Text

IR 05000338/2015002, 05000339/2015002; on 04/01/2015 - 06/30/2015; North Anna Power Station, Units 1 and 2, Maintenance Effectiveness
	ML15218A487
Person / Time
Site:	North Anna
Issue date:	08/06/2015
From:	Steven Rose; NRC/RGN-II/DRP/RPB5
To:	Heacock D; Virginia Electric & Power Co (VEPCO)
References
	IR 2015002
	Download: ML15218A487 (45)
	v • d • e

August 6, 2015

SUBJECT:

NORTH ANNA POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000338/2015002 and 05000339/2015002

Dear Mr. Heacock:

On June 30, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your North Anna Power Station Units 1 and 2. On July 29, 2015, 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.

The inspection examined activities conducted under your licenses as they related to safety and compliance with the Commissions rules and regulations and with the conditions of your licenses. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

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

If you wish to contest this NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington, DC 20555-001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the North Anna Power Station.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a response within 30 days of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at the North Anna Power Station. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390 of the NRCs Agency Rules of Practice and Procedure, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs Agencywide Document Access and Management System (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Steven D. Rose, Chief

Reactor Projects Branch 5

Division of Reactor Projects

Docket Nos.: 05000338, 05000339 License Nos.: NPF-4, NPF-7

Enclosure:

IR 05000338/2015002 and 05000339/2015002 w/Attachment: Supplementary Information

REGION II==

Docket Nos:

50-338, 50-339

License Nos:

NPF-4, NPF-7

Report No:

05000338/2015002 and 05000339/2015002

Licensee:

Virginia Electric and Power Company (VEPCO)

Facility:

North Anna Power Station, Units 1 & 2

Location:

Mineral, Virginia 23117

Dates:

April 1, 2015 through June 30, 2015

Inspectors:

G.Kolcum, Senior Resident Inspector

G. Skaggs Ryan, Resident Inspector C. Fontana, Emergency Preparedness Inspector, Sections 1EP2, 1EP3, 1EP4, 1EP5, and 4OA1 S. Sanchez, Senior Emergency Preparedness Inspector, Sections 1EP2, 1EP3, 1EP4, 1EP5, and 4OA1

R. Hamilton, Senior Health Physicist, Section 2RS8

R. Kellner, Senior Health Physicist, Sections 2RS6 and 4OA1 W. Pursley, Health Physicist, Sections 2RS7 and 4OA1

Approved by:

Steven D. Rose, Chief Reactor Projects Branch 5 Division of Reactor Projects

SUMMARY

IR 05000338/2015-002, 05000339/2015-002; 04/01/2015 - 06/30/2015; North Anna Power

Station, Units 1 and 2. Maintenance Effectiveness.

The report covered a three-month period of inspection by resident inspectors and senior operations engineers from the region. One self-revealing finding was identified and was determined to be a non-cited violation (NCV). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609,

Significance Determination Process (SDP), dated April 29, 2015. The cross-cutting aspects are determined using IMC 0310, Components Within the Cross Cutting Areas, dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated February 4, 2015. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5.

Cornerstone: Mitigating Systems

Green.

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

Procedures, and Drawings, was identified for the licensees failure to maintain an adequate maintenance procedure to set the governor valve on the Unit 1 Turbine Driven Auxiliary Feedwater (TDAFW) pump to the fully closed position. Specifically, the licensee failed to clarify key measurements in Maintenance Procedure 0-MCM-0412-02, Repair of the Terry Turbine Governor Valve, Revision 11, section 6.4.6, which sets the fully closed position of the governor valve that also adversely impacted the performance of the TDAFW system, and the TDAFW system suction source, the Emergency Condensate Storage Tank (ECST).

This issue was entered this into the licensees corrective action program as CR 572803.

The licensee failed to maintain an adequate maintenance procedure to set the governor valve on the Unit 1 TDAFW pump to the fully closed position was a performance deficiency (PD). Using Manual Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the PD was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage)and is therefore a finding. The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, and was determined to affect the short term secondary system heat removal safety function within the Mitigating Systems Cornerstone. The finding was determined to represent a loss of system function of the auxiliary feedwater (AFW) system as the incorrectly set governor caused the TDAFW pump to run at higher discharge pressure under low flow conditions, lifting the TDAFW discharge relief valve, which bypassed approximately 200 gpm flow to the ground. With the loss of 200 gpm the ECST could not have met its mission time which represented a loss of system function requiring a detailed risk analysis.

A detailed risk analysis was performed by a regional senior reactor analyst (SRA) in accordance with the guidance of NRC IMC 0609, Appendix A, The Significance Determination Process (SDP) for ndings At-Power, dated June 19, 2012, using the NRC North Anna SPAR model. The major analysis assumptions included: the ECST failed for a one year exposure period, no additional failure modes from the incorrectly set TDAFW pump governor valve other than the early depletion of the ECST, and no recovery for the condition other than to align to alternate suction source which remained at nominal failure probability.

The dominant sequence was a loss of offsite power with success of reactor protection system, success of the emergency power system and late failure of AFW and late failure of feed and bleed leading to core damage. The risk was mitigated by the availability of other suction sources. The result of the analysis was that the PD represented an increase in core damage frequency of < 1.0 E-6/year, a GREEN finding of very low safety significance.

