IR 05000338/2014003

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IR 05000338-14-003, 05000339-14-003; on 04/01/2014 - 06/30/2014; North Anna Power Station, Units 1 and 2: Fire Protection, Problem Identification and Resolution
ML14224A152
Person / Time
Site: North Anna  Dominion icon.png
Issue date: 08/12/2014
From: Mark King
NRC/RGN-II/DRP/RPB5
To: Heacock D
Virginia Electric & Power Co (VEPCO)
References
IR-14-003
Download: ML14224A152 (26)
v • d • e


Text

UNITED STATES ust 12, 2014

SUBJECT:

NORTH ANNA POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000338/2014003 AND 05000339/2014003

Dear Mr. Heacock:

On June 30, 2014, the U. S. Nuclear Regulatory Commission (NRC) completed an inspection at your North Anna Power Station, Units 1 and 2. On July 30, 2014, 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).

One of these findings was determined to be a violation of NRC requirements. Additionally, a licensee-identified violation which was determined to be of very low safety significance is listed in this report. The NRC is treating these as non-cited violations (NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy.

If you contest these non-cited violations, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington DC 20555-001; 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 or a finding not associated with a regulatory requirement 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:

Inspection Report 05000338/2014003, and 05000339/2014003 w/ Attachment: Supplemental Information

REGION II==

Docket Nos: 50-338, 50-339 License Nos: NPF-4, NPF-7 Report No: 05000338/2014003, and 05000339/2014003 Licensee: Virginia Electric and Power Company (VEPCO)

Facility: North Anna Power Station, Units 1 & 2 Location: Mineral, Virginia 23117 Dates: April 1, 2014 through June 30, 2014 Inspectors: G.Kolcum, Senior Resident Inspector R. Clagg, Resident Inspector S. Herrick, Acting Resident Inspector Approved by: Michael F. King, Chief Reactor Projects Branch 5 Division of Reactor Projects Enclosure

SUMMARY

IR 05000338/2014-003, 05000339/2014-003; 04/01/2014 - 06/30/2014; North Anna Power

Station, Units 1 and 2: Fire Protection, Problem Identification and Resolution The report covered a three-month period of inspection by resident inspectors. One self-revealing finding and one self-revealing non-cited violation (NCV) were identified. The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). 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 5, dated February 2014.

Cornerstone: Initiating Events

Green.

A self-revealing finding was identified for failure to follow procedure after a feedwater transient that resulted in a Unit 2 manual trip. Specifically, the licensee failed to use diverse or alternate indications, such as motor amps, feedwater pump discharge pressure, feedwater flow, or steam generator levels as required by both OP-AA-100,

Conduct of Operations, Revision 25, and OP-AA-1800, Operator Fundamentals,

Revision 7, after the loss of A main feedwater pump and the C main feedwater pump motor breaker closed red light failed to light.

The inspectors determined that the failure of the licensee to use diverse or alternate indications, as required by plant procedures, when deciding to trip the Unit 2 reactor was a performance deficiency. The performance deficiency was more than minor because it was associated with the Initiating Events cornerstone attribute of human performance and adversely affected the associated cornerstone objective to limit the likelihood of events that upset plant stability. Specifically, the human error associated with not using diverse or alternate indications resulted in an unnecessary plant trip. Using IMC 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 and the aspect of teamwork, H.4, because the licensee failed to communicate and coordinate actions when verifying the proper operation of the C main feedwater pump after auto start. The licensee is tracking this issue in their corrective action system as Condition Report (CR) 538653. (Section 4OA2.3)

Cornerstone: Mitigating Systems

Green.

A self-revealing NCV was identified for the licensees failure to meet the requirements of NAPS Renewed Operating License Conditions 2.D, and the approved FPP for NAPS, Units 1 and 2. Specifically, the licensee failed to maintain the diesel driven fire pump water pump with established procedures that incorporated the equipment manufacturers recommended maintenance.

