IR 05000338/2014004

IR 05000338/2014004, 05000339/2014004; on 07/01/2014 - 09/30/2014; North Anna Power Station, Maintenance Effectiveness

ML14316A338
Person / Time
Site:	North Anna
Issue date:	11/10/2014
From:	Mark King NRC/RGN-II/DRP/RPB5
To:	Heacock D Virginia Electric & Power Co (VEPCO)
References
IR 2014004
Download: ML14316A338 (57)

Text

UNITED STATES ember 10, 2014

SUBJECT:

NORTH ANNA POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000338/2014004 and 05000339/2014004

Dear Mr. Heacock:

On September 30, 2014, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your North Anna Power Station Units 1 and 2. The results of this inspection were discussed on October 27, 2014, with Mr. F. Mladen, and on November 10, 2014, with Mr. P.

Kemp, and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented one self-revealing finding of very low safety significance (Green) in this report which was determined to involve a violation of NRC requirements. The NRC is treating this finding as a non-cited violation (NCV) consistent with Section 2.3.2 of the NRC Enforcement Policy. Additionally, a licensee-identified violation which was determined to be of very low safety significance is listed in this report.

If you contest this non-cited violation, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the North Anna Power Station.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at the North Anna Power Station. In accordance with Title 10 Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its Enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRC's Agencywide Documents Access and Management System (ADAMS).

ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Michael F. King, Chief Reactor Projects Branch 5 Division of Reactor Projects Docket Nos.: 05000338, 05000339 License Nos.: NPF-4, NPF-7

Enclosure:

IR 05000338/2014004 and 05000339/2014004 w/Attachment: Supplementary Information

REGION II==

Docket Nos: 50-338, 50-339 License Nos: NPF-4, NPF-7 Report No: 05000338/2014004, and 05000339/2014004 Licensee: Virginia Electric and Power Company (VEPCO)

Facility: North Anna Power Station, Units 1 & 2 Location: Mineral, Virginia 23117 Dates: July 1, 2014 through September 30, 2014 Inspectors: G.Kolcum, Senior Resident Inspector S. Herrick, Acting Resident Inspector R. Carrion, Senior Reactor Inspector, Sections 1R07, 1R08 P. Cooper, Reactor Inspector, Section 1R08 R. Hamilton, Senior Health Physicist, Sections 2RS4, 2RS5, 4OA1 W. Pursley, Health Physicist, Sections 2RS1, 4OA1 R. Kellner, Health Physicist, Sections 2RS2, 2RS3 Approved by: Michael F. King, Chief Reactor Projects Branch 5 Division of Reactor Projects Enclosure

SUMMARY

IR 05000338/2014-004, 05000339/2014-004; 07/01/2014 - 09/30/2014; North Anna Power

Station. Maintenance Effectiveness.

The report covered a three-month period of inspection by resident inspectors and reactor inspectors from the region. One self-revealing finding was identified and was determined to be a non-cited violation (NCV). The significance of most findings is indicated by their color (Green,

White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5, dated February 2014.

Cornerstone: Barrier Integrity

Green.

A self-revealing NCV of 10 CFR 50 Appendix B, Criterion V, Instructions,

Procedures, and Drawings, was identified for a failure to prescribe maintenance procedures affecting the quality of fan 1-HV-AC-7 appropriate to the circumstances. Specifically, the licensee failed to incorporate vendor guidance for taking bearing clearance measurements into maintenance procedure 0-MCM-0508-01 Repair Buffalo Forge Centrifugal Fans as required by administrative procedure VPAP-0502. This issue was entered in the licensees corrective action program (CAP) as condition report (CR) 552780.

This finding was determined to be more than minor because it affects the reactor safety barrier integrity cornerstone attribute of control room barrier, and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that are required for the habitability of the control room. Specifically, the finding impacted the availability of 1-HV-AC-7, which affects the availability of the MCR/emergency switchgear room (ESGR) air conditioning system (ACS). The finding was determined to be associated with the barrier integrity cornerstone based on the NRC IMC 0609, Significance Determination Process (SDP), dated June 2, 2011, Attachment 4, Initial Characterization of Findings, dated June 19, 2012. The inspectors performed a Phase 1 analysis using the IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012 and determined that the finding was of very low significance (Green) because the finding did not represent a degradation of the barrier function of the control room against radiation protection, smoke or a toxic atmosphere. The redundant subsystem was able to provide cooling to the MCR/ESGR envelope and it was within the 30-day Technical Specification 3.7.11 LCO. The inspectors determined that this finding had a cross-cutting aspect in the area of human performance, design margins component, because the licensee failed to operate and maintain equipment within design margins where margins are carefully guarded and changed only through a systematic and rigorous process.

Specifically, the licensee failed to recognize that the bearing clearance measurement identified in VTM 59-B878-00001 and the SKF Bearing Maintenance Handbook was a critical design parameter. [H.6]

A violation of very low safety significance, which was identified by the licensee, was reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. This violation and its respective corrective actions are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the period at full Rated Thermal Power (RTP) and operated at full power for the entire report period.

Unit 2 began the period at full RTP. Unit 2 commenced ramp down and was off line on September 7, 2014 for the planned fall refueling outage. Unit 2 remained off line for the rest of the report period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

.1 Partial Walkdowns

a. Inspection Scope

The inspectors conducted three equipment alignment partial walkdowns, listed below, to evaluate the operability of selected redundant trains or backup systems with the other train or system inoperable or out of service. The inspectors reviewed the functional systems descriptions, Updated Final Safety Analysis Report (UFSAR), system operating procedures, and Technical Specifications (TS) to determine correct system lineups for the current plant conditions. The inspectors performed walkdowns of the systems to verify the operability of a redundant or backup system/train or a remaining operable system/train with a high risk significance for the current plant configuration (considering out-of-service, inoperable, or degraded condition); or a risk-significant system/train that was recently realigned following an extended system outage, maintenance, modification, or testing; or a risk-significant single-train system. The inspector conducted the reviews to ensure that critical components were properly aligned, and to identify any discrepancies which could affect operability of the redundant train or backup system.

• Unit 2 Casing Cooling system to check system readiness after the periodic test on the Unit 2 B Casing Cooling pump

• Unit 1 Safety Injection system after periodic test of A Safety Injection pump

• Unit 2 Safety Injection system, prior to periodic testing on B Safety Injection pump

b. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

The inspectors performed a detailed walkdown and inspection of the Unit 2 Auxiliary Feedwater (AFW) System to assess proper alignment and to identify discrepancies that could impact its availability and functional capacity, after maintenance on the Turbine-Driven AFW and the Motor-Driven AFW. The inspectors assessed the physical condition and position of the valves, whether manual, power operated, or automatic, to ensure correct positioning. The inspection also included a review of the alignment and the condition of support systems including fire protection, room ventilation, and emergency lighting. Equipment deficiency tags were reviewed and the condition of the system was discussed with the engineering personnel. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Quarterly Fire Protection Walkdowns

a. Inspection Scope

The inspectors conducted focused tours of the seven areas listed below that are important to reactor safety to verify the licensees implementation of fire protection requirements as described in fleet procedures CM-AA-FPA-100, Fire Protection/Appendix R (Fire Safe Shutdown) Program, Revision 9, CM-AA-FPA-101, Control of Combustible and Flammable Materials, Revision 6, and CM-AA-FPA-102, Fire Protection and Fire Safe Shutdown Review and Preparation Process and Design Change Process, Revision 5. The inspectors evaluated, as appropriate, conditions related to:

(1) licensee control of transient combustibles and ignition sources;

(2) the material condition, operational status, and operational lineup of fire protection systems, equipment, and features; and,

(3) the fire barriers used to prevent fire damage or fire propagation. Documents reviewed are listed in the Attachment.