The finding has a cross-cutting aspect in the area of human performance associated with resources attribute because leaders failed to ensure that personnel, equipment, procedures, and other resources were available and adequate to support nuclear safety to maintain the ECST inventory during the mission time. [H.1]. (1R12).

REPORT DETAILS

Summary of Plant Status

Unit 1 began the period at full Rated Thermal Power (RTP) and operated at full RTP power until the Unit experienced an automatic trip on April 2, 2015, due to an electronic card failure on the automatic voltage regulator. Unit 1 restarted on April 4, 2015 and returned to full RTP on April 5, 2015. Due to grid instability, Unit 1 lowered reactor power to 96 percent on April 6, 2015, and returned to full RTP on April 8, 2015. Unit 1 operated at full RTP for the remainder of the report period.

Unit 2 began the period at full RTP. Due to grid instability, Unit 2 lowered reactor power to 94 percent on April 6, 2015, and returned to full RTP on April 8, 2015. Unit 2 operated at full RTP power for the remainder of the 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 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 corrective action program (CAP) database for hot weather related issues.

The inspectors walked down three 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.

Unit 1 & 2 Emergency Diesel Generators (EDG)

Station Blackout Diesel

Switchyard

b. Findings

No findings were identified.

.3 Impending Adverse Weather Conditions

a. Inspection Scope

The inspectors performed three site specific weather related inspections due to anticipated adverse weather conditions. The inspectors reviewed licensees adverse weather response procedures, including 0-AP-41, Severe Weather Conditions, Revision 64, and site preparations including work activities that could impact the overall maintenance risk assessments.

April 10, 2015, high wind warnings with gusts up to 50 miles an hour for the area

June 25, 2015, severe thunderstorm with lightning

June 23, 2015, severe thunderstorm with lightning

b. Findings

No findings were identified.

==1R04 Equipment Alignment

==

.1 Partial Walkdowns

a. Inspection Scope

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

Unit 2 casing cooling pump house

Unit 1 and Unit 2 recirculation spray heat exchangers service water

Unit 1 and Unit 2 EDG exhaust and intake air bunker

Station blackout (SBO) EDG lube oil and jacket water

b. Findings

No findings were identified.

.2 Complete Walkdown

a. Inspection Scope

The inspectors performed a detailed walkdown and inspection of the Unit 2 AFW system to assess proper alignment and to identify discrepancies that could impact its availability and functional capacity. The inspectors assessed the physical condition and position of each recirculation spray and casing cooling valve, whether manual, power operated or automatic, to ensure correct positioning of the valves. The inspection also included a review of the alignment and the condition of support systems including fire protection, room ventilation, and emergency lighting. Equipment deficiency tags were reviewed and the condition of the system was discussed with the engineering personnel.

b. Findings

No findings were identified.

==1R05 Fire Protection

==

.1 Quarterly Fire Protection Walkdowns

a. Inspection Scope

The inspectors conducted focused tours of the seven areas listed below that are important to reactor safety to verify the licensees implementation of fire protection requirements as described in fleet procedures CM-AA-FPA-100, Fire Protection/Appendix R (Fire Safe Shutdown) Program, Revision 10, CM-AA-FPA-101, Control of Combustible and Flammable Materials, Revision 8, 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. Other documents reviewed are listed in the Attachment to this report.

Main Control Room

Unit 2 AFW pump houses

Unit 2 cable vault, tunnel, rod drive rooms

Unit 1 EDGs

Unit 2 EDGs

Unit 1 main steam valve house

Unit 2 main steam valve house

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation

a. Inspection Scope

During a fire protection drill on May 6, 2015, at the SBO EDG, the inspectors assessed:

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

b. Findings

No findings were identified.

==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, 2015, during a simulator scenario. The scenario required classifications and notifications that were counted for NRC performance indicator (PI) 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. Documents reviewed are listed in the Attachment to this report.

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:

On April 15, 2015, during Unit 2 service water (SW) B pump operation

On May 28, 2015 during Unit 1 TDAFW pump trip valve maintenance

On June 16, 2015 during SW air compressor high differential pressure alarm

b. Findings

No findings were identified.

==1R12 Maintenance Effectiveness

a. Inspection Scope

==

For the four 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 6. Other documents reviewed are listed in the Attachment to this report.

CR576317, Unit 2 recirculation spray B chiller

CR575828, Unit 1 automatic voltage regulator failed high

CR576240, Main steam radiation monitor alarms, 1-MS-RM-171

MRE18558, 1J EDG exhaust

b. Findings

Introduction:

A self-revealing NCV of 10 CFR 50 Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the licensees failure to maintain an adequate maintenance procedure to set the governor valve on the Unit 1 Turbine Driven Auxiliary Feedwater (TDAFW) pump to the fully closed position. Specifically, the licensee failed to clarify key measurements in Maintenance Procedure 0-MCM-0412-02, Repair of the Terry Turbine Governor Valve, Revision 11, section 6.4.6, which sets the fully closed position of the governor valve, that also, adversely impacted the performance of the TDAFW system, the TDAFW system suction source, and the Emergency Condensate Storage Tank (ECST). This issue was entered this into the licensees corrective action program as CR 572803.