Failure to maintain the diesel-driven fire pump water pump with established procedures that incorporated the equipment manufacturers recommended maintenance is a performance deficiency. This finding was determined to be more than minor because it was associated with the reactor safety mitigating systems cornerstone attribute of protection against external events (i.e. fire), and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the finding impacted the availability of the diesel driven fire pump which adversely impacted the fire protection programs defense-in-depth in the event of a fire. The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011,

Attachment 4, Initial Characterization of Findings, dated June 19, 2012, which determined that an IMC 0609 Appendix F, Fire Protection Significance Determination Process, dated September 20, 2013, review was required as the finding affected fire water supply. The inspectors evaluated this finding using the guidance in IMC 0609, Appendix F. The pump failed on November 8, 2013, and the last successful test was performed on November 7, 2013. The review determined that the unaffected motor driven fire pump was available to provide at least 50 percent of the required fire water capacity (flow at required pressure) and therefore the finding screened as very low safety significance (Green). The inspectors determined that there was no cross-cutting aspect associated with this finding because it was not reflective of current licensee performance. The violation was entered into the licensees corrective action program (CAP) as CR532383. (Section 1R05)

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 and operated at full power for the entire report period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Review of Offsite Power and Alternate AC Power Readiness

a. Inspection Scope

The inspectors verified that plant features and procedures for operation and continued availability of offsite and alternative alternating current (AC) power systems were appropriate. The inspectors reviewed the licensees procedures affecting those areas, and the communications protocols between the transmission system operator and the nuclear power plant to verify that the appropriate information was exchanged when issues arose that could impact the offsite power system. The inspectors evaluated the readiness of the offsite and alternative AC power systems by reviewing the licensees procedures that address measures to monitor and maintain the availability and reliability of the offsite and alternative AC power systems.

b. Findings

No findings were identified.

.2 Impending Adverse Weather Conditions

a. Inspection Scope

The inspectors performed a site specific weather related inspection due to anticipated adverse weather conditions. Between April 29 and April 30, 2014, the inspectors reviewed the licensee response to heavy winds and rains in the area which caused local flooding and necessitated lake level moderation. 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.

.3 Seasonal Susceptibilities

a. Inspection Scope

The inspectors reviewed the licensees adverse weather preparations for hot weather operations, specified in 0-GOP-4.1, Hot Weather Operations, Revision 32, and the licensees CAP database for hot weather related issues. The inspectors walked down two risk-significant systems/areas listed below to verify compliance with the procedural requirements and to verify that the specified actions provided the necessary protection for the structures, systems, or components.

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.

  • Unit 2 Main Control Room air conditioning during maintenance on 4C Main Control Room chiller
  • 1H and 2J EDGs during partial loss of offsite power (LOOP) event on May 15, 2014
  • A Reserved Station Service Transformers (RSST) trouble alarm

b. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Fire Protection Walkdowns

a. Inspection Scope

The inspectors conducted focused tours of the eight 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.
  • Main Control Room
  • Turbine Building including Chiller Rooms and Lube Oil Room
  • Service Water (SW) Pump House, Auxiliary SW Pump House, Motor-Driven Fire Pump House and SW Valve House
  • Main and Station Service Transformers, Security Auxiliary Power Supply Building, Alternate AC Building

b. Findings

Introduction:

A Green self-revealing non-cited violation (NCV) was identified for the licensees failure to meet the requirements of North Anna Power Station (NAPS)

Renewed Operating License Conditions 2.D, and the approved Fire Protection Program (FPP) for NAPS, Units 1 and 2. Specifically, the licensee failed to maintain the diesel driven fire pump water pump with established procedures that incorporated the equipment manufacturers recommended maintenance.

Description:

NAPS FPP requires the licensee to maintain two 100 percent capacity fire pumps so that 100 percent capacity will be available with one pump inactive. One pump is electrically driven while the other is powered from a diesel engine.

Beginning on October 21, 2013, a sequence of test and maintenance activities for the diesel driven fire pump identified abnormal indications in crankcase oil sample results; coolant level; and pump speed and pressure. On November 12, 2013, metal particles were found in the oil filter and approximately two gallons of coolant was drained out of the oil pan. The engine was subsequently replaced with a spare engine and the failed engine was sent to the vendor to determine the failure.

The vendor determined that the failure was due to overheating. The apparent cause of the engine overheating was due to a failed water pump. The water pump was discovered to have severe erosion of the impellor vanes.

The licensees administrative procedure, VPAP-0502, Procedure Process Control, Revision 58, has a reference step, 3.2.30, Generic Letter 83-28, Revise maintenance procedures, to ensure previous vendor and engineering recommendations are incorporated. In addition, Step 4.28, Verification, and substep 4.28.2, Technical Review, requires, A review to verify the technical accuracy of the procedure using technical experience, plant drawings, vendor manuals, and associated technical information.

