IR 05000338/2013004

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IR 05000338-13-004, 05000339-13-004; on 07/01/2013 09/30/2013; North Anna Power Station, Units 1 and 2, Problem Identification and Resolution
ML13304B766
Person / Time
Site: North Anna  Dominion icon.png
Issue date: 10/30/2013
From: Gerald Mccoy
NRC/RGN-II/DRP/RPB5
To: Heacock D
Virginia Electric & Power Co (VEPCO)
References
IR-13-004
Download: ML13304B766 (28)
v • d • e


Text

UNITED STATES ber 30, 2013

SUBJECT:

NORTH ANNA POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000338/2013004 and 05000339/2013004

Dear Mr. Heacock:

On September 30, 2013, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your North Anna Power Station Units 1 and 2. On October 29, 2013, the NRC inspectors discussed the results of this inspection with Mr. G. Bischof and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented two self-revealing findings of very low safety significance (Green)

in this report. These findings did not involve a violation of NRC requirements.

If you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the 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 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS) component of the NRCs Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reaading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Gerald J. McCoy, Chief Reactor Projects Branch 5 Division of Reactor Projects Docket No.: 50-338, 50-339 License No.: NPF-4, NPF-7

Enclosure:

Inspection Report 05000338/2013004 and 05000339/2013004 w/Attachment: Supplemental Information

REGION II==

Docket Nos: 50-338, 50-339 License Nos: NPF-4, NPF-7 Report No: 05000338/2013004, and 05000339/2013004 Licensee: Virginia Electric and Power Company (VEPCO)

Facility: North Anna Power Station, Units 1 & 2 Location: Mineral, Virginia 23117 Dates: July 1, 2013 through September 30, 2013 Inspectors: G. Kolcum, Senior Resident Inspector K. Miller, Acting Senior Resident Inspector R. Clagg, Resident Inspector D. Mills, Nuclear System Engineer, NSIR S. Ninh, Senior Project Engineer T. Stephen, Resident Inspector L. Lake, Senior Reactor Inspector, Section 1R08, 4OA5.2 M. Modes, Senior Reactor Inspector, Region I, Section 1R08 Accompanied By: J. Kusnick, Nuclear Safety Professional Development Program (Training)

Approved by: Gerald J. McCoy, Chief Reactor Projects Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000338/2013-004, 05000339/2013-004; 07/01/2013 - 09/30/2013; North Anna Power

Station, Units 1 and 2. Problem Identification and Resolution.

The report covered a three month period of inspection by resident inspectors, a nuclear system engineer from headquarters, and reactor inspectors from the regions. Two Green self revealing findings were identified which did not involve violations of NRC requirements. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). The cross-cutting aspect was determined using IMC 0310, Components Within the Cross Cutting Areas. 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 4, dated December 2006.

Cornerstone: Initiating Events

  • Green: A Green self revealing finding was identified for the failure to properly provide oversight over supplemental (vendor) personnel during the replacement of the Unit 2 turbine and exciter rotors during the spring of 2010 in accordance with Dominion procedure MA-AA-1001, Supplemental Personnel, Revision 9.

The failure to properly provide oversight over supplemental (vendor) personnel in accordance with Dominion procedure MA-AA-1001, Supplemental Personnel, section 3.8.1, during the spring 2010 replacement of the Unit 2 turbine and exciter rotors was a performance deficiency. The performance deficiency was more than minor because it adversely affected the Initiating Events cornerstone objective of reliability because the failure to properly conduct procedure MA-AA-1001 directly resulted in the upset of plant stability by tripping the unit and the challenge of critical plant safety functions. Using IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, issued June 19, 2012, the finding screens to green because although a reactor trip occurred, the loss of mitigating equipment for transitioning the plant to a safe shutdown condition did not occur. There is no cross cutting aspect for this finding because the initial cause of the finding occurred more than 3 years ago following turbine and exciter rotor replacement.

(Section 4OA2.2)

Green.

A Green self-revealing finding was identified for failure to establish and implement adequate preventative maintenance for the mechanism operated cell (MOC) switches.

Specifically the licensee failed to recognize and recommend proper maintenance for these components on the C main feedwater pump motor circuit breakers.