Description:

The February 26, 2015, reactor trip of Unit 1, actuated the TDAFW pump automatically and the relief valve on the pump discharge line was observed lifting, releasing approximately 200 gpm of ECST water to the general yard area. Upon further investigation, the licensee discovered the governor valve on the TDAFW pump was unable to fully seat by approximately 0.1875 inches. With the governor valve unable to fully seat, the TDAFW pump continued to run under low flow conditions and the discharge pressure increased to above the relief valve setpoint. The relief valve lifted as designed and discharged ECST water inventory to the yard area.

Maintenance Procedure 0-MCM-0412-02, section 6.4.6, instructs how to install the governor level assembly into the valve bonnet. The procedure steps are unclear with respect to several key measurements that set the full closed position of the governor valve. Unit 1 TDAFW governor valve was overhauled in February 2015, April 2012, May 2011 and March 2006. Based on the recorded measurements from the governor overhaul work packages, the governor valve would not fully close for Unit 1 from April 2012 to February 2015.

After reviewing pump discharge pressure and flow traces for Unit 1 during the above mentioned time periods, the inspectors noted that Unit 1 experienced TDAFW pressure spikes. The relief valve operates with a setpoint of 1480 psig with a +/- 3% tolerance (1435-1524 psig). The relief valve functions as a safety valve at 10% of its setpoint, 1628 psig with a flowrate of 786 gpm. Unit 1 TDAFW pump discharge pressure during the February 26, 2015 reactor trip reached 1555 psig and released approximately 200 gpm for approximately 15 minutes.

Per Surveillance Requirement SR 3.7.6.1 as defined in Technical Specification (TS)3.7.6, the ECST shall contain greater than 110,000 gallons of water. As the suction source for the AFW system, the ECST has a mission time of 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months to provide residual heat removal and to maintain the plant in Mode 3 would have required operator action to refill the tank from the condensate storage tank, the service water system or the fire protection system to remain operable.

Analysis:

The licensee failed to maintain an adequate maintenance procedure to set the governor valve on the Unit 1 TDAFW pump to the fully closed position was a performance deficiency (PD). Using Manual Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspectors determined that the PD was more than minor because it was associated with the procedure quality attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e. core damage). The finding was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609, Attachment 4, Initial Characterization of Findings, dated June 19, 2012, and was determined to affect the short term secondary system heat removal safety function within the Mitigating Systems Cornerstone. The finding was determined to represent a loss of system function of the AFW system as the incorrectly set governor caused the TDAFW pump to run at higher discharge pressure under low flow conditions, lifting the TDAFW discharge relief valve, which bypassed approximately 200 gpm flow to the ground. With the loss of 200 gpm the ECST could not have met its mission time which represented a loss of system function requiring a detailed risk analysis.

A detailed risk analysis was performed by a regional SRA in accordance with the guidance of NRC IMC 0609, Appendix A, The Significance Determination Process (SDP)for Findings At-Power, dated June 19, 2012, using the NRC North Anna SPAR model.

The major analysis assumptions included: the ECST failed for a one year exposure period, no additional failure modes from the incorrectly set TDAFW pump governor valve other than the early depletion of the ECST, and no recovery for the condition other than to align to alternate suction source which remained at nominal failure probability. The dominant sequence was a loss of offsite power with success of reactor protection system, success of the emergency power system and late failure of AFW and late failure of feed and bleed leading to core damage. The risk was mitigated by the availability of other suction sources. The result of the analysis was that the performance deficiency represented an increase in core damage frequency of < 1.0 E-6/year, a GREEN finding of very low safety significance.

The finding has a cross-cutting aspect in the area of human performance associated with resources attribute because leaders failed to ensure that personnel, equipment, procedures, and other resources were available and adequate to support nuclear safety to maintain the ECST inventory during the mission time. [H.1].

Enforcement:

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

The licensees maintenance procedure, 0-MCM-0412-02, Repair of the Terry Turbine Governor Valve, Revision 11, section 6.4.6, sets the fully closed position of the governor valve, that also, impacts the performance of the AFW system and the TDAFW system suction source, the ECST. Contrary to this requirement, the licensee failed to maintain an adequate maintenance procedure to set the governor valve on the Unit 1 TDAFW pump to the fully closed position. Specifically, the licensee failed to clarify key measurements in Maintenance Procedure 0-MCM-0412-02, Repair of the Terry Turbine Governor Valve, Revision 11, section 6.4.6, which sets the fully closed position of the governor valve, that also, adversely impacted the performance of the Unit 1 TDAFW system and the AFW system suction source, the ECST. 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 572803. This non-cited violation is identified as NCV 05000338/2015002-01, Failure To Maintain An Adequate Maintenance Procedure For The Turbine Driven Auxiliary Feedwater Pump.