• Unit 1 and Unit 2 Charging Pump Cubicles

• Unit 1 Quench Spray Pump House and Safeguards Area

• Unit 2 Quench Spray Pump House and Safeguards Area

• Fuel Building

• Unit 2 Cable Vault and Tunnel

• Main Control Room

• Service Water Pump House, Auxiliary Service Water Pump House, Motor-Driven Fire Pump Building, and Service Water Valve House

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation

a. Inspection Scope

During a fire protection drill on August 13, 2014, at the emergency switch gear room, the inspectors assessed the timeliness of the fire brigade in arriving at the scene, the fire fighting equipment brought to the scene, the donning of fire protection clothing, the effectiveness of communications, and the exercise of command and control by the scene leader. The inspectors also assessed the acceptance criteria for the drill objectives and reviewed the licensees corrective action program for recent fire protection issues. The condition reports (CRs) issued for drill critique items are listed in the Attachment.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Internal Flooding

a. Inspection Scope

The inspectors assessed the internal flooding vulnerability of the two areas listed below with respect to adjacent safety-related areas to verify that the flood protection barriers and equipment were being maintained consistent with the UFSAR. The licensees corrective action documents were reviewed to verify that corrective actions with respect to flood-related items identified in condition reports were adequately addressed. The inspectors conducted a field survey of the selected areas to evaluate the adequacy of flood barriers and floor drains to protect the equipment, as well as their overall material condition. Issues raised during this assessment are documented in the licensees corrective action program (CAP). Documents reviewed are listed in the Attachment.

• 1J Emergency Diesel Generator (EDG) room floor sumps

• Mechanical equipment room #1

b. Findings

No findings were identified.

1R07 Heat Sink Performance

.1 System Heat Exchangers

a. Inspection Scope

The inspectors selected the two risk significant heat exchangers (HX) listed below and reviewed inspection records, test results, maintenance work orders, and other documentation to ensure that deficiencies which could mask or degrade performance were identified and corrected. The test procedures and records were also reviewed to verify that they were consistent with Generic Letter 89-13 licensee commitments, and Electric Power Research Institute Heat Exchanger Performance Monitoring Guidelines.

In addition, the inspectors reviewed inspection documentation of the related service water piping to assess general material condition and to identify any degraded conditions. Documents reviewed are listed in the Attachment.

• A Component Cooling HX

• B Fuel Pool Cooling HX

b. Findings

No findings were identified.

.2 Triennial Review of Heat Sink Performance (IP 71111.07T)

a. Inspection Scope

The inspectors selected the Unit 1 A Component Cooling HX, the Unit 1 B Recirc Spray HX, and the Unit 2 C Control Room Chiller based on their risk-significance in the licensees probabilistic safety analysis, and their importance to safety-related mitigating system support functions.

For the three HXs, the inspectors reviewed the licensees inspection, maintenance, and monitoring of biotic fouling and macrofouling programs to ensure that they were adequate. The inspectors also reviewed the licensees inspection and cleaning activities to determine if they had established acceptance criteria consistent with industry standards and the as-found results were recorded, evaluated, and appropriately dispositioned to maintain structural integrity.

The inspectors reviewed the condition and operation of the Unit 1 A Component Cooling, the Unit 1 B Recirc Spray HX, and the Unit 2 C Control Room Chiller to ensure they were consistent with design assumptions in heat transfer calculations, as described in the final safety analysis report. This included determining whether the number of plugged tubes was within pre-established limits based on capacity and heat transfer assumptions for the Unit 1 A Component Cooling HX, and the Unit 2 C Control Room Chiller. (The inspector noted that there had been no eddy current testing of the Unit 1 B Recirc Spray HX, because it is kept in dry layup. However, it is scheduled for eddy current testing in 2015.) The inspectors also determined that the licensee had established adequate controls and operational limits to prevent heat exchanger degradation due to excessive flow induced vibration during operation.

The inspectors determined whether the performance of ultimate heat sinks (UHS), and their subcomponents such as piping, intake screens, pumps, valves, etc., was appropriately evaluated by tests or other equivalent methods, to ensure availability and accessibility to the in-plant cooling water systems.

The inspectors determined whether the licensees inspection of the UHS was thorough and of sufficient depth to identify degradation of the shoreline protection, or loss of structural integrity. This included determination of whether vegetation present along the slopes was trimmed, maintained, and not adversely impacting the embankment. In addition, the inspectors determined whether the licensee ensured sufficient reservoir capacity by trending and removing debris in the UHS.

The inspectors reviewed the licensees inspection of the UHS to determine if it was comprehensive and of significant depth to ensure sufficient reservoir capacity. This included the review of licensees periodic monitoring and trending of sediment buildup and heat transfer capability. In addition, the inspectors reviewed licensees periodic performance monitoring of the UHS structural integrity, to determine whether adjacent non-seismic or non-safety-related structures could degrade, or block safety-related flow paths, during a severe weather or seismic event. The inspectors also performed walkdowns of accessible portions of the UHS supply and return piping to look for possible settlement, or movement and piping conditions that would indicate loss of structural integrity.

The inspectors performed a system walkdown of the service water intake structure to determine whether the licensees assessment on structural integrity and component functionality was adequate. In addition, the inspectors determined whether service water pump bay silt accumulation was monitored, trended, and maintained at an acceptable level by the licensee, and that water level instruments were functional and routinely monitored. The inspectors also determined whether the licensees ability to ensure functionality during adverse weather conditions was adequate.

The inspectors reviewed condition reports related to the HXs/coolers and heat sink performance issues to determine whether the licensee had an appropriate threshold for identifying issues, and to evaluate the effectiveness of the corrective actions.

These inspection activities constituted four heat sink inspection samples as defined in IP 71111.07-05.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities (Inspection Procedure 71111.08P, Unit 2)

a. Inspection Scope

Non-Destructive Examination Activities and Welding Activities: From September 15 - 19, 2014, the inspectors conducted an onsite review of the implementation of the licensees inservice inspection (ISI) program for monitoring degradation of the reactor coolant system (RCS), emergency feedwater systems, risk-significant piping and components, and containment systems in Unit 2. The inspectors activities included a review of non-destructive examinations (NDE) to evaluate compliance with the applicable edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC),Section XI (Code of record: 2004 Edition with 2006 Addenda, 4 Interval, 1 Period, 3 Outage), and to verify that indications, and defects (if present), were appropriately evaluated and dispositioned in accordance with the requirements of the ASME Code,Section XI, acceptance standards.

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

• Ultrasonic Testing (UT) on Safety Injection (SI) Pipe to Pipe Weld 12050-WMKS-0103BB/6-SI-532/SW 36, Class 1 The inspectors also reviewed documentation for the following NDE activities:

• Liquid Penetrant Examination (PT) on Charging System Tee to Pipe, 12050-WMKS-0111AAD/3-CH-667/82, Class 3

• PT on Charging System Pipe to Tee, 12050-WMKS-0111AAD/3-CH-667/83, Class 3

• PT on Charging System Final Welds 82 & 83, MK. 2-CH-529 Line 3-CH-667 502-Q2, Class 3

• PT on Feedwater System, MK. 2-FW-134, Line 3-WAPD-429-Q3, Class 3

• Radiography Examination (RT) on Charging System, 2-CH-529, 3-CH-667-1502-Q2, Class 1

• RT on Feedwater System, 2-FW-134, 3-WAPD-429-601-Q2, Class 1

• UT on Reactor Coolant System Elbow to Pump, 12050-WMKS-109F-1/31-RC-405/20, Class 1

• UT on Charging System Tee to Pipe, 12050-WMKS-0111AAD/3-CH-667/82, Class 3

• UT on Charging System Pipe to Tee, 12050-WMKS-0111AAD/3-CH-667/83, Class 3

• UT on Safety Injection (SI) Pipe to Pipe Weld, 12050-WMKS-0103BB/6-SI-533/SW 42, Class 1

• UT on Safety Injection (SI) Pipe to Pipe, 12050-WMKS-0103BB/6-SI-532/SW 36, Class 1

• UT on Safety Injection (SI) Pipe to Pipe, 12050-WMKS-0103BB/6-SI-533/9, Class 1 The inspectors observed the welding activity referenced below and reviewed associated documents, in order to evaluate compliance with procedures and the ASME Code. The inspectors reviewed the work order, repair and replacement plan, weld data sheets, welding procedures, procedure qualification records, welder performance qualification records, and NDE reports.