The inspectors determined that the licensees failure to establish and implement adequate preventive maintenance for MOC switches in accordance with industry guidance through EPRI, the vendor, ABB, and operating experience was a performance deficiency. The performance deficiency was more than minor because it was associated with the Initiating Events cornerstone attribute of equipment performance and adversely affected the associated cornerstone objective in that loss of conductivity across contacts 25 and 26 in the upper MOC switch for circuit breaker 2-EP-BKR-25C5 caused the spurious closure of the C main feed pump discharge valve (2-FW-MOV-250C) and indirectly resulted in a manual reactor trip. Using Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, the finding was determined to be of very low safety significance (Green) because it was a transient initiator, but did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. In addition, this finding involved the cross cutting area of human performance, the component of decision making, and the aspect of systematic process for decision, H.1(a), because the licensee did not make risk-significant decisions using a systematic process for preventative maintenance activities when they failed to recognize and recommend proper maintenance for the MOC switches. (Section 4OA2.3)

REPORT DETAILS

Summary of Plant Status

Unit 1 began the period at full Rated Thermal Power (RTP). Unit 1 commenced ramp down on September 7, 2013 for a planned refueling outage. Unit 1 was off line on September 8, 2013 for the refueling outage, and remained off line for the rest of the report period.

Unit 2 operated at full RTP for the entire report period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Impending Adverse Weather Conditions

a. Inspection Scope

The inspectors performed a site specific weather related inspection due to anticipated adverse weather conditions. On July 11, 2013, the inspectors reviewed the licensee response to Tropical Storm Chantal which was expected to bring heavy winds and rains to the area. Specifically, the inspectors reviewed licensee adverse weather response procedures and site preparations including work activities that could impact the overall maintenance risk assessments.

b. Findings

No findings were identified.

1R04 Equipment Alignment

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 that critical components were properly aligned and to identify any discrepancies which could affect operability of the redundant train or backup system. Documents reviewed are listed in the Attachment.

  • Unit 1 1B and 1C Charging Pumps during planned maintenance on 1A Charging Pump

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Quarterly Fire Protection Walkdowns

a. Inspection Scope

The inspectors conducted focused tours of the five 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 8, CM-AA-FPA-101, Control of Combustible and Flammable Materials, Revision 4, and CM-AA-FPA-102, Fire Protection and Fire Safe Shutdown Review and Preparation Process and Design Change Process, Revision 4.

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.

  • Cable Tray Spreading Room Unit 1 and Unit 2
  • Auxiliary Building
  • Unit 1 Battery Rooms 1-I, 1-II, 1-III, 1-IV and Unit 2 Battery Rooms 2-I, 2-II, 2-III, 2-IV
  • Main and Station Service Transformers, Security Auxiliary Power Supply Building and Alternate AC Building
  • Turbine Building (including Chiller Rooms and Z-21B, Z-21C, Z-22, Z-34, Z-35, Z-36, and Z-46B) and Turbine Building Lube Oil Room

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation

a. Inspection Scope

During a fire protection drill on August 1, 2013, at the Unit 2 Station Service Transformer, the inspectors observed the station response of operations crew D and security crew B in an area that had not been tested since 2009. 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.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

.1 Internal Flooding

a. Inspection Scope

The inspectors assessed the internal flooding vulnerability of the Unit 1 and 2 Charging Pumps 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.

b. Findings

No findings were identified.

.2 Cables in Manholes/Underground Bunkers

a. Inspection Scope

The inspectors performed an annual review of cables located in underground bunkers/manholes for the Reserve Station Service Transformers. The inspectors evaluated, as appropriate, the two bunkers/manholes listed below for the following:

1) verified by direct observation that the cables were not submerged in water; 2) verified by direct observation that cables and/or splices appeared intact; 3) verified that drainage or an appropriate dewatering device (sump pump) was in operation; and 4) verified that level alarm circuits were set appropriately to ensure that the cables would not be submerged. Documents reviewed are listed in the Attachment to this report.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

Non-Destructive Examination Activities and Welding Activities

a. Inspection Scope

From September 16-27, 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 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,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 Ultrasonic (UT) examinations of 11715-WMKS-0102A/16-WFPD-24/9A, elbow to nozzle weld on SG A