==1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

==

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

(1) effectiveness of the risk assessments performed before maintenance activities were conducted;

(2) management of risk;

(3) appropriate and necessary steps taken to plan and control the resulting emergent work activities upon identification of an unforeseen situation; and,

(4) adequate identification and resolution of maintenance risk assessments and emergent work problems. The inspectors verified that the licensee was in compliance with the requirements of 10 CFR 50.65 (a)(4) and the data output from the licensees safety monitor associated with the risk profile of Units 1 and 2. The inspectors reviewed the corrective action program to verify that deficiencies in risk assessments were being identified and properly resolved.

Work week schedule after Unit 1 trip on April 2, 2015

Emergent work on Unit 1 AFW check valve, 1-FW-68, on April 2, 2015

Maintenance activities on Unit 1 TDAFW pump after oil sample on April 6, 2015

Work week schedule during grid loading Ladysmith line on April 13, 2015

Work week schedule 1J EDG inoperable on April 22, 2015

Maintenance activities during B SW header maintenance during week of June 22, 2015

b. Findings

No findings were identified.

==1R15 Operability Determinations and Functionality Assessments

==

.1 Operability and Functionality Review

a. Inspection Scope

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

(2) whether continued system operability was warranted;

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

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

(5) where continued operability was considered unjustified, the impact on TS Limiting Conditions for Operation and the risk significance in accordance with the SDP. The inspectors review included a verification that operability determinations (OD) were made as specified by procedure OP-AA-102, Operability Determination, Revision 13. Other documents reviewed are listed in the Attachment to this report.

Review of OD000616, Unit 1 AFW long term oil moisture content

Review of CR572803, ECST operability

Review of CR577502, 1J EDG exhaust inoperability

Review of CR577689, 2H and 2J exhaust operability

Review of CR580411, 2H EDG exhaust support operability

Review of CR581648, 1H EDG coolant leak

b. Findings

No findings were identified.

==1R18 Plant Modifications

==

.1 Permanent Modifications

a. Inspection Scope

The inspectors reviewed the three completed permanent plant modification design change packages (DCP) listed below. 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. Other documents reviewed are listed in the Attachment to this report.

DC-NA-11-01082, Main Steam Radiation Monitor Replacement

DC-NA-11-01168, Appendix R Radio Handset Replacement

DC-NA-15-00048, 1J EDG Pipe Support Anchor Repairs

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-OP-58.2, Rod Control System Operation, Revision 24 for Unit 1 step counter

1-PT-71.1Q, 1-FW-P-2, Turbine Driven Auxiliary Feedwater Pump and Valve Test, Revision 62 for Unit 1 TDAFW oil samples

WO59102859073 and WO 59102858809, for 1J EDG maintenance

WO59102858133, for diesel fire pump maintenance

2-PT-230.4, 2J Emergency Diesel Generator Starting Air Subsystem after B air compressor maintenance

2-PT-71.1Q, 2-FW-P-2, Turbine Driven Auxiliary Feedwater Pump and Valve Test, Revision 58 for Unit 2 TDAFW oil samples

b. Findings

No findings were identified.

==1R20 Refueling and Other Outage Activities

==

.1 Unit 1 Forced Outage for Generator Voltage Regulator Failure

a. Inspection Scope

Unit 1 forced outage on April 2, 2015, due to failed voltage regulator for the main generator. During the forced outage period, the inspectors used NRC inspection procedure 71111.20, Refueling and Outage Activities, to observe portions of the maintenance and startup activities to verify that the licensee maintained defense-in-depth commensurate with outage risk assessments and applicable TS. The inspectors reviewed licensee actions for the outage activities listed below.

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

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

Decay heat removal processes to verify proper operation and that steam generators, when relied upon, were a viable means of backup cooling.

Heat up and startup activities to verify TS, license conditions, and other requirements, commitments, and administrative procedure prerequisites for mode changes were met prior to changing modes or plant conditions. Reactor coolant system (RCS) integrity was verified by reviewing RCS leakage calculations and containment integrity was verified by reviewing the status of containment penetrations and containment isolation valves.

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-77.11C, Control Room Chiller 2-HV-E-4C Pump and Valve Test, Revision 42

Other Surveillance Tests:

1-PT-52.2A, Reactor Coolant System Leakrate, Revision 36

2-PT-17.3, Rod Position Verification Using The Incore Flux Mapping System, Revision 9

2-PT-71.2Q, 2-FW-P-3A, A Motor-Driven AFW Pump and Valve Test, Revision 38

2-PT-36.5.3B, Solid State Protection System Output Slave Relay Test (Train B),

Revision 38

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP2 Alert and Notification System Evaluation

a. Inspection Scope

The inspectors evaluated the adequacy of the licensees methods for testing the alert and notification system in accordance with NRC Inspection Procedure 71114, 02, Alert and Notification System Evaluation. The applicable planning standard, 10 CFR Part 50.47(b)

(5) and its related 10 CFR Part 50, Appendix E, Section IV.D requirements were used as reference criteria. The criteria contained in NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision (Rev.) 1, were also used as a reference.

The inspectors reviewed various documents which are listed in the Attachment, interviewed personnel responsible for siren maintenance and verified placement of several sirens. This inspection activity satisfied one inspection sample for the alert and notification system on a biennial basis.

b. Findings

No findings were identified.