• Repair and Replacement of 3 Check Valve on the Feedwater System, 2-FW-134.

The inspectors also reviewed documentation for the following welding activity:

• Addition of Reactor Coolant System Beyond Design Basis Alternate Connection, 3-CH-667-1502-Q2 and 3-CH-960-1502-Q2 During non-destructive surface and volumetric examinations performed since the previous refueling outage, the licensee did not identify any relevant indications that were analytically evaluated and accepted for continued service. Therefore, no NRC review was completed for this inspection procedure attribute.

Pressurized Water Reactor Vessel Upper Head Penetration Inspection Activities: For the Unit 2 vessel head, a bare metal visual (BMV) examination and a volumetric examination were not required during this outage, in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). Examinations for heads with nozzles, and partial penetration welds of PWSCC-resistant materials, are required every third refueling outage or every 5 years, whichever is less. The inspectors also reviewed the licensees Alloy 600 Management Plan, to verify the implemented strategy provides reasonable assurance that plant safety will be maintained.

The licensee did not identify any relevant indications that were accepted for continued service during the previous BMV exams. Additionally, the licensee did not perform any welding repairs to the vessel head penetrations since the beginning of the last Unit 2 refueling outage; therefore, no NRC review was completed for these inspection procedure attributes.

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

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

• CR510317, Dry Inactive Packing/Gland Follower Boric Acid Leakage on 1-SI-MOV- 2864A, 4/7/13

• CR510318, Dry Inactive Packing/Gland Follower Boric Acid Leakage on 1-SI-MOV-2864B, 4/7/13

• CR539666, 2-SI-MOV-2864B Has Dry Boric Acid Packing Leak

• CR543643, Boric Acid on 2-SI-MOV-2864B

• CR555976, Packing Leak on 2-SI-MOV-2864B Steam Generator Tube Inspection Activities: The inspectors observed the following activities and/or reviewed the following documentation, and evaluated them against the licensees technical specifications, commitments made to the NRC, ASME Section XI, and Nuclear Energy Institute (NEI) 97-06 (Steam Generator Program Guidelines):

• Reviewed the licensees in-situ steam generator (SG) tube pressure testing screening criteria. In particular, the inspectors assessed whether assumed NDE flaw sizing accuracy was consistent with data from the EPRI examination technique specification sheets (ETSS), or other applicable performance demonstrations.

• Compared the numbers and sizes of SG tube flaws/degradation identified against the licensees previous outage Operational Assessment.

• Reviewed the SG tube eddy current testing (ECT) examination scope and expansion criteria.

• Evaluated if the licensees SG tube ECT examination scope included potential areas of tube degradation identified in prior outage SG tube inspections, and/or as identified in NRC generic industry operating experience applicable to the licensees SG tubes.

• Reviewed the licensees implementation of their extent-of-condition inspection scope, and repairs for new SG tube degradation mechanism(s). No new degradation mechanisms were identified during the ECT examinations.

• Reviewed the licensees repair criteria and processes.

• Verified that primary-to-secondary leakage (e.g., SG tube leakage) was below 3 gallons per day, or the detection threshold, during the previous operating cycle according to licensee procedures.

• Evaluated if the ECT equipment and techniques used by the licensee to acquire data from the SG tubes were qualified or validated, to detect the known/expected types of SG tube degradation, in accordance with Appendix H, Performance Demonstration for Eddy Current Examination, of Electric power Research Institute (EPRI)

Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7.

• Reviewed the licensees secondary side SG Foreign Object Search and Retrieval (FOSAR) activities.

• Reviewed ECT personnel qualifications.

Identification and Resolution of Problems: The inspectors reviewed a sample of ISI-related problems that were identified by the licensee, and entered into the CAP as CRs. 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 Attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

Resident Inspector Quarterly Review

a. Inspection Scope

The inspectors reviewed a licensed operator performance on July 8, 2014, during a simulator scenario which involved a site area emergency with loss of four EDGs, and fires at the AFW pump houses and an above ground fuel oil storage tank. The scenario required classifications and notifications that were counted for NRC performance indicator input.

The inspectors observed the following elements of crew performance in terms of communications: 1) ability to take timely and proper actions; 2) prioritizing, interpreting, and verifying alarms; 3) correct use and implementation of procedures, including the alarm response procedures; 4) timely control board operation and manipulation, including high-risk operator actions; and 5) oversight and direction provided by the shift supervisor, including the ability to identify and implement appropriate TS actions. The inspectors observed the post training critique to determine that weaknesses or improvement areas revealed by the training were captured by the instructor and reviewed with the operators.

b. Findings

No findings were identified.

.2 Quarterly Control Room Operator Performance Observations

a. Inspection Scope

During the inspection period, the inspectors observed and assessed licensed operator performance during the slowdown of Unit 2 for the fall refueling outage on September 7, 2014, to ensure that the activities were consistent with the licensee procedures and regulatory requirements. This observation took place during weekend plant working hours. As part of this assessment, the inspectors observed the following elements of operator performance: 1) operator compliance and use of plant procedures including technical specifications; 2) control board/in-plant component manipulations; 3)use and interpretation of plant instruments, indicators and alarms; 4) documentation of activities; 5) management and supervision of activities; and, 6) communication between crew members.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

For the three equipment issues listed below, the inspectors evaluated the effectiveness of the respective licensee's preventive and corrective maintenance. The inspectors performed walkdowns of the accessible portions of the systems, performed in-office reviews of procedures and evaluations, and held discussions with licensee staff. The inspectors compared the licensees actions with the requirements of the Maintenance Rule (10 CFR 50.65), and licensee procedure ER-AA-MRL-10, Maintenance Rule Program, Revision 5.

• CR552780, 1-HV-AC-7 fan contacting shroud

• CR556439, The U1 Isophase Bus Duct Cooling has an air leak issuing from an access hole

• CR556525, Recommend inspection of Instrument Air Dryer Check Valve 2-IA-2083, and CR556528, Recommend inspection of Instrument Air Dryer Check Valve 2-IA-2084

b. Findings

Inadequate Procedure for Maintaining MCR/ESGR Air Handler

Introduction:

A Green self-revealing NCV of 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for a failure to prescribe maintenance procedures affecting the quality of fan 1-HV-AC-7 appropriate to the circumstances. Specifically, the licensee failed to incorporate vendor guidance for taking bearing clearance measurements contained in VTM 59-B878-00001 and the SKF Bearing Maintenance Handbook into the maintenance procedure 0-MCM-0508-01 Repair Buffalo Forge Centrifugal Fans as required by administrative procedure VPAP-0502.

Description:

North Anna UFSAR, Revision 49, Section 6.4, stated in part that the habitability systems for the control room were provided to ensure that continuous occupancy of the area is possible during and after natural phenomena, fire, and missiles, as well as for all postulated accidents that might or might not release radioactivity to the environs.

To ensure the control room habitability, MCR/Emergency Switchgear Room (ESGR) air conditioning system (ACS) provided cooling for the MCR/ESGR envelope during normal and emergency operations. It consisted of two independent and redundant subsystems that provided cooling of MCR/ESGR envelope air. Each subsystem consisted of two air handling units (one for the MCR and one for the ESGR). Each subsystem could provide 100 percent capacity of cooling to maintain the MCR/ESGR envelope within the design limits. Fan 1-HV-AC-7 was the air handling unit for the ESGR for one of the subsystems for Unit 1.