  • Reviewed records o UT examinations of 11715-WMKS-0102B/16-WFPD-23/17A, elbow to nozzle weld on SG B o UT examinations of 11715-WMKS-0102C/16-WFPD-22/18A, elbow to nozzle weld on SG C o UT examinations of 11715-WMKS-0110A/6-RC-39/PWOL-2, pressurizer (PZR)nozzle to pipe weld overlay o UT examinations of 11715-WMKS-0110A/6-RC-38/PWOL-3, PZR nozzle to pipe weld overlay o UT examinations of 11715-WMKS-0110A/6-RC-37/PWOL-4, PZR nozzle to pipe weld overlay The inspectors reviewed documentation for the repair/replacement of the following pressure boundary welds. The inspectors evaluated if the licensee applied the pre-service non-destructive examinations and acceptance criteria required by the Construction Code. In addition, the inspectors reviewed the welding procedure specifications, welder qualifications, welding material certifications, and supporting weld procedure qualification records to evaluate if the weld procedures were qualified in accordance with the requirements of Construction Code and the ASME Code Section IX.

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

The inspectors reviewed the following 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.

  • CA 266810-Boric acid on valve 2-CH-223 packing
  • CA 266811-Boric acid leak from 2-CH-255 packing
  • North Anna Fall 2013 Steam Generator Assessment. The site specific assessment was compared with the guidance contained in Electric Power and Research Institute (EPRI) Pressurized Water Reactor Steam Generator Guideline, Revision 7, and EPRI "Steam Generator Integrity Assessment Guidelines", Revision 3.
  • The inspectors compared the site specific assessment with the eddy current inspection plan to determine if the results of the assessment were adequately reflected in the scope of inspection.
  • Evaluated if the licensees SG tube ET 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 inspection scope. The inspectors reviewed the results of the eddy current inspection for the current outage and no new degradation mechanisms were identified during the EC examinations.
  • The inspectors discussed the results of the inspection with licensee staff and vendor eddy current inspection personnel.
  • Reviewed the licensees secondary side SG Foreign Object Search and Removal activities. The inspectors reviewed secondary side inspections of the post sludge-lancing and Steam Drum inspections of SG C. The inspectors reviewed the history of secondary side sludge taken from the generators. These results were compared with the results of plugging and sludge removal from previous outages.

There was no in-situ pressure testing required during this outage. There was no tube leakage prior to the beginning of the outage thus no repairs undertaken during this outage. The inspector performed a sample review of inspections of steam generator tubes with eddy current to determine if proper analysis techniques were applied and reviewed the analysis of data performed by the vendor/licensee.

Identification and Resolution of Problems:

The inspectors performed a review 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 10CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements.

Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Resident Inspector Quarterly Review

a. Inspection Scope

The inspectors reviewed licensed operator performance on July 31, 2013, during a simulator scenario which involved a main turbine generator governor valve failure, a pressurizer spray valve failure, and the loss of the auxiliary feed water to the steam generators following a reactor trip. 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 conducted three observations of licensed reactor operators actions and activities to ensure that the activities were consistent with the licensee procedures and regulatory requirements. These observations took place during both normal and off-normal 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.

The inspectors observed and assessed licensed operator performance during the following events:

  • Station Service Bus 2A Fuse replacement on July 24, 2013
  • Unit 1 RCS loop isolation and drain down on September 10, 2013

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

For the two 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.

  • Maintenance Rule Evaluation (MRE) 016578, MRE to Engineering to address SBO bldg damper issues noted on CR519879 and 519880
  • MRE016591, MRE: 1-HV-E-4 A Main Control Room (MCR) chiller tripped after placing in service

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

1) effectiveness of the risk assessments performed before maintenance activities were conducted; 2) management of risk; 3) upon identification of an unforeseen situation, necessary steps were taken to plan and control the resulting emergent work activities; and 4) maintenance risk assessments and emergent work problems were adequately identified and resolved. 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.

  • Risk review for emergent work on July 15, 2013
  • Emergent work for undervoltage (UV)/underfrequency (UF) fuse replacements on August 22, 2013

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed five 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 compensating 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 (ODs) were made as specified by procedure OP-AA-102, Operability Determination, Revision 10.

  • Review of OD000546, "Station Service Busses 2A-2B-2C UV Relay Trouble Alarm
  • Review of OD000548, OD for North Anna 1 cycle 24 fuel rod bow
  • Review of OD000550, Perform a formal evaluation on containment peak pressure calculations

b. Findings

No findings were identified.