1EP3 Emergency Response Organization Staffing and Augmentation System

a. Inspection Scope

The inspectors reviewed the licensees Emergency Response Organization (ERO)augmentation staffing requirements and process for notifying the ERO to ensure the readiness of key staff for responding to an event and timely facility activation. The qualification records of key position ERO personnel were reviewed to ensure all ERO qualifications were current. A sample of problems identified from augmentation drills or system tests performed since the last inspection were reviewed to assess the effectiveness of corrective actions.

The inspection was conducted in accordance with NRC Inspection Procedure 71114, 03, Emergency Response Organization Staffing and Augmentation System.

The applicable planning standard, 10 CFR 50.47(b) (2), and its related 10 CFR 50, Appendix E requirements were used as reference criteria.

The inspectors reviewed various documents which are listed in the Attachment. This inspection activity satisfied one inspection sample for the ERO staffing and augmentation system on a biennial basis.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

Since the last NRC inspection of this program area, one change was made to the Radiological Emergency Plan, along with changes to several implementing procedures.

The licensee determined that, in accordance with 10 CFR 50.54(q), the Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The inspectors reviewed these changes to evaluate for potential reductions in the effectiveness of the Plan. However, this review was not documented in a Safety Evaluation Report and does not constitute formal NRC approval of the changes.

Therefore, these changes remain subject to future NRC inspection in their entirety.

The inspection was conducted in accordance with NRC Inspection Procedure 71114, 04, Emergency Action Level (EAL) and Emergency Plan Changes. The applicable planning standards of 10 CFR 50.47(b), and its related requirements in 10 CFR 50, Appendix E, were used as reference criteria.

The inspectors reviewed various documents that are listed in the Attachment to this report. This inspection activity satisfied one inspection sample for the emergency action level and emergency plan changes on an annual basis.

b. Findings

No findings were identified.

1EP5 Maintenance of Emergency Preparedness

a. Inspection Scope

The inspectors reviewed the corrective actions identified through the Emergency Preparedness program to determine the significance of the issues, the completeness and effectiveness of corrective actions, and to determine if issues were recurring. The licensees drill and exercise critique reports, self-assessments, and audits were reviewed to assess the licensees ability to be self-critical, thus avoiding complacency and degradation of their emergency preparedness program. The licensees 10 CFR 50.54(q)change process and selected evaluations of Emergency Preparedness document revisions were reviewed to assess adequacy. The inspectors toured facilities and reviewed equipment and facility maintenance records to assess licensees adequacy in maintaining them. During tours of the main control room, the inspectors observed licensee staff demonstrate the capabilities of selected radiation monitoring instrumentation used to detect dose rates of selected areas of the plant to adequately support declaration of the effected EALs. In addition, the inspectors reviewed licensee procedures and training for the evaluation of changes to the emergency plans.

The inspection was conducted in accordance with NRC Inspection Procedure 71114, 05, and Maintenance of Emergency Preparedness. The applicable 10 CFR 50.47(b) planning standards and related 10 CFR 50, Appendix E requirements were used as reference criteria.

The inspectors reviewed various documents which are listed in the Attachment. This inspection activity satisfied one inspection sample for the maintenance of emergency preparedness on a biennial basis.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

Emergency Preparedness Drill

a. Inspection Scope

On June 23, 2015, the inspectors reviewed and observed the performance of a drill that involved a General Emergency where a main steam line failed, leading to a ruptured steam generator, and failed fuel. The inspectors assessed emergency procedure usage, emergency plan classification, notifications, and the licensees identification and entrance of any problems into their corrective action program. This inspection evaluated the adequacy of the licensees conduct of the drill and performance critique. Exercise issues were captured by the licensee in their corrective action program as CRs.

Requalification training deficiencies were captured within the operator training program.

b. Findings

No findings were identified.

RADIATION SAFETY

(RS)

Cornerstones: Occupational Radiation Safety (OS) and Public Radiation Safety (PS)

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

Event and Effluent Program Reviews: The inspectors reviewed the 2013 and 2014 Annual Radiological Effluent Release Report (ARERR) documents for consistency with requirements in the Offsite Dose Calculation Manual (ODCM) and TS. Five ODCM revisions completed since the last inspection were reviewed by the inspectors. The revisions were primarily administrative or applicable to the Radiological Environmental Monitoring Program (REMP). No changes were made to radioactive gaseous or liquid effluent treatment systems. Routine and abnormal effluent release results and reports, as applicable, were reviewed and discussed with responsible licensee representatives.

Status of the radioactive gaseous and liquid effluent processing and monitoring equipment as described in the UFSAR and current ODCM were discussed with responsible staff.

Radioactive Waste Treatment Systems: The inspectors walked-down the gaseous and liquid radioactive waste (radwaste) processing and discharge systems for material condition and configuration. To the extent practical, the inspectors observed and evaluated the material condition of in-place waste processing equipment for indications of degradation or leakage that could constitute a possible release pathway to the environment. Inspected components included waste monitor tanks (clarifier), waste gas decay tanks, ventilation filtration systems, boron recovery tanks, vendor-supplied liquid waste processing equipment, and associated piping and valves. The inspectors interviewed licensee staff regarding radwaste equipment configuration and effluent monitor operation. The inspectors also reviewed surveillance testing records for auxiliary building ventilation filtration systems.