On June 28, 2014, North Anna Security notified Operations that there was a burning smell coming from the motor side of 1-HV-AC-7 fan. 1-HV-AC-7 was secured and its power supply breaker was opened. As a result of the inoperability of 1-HV-AC-7, a 30-day LCO of T.S. 3.7.11 was entered on June 28, 2014, at 1515. The licensee exited the LCO on July 2, 2014 after 1-HV-AC-7 was repaired and declared to be operable.

The licensees mechanical maintenance for 1-HV-AC-7 was controlled by procedure 0-MCM-0508-01, Repair Buffalo Forge Centrifugal Fans Revision 5. The 1-HV-AC-7 fan bearings are SKF Spherical Roller Pillow Block bearings, Model # 22511. To ensure that an even bearing clearance was held consistent throughout the bearing before it was installed and when it was set for installation, the SKF Bearing Maintenance Handbook, dated 1991, and the Vendor Technical Manual (VTM) stated that bearing clearance measurements should to be taken with the bearing unloaded for both the initial un-mounted and final mounted measurements. However, 0-MCM-0508-01, Section 6.8, Bearing Installation, had personnel install and load the bearing prior to verifying clearance measurements. This introduced for the potential incorrect bearing clearance measurements and inadequate bearing sleeve compression.

The licensees administrative procedure, VPAP-0502, Procedure Process Control, Revision 31, dated January 31, 2005, had a reference step, 3.2.30, Generic Letter 83-28, to ensure previous vendor and engineering recommendations are incorporated. In addition, Step 4.27.2, Technical Review, required a review to verify the technical accuracy of the procedure using technical experience, plant drawings, vendor manuals, and associated technical information.

0-MCM-0508-01 was established on July 5, 2005 and received subsequent revisions, the most recent being the 5th revision dated June 9, 2014. However, specific guidance related to taking bearing clearance measurements stated in VTM 59-B878-00001, the SKF Bearing Installation and Maintenance Guide, dated November 2012, and the SKF Bearing Maintenance Handbook, dated 1991, was never incorporated into the 5th or earlier versions of 0-MCM-0508-01 As a result of the inadequate guidance for setting of the bearings which were installed on April 17, 2014, the fan assembly came into contact with the fan shroud and eventually resulted in failure of the 1-HV-AC-7 and impact to the MCR/ESGR habitability. The licensee entered this issue into the CAP as CR552780.

The licensees apparent cause evaluation (ACE) 019764 concluded that the maintenance strategy did not include the manufacturer recommendation for taking bearing clearance measurements for both the initial un-mounted and final mounted measurements. This potentially led to incorrect bearing clearance measurements and caused high bearing vibrations in January 2014, loose bearing locknut and fan shaft scouring in April 2014, and subsequently the failure of 1-HV-AC-7.

Analysis:

The licensees failure to incorporate vendor guidance for taking bearing clearance measurements contained in VTM 59-B878-00001 and the SKF Bearing Maintenance Handbook into the maintenance procedure 0-MCM-0508-01 Repair Buffalo Forge Centrifugal Fans as required by VPAP-0502 was a performance deficiency. This finding was determined to be more than minor because it affects the reactor safety barrier integrity cornerstone attribute of control room barrier, and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that are required for the habitability of the control room.

Specifically, the finding impacted the availability of 1-HV-AC-7, which affects the availability of the MCR/ESGR ACS. The finding was determined to be associated with the barrier integrity cornerstone based on the NRC IMC 0609, Significance Determination Process (SDP), dated June 2, 2011, Attachment 4, Initial Characterization of Findings, dated June 19, 2012. The inspectors performed a Phase 1 analysis using the IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, dated June 19, 2012 and determined that the finding was of very low significance (Green) because the finding did not represent a degradation of the barrier function of the control room against radiation protection, smoke or a toxic atmosphere. The redundant subsystem was able to provide cooling to the MCR/ESGR envelope and 1-HV-AC-7 was repaired within the 30-day T.S. 3.7.11 LCO.

The inspectors determined that this finding had a cross-cutting aspect in the area of human performance, design margins component, because the licensee failed to operate and maintain equipment within design margins where margins are carefully guarded and changed only through a systematic and rigorous process. Specifically, the licensee failed to recognize that the bearing clearance measurement identified in VTM 59-B878-00001 and the SKF Bearing Maintenance Handbook was a critical design parameter.

[H.6]

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, required, in part, that activities affecting quality be prescribed by documented instructions and procedures appropriate to the circumstances and shall be accomplished in accordance with these instructions and procedures.

VPAP-0502, Procedure Process Control, Revision 31, dated January 31, 2005, had a reference step, 3.2.30, Generic Letter 83-28, to ensure previous vendor and engineering recommendations were incorporated. In addition, Step 4.27.2, Technical Review, required a review to verify the technical accuracy of the procedure using technical experience, plant drawings, vendor manuals, and associated technical information.

VTM 59-B878-00001 Centrifugal Fans -Ventilating/Industrial, Revision 4, dated June 29, 2009, the SKF Bearing Installation and Maintenance Guide, dated November 2012, and the SKF Bearing Maintenance Handbook, dated 1991, stated that while taking bearing clearance measurements, the bearing should be unloaded for both the initial unmounted and final mounted measurements.

Contrary to the above, since July 5, 2005, the licensee failed to prescribe maintenance procedures affecting the quality of 1-HV-AC-7 appropriate to the circumstances.

Specifically, the licensee failed to ensure that the vendor guidance for taking bearing clearance measurements contained in VTM 59-B878-00001, the SKF Bearing Installation and Maintenance Guide, and the SKF Bearing Maintenance Handbook were incorporated into maintenance procedure 0-MCM-0508-01 as required by administrative procedure VPAP-0502. As a result, 1-HV-AC-7 became inoperable on June 28, 2014, which led to an unplanned entry into a LCO of T.S. 3.7.11. Because it is of very low safety significance (Green), this violation is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy. The violation was entered into the licensees corrective action program as CR 552780. This non-cited violation is identified as NCV 05000338/2014004-01, Inadequate Procedure for Maintaining MCR/ESGR Air Handler.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors evaluated, as appropriate, the five activities listed below for the following:

1) effectiveness of the risk assessments performed before maintenance activities were conducted; 2) management of risk; 3) appropriate and necessary steps taken to plan and control the resulting emergent work activities upon identification of an unforeseen situation; and, 4) adequate identification and resolution of maintenance risk assessments and emergent work problems. The inspectors verified that the licensee was in compliance with the requirements of 10 CFR 50.65 (a)(4) and the data output from the licensees safety monitor associated with the risk profile of Units 1 and 2. The inspectors reviewed the corrective action program to verify that deficiencies in risk assessments were being identified and properly resolved.

• Emergent work for the Woodward governor actuator for the Station Blackout (SBO)diesel which impacted troubleshooting blown control power fuses as documented in CR554769 on July 25,2104

• Emergent work to address SBO hi lube oil temperature alarm, as documented in CR554934 on July 28, 2014

• Emergent work for the 1 J EDG undervoltage protection circuit, as documented in CR558617

• Emergent work to deal with a fire from Unit 2 Refueling Water Storage Tank B pump in the Quench Spray pump house, as documented in CR560148

• 2H EDG 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> run as documented in CR559873

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed six operability determinations and functionality assessments, listed below, affecting risk-significant mitigating systems, to assess, as appropriate: (1)the technical adequacy of the evaluations;

(2) whether continued system operability was warranted;

(3) whether other existing degraded conditions were considered as compensatory measures;

(4) whether the compensatory measures, if involved, were in place, would work as intended, and were appropriately controlled; and

(5) where continued operability was considered unjustified, the impact on TS Limiting Conditions for Operation and the risk significance in accordance with the Significant Determination Process (SDP). The inspectors review included a verification that operability determinations (OD) were made as specified by procedure OP-AA-102, Operability Determination, Revision 12. Other documents reviewed are listed in the Attachment to this report.