The licensees maintenance was controlled by procedure 0-MPM-0107-01, Diesel Fire Pump Preventive Maintenance, Revision 16. Section 6.23 covers water pump maintenance which checks for bearing wear and lubricates the bearings if equipped with grease fittings. The vendor technical manual or equipment manufacturer recommends lubrication of the bearings if equipped with grease fittings and to completely disassemble, clean, and inspect the water pump; and, if there are no grease fittings, to completely disassemble, clean, and inspect of the water pump more frequently.

Inspectors identified that the licensees maintenance procedure did not include the step to disassemble, clean, and inspect the water pump. The inspectors reviewed the equipment manufacturers recommended maintenance, and the maintenance strategy as documented in Engineering Work Request 87-430, Eval 1-FP-P-2 Maint VS. Tech Spec & Vendor Requirements, dated April 20, 1989, and concluded the licensees maintenance strategy failed to include the manufacturer recommended maintenance to completely disassemble, clean, and inspect of the water pump on a periodic basis.

Analysis:

Failure to maintain the diesel-driven fire pump water pump with established procedures that incorporated the equipment manufacturers recommended maintenance is a performance deficiency. This finding was determined to be more than minor because it was associated with the reactor safety mitigating systems cornerstone attribute of protection against external events (i.e. fire), and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the finding impacted the availability of the diesel driven fire pump which adversely impacted the fire protection programs defense-in-depth in the event of a fire. The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, which determined that an IMC 0609 Appendix F, Fire Protection Significance Determination Process, dated September 20, 2013, review was required as the finding affected fire water supply. The inspectors evaluated this finding using the guidance in IMC 0609, Appendix F. The pump failed on November 8, 2013, and the last successful test was performed on November 7, 2013.

The review determined that the unaffected motor driven fire pump was available to provide at least 50 percent of the required fire water capacity (flow at required pressure) and therefore the finding screened as very low safety significance (Green). The inspectors determined that there was no cross-cutting aspect associated with this finding because it was not reflective of current licensee performance.

Enforcement:

NAPS Renewed Operating License Condition 2.D, Fire Protection, for Units 1 and 2, states, in part, that the licensee shall implement and maintain in effect all provisions of the approved FPP as described in the UFSAR for the facility and as approved in the safety evaluation report dated February 1979. UFSAR, Section 9.5.1.1, Design Bases, identifies one requirement as the Stations FPP document which is procedure CM-AA-FPA-100, Fire Protection/Appendix R (Fire Safe Shutdown)

Program, Revision 9. Section 3.16 of the FPP procedure, Instructions, Procedures, and Drawings, states that the FPP is addressed, defined, and maintained, in part, by Station and Department Administrative Procedures. The station administrative procedure, VPAP-0502, Procedures Process Control, Revision 58, has a reference step, 3.2.30, Generic Letter 83-28, which requires revisions to maintenance procedures to ensure previous vendor and engineering recommendations are incorporated. In addition, Step 4.28, Verification, and substep 4.28.2, Technical Review, requires, A review to verify the technical accuracy of the procedure using technical experience, plant drawings, vendor manuals, and associated technical information.

Contrary to the above, since 1989, the licensee failed to implement and maintain in effect the approved FPP. Specifically, the diesel-driven fire pump maintenance procedure, 0-MPM-0107-01, did not incorporate the equipment manufacturers recommended maintenance for the water pump. 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 532383. This non-cited violation is identified as NCV 05000338, 339/2014003-01, Failure to Maintain the Diesel Driven Fire Pump.

1R06 Flood Protection Measures

Cables in Manholes/Underground Bunkers

a. Inspection Scope

The inspectors performed an annual review of cables located in underground bunkers/manholes. The inspectors evaluated, as appropriate, the security and electrical cable vaults 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.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Resident Inspector Quarterly Review

a. Inspection Scope

The inspectors reviewed a licensed operator performance on May 27, 2014, during a simulator scenario which involved a tube rupture on A steam generator requiring safety injection, which led to an Alert being declared. 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 Unit 1 and Unit 2 Partial LOOP with the C RSST on May 15, 2014, to ensure that the activities were consistent with the licensee procedures and regulatory requirements. This observation took place during 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.

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) 017468, Unit 1 C Blowdown radiation monitor appears to have failed low
  • MRE017416, The 26/48 VDC power supply in Unit 2 Hathaway System is bad

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors evaluated, as appropriate, the three 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.