1R18 Plant Modifications

Permanent Modifications

a. Inspection Scope

The inspectors reviewed the completed permanent plant modification design change package DC-NA-12-00066, Unit 2 Auxiliary Feedwater and RWST FLEX Mechanical Connections for Beyond Design Basis Events. The inspectors conducted a walkdown of the installation, discussed the desired improvement with system engineers, and reviewed the 10 CFR 50.59 Safety Review/Regulatory Screening, technical drawings, test plans and the modification package to assess the TS implications.

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

Inspection Scope The inspectors reviewed five 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.

  • 1-PT-75.2B.1, Service Water Pump (1-SW-P-1B) Head Curve Verification, Revision 31, for Work Order (WO) 59102619158
  • 0-PT-100.1.2, Diesel Driven Fire Protection Pump 1-FP-P-2 Exercise, Revision 17
  • 1-PT-14.1, Charging Pump 1-CH-P-1A, Revision 51
  • WO59102632580, 1-CC-P-1B, Drain, Flush, Refill Inboard Bearing Reservoirs

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 1 refueling outage, which began September 8, 2013, 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 used NRC inspection procedure 71111.20, Refueling and Outage Activities, to observe portions of the shutdown, cooldown, 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, and to confirm that the licensee has mitigation strategies in place for losses of key safety functions, as well as to ensure that configuration changes due to emergent work and unexpected conditions are controlled in accordance with the outage risk control plan.
  • Implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing.
  • Installation and configuration of reactor coolant pressure, level, and temperature instruments 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.
  • Controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system.
  • Reactor water inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss.
  • Controls over activities that could affect reactivity.
  • Licensee identification and resolution of problems related to refueling outage activities.
  • Performance of fuel handling operations (removal, inspection, sipping, reconstitution, and insertion) in accordance with TS and approved procedures.
  • Tracking of fuel assemblies locations from core off-load through core reload.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

For the five 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.

In-Service Test:

  • 2-PT-71.3Q.1, 2-FW-P-3B, A Motor-Driven AFW IST Comprehensive Pump and Valve Test, Revision 10 Other Surveillance Tests:

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation Simulator Drill

a. Inspection Scope

On July 30, 2013, the inspectors observed the licensee simulator based training that involved an unplanned actuation of the EDG 1H CARDOX system, a large break loss of cooling accident with the failure of the A and B quench spray pumps, loss of fuel clad and reactor coolant system barriers with the potential loss of containment. The inspectors assessed emergency procedure usage, emergency plan classification, notification, and the licensees identification and entrance of any problems into their corrective action program (CAP). This inspection evaluated the adequacy of the licensees conduct of the drill and critique performance. Drill issues were captured by the licensee in the CAP as CR521966

b. Findings

No findings were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors performed a periodic review of the following five Unit 1 and 2 PIs 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 6. 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, 2012 through June 30, 2013. Documents reviewed included applicable NRC inspection reports, licensee event reports, operator logs, station performance indicators, and related CRs.

  • Emergency AC Power Systems (MS06)
  • High Pressure Injection Systems (MS07)
  • Heat Removal Systems (MS08)
  • Cooling Water Systems (MS10)

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Review of Items Entered into the Corrective Action Program

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.

Documents reviewed are listed in the Attachment.

.2 Annual Sample: Review of Root Cause Evaluation (RCE) 001100, RCE to Eng for U2

Manually Tripped due to Increased Vibrations on #9 Bearing

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for RCE001100, RCE to Eng for U2 manually tripped due to increased vibrations on #9 bearing 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 RCE against the requirements of the licensees CAP as specified in procedure, PI-AA-200, Corrective Action Program, Revision 21 and 10 CFR 50, Appendix B.

b. Findings and Observations

Introduction:

A Green self-revealing finding was identified for the failure to properly provide oversight over supplemental (vendor) personnel during the replacement of the Unit 2 turbine and exciter rotors during the spring of 2010 in accordance with Dominion procedure MA-AA-1001, Supplemental Personnel, Revision 9.