• CR556475, Continued increasing trend 2H EDG coolant level

• CR556497, Elevated Inboard Bearing Temperature for 1-HV-F-7A

• CR556572, Suspect faulty gauge 1-EG-PI-704J

• CR555696, 1H EDG Day Tank Level Indicator 1-EG-LG-106A as found cal data was out of spec

• CR557267, 1-FW-P-2 Inoperable Unit 1 terry turbine

• CR557565, 01-EG-P-3H leakage has increased to 40 drops per minute

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors reviewed eight post maintenance test procedures and/or test activities, listed below, for selected risk-significant mitigating systems to assess whether:

(1) the effect of testing on the plant had been adequately addressed by control room and/or engineering personnel;

(2) testing was adequate for the maintenance performed; (3)acceptance criteria were clear and adequately demonstrated operational readiness consistent with design and licensing basis documents;

(4) test instrumentation had current calibrations, range, and accuracy consistent with the application;

(5) tests were performed as written with applicable prerequisites satisfied;

(6) jumpers installed or leads lifted were properly controlled;

(7) test equipment was removed following testing; and,

(8) equipment was returned to the status required to perform in accordance with VPAP-2003, Post Maintenance Testing Program, Revision 14. Other documents reviewed are listed in the Attachment.

• Work Order (WO) 59102742408 Unit 1 Air Conditioning Fan shielded motor bearings

• 1J EDG diesel air compressor using procedure 1-OP-6.7, Diesel Air System, Revision 15

• 1-PT-77.11A.1, Control Room Chiller 1-HV-E-4A IST Comprehensive Pump and Valve Test, Revision 8

• 2-OP-6.7, Operation of the SBO Diesel (Non-SBO Event) to Reenergize 2H 4160V Emergency Bus, Following Loss of 2H 4160V Emergency Bus, Revision 1

• B Fuel Pit Cooling Pump/Heat Exchanger using procedure 0-MOP-16.05, Spent Fuel Pit Cooling Pump 1-FC-P-1B, Revision 10

• Diesel driven fire pump using procedure 0-PT-100.2, Protection Pumps Annual Testing, Revision 24

• 2-PT-14.2 ,Charging Pump 2-CH-P-1B Operations Periodic Test, Revision 50

• 2-PT-70.1, Main Steam Safety Valve Setpoint Verification Using Trevitest, Revision 9

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

Refueling Outage

a. Inspection Scope

The inspectors reviewed the Outage Safety Review (OSR) and contingency plans for the Unit 2 refueling outage, which began September 7, 2014, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. The inspectors also confirmed that the licensee had mitigation/response strategies in place for any losses of key safety functions. Using NRC inspection procedure 71111.20, Refueling and Outage Activities. the inspectors observed portions of the shutdown, cooldown, refueling, and maintenance activities to verify that the licensee maintained defense-in-depth commensurate with the outage risk plan and applicable TS. The inspectors monitored licensee controls over the outage activities listed below.

• Licensee configuration management, including daily outage reports, to evaluate maintenance of defense-in-depth commensurate with the OSR for key safety functions and compliance with the applicable TS when taking equipment out of service.

• Implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing.

• Implementation of licensee procedures for foreign material exclusion.

• Installation and configuration of Reactor Coolant System (RCS) instrumentation for system pressure, level, and temperature to provide accurate indication, and an accounting for instrument error.

• Controls over the status and configuration of electrical systems to ensure that TS and outage safety plan requirements were met, and controls over switchyard activities.

• Monitoring of decay heat removal.

• Controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system.

• Reactor inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss.

• Controls over activities and SSCs which could affect reactivity.

• Fatigue management in accordance with meeting the rule requirements for each process.

• Verification of plant systems configurations during reduced inventory to assess compliance with Generic Letter 88-17 commitments.

• Refueling activities, including fuel handling operations (removal, inspection, sipping, reconstitution and insertion), and fuel assemblies tracking, including new fuel, from core offload through core reload.

• Controls over containment penetrations, per TS, such that containment closure could be achieved at all times.

• Licensee identification and resolution of problems related to refueling outage activities.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

For the eight surveillance tests listed below, the inspectors examined the test procedures, witnessed testing, or reviewed test records and data packages, to determine whether the scope of testing adequately demonstrated that the affected equipment was functional and operable, and that the surveillance requirements of TS were met. The inspectors also determined whether the testing effectively demonstrated that the systems or components were operationally ready and capable of performing their intended safety functions. The documents reviewed are listed in the Attachment to this report.

In-Service Test:

• 1-PT-71.2Q, 1-FW-P-3A A Motor-Driven AFW Pump and Valve Test, Revision 40

• 2-PT-213.8B, Valve Inservice Inspection (B Train of Safety Injection System),

Revision 13 Containment Isolation Valve:

• 2-PT-61.3, Containment Type C Testing, Revision 43, for containment isolation valves 2-LM-TV-200E, 2-LM-TV-200F, 2-HC-TV-205A and 2-HC-TV-205B Other Surveillance Tests:

• 2-PT-82.2A, 2H Diesel Generator Test (Simulated Loss of Off-Site Power),

Revision 67

• 2-PT-13.4, Moderator Temperature Coefficient Measurement-Power Exchange Method, Revision 6, with 2-OP-2.1, Unit Startup From Mode 2 to Mode 1, Revision 115P1

• 1-PT-82.2B, 2J Diesel Generator Test (Simulated Loss of Off-Site Power),

Revision 71

• 1-PT-82.2A, 1H Diesel Generator Test (Simulated Loss of Off-Site Power),

Revision 51

• 2-PT-57.1B, Emergency Core Cooling Subsystem - Low Head Safety Injection Pump (2-SI-P-1B), Revision 60

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation Emergency Preparedness (EP) Drill

a. Inspection Scope

On July 8, 2014, the inspectors reviewed and observed the performance of a Hostile Action Based Drill that involved a General Emergency and loss of all AC. The inspectors assessed emergency procedure usage, emergency plan classification, notifications, and the licensees identification and entrance of any problems into their corrective action program. This inspection evaluated the adequacy of the licensees conduct of the drill and performance critique. Exercise issues were captured by the licensee in their corrective action program as multiple CRs. These CRs were reviewed and are listed in the Attachment to this report. Requalification training deficiencies were captured within the operator training program.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

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 Very High Radiation Areas (VHRAs) established within the radiologically controlled area (RCA) of the auxiliary building, Unit 2 (U2) reactor containment building, ISFSI 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 surveys for alpha emitters, discrete radioactive particles, airborne radioactivity, gamma surveys with a range of dose rate gradients, and pre-job surveys for upcoming tasks. The inspectors also discussed changes to plant operations that could contribute to changing radiological conditions since the last inspection and were made aware during refuel activities on U2 that fuel debris had been discovered in the U2 reactor cavity and transfer canals from a fuel pin failure. For selected outage jobs, the inspectors attended pre-job briefings and reviewed radiation work permit (RWP) details to assess communication of radiological control requirements and current radiological conditions to workers.

Hazard Control and Work Practices. The inspectors evaluated access barrier effectiveness for selected Locked High Radiation Area (LHRA) locations and discussed changes to procedural guidance for LHRA and VHRA controls with health physics (HP)supervisors. The inspectors reviewed implementation of controls for the storage of irradiated material within the spent fuel pool (SFP). Established radiological controls (including airborne controls) were evaluated for selected Unit 2 Refueling Outage 23 (2R23) tasks including recovery of fuel debris from the reactor cavity, U2 seal table and miscellaneous valve work. In addition, the inspectors reviewed licensee controls for areas where dose rates could change significantly as a result of plant shutdown and refueling operations.

Through direct observations and interviews with licensee staff, inspectors evaluated occupational workers adherence to selected RWPs and HP technician (HPT) proficiency in providing job coverage. Electronic dosimeter (ED) alarm set points and worker stay times were evaluated against area radiation survey results for selected 2R22 job tasks.

The inspectors also reviewed the use of personnel dosimetry (ED alarm response, extremity dosimetry, multi-badging in high dose rate gradients, etc.).