  • Emergent work for A RSST maintenance from a failed cable on April 1, 2014
  • Updated maintenance risk assessment during heavy rains and forecasted thunderstorms with high winds on April 30, 2014
  • Unit 1 instrument air compressor motor failure on June 13, 2014

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

a. Inspection Scope

The inspectors reviewed seven 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 SDP. The inspectors review included a verification that operability determinations (OD) were made as specified by procedure OP-AA-102, Operability Determination, Revision 8.
  • OD000581, Evaluate the above ground supports for RSST overhead conduits
  • CR543641,1J EDG jacket coolant pump seal leak
  • CR543912, High iron count in 2-FW-P-2
  • CR546421, Unit 1 B component cooling pump outboard seal leakage
  • CR548667, Unit 1 B charging pump speed increaser oil pressure low
  • CR550998, Sink hole near Unit 2 casing cooling building

b. Findings

No findings were identified.

1R18 Plant Modifications

Permanent Modifications

a. Inspection Scope

The inspectors reviewed the two completed permanent plant modification design change packages noted below. The inspectors conducted a walkdown of the installations, 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 packages to assess the TS implications.

  • Design Change Package NA-13-00084, BDB Primary Grade Water Storage Tank 1-PG-TK-1A Flex Connection NAPS Unit 1
  • Design Change Package NA-14-00086, BDB Primary Grade Water Storage Tank 1-PG-TK-1B Flex Connection NAPS Unit 1

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors reviewed six 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-36.1B, Train B Reactor Protection and ESF Logic Actuation Test, Revision 67
  • 0-GOP-26.2, A RSST Load Tap Changer Functional Testing, Revision 5
  • WO591079941, Tan Delta Test of Transfer Bus D Underground Lines from A RSST

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

For the seven 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-63.1A.2, Quench Spray System - A Subsystem Comprehensive Pump Test, Revision 5
  • 2-PT-63.1B, Quench Spray System - B Subsystem Comprehensive Pump Test, Revision 6 Other Surveillance Tests:
  • 1-PT-36.1A, Train A Reactor Protection and ESF Logic Actuation Logic Test, Revision 66
  • 1-PT-60.5, Safeguard Valve Pit Valves, Revision 12
  • 2-PT-60.5, Safeguard Valve Pit Valves, Revision 12

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation Simulator Drill

a. Inspection Scope

On June 3, 2014, the inspectors observed the licensee simulator based training that involved a hostile action based drill affecting the auxiliary feedwater pump house, a loss of AFW, and a loss of spent fuel pool cooling, which required a General Emergency to be declared. The inspectors assessed emergency procedure usage, emergency plan classification, notification, and the licensees identification and entrance of any problems into their CAP. This inspection evaluated the adequacy of the licensees conduct of the drill and critique performance.

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 two Unit 1 and 2 Barrier Integrity 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 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 April 1, 2013 through March 31, 2014. Documents reviewed included applicable NRC inspection reports, licensee event reports, operator logs, station performance indicators, and related CRs.

  • RCS Specific Activity (BI01)

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.

.2 Annual Sample: Review of CA273254, Investigate 1-FP-P-2 to support 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 CR against the requirements of the licensees CAP as specified in procedure, PI-AA-200, Corrective Action Program, Revision 22, 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, and had proposed or implemented appropriate corrective actions.

.3 Annual Sample: Review of RCE01115, Unit 2 Reactor tripped following 2-FW-P-1A

motor faulted

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for RCE01115, Unit 2 Reactor tripped following 2-FW-P-1A motor faulted, 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 22, and 10 CFR 50, Appendix B.

b. Findings and Observations

Introduction:

A Green self-revealing finding was identified for failure to follow procedure after a feedwater transient that resulted in a Unit 2 manual trip. Specifically, the licensee failed to use diverse or alternate indications, such as motor amps, feedwater pump discharge pressure, feedwater flow, or steam generator levels as required by both OP-AA-100, Conduct of Operations, Revision 25, and OP-AA-1800, Operator Fundamentals, Revision 7, after the loss of A main feedwater pump and the C main feedwater pump motor breaker closed red light failed to light.

Description:

On February 2, 2014, Unit 2 was operating at 100 percent power with main feedwater being supplied by the A and B main feedwater pumps. At 0859 hours0.00994 days <br />0.239 hours <br />0.00142 weeks <br />3.268495e-4 months <br />, the A main feedwater pump failed and caused the C main feedwater pump to automatically start as designed. The shift manager performed a crew brief which was acknowledged by the crew members. The plant was stable and a reactor trip was not required with two running feed pumps. Following the crew brief, an operator identified that the C main feedwater pump motor breaker closed red light failed to light on the control board. The operator failed to use diverse or alternate indications, such as motor amps, feedwater pump discharge pressure, feedwater flow, or steam generator levels and, as a result, incorrectly concluded that the C main feedwater pump had not started as designed. The operator continued with the immediate actions of 2-AP-31, Loss of Main Feedwater, Revision 13, as required for one main feedwater pump running at 100 percent power and manually tripped the Unit 2 reactor. Subsequent repair activities revealed that the C main feedwater breaker closed red light did not illuminate due to a failed indicator light, however all alternate indications were indicating normally and were available to confirm that the C main feedwater pump had started and was operating properly.