Description:

On May 10, 2013, Unit 2 reactor was manually tripped from 60% power due to indications of increased vibrations on the #9 turbine/generator bearing and observations of a luminous discharge on the Unit 2 Exciter revealed between the #9 bearing housing and the exciter fan. The alignment dowel was improperly installed by supplemental (vendor) personnel during the spring 2010 refueling outage. During turbine operation, a ground developed on the #9 pedestal which allowed electrical erosion to remove material from the bearing surface causing a hydraulic rub on the #9 bearing and improper bearing loading caused by misalignment of the #9 bearing pedestal. During the turbine bearing failure investigation, the licensee determined that the #9 pedestal bearing alignment had been adjusted by the vendor without knowledge of the licensee.

Dominion procedure MA-AA-1001, Supplemental Personnel, section 3.8.1, requires oversight over supplemental (vendor) personnel involving work activities at the station.

The licensee did not have adequate knowledge of the activities being performed by the vendor and did not adequately question or verify proper installation of the turbine and exciter rotor by the vendor. The cyclical vibrations became more pronounced over time until they became severe enough to prompt the unit operators to trip the reactor and the turbine to prevent further damage to the turbine beyond the turbine/generator bearings.

Analysis:

The failure to properly provide oversight over supplemental (vendor)personnel in accordance with Dominion procedure MA-AA-1001, Supplemental Personnel, section 3.8.1, during the spring 2010 replacement of the Unit 2 turbine and exciter rotors was a performance deficiency. The performance deficiency was more than minor because it adversely affected the Initiating Events cornerstone objective of reliability because the failure to properly conduct procedure MA-AA-1001 directly resulted in the upset of plant stability by tripping the unit and the challenge of critical plant safety functions. Using IMC 0609, Appendix A, The Significance Determination Process for Findings at Power, issued June 19, 2012, the finding screens to green because although a reactor trip occurred, the loss of mitigating equipment for transitioning the plant to a safe shutdown condition did not occur. There is no cross cutting aspect for this finding because the initial cause of the finding occurred more than 3 years ago following turbine and exciter rotor replacement.

Enforcement:

This finding did not involve enforcement action. Because this finding is of very low safety significance, Green, and was it was entered into the licensees CAP as CR 515250 this finding is identified as FIN 05000339/2013004-01, Failure to Provide Vendor Oversight Results in a Manual Reactor Trip.

.3 Annual Sample: Review of RCE001101, Unit 2 Reactor Trip Due to Secondary

Feedwater Transient

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for RCE001101, Unit 2 Reactor Trip Due to Secondary Feedwater Transient, 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 RCE against the requirements of the licensees CAP as specified in procedure, PI-AA-200, Corrective Action Program, Revision 21 and 10 CFR 50, Appendix B.

b. Findings and Observations

Introduction:

A Green, self-revealing finding was identified for failure to establish and implement adequate preventative maintenance (PM) for the mechanism operated cell (MOC) switches. Specifically the licensee failed to recognize and recommend proper maintenance for these components on the C main feedwater pump motor circuit breakers.

Description:

On May 28, 2013 at 1507 hours0.0174 days <br />0.419 hours <br />0.00249 weeks <br />5.734135e-4 months <br />, Unit 2 was manually tripped from approximately 98 percent power due to a spurious closure of C main feedwater pump discharge valve, auto-starting of B main feedwater pump, and the subsequent opening of the main feedwater recirculation valves, that resulted in the tripping of A main feedwater pump on low suction pressure. The operators manually tripped the reactor to prevent an automatic trip due to low-low steam generator levels. The investigation determined that loss of conductivity across contacts 25 and 26 in the upper MOC switch (AF 52S) in 1C1 Main Feedwater Pump Motor Circuit breaker 2-EP-BKR-25C5, caused the spurious closure of the C main feedwater pump discharge valve, 2-FW-MOV-250C.

The licensee attributed this to debris, hardening grease and/or linkage alignment/binding related to the upper MOC switch of 4160 volt circuit breaker 2-EP-BKR-25C5. Multiple opportunities existed through work management which could have prevented this spurious valve closure or uncovered additional problems with these MOC switches in 4160 volt circuit breakers. The licensee cancelled WO 59102527129 to perform work on breaker 2-EP-BKR-25C5 cell switch, based on a log entry on 10/19/2012. A design change was issued on October 27, 2012 indicating that work would be performed during the next Unit 2 outage in the spring of 2013. Since the work order was cancelled, no maintenance was performed during the spring 2013 refueling outage.