Control of Radioactive Material. The inspectors observed surveys of material and personnel being released from the RCA using small article monitor (SAM), personnel contamination monitor (PCM), and portal monitor (PM) instruments. The inspectors discussed equipment sensitivity, alarm setpoints and release program guidance with licensee staff. The inspectors compared recent 10 Code of Federal Regulations (CFR)

Part 61 results for the Dry Active Waste (DAW) radioactive waste stream with radionuclides used in calibration sources to evaluate the appropriateness and accuracy of release survey instrumentation. 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. The inspectors reviewed and assessed CRs associated with radiological hazard assessment and control. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with licensee procedures. The inspectors also reviewed recent self-assessment results.

Radiation protection activities were evaluated against the requirements of UFSAR Section 12; TS Sections 5.4 (Procedures) and 5.7 (High Radiation Areas); 10 CFR Parts 19 and 20; 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.

2RS2 Occupational ALARA Planning and Controls

a. Inspection Scope

Radiological Work Planning. Inspectors evaluated As Low As Reasonably Achievable (ALARA) program guidance and implementation for ongoing tasks associated with U2R23. Inspectors also evaluated tasks and review of post-outage ALARA activities associated with U1R23 refueling outage. A list was obtained from the licensee of work activities for their current outage. Inspectors selected five work activities to evaluate the ALARA Plan and associated documentation for jobs, including NDE and ISI inspection activities, reactor head disassembly and reassembly, insulation removal and installation, disassembly, reactor coolant pump maintenance, and repair of Reactor Coolant system loop isolation valve 2-RC-MOV-2593. Inspectors evaluated dose mitigation considerations, dose goals and other factors that went into planning the dose goal for each task, including the review of TEDE ALARA evaluations for the decrease of worker efficiency from the use of respiratory protective devices. Selected RWPs were reviewed by inspectors to verify the integration of ALARA requirements into the documents for worker instruction. Inspectors followed the progression of available work activities to compare dose rates accrued and work evolution to the ALARA planning. The inspectors reviewed temporary shielding documentation and observed the as installed configuration.

Verification of Dose Estimates and Exposure Tracking Systems. Five in progress and two closed ALARA work packages and the assumptions and basis for the collective exposure estimates were reviewed by inspectors. The inspectors reviewed ALARA procedures, had discussions with ALARA personnel, reviewed daily exposure graphs and outage reports that tracked and trended the dose of ongoing work, and reviewed monthly Station ALARA Committee Meeting Minutes. The use of Work-In-Progress reviews for ALARA trigger points were also evaluated by the inspectors.

Source Term Reduction and Radiation Worker Performance. The inspectors evaluated source term reduction methods through the review of licensee documents and records, and discussions with ALARA personnel. Inspectors reviewed actions already executed by the licensee to reduce source term, including replacing various plant components with Stellite free components, using macro porous resin for RCS cleanup, use of submicron filters, and zinc injection. The inspectors also reviewed future plans for source reduction, including the reduction of hotspots and soluble cobalt concentrations, and the use of permanent shielding.

The inspectors observed radiation worker performance through CCTV remote monitoring and direct observations. This included the reactor head lift, reactor coolant filter change-out, and attending ALARA and High Radiation Area (HRA) pre-job briefs.

Problem Identification and Resolution. The inspectors reviewed licensee corrective action documents associated with ALARA planning and controls. This included review of selected Condition Reports (CRs) and self-assessments. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with procedure PI-AA-200, Corrective Action.

ALARA activities and radiation worker performance were evaluated against the requirements in TS Sections 5.4 and 5.7; Title 10 Code of Federal Regulations (CFR)

Parts 19 and 20; and approved licensee procedures. Records reviewed are listed in the

.

The inspectors completed 1 sample, as described in Inspection Procedure (IP)71124.02.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

Engineering Controls. The inspectors reviewed the use of temporary and permanent engineering controls to mitigate airborne radioactivity during Unit 2 Refueling Outage 23.

In addition, during observations of jobs in-progress and containment walk-downs, inspectors observed the placement and use of HEPA negative pressure units, and air sampling equipment.

Use of Respiratory Protection Devices & Self-Contained Breathing Apparatus for Emergency Use. Inspectors reviewed the use of respiratory protection devices to limit the intake of radioactive material, including devices used for routine tasks and devices stored for use in emergency situations. Inspectors observed the physical condition of Self-Contained Breathing Apparatus (SCBA) units, negative pressure respirators (NPRs), powered air purifying respirators/hoods and device components staged for routine and emergency use throughout the plant. SCBA bottle air pressure, the number of units, and the number of spare masks and air bottles available was also evaluated by inspectors. The inspectors reviewed maintenance records for selected SCBA units for the past two years and evaluated SCBA and NPR compliance with National Institute for Occupational Safety and Health certification requirements. The inspectors also reviewed records of Grade D (or better) air quality testing for supplied-air devices and SCBA bottles. The inspectors reviewed the status and surveillance records of SCBAs staged for in-plant use during emergencies through review of records and walk-down of SCBA staged in the control room and selected locations.

The inspectors verified the licensee had procedures in place to ensure that the use of respiratory protection devices was ALARA when engineering controls were not practicable. Control room operators and fire brigade were interviewed on the use of the devices including SCBA bottle change-out and use of corrective lens inserts. In addition, qualifications for individuals responsible for testing and repairing SCBA vital components were evaluated through review of training records. Selected maintenance records for SCBA units and air cylinder hydrostatic testing documentation were reviewed.

The inspectors verified that the licensee has procedural requirements in place for evaluating air samples for the presence of alpha emitters and reviewed airborne radioactivity and contamination survey records for selected plant areas to ensure air samples are screened and evaluated per the procedure requirements.

The inspectors walked-down the respirator issue and storage locations and verified that the equipment was appropriately stored and maintained. Records of monthly inventory and inspection of the equipment were also reviewed by the inspectors. The inspectors discussed and observed the process for issuing respirators, and verified that selected individuals qualified for respirator and/or SCBA use had completed the required training, fit-test, and medical evaluation.

Problem Identification and Resolution. Licensee CAP documents associated with the control and mitigation of in-plant radioactivity were reviewed and assessed. This included review of selected CRs related to use of respiratory protection devices including SCBA. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with procedure PI-AA-200, Corrective Action and PI-AA-300, Cause Evaluation, Revision 7. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results. Licensee CAP documents reviewed are listed in the Attachment to this report.

Radiation protection activities were evaluated against the requirements specified in 10 CFR Parts 19 and 20; and approved licensee procedures. Records reviewed are listed in the Attachment to this report.

The inspectors completed all specified line-items detailed in IP 71124.03 (sample size of 1).

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

External Dosimetry. The inspectors reviewed the licensees National Voluntary Accreditation Program (NVLAP) certification data for accreditation for 2014-2015 for Ionizing Radiation Dosimetry. The inspectors reviewed program procedures for processing active personnel dosimeters (ED)s and onsite storage of Thermo Luminescent Dosimeters (TLDs). Comparisons between ED and TLD results, including correction factors, were discussed in detail. The inspectors also reviewed dosimetry occurrence reports regarding alarming dosimeters.

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

Inspectors reviewed and evaluated Whole Body Counter (WBC) sensitivity, count time and libraries. The inspectors evaluated the licensees program for in vitro monitoring, however there were no dose assessments using this method to review. There were no internal dose assessments for internal exposure greater than 10 millirem committed effective dose equivalent to review.

Special Dosimetric Situations. The inspectors reviewed records for one currently declared pregnant worker (DPW) and discussed guidance for monitoring and instructing DPWs. Inspectors reviewed the licensees practices for monitoring external dose in areas of expected dose rate gradients, including the use of multi-badging, extremity dosimetry, and calculation and reporting of Effective Dose Equivalent (EDE). The inspectors evaluated the licensees neutron dosimetry program including instrumentation which was evaluated under procedure 71124.05.