OP-AA-100, Conduct of Operations, Revision 25, Attachment 1, Section 1.1, states operators utilize alternate indications to validate information. OP-AA-1800, Operator Fundamentals, Revision 7, Attachment 1, Section 3.j., states validate the accuracy and proper function of indications through multiple and diverse indications to confirm proper plant conditions and response, if available, avoiding undue focus on any single parameter.

Analysis:

The inspectors determined that the failure of the licensee to use diverse or alternate indications, as required by plant procedures, when deciding to trip the Unit 2 reactor was a performance deficiency. The performance deficiency was more than minor because it was associated with the Initiating Events cornerstone attribute of human performance and adversely affected the associated cornerstone objective to limit the likelihood of events that upset plant stability. Specifically, the human error associated with not using diverse or alternate indications resulted in an unnecessary plant trip. Using IMC 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 and the aspect of teamwork, H.4, because the licensee failed to communicate and coordinate actions when verifying the proper operation of the C main feedwater pump after auto start.

Enforcement:

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. Because this finding does not involve a violation and is of very low safety, it is identified as a FIN 05000339/2014003-02, Unit 2 Manual Reactor Trip After Loss of Main Feedwater Pump.

.4 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment and corrective maintenance issues but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.1. The review included issues documented outside the normal CAP in system health reports, corrective maintenance work orders, component status reports, site monthly meeting reports, and maintenance rule assessments. The inspectors review nominally considered the six month period of January 2014 through June 2014, although some examples expanded beyond those dates when the scope of the trend warranted.

The inspectors compared and contrasted their results with the results contained in the licensees latest integrated quarterly assessment report. Corrective actions associated with a sample of the issues identified in the licensees trend report were reviewed for adequacy. Trends noted by the inspectors were previously identified by the licensee and addressed in their CAP.

b. Assessment and Observations No findings were identified. In general, the licensee has identified trends and has addressed the trends with their CAP.

4OA3 Event Followup

.1 (Closed) Licensee Event Report (LER) 05000339/2013-003-00: 2A Station Service Bus

Under Frequency Protection Relay Inoperable Greater Than Technical Specification Completion Time On July 1, 2013, with Unit 2 operating at 100 percent power (Mode 1), the Unit 2 annunciator, 2G-B5 Station Service Busses 2A-2B-2C UV Relay Trouble, alarmed and locked in. Troubleshooting indicated that the under voltage (UV) relay monitoring B-C phase for Station Service Bus 2A had actuated. The 2A UV channel was placed into trip on July 3, 2013, per TS 3.3.1 Condition L, but the 2A under frequency (UF) channel was not placed into trip. A multi-discipline team which included the vendor had determined that the UF relay would remain operable with the degraded voltage. An OD was developed and approved to document the conclusion. However, on July 10, 2013, it was revealed through additional testing that the OD contained inaccurate information and the 2A UF relay would not operate within the required time frame, and therefore was inoperable. The 2A UF relay channel was placed in trip on July 10, 2013. A potential transformer blown fuse was replaced, and the UV and UF channels were restored to operable on July 22, 2013.

The inoperable UF channel was not placed into trip within the time limits of the TS. This is a condition prohibited by the TS and reportable pursuant to 10 CFR 50.73(a)(2)(i)(B).

The health and safety of the public were not affected by the event, and no significant safety consequences resulted. The safety function of UF monitoring was maintained by the two remaining operable channels. This is a licensee identified violation and is discussed in Section 4OA7 of this report. This issue is in the licensees CAP as CR520296, Unit 2 2A Underfrequency Relay Determined Non-Functional.