Procedure ER-AA-PRS-1010, Preventative Maintenance Task Basis and Maintenance Strategy, Revision 4, requires that when developing PM Basis and Maintenance Strategies, ensure component level replacement recommendations are developed with consideration of the component manufacturer guidance when available. The MOCs did not have any component classification and did not have a specific PM basis or maintenance strategy. In addition, ER-AA-PRS-1010, also states that changes to the maintenance strategy should include items such as industry operating experience (vendor, EPRI, INPO, new predictive technology). ABB, the circuit breaker vendor, communicated to the industry through the EPRI Circuit Breaker Users Group, failure of cell switches due to excess grease and the need to refurbish cell switches. Industry guidance through EPRI, ABB, and operating experience have shown that MOCs were a known industry issue for over 10 years and replacement was recommended at the same time as the breaker which would occur every 9 years. The licensee was informed of this replacement recommendation frequency but chose to only perform visual and functional testing of the MOCs. The licensee was also aware of MOC operating experience failures related to debris, hardening grease and/or linkage alignment/binding issues; however, the licensee did not implement this maintenance practice.

Analysis:

The inspectors determined that the licensees failure to establish and implement adequate preventive maintenance for MOC switches in accordance with industry guidance through EPRI, the circuit breaker vendor, ABB, and operating experience was a performance deficiency. The performance deficiency was more than minor because it was associated with the Initiating Events cornerstone attribute of equipment performance and adversely affected the associated cornerstone objective in that loss of conductivity across contacts 25 and 26 in the upper MOC switch for circuit breaker 2-EP-BKR-25C5 caused the spurious closure of the C main feedwater pump discharge valve (2-FW-MOV-250C) and resulted in a manual reactor trip. Using Inspection Manual Chapter 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, the finding was determined to be of very low safety significance (Green) because it was a transient initiator, but did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions would not be available. In addition, this finding involved the cross cutting area of human performance, the component of decision making, and the aspect of systematic process for decision, H.1(a), because the licensee did not make risk-significant decisions using a systematic process for preventative maintenance activities when they failed to recognize and recommend proper maintenance for the MOC switches.

Enforcement:

This finding did not involve enforcement action. Because this finding was determined to be of very low safety significance, Green, and was entered into the licensees CAP as CR516848 this finding is identified as FIN 05000339/2013004-02, Failure to Establish and Implement Adequate Preventative Maintenance Causes a Reactor Trip.

.4 Annual Sample: Review of ACE019510, 1-HV-E-4A A MCR Chiller Tripped After

Placing in Service

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for ACE019510, ACE: 1-HVV-E-4A A MCR Chiller tripped after placing in service, 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 ACE against the requirements of the licensees CAP as specified in procedure, PI-AA-200, Corrective Action Program, Revision 21 and 10 CFR 50, Appendix B.

b. Findings and Observations

No findings were identified. In general, the inspectors verified that the licensee had identified problems at an appropriate threshold and entered them into the CAP database as CR520180, and had proposed or implemented appropriate corrective actions.

4OA3 Event Followup

.1 (Closed) Licensee Event Report (LER) 05000339/2013-001-00: Manual Reactor Trip

due to Increased Vibration on Main Turbine/Generator Bearing Number 9 On May 10, 2013, with Unit 2 in Mode 1, 60 percent power following a refueling outage, a manual reactor trip was initiated as a result of increased vibrations on the number 9 main turbine/generator bearing and a report of luminous discharge in the main generator exciter enclosure. The auxiliary feed water pumps received an automatic start signal due to the resulting low-low level in the C steam generator. The direct cause of the event was a combination of the alignment dowel causing a ground on the number 9 bearing pedestal which allowed electrical erosion to remove material from the bearing surface causing a hydraulic rub on the number 9 bearing, and improper bearing loading caused by misalignment of the number 9 bearing pedestal. The licensee entered this problem in their CAP as CR515250. Corrective actions are being tracked under RCE001100. The findings aspect of this issue is as discussed in section 4OA2.2 of this inspection report. This LER is closed.

