steps to identify degradation in the 1E2 transformer windings prior to failure.

Description:

On August 8, 2013, the 1E2 480VAC/6.9kVAC transformer failed while it was energized providing power to nonsafety-related electrical loads. The failure caused a loss of the moisture separator reheaters which resulted in decreased efficiency. This caused reactor power to increase greater than RTP for a short time, before operators stabilized the plant at 92.5 percent RTP. This failure caused the licensee to declare an Alert, which was discussed in NRC inspection report 05000400/2013004. The licensee entered these issues into the CAP as AR #621738.

The failure mechanism of the transformer was determined to be a turn-to-turn short on the primary windings of the A phase. Further analysis of the transformer was inconclusive in identifying the cause of the turn-to-turn short. However, the licensee determined that the testing prescribed by procedure NGG-PMB-XFM-02 and performed under procedure PM-E0015 was inadequate to identify degradation in the windings prior to failure.

The licensee previously evaluated the adequacy of the transformer PM program in March 2012, using AR #503605. Specifically, this evaluation determined that power factor testing did not need to be performed as part of the PM program. However, the licensee has since determined that power factor testing might have indicated that the transformer windings had experienced insulation degradation prior to the failure of the 1E2 transformer.

Analysis:

The inspectors determined that inadequate testing prescribed by NGG-PMB-XFM-02 and performed under procedure PM-E0015 was a performance deficiency.

Specifically, licensee procedure ADM-NGGC-0107, Equipment Reliability Process Guideline, resulted in the determination that the 1E2 transformer was a critical component. Licensee procedure NGG-PMB-XFM-02, states that critical components are maintained to not allow any failure that would result in a trip, transient, or significant challenge to continued safe operation. However, implementing procedure PM-E0015, failed to contain steps to identify the degradation in the 1E2 transformer windings prior to failure. This finding was more than minor because it was associated with the Initiating Events cornerstone attribute of Procedure Quality, and adversely affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operation. Specifically, a reactor power transient resulted from the 1E2 failure. Using IMC 0609, Significance Determination Process, Appendix A, Exhibit 1- Initiating Events Screening Questions, the inspectors determined this finding to be of very low safety significance (Green)because the finding did not cause a reactor trip and the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss of feedwater). The finding had a cross-cutting aspect of Long Term Safety, as described in the Resources component of the Human Performance cross-cutting area because the licensees evaluation of the transformer PM program in March 2012 removed additional testing which might have indicated that the transformer windings had experienced insulation degradation. H.2(a)

Enforcement:

This issue does not involve enforcement action because no regulatory requirement was identified for the testing performed on this nonsafety-related transformer. As corrective action, the licensee replaced the transformer and plans to revise procedure PM-E0015 to incorporate additional testing to aid in the identification of winding degradation prior to transformer failure. The licensee entered these issues into the CAP as AR #621738. Because this performance deficiency does not involve a violation of regulatory requirements and has very low safety significance, it is identified as finding: FIN 05000400/2013005-03, Inadequate Transformer Preventive Maintenance Procedure.

4OA3 Follow-up of Events

.1 (Closed) Licensee Event Report (LER) 05000400/2013-001-00, Reactor Pressure

Vessel Head Penetration Nozzle Indications Attributed to Primary Water Stress Corrosion Cracking On May 15, 2013, while in Mode 1 and at 98 percent RTP, the licensee identified a flaw in Nozzle 49 of the Reactor Pressure Vessel Head. In 2012, four nozzles were identified with similar indications during RFO- 17 and repaired. Nozzle 49 was not identified as having an issue at that time. Because Nozzle 49 was identified while the unit was at power, Technical Specification 3.4.6.2 (Reactor Coolant System Pressure Boundary)required a shutdown unit.

The licensee submitted LER 05000400/2013-001-00 on May 15, 2013, for this issue. An NRC Severity Level IV violation associated with this issue is documented in NRC Special Inspection Report 05000400/2013010. This LER is closed.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

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

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

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

b. Findings

No findings were identified.