.2 (Closed) LER 05000339/2014-001-00: Manual Reactor Trip During Feedwater Transient

On February 2, 2014, with Unit 2 operating at 100 percent power, the A Main Feedwater (MFW) Pump had a motor lead connection that grounded and caused the power supply breakers for the pump to trip open. The standby pump auto started as designed. The Reactor Operator (RO) believed the standby pump did not auto start, since the control room indicating lights did not illuminate as expected. The RO believed that only one MFW pump was running with two required for operation greater than 70 percent power. Based on this indication and the perceived loss of MFW, the RO initiated a manual reactor trip as directed in procedures. Following the manual trip, the unit was stabilized in Mode 3 at normal reactor coolant temperature and pressure. The auxiliary feedwater pumps started automatically as designed and provided makeup flow to the steam generators.

This event was reportable per 10 CFR 50.72 (b)(3)(iv)(A) for the actuation of an engineered safety feature system. The health and safety of the public were not affected by this event because the reactor was placed in a safe condition by the RO. This is a self-revealing finding, FIN 05000338/2014-003, and the analysis aspects of this are discussed in Section 4OA2.3. This issue is in the licensees CAP as RCE001115, Unit 2 Reactor Tripped following 2-FW-P-1A motor faulted, and CR 538653, Unit 2 Reactor Trip.

4OA5 Other Activities

.1 Institute of Nuclear Power Operations (INPO) Plant Assessment Report Review

a. Inspection Scope

The DRP Branch Chief reviewed the final report for the INPO plant assessment of North Anna Power Station issued in July 2013. The report was reviewed to ensure that issues identified were consistent with the NRC perspectives of licensee performance and to verify if any significant safety issues were identified that required further NRC follow-up.

b. Findings

No findings were identified.

.2 Review of the Operation of an Independent Spent Fuel Storage Installation - Selected

Records Review (Inspection Procedure 60855.1)

a. Inspection Scope

Inspectors reviewed the normal operation of the Independent Spent Fuel Storage Installation (ISFSI). The inspectors walked down the ISFSI pad to assess the material condition of the casks, the installation of security equipment, and the performance of monitoring systems. The inspector reviewed procedure 0-OP-4.54, Transfer Cask/Dry Shielded Canister Transfer to ISFSI and Dry Shielded Canister Transfer Cask to Horizontal Storage Module, Revision 7, and observed the activities of transferring a loaded transfer cask to the transfer trailer. The operation was conducted in a safe manner and in compliance with the procedure.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On July 30, 2014, 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.

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 the NRC Enforcement Policy, Section 2.3.2, for being dispositioned as an NCV:

The failure of the licensee to place the 2A Under Frequency (UF) channel into trip on July 3, 2013, per TS 3.3.1 Condition L constituted a violation of TS. The channel should have been placed in trip within 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br />. After further testing by the licensee, the 2A UF relay channel was placed in trip on July 10, 2013. A potential transformer blown fuse was replaced and the UV and UF channels were restored to operability on July 22, 2013. The safety function of UF monitoring was maintained by the two remaining operable channels. Using IMC 0609, Attachment 4, Initial Characterization of Findings, issued June 19, 2012, the finding was determined to be of very low safety significance (Green) because the finding was not a deficiency affecting the design or qualification of mitigating SSCs, does not represent a loss of system or function, does not represent an actual loss of function of at least a single Train greater than its TS allowed outage time, and does not represent an actual loss of function of one or more non-TS trains of equipment.

This issue is in the licensees CAP as CR520296, Unit 2 2A Underfrequency Relay determined Non-Functional.

ATTACHMENT: SUPPPLEMENTAL INFORMATION

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

M. Becker, Manager, Nuclear Outage and Planning
G. Bischof, Site Vice President
J. Daugherty, Director, Nuclear Station Safety & Licensing
R. Evans, Manager, Nuclear Training
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
J. Leberstein, Technical Advisor, Licensing
F. Malden, Plant Manager
J. Plossl, Supervisor, Nuclear Station Procedures
J. Schleser, Manager, Nuclear Organizational Effectiveness
J. Slattery, Manager, Nuclear Operations
M. Whalen, Technical Advisor, Licensing

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Opened and Closed

05000338, 339/2014003-01 NCV Failure to Maintain the Diesel Driven Fire Pump (Section 1R05)
05000339/2014003-02 FIN Unit 2 Manual Reactor Trip After Loss of Main Feedwater Pump (Section 4OA2.3)

Closed

05000339/2013-003-00 LER 2A Station Service Bus UnderFrequency Protection Relay Inoperable Greater Than Technical Specification Completion Time (Section 4OA3.1)
05000339/2014-001-00 LER Manual Reactor Trip During Feedwater Transient (Section 4OA3.2)

Discussed

None

LIST OF DOCUMENTS REVIEWED

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