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

HP program occupational dose assessment activities were evaluated against the requirements of UFSAR Section 12.3; 10 CFR Parts 19 and 20; and approved licensee procedures. Documents and records reviewed are listed in the Attachment to this report.

The inspectors completed 1 sample as required by IP 71124.04 (sample size of 1).

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

The inspectors reviewed the licensees radiation monitoring instrumentation programs to verify the accuracy and operability of radiation monitoring instruments used to monitor areas, materials, and workers to ensure a radiologically safe work environment and to detect and quantify radioactive process streams and effluent releases.

Walkdowns and Observations: During tours of the reactor buildings (RAB), turbine deck, SFP areas, control room, and RCA exit points, the inspectors observed installed radiation detection equipment including the following instrument types: area radiation monitors (ARM)s, continuous air monitors, personnel contamination monitors (PCMs)

(including hand and foot monitors), small article monitors (SAMs), personnel monitors (PMs), and liquid and gaseous effluent monitors. The inspectors observed the physical location of the components, noted the material condition, noted flow measurement devices, input and output of flow to monitors, and compared sensitivity ranges with UFSAR requirements. In addition to equipment walk-downs, the inspectors observed source checks and alarm setpoint testing of a PM-7 portal monitor and discussed the function checks and calibrations of various portable and fixed detection instruments, including ion chambers, a telepole, PM-7, PCM-12, and SAMs. Material condition of source check devices, device operation, and establishment of source check acceptance ranges were also discussed with calibration lab personnel.

Calibration and Testing Program: The inspectors reviewed the last calibration records for selected ARMs, PCMs, PMs, SAMs, and containment high-range ARMs and the most recent calibration record for a whole body counter. Inspectors reviewed records of survey instrument function/source checks and observed and discussed performance of required checks with calibration lab personnel. Calibration source documentation was reviewed for the ARM high-range calibrator and the Cs-137 (J.L. Shepherd) source used for portable instrument checks. Calibration stickers on portable survey instruments were reviewed and inspections of storage areas for 'ready-to-use' equipment were completed during walkdowns. The inspectors reviewed alarm setpoint values for selected ARMs, PCMs, PMs, SAMs, and effluent monitors. The inspectors also reviewed count room daily performance checks and calibration records for germanium detectors and liquid scintillator counters.

Operability and reliability of selected radiation detection instruments were reviewed against details documented in the following: 10 CFR Part 20; NUREG-0737, Clarification of TMI Action Plan Requirements; UFSAR Chapters 11; TS Section 3.3 and 3.7, and applicable licensee procedures. Documents reviewed are listed in the report Attachment.

Problem Identification and Resolution: The inspectors reviewed and discussed selected Corrective Action Program (CAP) documents associated with radiological instrumentation. The reviewed items included CRs, self-assessment, and quality assurance audit documents. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with licensee procedures. Documents reviewed are listed in the Attachment to this report.

The inspectors completed 1 sample as required by IP 71124.05 (sample size of 1).

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, and Occupational Radiation Safety

4OA1 Performance Indicator (PI) Verification

.1 Mitigating Systems PIs

a. Inspection Scope

The inspectors performed a periodic review of the five Unit 1 and Unit 2 PIs listed below to assess the accuracy and completeness of the submitted data, and whether the performance indicators were calculated in accordance with the guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspection was conducted in accordance with NRC inspection procedure 71151, Performance Indicator Verification. Specifically, the inspectors reviewed the Unit 1 and Unit 2 data reported to the NRC for the period July 1, 2013 through June 30, 2014. Documents reviewed included applicable NRC inspection reports, licensee event reports, operator logs, station performance indicators, and related CRs. Other documents reviewed are listed in the Attachment to this report.

• Emergency AC Power System

• High Pressure Injection System

• Heat Removal System

• Residual Heat Removal System

• Cooling Water System

b. Findings

No findings were identified.

.2 Radiation Safety PIs

a. Inspection Scope

Occupational Radiation Safety Cornerstone. The inspectors reviewed the Occupational Exposure Control Effectiveness PI results for the Occupational Radiation Safety Cornerstone from April 2013 through August 2014. The inspectors reviewed electronic dosimeter alarm logs and CRs related to controls for exposure significant areas.

Documents reviewed are listed in the Attachment.

Public Radiation Safety Cornerstone. The inspectors reviewed the Radiological Control Effluent Release Occurrences PI results for the Public Radiation Safety Cornerstone from February 2013 through August 2014. For the assessment period, the inspectors reviewed cumulative and projected doses to the public contained in liquid and gaseous release permits and CRs related to Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual issues. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents reviewed are listed in the

.

The inspectors completed two of the required samples specified in Inspection Procedure (IP) 71151.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As required by NRC inspection procedure 71152, Identification and Resolution of Problems, and in order to help identify repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the licensees CAP. This review was accomplished by reviewing daily CR report summaries and periodically attending daily CR Review Team meetings.

b. Findings

No findings were identified.

.2 Annual Sample: Review of CA273254, Investigate 1-FP-P-2 to Support Maintenance

Rule Evaluation (MRE) and Recommend/Initiate Any Actions

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for CA273254, Investigate 1-FP-P-2 to Support MRE and Recommend/Initiate Any Actions, to ensure that the full extent of the issue was identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. The inspectors also evaluated the CA against the requirements of the licensees CAP as specified in procedure, PI-AA-200, Corrective Action Program, Revision 23, and 10 CFR 50, Appendix B. Documents reviewed are listed in the

.

b. Findings and Observations

No findings were identified. In general, the inspectors verified that the licensee had proposed or implemented appropriate corrective actions.

.3 Annual Sample: Review of CR552780, 1-HV-AC-7 fan contacting shroud

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for CR552780, 1-HV-AC-7 fan contacting shroud to ensure that the full extent of the issue was identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. The inspectors also evaluated the CR against the requirements of the licensees CAP as specified in procedure, PI-AA-200, Corrective Action Program, Revision 23, and 10 CFR 50, Appendix B. Documents reviewed are listed in the Attachment.

b. Findings and Observations

In general, the inspectors verified that the licensee had proposed or implemented appropriate corrective actions. However, one Green NCV was identified and discussed in Section 1R12 of this report.

.4 Annual Sample: Review of CR549139, Load Side Fault on XFMR #3 causes loss of Bus

1. 5 and C RSST

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for CR549139, Load Side Fault on XFMR #3 causes loss of Bus #5 and C RSST, to ensure that the full extent of the issue was identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. The inspectors also evaluated the CR against the requirements of the licensees CAP as specified in procedure, PI-AA-200, Corrective Action Program, Revision 23, and 10 CFR 50, Appendix B. Documents reviewed are listed in the

.

b. Findings and Observations

No findings were identified. In general, the inspectors verified that the licensee had proposed or implemented appropriate corrective actions.

5. Annual Sample: Review of CR556057, 1-HV-PCV-1235B-1 did not fail closed per

1-PT-77.11B

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for CR556057, 1-HV-PCV-1235B-1 did not fail closed per 1-PT-77.11B, to ensure that the full extent of the issue was identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. The inspectors also evaluated the CR against the requirements of the licensees CAP as specified in procedure, PI-AA-200, Corrective Action Program, Revision 23, and 10 CFR 50, Appendix B. Documents reviewed are listed in the Attachment.

c. Findings and Observations

No findings were identified. In general, the inspectors verified that the licensee had proposed or implemented appropriate corrective actions.