Effluent Processing: The inspectors observed the collection of liquid effluent samples from the Steam Generator High Capacity Blow Down Tank, and the Clarifier Effluent Proportional Tank. Inspectors observed technician proficiency in collecting and analyzing some of the samples. The inspectors discussed liquid and gaseous effluent discharge pathways and operability of the effluent radiation monitors with plant personnel. The inspectors reviewed gaseous and liquid release permits, effluent monitor setpoints, and public dose calculations. The reviews included review and discussion of selected dose calculation summaries. Release quantities and dose impacts were reviewed and discussed. Inspectors reviewed 10 CFR 61 analysis data. The inspectors reviewed the calculated public dose results for any indications of higher than anticipated or abnormal releases. The inspectors also reviewed compensatory sampling data for time periods when selected radiation monitors were out of service. The inspectors reviewed the results of the radiochemistry cross-check program for 2013 and 2014 to evaluate the quality of the radioactive effluent sample analyses, and results of the 2013 and 2014 land use census. Meteorological data used to calculate doses to the public were evaluated as part of Inspection Procedure (IP) 71124.07.

Ground Water Protection: The inspectors reviewed historical and current groundwater sample results. The inspectors discussed changes in the groundwater protection program, updates to the site hydrology model, and efforts to identify the source of tritium detected in several on-site monitoring wells. The groundwater program was discussed with Radiation Protection representatives. The inspectors reviewed and discussed the licensees program for monitoring of structures, systems, and components with the potential to release radioactive material to the environment, including selected portions of the liquid radwaste system. Potential effluent release points due to onsite surface water bodies were also evaluated.

Problem Identification and Resolution: The inspectors reviewed selected CAP CR documents in the areas of gaseous and liquid effluent processing and release activities.

The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with procedure PI-AA-200, Corrective Action, Rev. 24. The inspectors also discussed the scope of the licensees internal audit program and reviewed recent assessment results.

Effluent process and monitoring activities were evaluated against details and requirements documented in UFSAR Sections 11 and 12; ODCM; TS 5.6.3 (Annual Radioactive Release Report),10 CFR Part 20; Appendix I to 10 CFR Part 50; and approved licensee procedures. In addition, ODCM and UFSAR changes since the last onsite inspection were reviewed against the guidance in NUREG-1301 and Regulatory Guide (RG) 1.109, RG 1.21, and RG 4.1. Documents and records reviewed are listed in the report Attachment.

b. Findings

No findings were identified.

2RS7 Radiological Environmental Monitoring Program

a. Inspection Scope

REMP Status and Results: The inspectors reviewed and discussed planned changes to the ODCM and results presented in the Annual Environmental Radiological Environmental Operating Report (AREOR) documents issued for 2013 and 2014. The REMP contract laboratory (Teledyne Brown Engineering (TBE)) cross-check program results and current procedural guidance for offsite collection, processing and analysis of airborne particulate and iodine, broadleaf vegetation, and surface water samples were reviewed and discussed. The AREOR environmental measurement results were reviewed for consistency with licensee effluent data and evaluated for radionuclide concentration trends. The inspectors reviewed and discussed detection level sensitivity requirements and results for selected environmental media analyzed by the offsite environmental laboratory.

Site Inspection and Equipment Walkdown: The inspectors discussed implementation of selected REMP monitoring and sample collection activities for atmospheric, broadleaf vegetation samples, and water and milk samples as specified in the current ODCM and applicable procedures. The inspectors observed equipment material condition and verified operability, including verification of flow rates and total sample volume results for the weekly airborne particulate filter and iodine cartridge change-outs at twelve atmospheric sampling stations. In addition, the inspectors discussed broadleaf vegetation sampling for selected stations. Thermo-luminescent dosimeter (TLD)material condition and placement were verified by direct verification at twelve ODCM locations. Land use census results, actions for missed samples including compensatory measures, sediment sample collection/processing activities, and availability of replacement equipment were discussed with knowledgeable licensee staff. In addition, sample pump calibration and maintenance records for selected environmental air samplers were reviewed. The current status and completeness of the licensees 10 CFR 50.75(g) decommissioning files were reviewed and discussed, as well as the licensees assessment of structures, systems, and components (SSCs) that could potentially leak material into the groundwater. Additional assessment of the ground water protection program, including sampling of wells was completed and is documented in Section 2RS6.

Meteorological Monitoring Program: The inspectors conducted a tour of the meteorological tower and observed local data collection equipment computer used to provide local readout if required. The inspectors observed the physical condition of the tower and associated instruments and discussed equipment operability, maintenance history, and backup power supplies with responsible licensee staff. The inspectors evaluated transmission of locally generated meteorological data from the meteorological tower to the main control room operators. For the meteorological measurements of wind speed, wind direction, and temperature, the inspectors reviewed applicable tower instrumentation calibration records for 2013 and 2014 and evaluated meteorological measurement data recovery for 2013 and 2014.