.2 (Closed) URI 05000400/2013003-02 Review the Significance of Environmental Air

Samplers Collecting Diluted Airborne Particulate Samples

a. Inspection Scope

In Inspection Report 05000400/2013003, the inspectors identified an URI regarding environmental air samplers that might have been collecting particulate samples that were not representative of actual airborne radionuclide concentrations. During an observation of environmental sample collection, the inspectors noted that three of the nine environmental air samplers (locations 63, 90, and 91) contained a housing fan that appeared to blow exhaust air directly onto the inlet of the particulate/iodine sampling head. The inspectors also noted that the interior walls of the air sampler housing contained a fibrous insulation media that appeared to act as a mechanical filter due to the particulate loading stains readily visible. Since the housing fan drew air from the interior of the enclosure, and blew the exhaust directly onto the air sampler intake, the potential existed for the air sampler to collect a non-representative (diluted) sample.

Immediate licensee corrective actions included removal of the insulation media, movement of the air sample intakes to the other side of the enclosures, and communication with the air sampler equipment vendor.

The inspectors reviewed a joint vendor-licensee evaluation of the significance of this air sampling arrangement. Two studies were performed as a part of the evaluation; first, an evaluation of the potential for recirculation of particulates from inside the housing back through the intake; and second, a comparison of Berylium-7 and gross beta concentrations at locations 63, 90, and 91 with other air sampling locations that do not contain the insulation media. Berylium-7 is a naturally occurring radioactive airborne particulate that is easily detectable, and gross beta is an indicator of the total particulate radioactivity present in the atmosphere. Using a colored tracer gas, the first study indicated that very small amounts of airborne particulate originating inside the enclosure are recirculated back into the air sampler intake. This was shown by a slight discoloration of the air sample filter. The second study showed no discernible difference between airborne concentrations of Berylium-7 obtained at locations with the insulation media and those without. The gross beta evaluation had similar results. This indicates that the insulation media does not constitute a filtration mechanism of the outside air.

The inspectors determined that although recirculation of the air inside the enclosure back onto the air sample intake was a measurable phenomenon, the insulation media was not acting as a filter for the outside air as suspected during the initial inspection.

Therefore air samples collected in this manner were still representative of atmospheric concentrations even though a small amount of recirculation existed.

b. Findings

No findings were identified.

.3 (Closed) URI 05000400/2013002-04: No. 1 Reactor Coolant Pump Seal Leakoff Line

Over-Pressurization

a. Inspection Scope

During the 2013 baseline inspection per Inspection Procedure 71111.17, Evaluations of Changes, Tests, and Experiments and Permanent Plant Modifications, the team identified an URI associated with the licensees capability to meet their station blackout (SBO) mitigation strategy as a result of concerns identified in the 1992 Westinghouse Technical Bulletin, NSD-TB-1-07-R1, Over-Pressurization of RCP No.1 Seal Leak-off Line. The bulletin indicated the potential over-pressurization of the No.1 seal leakoff line during high seal leakoff flow conditions resulting from abnormal performance of the No.1 RCP seal. High flow conditions could result from a failure of the No. 1 RCP seal and a loss of seal cooling (LOSC) event. Although the licensee implemented operation and maintenance recommendations contained in the bulletin, which minimized the likelihood of seal failures during normal operations, the licensee did not identify that, under LOSC events, the line would be exposed to pressure and temperature conditions above its design rating. The integrity of the leakoff line is important during LOSC events because a flow measuring restriction orifice in the line creates high resistance to flow and results in backpressure on the No.1 RCP seal, which is credited to limit seal leakage to 21 gpm. Leakage past the RCP seals during LOSC events is an input to the RCS inventory analyses, which demonstrates the ability to ensure the core is cooled throughout the event. This issue was unresolved pending further inspection to determine if the licensees performance constituted a violation of NRC regulatory requirements.

The licensee performed engineering analyses to determine the worst case temperature and pressure conditions to which the seal leakoff line would be exposed during LOSC events. The licensee used the worst case temperature and pressure conditions to evaluate the structural capability of the seal leakoff piping through the orifice. The licensees evaluation determined that the structural integrity of the piping would be maintained and capable of supporting RCP seal backpressure during LOSC events.

The team performed an in-office review of the additional information and determined they were adequate.

b. Findings

The inspectors identified a minor performance deficiency for the licensees failure to follow NRC Regulatory Guide 1.155, Station Blackout, guidance (to which they are committed in the UFSAR) for evaluating the plants capability to withstand and recover from an SBO of the acceptable duration determined by the plant. In accordance with IMC 0612, Power Reactor Inspection Reports, dated January 24, 2013, minor performance deficiencies are not routinely documented in inspections reports; however, they may be documented to capture inspection activities and conclusions for closing a URI.

The inspectors determined that the licensees failure to evaluate the No. 1 RCP seal leakoff line capability to provide the RCP seal backpressure, which was required to support RCS inventory assumptions, to ensure the plants capability to withstand and recover from an SBO was a performance deficiency. Using IMC 0612 Appendix B, Issue Screening, dated September 7, 2012, the team determined this performance deficiency to be of minor significance because the licensees structural evaluation of the leakoff line concluded that integrity of the piping would be maintained; hence, the performance deficiency did not adversely affect the plants capability withstand and recover from an SBO. Because this issue was entered into the licensees corrective action program, as Condition Report 663072, and was of minor significance, the failure to follow NRC Regulatory Guide 1.155, Station Blackout, guidance constitutes a minor performance deficiency that is not subject to enforcement action in accordance with NRCs Enforcement Policy. This URI is now closed.

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 30, 2014, the inspector presented the inspection results to Mr. Kapopoulos, and other members of the licensee staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

On January 14, 2014, the Engineering Modifications inspection team presented the inspection results to Mr. Kapopoulos and other members of the licensees staff. The team verified that no proprietary information was retained by the inspectors or documented in this report.

On November 22, 2013, the Engineering ISI and Health Physics inspectors conducted an exit meeting with Mr. Kapopoulos and his staff. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

D. Corlett, Supervisor, Licensing/Regulatory Programs

J. Dufner, Plant Manager

D. Griffith, Training Manager

L. Hughes, Superintendent, Environmental and Chemistry

E. Kapopoulos, Vice President Harris Plant

C. Kidd, Manager, Nuclear Oversight

D. Martano, Supervisor, Engineering Programs

S. OConnor, Director, Engineering

M. Parker, Superintendent, Radiation Control

T. Slake, Manager, Security

A. Staller, Manager, ISI Program (From Al Butcavage)

M. Wallace, Senior Specialist Regulatory Affairs

J. Warner, Manager, Outage and Scheduling

S. Williams, Boric Acid Program Contact

S. Volk, Project Manager

F. Womack, Manager, Operations

NRC personnel

G. Hopper, Chief, Reactor Projects Branch 4, Division of Reactor Projects, Region II

K. Manoly, Senior Level Advisor for Structural Mechanics, NRR

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000400/2013005-01 NCV Failure to Maintain Environmental Qualification for Electric Equipment (Section 1R18)

05000400/2013005-03 FIN Inadequate Transformer Preventive Maintenance Procedure (Section 4OA2.4)

Opened

05000400/2013005-02 URI Potential Performance Deficiency Associated with Oxygen Concentration in the Waste Gas System (Section 4OA2.3)

Closed

05000400/2013-001-00 LER Reactor Pressure Vessel Head Penetration Nozzle Indications Attributed to Primary Water Stress Corrosion Cracking (Section 4OA3)

05000400/2013003-02 URI Evaluate the Effects of Environmental Air Samplers Collecting Diluted Airborne Particulate Samples (Section 4OA5)

05000400/2013002-04 URI No. 1 Reactor Coolant Pump Seal Leakoff Line Over-

Pressurization (Section 4OA5)