4OA3 Event Followup

.1 (Closed) Licensee Event Report (LER) 05000338/2014-001-00: Engineered Safety

Feature Actuations Due to Loss of Power to C Reserve Station Service Transformer On May 15, 2014, with both Unit 1 and Unit 2 operating at 100% power, the load side of switchyard transformer #3 faulted, causing a loss of the C Reserve Station Service Transformer (RSST). The cause of the event was due to a bird making contact with Bus

1. 5 A phase which created a short circuit to ground. The loss of the C RSST caused a power loss on the 1H and 2J emergency busses. The associated EDGs auto-started and re-energized the busses. In addition, the Unit 2 A charging pump auto-started due to the under-voltage condition on the 2J bus. The pump was secured and returned to auto at 1938 on May 15, 2014. At 2046, offsite power was restored to the 1H emergency bus, and the 1H EDG was secured. At 0410 on May 16, 2014, offsite power was restored to the 2J emergency bus, and the 2J EDG was secured. No significant safety consequences resulted from this event because the 1H and 2J EDGs powered the emergency busses, as designed. Offsite power sources were restored in a timely manner, and the associated EDGs were secured and returned to automatic. The health and safety of the public were not affected by this event.

No additional corrective actions were identified by the apparent cause evaluation. The fleet and industry standard design is to not have any electrical covers on open air non-insulated electrical conductors/tube buss work. Engineering is evaluating installation of electrical protective covers on susceptible areas of the switchyard buss to prevent future faults from animal contact. No findings or violations of NRC requirements were identified

.2 (Closed) LER 05000338, 339/2013-003-00: Units 1 and 2 Outside Recirculation Spray

Pumps Declared Inoperable On November 21, 2013, with Unit 1 and 2 operating at 100 percent power (mode 1),engineering personnel determined that the Casing Cooling tank low level setpoint did not account for necessary submergence to avoid vortexing in the pump section. During a review of the channel statistical allowance (CSA), it was identified that the final Casing Cooling tank level would be below the top of the pump suction nozzle when accounting for the full CSA on the low level bistable and closure time for the tank isolation motor operated valves. This condition could have allowed air entrapment and caused a reduction in Recirculation Spray system flow during a Containment Depressurization Actuation. As a result the Outside Recirculation Spray (ORS) pumps for both units were declared inoperable and TS 3.0.3 was entered for each unit. An operability determination was completed with actions to isolate the Casing Cooling tank on a low level at less than or equal to 10% versus the current setpoint of 4%.

The lack of integration of diverse technical documents provided a latent error where the latest usable volume calculation conflicted with the original calculation. This resulted in the inadequate level setpoint not being identified as part of the NRC Generic Letter 2008-01 review. The health and safety of the public were not affected by this event.

This condition is reportable pursuant to 10 CFR 50.73(a)(2)(v)(D). An operability determination (OD) was completed which included compensatory actions. Associated calculations will be updated to include the net positive suction head evaluation for the casing cooling pumps. This is a licensee identified violation and the corrective actions are discussed in Section 4OA7. This issue is in the licensees CAP as CR533387, Casing Cooling Tank Low Level setpoint does not account for vortexing.

4OA5 Other Activities

.1 Review of the Operation of an Independent Spent Fuel Storage Installation (ISFSI)

(Inspection Procedure 60855.1 02.02)

a. Inspection Scope

The inspectors reviewed the changes made to programs and procedures listed below to verify that changes made were consistent with the license and did not reduce the effectiveness of the program. The inspectors verified that the procedures still fulfill the commitments and requirements specified in the Safety Analysis Report, Certificate of Compliance, the site-specific license 10 CFR Part 72, the TS as applicable, any related 10 CFR 50.59 and 72.48 evaluations, and 10 CFR 72.212(b) evaluation for general licensed ISFSIs.

• Plant Operations

• Radwaste Storage and Handling

• Control of Heavy Loads

• Radiation Protection

• Security and Safeguards

• Emergency Preparedness

• Maintenance

• Surveillance

• Fire Protection

• Training

• Environmental Monitoring

• QA Activities

• Administrative Procedures

b. Findings

No findings were identified.

.2 Review of the Operation of an ISFSI (Inspection Procedure 60855.1 02.05)

a. Inspection Scope

Inspectors verified by direct observation, or review of selected records, that the licensee had identified fuel assemblies placed in the ISFSI. The inspectors verified that the parameters and characteristics of each fuel assembly were recorded, and that a record of each fuel assembly was made as a controlled document.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On October 27, 2014, the senior resident inspector presented the inspection results to Mr. F. Mladen and other members of the staff, who acknowledged the finding. The inspectors verified no proprietary information was retained by the inspectors or documented in this report.

On November 10, 2014, the senior resident inspector had an additional exit meeting with Mr. P. Kemp via telephone.

4OA7 Licensee Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meet the criteria of Section 2.3.2 of the NRC Enforcement Policy for characterization as a NCV:

• 10 CFR Part 50, Appendix B, Criterion III, Design Control required, in part, that design control measures shall provide for verifying or checking the adequacy of design reviews, by the use of alternate or simplified calculation methods, or by the performance of a suitable testing program. Generic Letter (GL) 2008-01 required, in part, licensees to evaluate the potential impact of vortexing on tanks and recirculation sumps. Contrary to the above, since December 2008, the licensee failed to verify the adequacy of design for the casing cooling system to meet Generic Letter (GL) 2008-01 vortex evaluation requirements. Specifically, the licensee identified that the 1990 calculation accounted for vortexing in usable volume, but did not verify that the low-low level setpoint accounted for this required submergence. A detailed risk assessment was performed in accordance with NRC Inspection Manual Chapter 0609 Appendix A using the NRC North Anna standardized plant analysis risk (SPAR) model. The major analysis assumptions included: Non-recoverable common cause failure to run of the outside recirculation spray pumps caused by vortexing of the casing cooling pumps, a one year exposure period, North Anna site specific performance testing restoration values for the Inside Recirculation Spray pumps. Seismic and high wind conditions external event risk was included. The risk evaluation concluded that the violation represented a risk increase in core damage frequency of < 1 E-6 /year, a GREEN finding of very low safety significance.

This issue is in the licensees CAP as CR533387, Casing Cooling Tank Low Level Setpoint does not Account for Vortexing. The instruments were recalibrated and tested to the required setpoint.

ATTACHMENT:

SUPPLEMENTARY INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

M. Becker, Manager, Nuclear Outage and Planning

G. Bischof, Site Vice President

B. Blanchard, Containment ISI

B. Britt, BACC Program

C. Cherry, ISI Program Manager

J. Daugherty, Director, Nuclear Station Safety & Licensing

B. Derreberry, Supervisor, ISI/NDE

B. Gaspar, Manager, Nuclear Site Services

R. Hanson, Manager, Nuclear Protection Services

E. Hendrixson, Director, Nuclear Site Engineering

J. Jenkins, Manager, Nuclear Maintenance

P. Kemp, Supervisor, Station Licensing

K. LeBarron, Service Water System Engineer

J. Leberstien, Technical Advisor, Licensing

F. Mladen, Plant Manager

P. Naughton, Alloy 600 Program

N. Nicholson, Health Physicist III

T. Pastor, Supervisor Radiation Protection Technical Services

J. Plossl, Supervisor, Nuclear Station Procedures

J. Schleser, Manager, Nuclear Organizational Effectiveness

B. Scott, Assistant Manager, Operations

R. Simmons, Supervisor Radiation Protection Operations

J. Slattery, Manager, Nuclear Operations

R. Stack, NDE Lead

W. Standley, Manager, Nuclear Training

J. Swenson, Site Welding Engineer

D. Taylor, Quality Specialist

A. Tessier, Steam Generator Program Owner

M. Walker, Manager, System Engineering

M. Whalen, Technical Advisor, Licensing

LIST OF ITEMS

Opened and Closed

05000338/2014004-01 NCV Inadequate Procedure for Maintaining MCR/ESGR Air Handler (Section 1R12)

Closed

05000338/2014-001-00 LER Engineered Safety Feature Actuations Due to Loss of Power to C Reserve Station Service Transformer (Section 4OA3.1)

05000338, 339/2013-003-00 LER Units 1 and 2 Outside Recirculation Spray Pumps Declared Inoperable (Section 4OA3.2)

Discussed

None