.2 (Closed) Licensee Event Report (LER) 05000339/2013-002-00: Manual Reactor Trip

due to Closure of 2-FW-MOV-250C and Auto-Start of 2-FWP-1B On May 28, 2013, with Unit 2 operating at 98 percent power, Mode 1, and ramping up in power, a manual reactor trip was initiated due to a main feed water system transient.

The main feed water system transient resulted from the spurious closure of the C main feed water pump discharge motor-operated valve. The manual reactor trip was initiated to preclude an automatic reactor trip due to low-low steam generator levels. The steam generator levels were subsequently restored to normal operating level and the AFW pumps were secured and returned to automatic. The licensee entered this problem in their CAP as CR516848. Corrective actions are being tracked under RCE001101. The findings aspect of this issue is as discussed in section 4OA2.3 of this inspection report.

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 the 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 review and inspection activities.

b. Findings

No findings were identified.

.2 (Closed) Unresolved Item Report (URI) 05000338, 339/2012-003, Examination of SG

Safe-End Weld with Possible Unqualified Ultrasonic (UT) Examination

a. Inspection Scope

URI 05000338/2012003-02, Examination of SG Safe-End Weld with Possible Unqualified Ultrasonic Examination Procedures, was opened in NRC Inspection Integrated Report 05000338/2012003. This URI consisted of the resolution of questions on performing UT examinations on the SG nozzle safe-end welds with procedures and techniques that were performed with the intention to meet the for qualification requirements in accordance with 10CFR50.55a, ASME CC-770-01 and Appendix VIII of Section XI. The issue remained unresolved until questions associated with the qualification of the UT procedure and the adequacy of the site specific mock-ups was resolved.

This issue was subject to continued review by the NRC headquarters staff and the industry group EPRI/PDI for resolution. Although there were changes to the EPRI/PDI documents clarifying the requirements for site specific mock ups and procedure qualification of procedures and UT techniques for site specific configurations, the NRC headquarters staff is continuing its review with industry groups on the acceptance of these changes. This effort is being tracked as an industry issue by the NRC headquarters staff and will be closed as an industry generic issue. Since this issue is being followed by the headquarters staff, and the issue is no longer a North Anna specific issue, this URI is closed.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On October 29, 2013, the senior resident inspector presented the inspection results to Mr. G. Bischof and other members of the staff, who acknowledged the findings. The inspectors verified no proprietary information was retained by the inspectors or documented in this report.

ATTACHMENT: SUPPPLEMENTAL INFORMATION

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

M. Becker, Manager, Nuclear Outage and Planning
G. Bischof, Site Vice President
D. Blakeney, Director, Nuclear Station Safety & Licensing
B. Britt, Boric Acid Program Engineer
C. Cherry, ISI Program Engineer
J. Daugherty, Manager, Nuclear Maintenance
B. Derreberry, Engineering Programs Supervior
R. Evans, Manager, Radiological Protection
B. Gaspar, Manager, Nuclear Site Services
R. Hanson, Manager, Nuclear Protection Services
E. Hendrixson, Director, Nuclear Site Engineering
S. Hughes, Manager, Nuclear Operations
P. Kemp, Supervisor, Station Licensing
J. Leberstien, Technical Advisor Licensing
C. McClain, Manager, Nuclear Training
F. Mladen, Plant Manager
J. Plossl, Supervisor, Nuclear Station Procedures
J. Schleser, Manager, Nuclear Organizational Effectiveness
R. Stack, NDE Lead
T. Tessier, SG Program Engineer
M. Whalen, Technical Advisor Licensing

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Opened and Closed:

05000339/2013004-01 FIN Failure to Provide Vendor Oversight Results in a Manual Reactor Trip (Section 4OA2.2)
05000339/2013004-02 FIN Failure to Establish and Implement Adequate Preventative Maintenance Causes a Reactor Trip (Section 4OA2.3)

Closed:

05000339/2013-001-00 LER Manual Reactor Trip due to Increased Vibration on Main Turbine/Generator Bearing Number 9 (Section 4OA3.1)
05000339/2013-002-00 LER Manual Reactor Trip due to closure of 2-FW-MOV-250C and Auto-Start of 2-FWP-1B (Section 4OA3.2)
05000338/2012003-02 URI Examination of SG Safe-End Weld with Possible Unqualified Ultrasonic Examination (Section 4OA5.2)

LIST OF DOCUMENTS REVIEWED

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