Procedural guidance, program implementation, quantitative analysis sensitivities, and environmental monitoring results were reviewed against 10 CFR Part 20; Appendix I to 10 CFR Part 50; TS Sections 5.6.1, ODCM, Rev. 26; RG 4.15, Quality Assurance for Radiological Monitoring Programs (Normal Operation) - Effluent Streams and the Environment; and the Branch Technical Position, An Acceptable Radiological Environmental Monitoring Program - 1979. Licensee procedures and activities related to meteorological monitoring were evaluated against: ODCM; UFSAR Chapter 11; RG 1.23, Meteorological Monitoring Programs for Nuclear Power Plants, and ANSI/ANS-2.5-1984, Standard for Determining Meteorological Information at Nuclear Power Sites.

Procedures and records reviewed during the inspection are listed in the Attachment.

Problem Identification and Resolution: The inspectors reviewed selected CAP CR documents in the areas of environmental and meteorological monitoring. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with PI-AA-200, Corrective Action, Rev. 24. Documents and records reviewed are listed in the report attachment.

b. Findings

No findings were identified.

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

Transportation

a. Inspection Scope

Waste Processing and Characterization: During inspector walk-downs, accessible sections of the liquid and solid radioactive waste (radwaste) processing systems were assessed for material condition and conformance with system design diagrams.

Inspected equipment included radwaste storage tanks; resin transfer piping, resin and filter packaging components; and abandoned evaporator equipment. The inspectors discussed component function, processing system changes, and radwaste program implementation with licensee staff.

The 2013, and 2014 Annual Radiological Effluent Release Reports and radionuclide characterizations for selected waste streams were reviewed and discussed with Radioactive Material Control (RMC) staff. For the Unit 1, Unit 2, and Common Dry Active Waste (DAW) waste streams the inspectors evaluated analyses for hard-to-detect nuclides, reviewed the use of scaling factors, and examined quality assurance (QA)comparison results between licensee waste stream characterizations and outside laboratory data. Waste stream mixing and concentration averaging methodology for resins and filters was evaluated and discussed with RMC staff. The inspectors also reviewed the licensees procedural guidance for monitoring changes in waste stream isotopic mixtures and discussed radionuclide characterization data for radioactive filter media, and resins.

Radioactive Material Storage: During walk-downs of indoor and outdoor radioactive material storage areas located inside and outside the protected area, the inspectors observed the physical condition and labeling of storage containers and the posting of Radioactive Material Areas. The inspectors also reviewed licensee procedural guidance for storage and monitoring of radioactive material.

Radioactive material and waste storage activities were reviewed against the requirements of 10 CFR Part 20. Reviewed documents are listed in Section 2RS8 of the report Attachment.

Transportation: There were no significant shipments during the week of inspection, however the inspectors did review shipping procedure requirements and discussed preparation of shipping documents, package marking and labeling, and interviewed shipping technicians regarding Department of Transportation (DOT) regulations.

Selected shipping records were reviewed for consistency with licensee procedures and compliance with NRC and DOT regulations. The inspectors reviewed emergency response information, DOT shipping package classification, waste classification, radiation survey results, and evaluated whether receiving licensees were authorized to accept the packages. Licensee procedures for handling shipping containers were compared to Certificate of Compliance requirements and manufacturer recommendations. In addition, training records for selected individuals currently qualified to ship radioactive material were reviewed.

Problem Identification and Resolution: The inspectors reviewed CRs in the area of radioactive material control, radwaste processing, and transportation. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure PI-AA-200, Corrective Action, Rev. 24. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Radwaste processing activities and equipment configuration were reviewed for compliance with the licensees Process Control Program (PCP) and UFSAR, Chapter 11. Waste stream characterization analyses were reviewed against regulations detailed in 10 CFR Part 20, 10 CFR Part 61, and guidance provided in the Branch Technical Position on Waste Classification (1983). Transportation program implementation was reviewed against regulations detailed in 10 CFR Part 20, 10 CFR Part 71, 49 CFR Parts 172-178, as well as the guidance provided in NUREG-1608. Training activities were assessed against 49 CFR Part 172 Subpart H. Documents and records reviewed are listed in the report attachment.

b. Findings

No findings were identified.

OTHER ACTIVITIES

Cornerstones: Barrier Integrity, Emergency Preparedness, Public Radiation Safety, and Occupational Radiation Safety

4OA1 Performance Indicator (PI) Verification

.1 Barrier Integrity PIs

a. Inspection Scope

The inspectors performed a periodic review of the two Unit 1 and 2 PIs listed below to assess the accuracy and completeness of the submitted data and whether the performance indicators were calculated in accordance with the guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7. The inspection was conducted in accordance with NRC inspection procedure 71151, Performance Indicator Verification. Specifically, the inspectors reviewed the Unit 1 and Unit 2 data reported to the NRC for the period April 1, 2014 through March 31, 2015. Documents reviewed included applicable NRC inspection reports, licensee event reports, operator logs, station performance indicators, and related CRs.

RCS Specific Activity (BI01)

RCS Leakage (BI02)

b. Findings

No findings were identified.

.2 Emergency Preparedness PIs

a. Inspection Scope

The inspectors sampled licensee submittals relative to the PIs listed below for the period April 1, 2014, through March 31, 2015. To verify the accuracy of the PI data reported during that period, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Rev. 7, was used to confirm the reporting basis for each data element.

Emergency Preparedness Cornerstone

Drill/Exercise Performance

Emergency Response Organization Drill Participation

Alert and Notification System Reliability For the specified review period, the inspectors examined data reported to the NRC, procedural guidance for reporting PI information, and records used by the licensee to identify potential PI occurrences. The inspectors verified the accuracy of the PI for ERO drill and exercise performance through review of a sample of drill and event records.

The inspectors reviewed selected training records to verify the accuracy of the PI for ERO drill participation for personnel assigned to key positions in the ERO. The inspectors verified the accuracy of the PI for alert and notification system reliability through review of a sample of the licensees records of periodic system tests. The inspectors also interviewed the licensee personnel who were responsible for collecting and evaluating the PI data. Licensee procedures, records, and other documents reviewed within this inspection area are listed in the Attachment. This inspection satisfied three inspection samples for PI verification on an annual basis.

b. Findings

No findings were identified.

.3 Radiation Safety PIs

a. Inspection Scope

Occupational Radiation Safety Cornerstone: The inspectors reviewed the Occupational Exposure Control Effectiveness PI results for the Occupational Radiation Safety Cornerstone from September 2014 through May 2015. For the assessment period, the inspectors reviewed electronic dosimeter (ED) alarm logs and selected CRs related to controls for exposure significant areas. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents reviewed are listed in of the report Attachment

Public Radiation Safety Cornerstone: The inspectors reviewed the Radiological Control Effluent Release Occurrences PI results for the Public Radiation Safety Cornerstone from July 2014 through April 2015. For the assessment period, the inspectors reviewed cumulative and projected doses to the public contained in liquid and gaseous release permits and CRs related to Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual issues. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents and records reviewed are listed in the report attachment.

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 CR575828, Unit 1 Trip and Automatic Voltage Regulator Failure

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for CR575828, Unit 1 Trip and Automatic Voltage Regulator Failure, 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 licensee procedure, PI-AA-200, Corrective Action Program, Revision 25 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 CR573058, Unit 2 Main Control Room Chiller Arc/Fire

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for CR573058, Unit 2 Main Control Room Chiller Arc/Fire, 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 licensee procedure, PI-AA-200, Corrective Action Program, Revision 25, 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.

.4 Annual Sample:

Review of ACE19889, Unit 1 Terry Turbine Governor and Relief Valve

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for ACE19889, Unit 1 Terry Turbine Governor and Relief Valve, 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 licensee procedure, PI-AA-200, Corrective Action Program, Revision 25, and 10 CFR 50, Appendix B.

b. Findings and Observations

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. See section 1R12 for details of findings.

.5 Annual Sample:

Review of RCE1134, Unit 1 Trip Due to B Main Feed Regulating Valve Failure

a. Inspection Scope

The inspectors performed a review regarding the licensees assessments and corrective actions for RCE1134, Unit 1 Trip Due to B Main Feed Regulating Valve Failure 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 licensee procedure, PI-AA-200, Corrective Action Program, Revision 25, 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.

.6 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees corrective action program 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 corrective action program item screening discussed in Section 4OA2.1. The review included issues documented outside the normal corrective action program 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 2015 through June 2015, 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 corrective action program.

4OA3 Event Followup

.1 (Closed) LER 05000338/2015-001-00:

Automatic Reactor Trip Due to Low-Low Level on B Steam Generator

On February 26, 2015, with Unit 1 in Mode 1 at 96 percent power, at 1511 hours0.0175 days 0.42 hours 0.0025 weeks 5.749355e-4 months an automatic trip occurred. The initiating signal was a low-low level on B steam generator caused by the closure of the B main feed regulating valve. Closure of the valve was due to a loss of power on the final driver card. The event posed no significant safety implications and the health and safety of the public were not affected by this event.

The cause of the event was a faulty component. Completed interim actions included removing the circuit card for failure analysis. The TDAFW pump relief valve lifted and discharged approximately 200 gpm to the ground.

This issue is in the licensees CAP as CR572757 and RCE1134. See section 1R12 for details of findings.

.2 (Closed) LER 05000338/2015-002-00 Manual Reactor Trip Due To Inability To Maintain

Main Generator Voltage In Specification

The inspectors followed up on actions taken in response to the failure of the Unit 1 Main Generator Voltage Regulator which required a manual reactor trip on April 2, 2015 at 0426 EDT, while operating at 100 percent power. The operations crew entered the reactor trip procedure and stabilized the unit in Mode 3 at normal operating pressure and temperature. All control rods fully inserted into the core following the reactor trip. This reactor protection system actuation and the AFW System actuated as designed. The inspectors reviewed the problem resolution documents and the licensee actions taken to ensure appropriate corrective actions were specified and prioritized. Documents reviewed are listed in the Attachment to this report. No findings or violations of NRC requirements were identified.

4OA6 Meetings, Including Exit

Exit Meeting Summary

On July 29, 2015, the resident inspectors 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: