IR 05000424/2011004

IR 05000424-11-004, 05000425-11-004, on 07/01/2011 - 09/30/2011, Vogtle Electric Generating Plant, Units 1 and 2, Identification and Resolution of Problems

ML113010478
Person / Time
Site:	Vogtle
Issue date:	10/28/2011
From:	Jim Hickey NRC/RGN-II/DRP/RPB2
To:	Tynan T Southern Nuclear Operating Co
References
IR-11-004
Download: ML113010478 (40)

Text

UNITED STATES ber 28, 2011

SUBJECT:

VOGTLE ELECTRIC GENERATING PLANT - NRC INTEGRATED INSPECTION REPORT 05000424/2011004 AND 05000425/2011004

Dear Mr. Tynan:

September 30, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Vogtle Electric Generating Plant, Units 1 and 2. The enclosed integrated inspection report documents the inspection findings, which were discussed on October 19, with you and other members of your staff.

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

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

This report documents one NRC-identified finding of very low safety significance (Green) which was determined to be a violation of regulatory requirements. In addition, one licensee-identified violation, which was determined to be of very low safety significance, is listed in the enclosed inspection report. However, because of the very low safety significance and because they were entered into your corrective action program, the NRC is treating these findings as non-cited violations (NCV) consistent with the NRC Enforcement Policy. If you contest any 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 20555-0001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Vogtle Electric Generating Plant. In addition, if you disagree with the cross-cutting aspect assigned to any finding in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Senior Resident Inspector at the Vogtle facility. The information you provide will be considered in accordance with Inspection Manual Chapter 0305.

SNC 2 In accordance with the Code of Federal Regulations 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosures, 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 the NRCs document 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/

James A. Hickey, Chief Reactor Projects Branch 2 Division of Reactor Projects Docket Nos.: 50-424, 50-425 License Nos.: NPF-68 and NPF-81

Enclosures:

Inspection Report 05000424/2011004 and 05000425/2011004 w/Attachment: Supplemental Information

REGION II==

Docket Nos.: 50-424, 50-425 License Nos.: NPF-68, NPF-81 Report Nos.: 05000424/2011004 and 05000425/2011004 Licensee: Southern Nuclear Operating Company, Inc. (SNC)

Facility: Vogtle Electric Generating Plant, Units 1 and 2 Location: Waynesboro, GA 30830 Dates: July 01, 2011 through September 30, 2011 Inspectors: M. Cain, Senior Resident Inspector T. Chandler, Resident Inspector J. Dodson, Senior Project Engineer T. Lighty, Project Engineer R. Hamilton, Senior Health Physicist (2RS5, 4OA1)

W. Loo, Senior Health Physicist (2RS1, 4OA1, 4OA5)

J. Rivera, Health Physicist (In Training) (2RS5)

A. Rodgers, Reactor Inspector (1R07, 1R08)

R. Williams, Reactor Inspector (1R08)

Approved by: James Hickey, Chief Reactor Projects Branch 2 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000424/2011-004, 05000425/2011-004; 07/01/2011 - 09/30/2011; Vogtle Electric

Generating Plant, Units 1 and 2; Identification and Resolution of Problems The report covered a three-month period of inspection by the resident inspectors, a project engineer, senior project engineer, and a reactor inspector. One non-cited violation (NCV) with very low safety significance (Green) was identified. The significance of most findings is indicated by their color (great than Green, or Green,

White, Yellow, Red); the significance was determined 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; and that findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.

Cornerstone: Mitigating Systems

Green.

An NRC-identified Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI,

Corrective Action, was identified for failure to develop and implement adequate corrective action to prevent recurrence (CAPR) in response to a significant condition adverse to quality (SCAQ) associated with E-MAX safety-related breaker front cover mounting screws. The licensee performed a field walk-down of all installed E-MAX breakers and identified a total of six breakers that had been inadvertently installed with the top right-hand front cover plate screw not removed. The licensee immediately removed the suspect screws and implemented corrective actions to address future E-MAX breaker installations. The licensee entered this issue into their corrective action program (CAP) as CR 332562.

The finding was considered more than minor because it impacted the Reactor Safety Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and affected the cornerstone attribute of equipment performance.

Specifically, the inadequate corrective action allowed for the installation of non-conforming safety-related breakers that incurred unplanned unavailability to implement the associated temporary modification and also decreased reliability during the time the breaker was in-service without the temporary modification installed. The inspectors determined that the cause of this finding was related to the Corrective Action Program component of the Problem Identification and Resolution cross-cutting area due to the licensees failure to take appropriate corrective actions to address safety issues in a timely manner, commensurate with their safety significance and complexity P.1(d).

(Section 4OA2.2)

Licensee Identified Violations

Violations of very low safety significance that were identified by the licensee have been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensees corrective action program. These violations and the corrective action tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 started the report period at full rated thermal power (RTP) and subsequently tripped from 100% power on August 31 due to a high level in the loop 2 steam generator that caused a main turbine trip and subsequently a reactor trip. The unit was restarted on September 01 and attained full RTP power on September 11. Unit 1 operated at essentially full RTP for the remainder of the inspection period.

Unit 2 started the report period at full rated thermal power (RTP) and shutdown for a planned refueling outage on September 18. The unit was shutdown for the remainder of the reporting period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R04 Equipment Alignment

a. Inspection Scope

Partial System Walkdown The inspectors performed partial walkdowns of the following three systems to verify correct system alignment. The inspectors checked for correct valve and electrical power alignments by comparing positions of valves, switches, and breakers to the documents listed in the Attachment. Additionally, the inspectors reviewed the condition report database to verify that equipment alignment problems were being identified and appropriately resolved.

• Unit 2 train A engineered safety features (ESF) chiller during the train B chiller outage

• Unit 2 train B & C auxiliary feedwater (AFW) system during the train A motor driven AFW pump maintenance outage

• Unit 1 train A high head safety injection (SI) pump during the train B maintenance outage

b. Findings

No findings were identified.

1R05 Fire Protection

a. Inspection Scope

Fire Area Tours The inspectors walked down the following five plant areas to verify the licensee was controlling combustible materials and ignition sources as required by procedures 92015-C, Use, Control, and Storage of Flammable/Combustible Materials, and 92020-C, Control of Ignition Sources. The inspectors assessed the observable condition of fire detection, suppression, and protection systems and reviewed the licensees fire protection Limiting Condition for Operation (LCO) log and condition report (CR) database to verify that the corrective actions for degraded equipment were identified and appropriately prioritized. The inspectors also reviewed the licensees fire protection program to verify the requirements of Updated Final Safety Analysis Report (UFSAR) section 9.5.1, Fire Protection Program, and Appendix 9A, Fire Hazards Analysis, were met. Documents reviewed are listed in the Attachment.

• Unit 2 component cooling water (CCW) heat exchanger rooms

• Unit 1 A train emergency diesel generator (EDG)

• Unit 1 EDG fuel oil storage tanks

• Unit 2 EDG fuel oil storage tanks

• Unit 2 containment building levels A, B, 1, 2, and 3

b. Findings

No findings were identified.

1R07 Heat Sink Performance

a. Inspection Scope

Triennial Review The inspectors reviewed testing, inspection, maintenance, and monitoring programs associated with the Unit 2 A and B CCW heat exchangers (HXs),

Unit 2 A and B EDG jacket water HXs and the Unit 1 A and B containment spray (CS)motor cooler HXs to verify that heat transfer performance was maintained as designed.

These heat exchangers, which are directly cooled by the nuclear service cooling water system (NSCW), were chosen based on their risk significance in the licensees probabilistic safety analysis, their important safety-related mitigating system support functions, and their relatively low margin.

For the selected heat exchangers the inspectors reviewed, as applicable, eddy current test results, visual inspection results, maintenance records, and monitoring of biotic fouling and macro-fouling programs to ensure proper heat transfer. This was accomplished by determining whether the methods used to inspect and clean heat exchangers were consistent with as-found conditions identified and expected degradation trends and industry standards, the licensees inspection and cleaning activities had established acceptance criteria consistent with industry standards, and the as-found results were recorded, evaluated, and appropriately dispositioned such that the as-left condition was acceptable.

The inspectors determined whether the condition and operation of the heat exchangers were consistent with design assumptions in heat transfer calculations and as described in the final safety analysis report. This included determining whether the number of plugged tubes was within pre-established limits based on capacity and heat transfer assumptions. The inspectors determined whether the licensee evaluated the potential for water hammer and established adequate controls and operational limits to prevent heat exchanger degradation due to excessive flow induced vibration during operation. In addition, eddy current test reports and visual inspection records were reviewed to determine the structural integrity of the heat exchanger.

Additionally, the inspectors reviewed condition reports related to the heat exchangers/coolers, and heat sink performance issues to verify that the licensee had an appropriate threshold for identifying issues through the Corrective Action Program and to evaluate the effectiveness of the corrective actions. The documents that were reviewed are included in the Attachment.

These inspection activities constituted six heat sink inspection samples as defined in IP 71111.07.

a. Findings

No findings were identified.

1R08 Inservice Inspection Activities

From September 26, 2011, through September 30, 2011, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, steam generator tubes, emergency core cooling systems, risk-significant piping and components and containment systems.

The inspections described in Sections 1R08.1, 1R08.2, 1R08.3, 1R08.4 and 1R08.5 below constituted one inservice inspection sample as defined in inspection procedure 71111.08-05.

Piping Systems ISI

b. Inspection Scope

The inspectors reviewed records of the following non-destructive examinations mandated by the ASME Code Section XI to evaluate compliance with the ASME Code Section XI and Section V requirements and, if any indications and defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement:

• Ultrasonic (UT) examination on a 10 elbow-to-pipe weld in the safety injection (SI)system, ASME Class 1

• UT examination on a 10 pipe-to-valve weld in the SI system, ASME Class 1

• Liquid Penetrant (PT) examination on a 14 inlet nozzle to tube side shell weld in the residual heat removal (RHR) system, ASME Class 2

• PT examination on 14 outlet nozzle to tube side shell weld in the RHR system, ASME Class 2

• Magnetic Particle (MT) examination on a 4 reactor vessel upper head to safety nozzle weld, ASME Class 1

• MT examination on a 6 reactor vessel upper head to safety nozzle weld, ASME Class 1 The inspectors observed the following nondestructive examinations conducted as part of the licensees industry initiative inspection program for primary water stress corrosion cracking to determine if the examination was conducted in accordance with the licensees augmented inspection program, industry guidance documents and associated licensee examination procedures and if any indications and defects were detected, to evaluate if they were dispositioned in accordance with approved procedures and NRC requirements:

• UT examination of reactor vessel outlet nozzle DM weld (W-33), ASME Class 1

• Phased Array UT examination of reactor vessel inlet nozzle DM weld (W-39), ASME Class 1 During non-destructive surface and volumetric examinations performed since the previous refuelling outage, the licensee did not identify any recordable indications that were analytically evaluated and accepted for continued service. Therefore, no NRC review was completed for this inspection procedure attribute.

The licensee did not perform pressure boundary welding since the beginning of the previous Unit 2 refueling outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

For the Unit 2 vessel head, no examination was required pursuant to 10 CFR 50.55a(g)(6)(ii)(D) for the current refueling outage. Therefore, no NRC review was completed for this inspection procedure attribute. The previous bare metal visual (BMV)examination for the vessel upper head was performed during the Fall 2008 refueling outage and the next examination is scheduled for the Spring 2013 refueling outage. The previous UT examination for the vessel upper head was performed during the Spring 2007 refueling outage and the next examination is scheduled for the Spring 2013 refueling outage.

b. Findings

No findings were identified.

Boric Acid Corrosion Control (BACC)a. inspection Scope The inspectors performed an independent walkdown of portions of borated systems which recently received a licensee boric acid walkdown and evaluated if the licensees BACC visual examinations emphasized locations where boric acid leaks could cause degradation of safety-significant components.

The inspectors reviewed the following licensee evaluations of reactor coolant system components with boric acid deposits to evaluate if degraded components were documented in the corrective action program. The inspectors also evaluated the corrective actions for any degraded reactor coolant system components against the component ASME Code Section XI:

• Corrosion Assessment 1201-2010-001

• Corrosion Assessment 1208-2010-008

• Corrosion Assessment 1901-2010-001 The inspectors reviewed the following corrective actions related to evidence of boric acid leakage to evaluate if the corrective actions completed were consistent with the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B, Criterion XVI:

• CR 340402, Dry white residue was discovered on the pipe cap for 21204X4017

• CR 340429, Dry discolored residue was discovered in the packing area of valve 21213U4070

• CR 340440, A moderate amount of moist slightly discolored residue was discovered originating from the body to bonnet connection of 21208U4287

b. Findings

No findings were identified.

Steam Generator (SG) Tube Inspection Activities

a. Inspection Scope

The inspectors reviewed the Unit 2 eddy current (EC) examination activities in SGs 1 and 4 to evaluate the inspection activities against the licensees Technical Specifications, NRC commitments, ASME Section XI, and Nuclear Energy Institute (NEI)97-06, Steam Generator Program Guidelines. The inspectors reviewed the scope of the EC examinations to verify it included the applicable potential areas of tube degradation.

The inspectors also verified that appropriate inspection scope expansion criteria were planned based on inspection results. Additionally, the inspectors reviewed EC examination status reports to ensure that all tubes with relevant indications were appropriately screened for in-situ pressure testing. Based on the EC examination results, no new degradation mechanisms were identified, no EC scope expansion was required, and none of the SG tubes examined met the criteria for in-situ pressure testing.

The inspectors reviewed the last Condition Monitoring and Operational Assessment report to assess the licensees prediction capability for maximum tube degradation. The inspectors review also included the licensees repair criteria and repair process to ensure they were consistent with plant Technical Specifications and industry guidelines.

This included record review of tube plugging activities in SG 4. The inspectors also reviewed the primary to secondary leakage (e.g., SG tube leakage) history for the last operating cycle. The inspectors noted that primary to secondary leakage was below the detection threshold during the previous operating cycle.

Additionally, the inspectors reviewed documentation to ensure that data analysis, EC probes, and equipment configurations were qualified to detect the existing and potential SG tube degradation mechanisms. The inspectors review included a sample of site-specific Examination Technique Specification Sheets (ETSSs) to ensure that their qualification was consistent with Appendix H or I of the Electric Power Research Institute Pressurized Water Reactor Steam Generator Examination Guidelines, Rev. 7.

Furthermore, the inspectors reviewed a sample of EC data with a qualified data analyst for the following tubes: SG 1 (R43C100, R1C78, R49C89, R58C75); and SG4 (R53C43, R42C93, R40C106, R55C28). Finally, the inspectors reviewed the licensees corrective actions for indications (either from EC or secondary side visual inspections) of potential loose parts on the SG secondary side, including direct observation of Foreign Object Search and Retrieval (FOSAR) activities.

b. Findings

No findings were identified.

Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI/SG related problems entered into the licensees corrective action program and conducted interviews with licensee staff to determine if:

• The licensee had established an appropriate threshold for identifying ISI/SG related problems;

• The licensee had performed a root cause (if applicable) and taken appropriate corrective actions; and

• The licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity.

The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

a. Inspection Scope

Resident Quarterly Observation The inspectors observed operator performance during the week of September 5, during licensed operator simulator training described on simulator exercise guides V-RQ-SE-11501-1.0 and V-RQ-SE-11502-1.0. The first scenario observed consisted of a seismic event and an Eagle 21 processor failure combined with a reactor trip and subsequent loss of offsite power. The second scenario consisted of a pressurizer level controller failure coupled with a turbine load rejection and a 50 gpm reactor coolant system (RCS) leak. Documents reviewed are listed in the

. The inspectors specifically assessed the following areas:

• Correct use of the abnormal and emergency operating procedures

• Ability to identify and implement appropriate actions in accordance with the requirements of the technical specifications (TS)

• Clarity and formality of communications in accordance with procedure 10000-C, Conduct of Operations

• Proper control board manipulations including critical operator actions

• Quality of supervisory command and control

• Effectiveness of the post-evaluation critique

b. Findings

No findings were identified.

1R12 Maintenance Rule Effectiveness

a. Inspection Scope

The inspectors evaluated two equipment issues described in the CRs listed below to verify the licensees effectiveness with the corresponding preventive or corrective maintenance associated with structures, systems, and components (SSCs). The inspectors reviewed Maintenance Rule (MR) implementation to verify that component and equipment failures were identified, entered, and scoped within the MR program.

Selected SSCs were reviewed to verify proper categorization and classification in accordance with 10 CFR 50.65. The inspectors examined the licensees 10 CFR 50.65(a)(1) corrective action plans to determine if the licensee was identifying issues related to the MR at an appropriate threshold and that corrective actions were established and effective. The inspectors review also evaluated if maintenance preventable functional failures (MPFFs) or other MR findings existed that the licensee had not identified.

The inspectors reviewed the licensees controlling procedure, i.e., procedure 50028-C, Revision 18.1, Engineering Maintenance Rule Implementation.

• CR 2011342675, Unit 2 RCS Return to 10 CFR 50.65(a)2 Status

• CR 2011107100, Returning Unit 1 Standby Power (Safety Features Sequencer)

System 1821 to MR 10 CFR 50.65(a)2 Status

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the following five work activities to verify plant risk was properly assessed by the licensee prior to conducting the activities. The inspectors reviewed risk assessments and risk management controls implemented for these activities to verify they were completed in accordance with procedure 00354-C, Maintenance Scheduling, and 10 CFR 50.65(a)(4). The inspectors also reviewed the CR database to verify that maintenance risk assessment problems were being identified at the appropriate level, entered into the corrective action program, and appropriately resolved.

• Operability testing on the 2B EDG concurrent with high-risk work being performed in the high voltage switchyard

• Maintenance outage on the Unit 1 train A nuclear service cooling water (NSCW)tower return valves

• Operability testing on the 1A EDG concurrent with NSCW fan #1 OOS

• Maintenance outage on the Unit 1 train A residual heat removal (RHR) pump concurrent with high-risk work being performed in the high voltage switchyard

• Defense-In-Depth contingency plan for hot fueled mid-loop operation during 2R15 refueling outage

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following five evaluations to verify they met the requirements of procedure NMP-GM-002, Corrective Action Program, and NMP-GM-002-001, Corrective Action Program Instructions. The scope of this inspection included a review of the technical adequacy of the evaluations, the adequacy of compensatory measures, and the impact on continued plant operation.

• CR 334109, 1A ESF chiller did not start as expected

• CR 336395, Installation of non-safety related parts in a safety related application

• CR 354089, 2FT-0533 loop 3 steam generator steam flow transmitter, has head turned on rosemount environmental qualification (EQ) transmitter

• CR 352493, 2N-32 source range nuclear instrument spiking

• CR 354414, tan delta testing for B train AFW pump motor cables results exceeded acceptance criteria

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

Temporary Modifications Reviewed temporary modification SNC 332440 and associated 10CFR50.59 screening criteria against the system design bases documentation and procedure 00307-C, Temporary Modifications. This temporary modification removed 2N36 intermediate range nuclear instrument from service thus halving 2N32 source range nuclear instrument indication. The inspectors reviewed the implementation, engineering justification, and operator awareness for this temporary modification.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

a. Inspection Scope

The inspectors either observed post-maintenance testing or reviewed the test results for the following six maintenance activities to verify that the testing met the requirements of procedure 29401-C, Work Order Functional Tests, for ensuring equipment operability and functional capability was restored. The inspectors also reviewed the test procedures to verify the acceptance criteria were sufficient to meet the TS operability requirements.

• Replacement of a 7300 series printed circuit board in the Unit 1 solid-state protection system (SSPS)

• Replacement of the electronic governor on the 2B EDG

• Maintenance outage on the Unit 2 A train essential chilled water system

• 2N32 source range nuclear instrument temporary modification installation

• Safety-related battery 2-1806-B3-BYB modified performance test

• 2BB1606, NSCW B train fan 2, failed to close

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

a. Inspection Scope

The inspectors performed the inspection activities described below for the Unit 2 refueling outage that began on September 18, 2011. The inspectors confirmed that, when the licensee removed equipment from service, the licensee maintained defense-in-depth commensurate with the outage risk control plan for key safety functions and applicable technical specifications and that configuration changes due to emergent work and unexpected conditions were controlled in accordance with the outage risk control plan. Reviewed the licensees commitments from GL 88-17 and confirmed that they were in place and adequate. During the reduced inventory and mid-loop condition, verified that the configurations of the plant systems were in accordance with the commitments. During mid-loop operations, observed the effect of distractions from unexpected conditions or emergent activities on the operators ability to maintain required reactor vessel level. Documents reviewed are listed in the Attachment.

Inspection activities included:

• Prior to the outage, the resident inspectors reviewed the licensees integrated risk control plan to verify that activities, systems, and/or components which could cause unexpected reactivity changes were identified in the outage risk plan.

• Observed portions of the plant shutdown and cooldown to verify that the technical specification cooldown restrictions were followed. Reactor coolant system (RCS)integrity was verified by reviewing RCS leakage calculations.

• Verified that the licensee reviewed their controls and administrative procedures governing mid-loop operation, and conducted training for mid-loop operation.

• Verified that procedures were in use for Containment closure capability for mitigation of radioactive releases; identified unexpected RCS inventory changes and verified an adequate RCS vent path existed during RCS drain down to mid-loop; and Emergency/abnormal operation during reduced inventory.

• Verified that Indications of core exit temperature were operable and periodically monitored; Indications of RCS water level were operable and periodically monitored; RCS perturbations were avoided; Means of adding inventory to the RCS were available; Reasonable assurance was obtained that all hot legs were not simultaneously blocked by nozzle dams unless the upper plenum was vented; and Contingency plans existed to repower vital electrical busses from an alternate source if the primary source was lost.

• Reviewed reactor coolant system pressure, level, and temperature instruments to verify that the instruments provided accurate indication and that allowances were made for instrumentation errors.

• Verified that outage work did not impact the operation of the spent fuel cooling system.

• Reviewed the status and configuration of electrical systems to verify that those systems met technical specification requirements and the licensees outage risk control plan.

• Observed decay heat removal parameters to verify that the system was properly functioning and providing cooling to the core, specifically during hot mid-loop operations.

• Reviewed system alignments to verify that the flow paths, configurations and alternative means for inventory addition were consistent with the outage risk plan.

• Reviewed selected control room operations to verify that the licensee was controlling reactivity in accordance with the technical specifications.

• Observed the licensees control of containment penetrations to verify that the requirements of the technical specifications were met.

• Reviewed the licensees plans for changing plant configuration to verify that technical specifications, license conditions, and other requirements, commitments, and administrative procedure prerequisites were met prior to changing plant configuration.

• Observed refueling activities for compliance with Technical Specifications, to verify proper tracking of fuel assemblies from the spent fuel pool to the core, and to verify foreign material exclusion was maintained.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the following six surveillance test procedures and either observed the testing or reviewed test results to verify that testing was conducted in accordance with the procedures and that the acceptance criteria adequately demonstrated that the equipment was operable. Additionally, the inspectors reviewed the CR database to verify that the licensee had adequately identified and implemented appropriate corrective actions for surveillance test problems.

Surveillance Tests

• 14980A-2 Rev 22.4, Diesel Generator 2A Operability Test

• 14980A-1 Rev 23.3, Diesel Generator 1A Operability Test

• 24411-2 Rev. 8, Nuclear Instrumentation System Power Range Channel 2N-50 Channel Calibration In-Service Tests (IST)

• 14805A-1 Rev. 3, Train A Residual Heat Removal Pump IST and Response Time Test

• 14804A-1 Rev. 3.2, Safety Injection Pump A Inservice and Response Time Tests Containment Isolation Valve Tests

• 14335-2, Revision 8, Containment Penetration No. 35 Containment Spray Train A Local Leak Rate Test

b. Findings

No findings were identified.

RADIATION SAFETY

(RS)

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

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

Hazard Assessment and Instructions to workers During facility tours, the inspectors directly observed labeling of radioactive material and postings for radiation areas, high radiation areas (HRAs), and airborne radioactivity areas established within the radiologically controlled area (RCA) of the Unit 2 (U2) containment, Unit 1 (U1) and U2 auxiliary buildings, radwaste processing facility and selected storage locations. The inspectors independently measured radiation dose rates or directly observed conduct of licensee radiation surveys for selected RCA areas. The inspectors reviewed survey records for several plant areas including surveys for alpha emitters, hot particles, airborne radioactivity, gamma surveys with a range of dose rate gradients, and pre-job surveys for selected U2 Refueling Outage 15 (2R15) tasks. The inspectors also discussed changes to plant operations that could contribute to changing radiological conditions since the last inspection. For selected 2R15 jobs, the inspectors attended pre-job briefings and reviewed radiation work permit (RWP) details to assess communication of radiological control requirements and current radiological conditions to workers.

Hazard Control and Work Practices The inspectors evaluated access barrier effectiveness for selected U1 and U2 locked high radiation area (LHRA) and very high radiation area (VHRA) locations. Changes to procedural guidance for LHRA and VHRA controls were discussed with health physics (HP) supervisors. Controls and their implementation for storage of irradiated material within the spent fuel pool were reviewed and discussed in detail. Established radiological controls (including airborne controls)were evaluated for selected 2R15 tasks including pressurizer code safety valve removal, steam generator (S/G) manway removals and diaphragm insertions, detensioning of the reactor head in the cavity, reactor head lift and scaffolding installation. In addition, licensee controls for areas where dose rates could change significantly as a result of plant shutdown and refueling operations were reviewed and discussed.

Occupational workers adherence to selected RWPs and HP technician (HPT)proficiency in providing job coverage were evaluated through direct observations and interviews with licensee staff. Electronic dosimeter (ED) alarm set points and worker stay times were evaluated against area radiation survey results for pressurizer code safety valve removal, S/G manway removals and diaphragm insertions, detensioning of the reactor head in the cavity, reactor head lift and scaffolding installation. ED alarm logs were reviewed and worker response to dose and dose rate alarms during selected work activities was evaluated. For HRA tasks involving significant dose rate gradients, e.g. S/G maintenance activities, the inspectors evaluated the use and placement of whole body and extremity dosimetry to monitor worker exposure.

Control of Radioactive Material The inspectors observed surveys of material and personnel being released from the RCA using small article monitors (SAMs), personnel contamination monitors (PCMs), and portal monitors (PMs) instruments. The inspectors reviewed the last two calibration records for selected release point survey instruments and discussed equipment sensitivity, alarm setpoints, and release program guidance with licensee staff. The inspectors compared recent 10 Code of Federal Regulations (CFR) Part 61 results for the dry active waste (DAW) radioactive waste stream with radionuclides used in calibration sources to evaluate the appropriateness and accuracy of release survey instrumentation. The inspectors also reviewed records of leak tests on selected sealed sources and discussed nationally tracked source transactions with licensee staff.

Problem Identification and Resolution Condition Reports (CR)s associated with radiological hazard assessment and control were reviewed and assessed. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure NMP-GM-002, Corrective Action Program, Version (Ver.)

12.0. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Radiation protection (RP) activities were evaluated against the requirements of Updated Final Safety Analysis Report (UFSAR) Section 12; Technical Specifications (TS)

Sections 5.4 and 5.7; 10 CFR Parts 19 and 20; and approved licensee procedures.

Licensee programs for monitoring materials and personnel released from the RCA were evaluated against 10 CFR Part 20 and IE Circular 81-07, Control of Radioactively Contaminated Material. Documents reviewed are listed in Section 2RS1 of the

.

The inspectors completed all specified line-items detailed in Inspection Procedure (IP)71124.01 (sample size of 1).

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

Radiation Monitoring Instrumentation During walk-downs of the auxiliary building and the RCA exit point, the inspectors observed installed and portable radiation detection equipment. These included area radiation monitors (ARM)s, continuous air samplers, liquid and gaseous effluent monitors, PCMs, SAMs, PMs, a whole body counter (WBC),count room equipment, and portable survey instruments. The inspectors observed the physical location of the components, noted their material condition, observed the currency of calibration and source check stickers, and discussed performance of equipment with RP personnel.

In addition to equipment walk-downs, the inspectors observed source functional checks of portable detection instruments, including ion chambers and telepoles. For the portable instruments, the inspectors observed the use of a high-range calibrator, and discussed periodic output value testing, calibration, and source check processes with health physics technicians. The inspectors reviewed calibration records and discussed with chemistry personnel alarm setpoint values for PCMs, PMs, effluent monitors, WBCs, and an ARM. This included a sampling of instruments used for post-accident monitoring such as a containment high-range radiation monitor and effluent monitors for noble gas and iodine. The most recent 10 CFR Part 61 analysis for DAW was reviewed to determine if calibration and check sources are representative of the plant source term.

The inspectors observed computerized performance check calibration efficiency information for countroom gamma detectors and a liquid scintillation detector. The inspectors also observed the currency of calibration for selected EDs at the RCA entry point.

Effectiveness and reliability of selected radiation detection instruments were reviewed against details documented in the following: 10 CFR Part 20; NUREG-0737, Clarification of TMI Action Plan Requirements; UFSAR Chapters 11 and 12; and applicable licensee procedures. Documents reviewed during the inspection are listed in section 2RS5 of the Attachment.

Problem Identification and Resolution The inspectors reviewed selected Corrective Action Program reports in the area of radiological instrumentation. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure NMP-GM-002-001, Corrective Action Program Instructions, Ver. 26.0.

Documents reviewed are listed in section 2RS5 of the Attachment.

The inspectors completed all specified line-items detailed in IP 71124.05 (sample size of 1).

b. Findings

No findings were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors reviewed the facility activation exercise guide and observed the following emergency response activity to verify the licensee was properly classifying emergency events, making the required notifications, and making appropriate protective action recommendations in accordance with procedures 91001-C, Emergency Classifications, and 91305-C, Protective Action Guidelines.

• On 7/26/11, the licensee conducted an emergency preparedness drill which involved actuation of the TSC, the OSC, and the EOF. The drill scenario began with a steam generator tube rupture greater than 700 gpm, followed by a complete loss of all AC power due to a string of sabotage events.

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

.1 Barrier Integrity Cornerstone

a. Inspection Scope

The inspectors sampled licensee submittals for the listed PIs during the period from July 1, 2010, through June 30, 2011, for both Unit 1 and Unit 2. The inspectors verified the licensees basis in reporting each data element using the PI definitions and guidance contained in procedure 00163-C, Rev. 14.0, NRC Performance Indicator and Monthly Operating Report Preparation and Submittal.

• High Head Safety Injection

• Residual Heat Removal

• Heat Removal The inspectors reviewed Unit 1 and Unit 2 unavailability tracking sheets and demand/failure tracking sheets along with operator log entries, the monthly operating reports, and monthly PI summary reports to verify that the licensee had accurately submitted the PI data. Because the probabilistic risk assessment for the station has been updated, the inspectors verified the constants used in the mitigating systems performance index (MSPI) calculations for the 2nd quarter were consistent with the new PRA constants documented in MSPI basis document, version 4.

b. Findings

No findings were identified.

.2 Radiation Safety Cornerstone

a. Inspection Scope

The inspectors sampled licensee records to verify the accuracy of reported Performance Indicator (PI) data for the periods listed below. To verify the accuracy of the reported PI elements, the reviewed data were assessed against guidance contained in NEI 99-02, "Regulatory Assessment Indicator Guideline," Rev. 6.

Occupational Radiation Safety Cornerstone The inspectors reviewed the Occupational Exposure Control Effectiveness PI results for the Occupational Radiation Safety Cornerstone from January 2010 to June 2011. For the assessment period, the inspectors reviewed 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 sections 2RS1 and 4OA1 of the report Attachment Public Radiation Safety (PS) Cornerstone The inspectors reviewed the Radiological Effluent Technical Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences PI results from January 2010 through June 2011. The inspectors reviewed CAP documents, effluent dose data, and licensee procedural guidance for classifying and reporting PI events. The inspectors also interviewed licensee personnel responsible for collecting and reporting the PI data.

Reviewed documents are listed in Section 4OA1 of the Attachment.

The inspectors completed two

(2) of the required samples for IP 71151.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Daily Condition Report Review As required by 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 corrective action program. This review was accomplished by either attending daily screening meetings that briefly discussed major CRs, or accessing the licensees computerized corrective action database and reviewing each CR that was initiated.

.2 Focused Review

a. Inspection Scope

The inspectors performed a detailed review of the following four CR(s) which addresses the 2B emergency diesel generator not maintaining load during a surveillance run and the installation of E-MAX safety-related breakers. The goal of the review was to verify that the full extent of the issue was identified, an appropriate evaluation was performed, and appropriate corrective actions were specified and prioritized. The inspectors evaluated the CR against the licensees corrective action program as delineated in licensee procedure NMP-GM-002, and 10 CFR 50, Appendix B. Documents reviewed are listed in the Attachment.

• 332810, 2B EDG lost full load during testing

• 332562, corrective action process does not ensure identification of significant conditions adverse to quality (SCAQ)

• 2011106884, E-MAX breakers installed with cover screw installed

• 2011107450, E-MAX breakers installed with cover screw installed

b. Findings and Observations

Introduction:

An NRC-identified Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified by resident inspectors for failure to develop and implement adequate corrective action to prevent recurrence (CAPR) in response to a significant condition adverse to quality (SCAQ) associated with E-MAX safety-related breaker front cover mounting screws. The licensee entered this issue into their corrective action program (CR 332562).

Description:

On October 24, 2010, the licensee attempted to manually start Unit 1 Containment Cooling Unit #8 in low speed during the performance of a Containment Cooling System Operability and Response Time Test and the cooling unit did not start.

The work order investigation identified that the circuit breaker had two breaker cover mounting holes that were cracked. This allowed the top right hand side screw to come in contact with the breakers closing mechanism, thus preventing the breaker from closing. The front breaker cover was replaced, the breaker was tested. The licensee wrote Condition Report (CR 2010113375) on the failed breaker which placed the condition into their corrective action program. Of note, this initiating event/condition met the definition of a SCAQ per the licensees corrective action program document NMP-GM-002.

The licensee wrote temporary modification packages and associated installation work orders (TMs 1102221001 and 2012221301) to remove the upper right hand screw from all of the currently installed E-MAX safety-related breakers. Future corrective actions were to develop design change packages that would restore the breakers to their original configuration with a new shorter front cover plate screw and apply a maximum torque value for the screws. During the development of both the temporary modification and work order installation package instructions, the licensee failed to develop corrective actions and/or instructions that would address any future planned or unplanned E-MAX breaker installations. Subsequently, a total of six E-MAX safety-related breakers were installed in the plant without having the temporary modification to remove the top right-hand screw implemented prior to installation and return to service. The licensee immediately removed the subject screws and developed corrective actions to address future E-MAX breaker installations.

Analysis:

The failure to develop and implement adequate corrective action to prevent recurrence (CAPR) in response to a significant condition adverse to quality (SCAQ) is a performance deficiency. The finding was considered more than minor because it impacted the Reactor Safety Mitigating Systems Cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and affected the cornerstone attribute of equipment performance. Specifically, the inadequate corrective action allowed for the installation of non-conforming safety-related breakers that incurred unplanned unavailability to implement the associated temporary modification and also decreased reliability during the time the breaker was in-service without the temporary modification installed.

The inspectors evaluated the finding using IMC 0609, Appendix A, Attachment 1, Significance Determination of Reactor Inspection Findings for At-Power Situations, using the Phase 1 Worksheet for the Mitigating Systems Cornerstone. Since the inspectors answered No to all of the Exhibit 1, Table 4a Mitigating Systems questions, the inspectors concluded that the finding was of very low safety significance (Green).

The deficiency is indicative of current licensee performance and that the cause of this finding was related to the Corrective Action Program component of the Problem Identification and Resolution cross-cutting area due to the licensees failure to take appropriate corrective actions to address safety issues in a timely manner, commensurate with their safety significance and complexity P.1(d)

Enforcement:

10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. In the case of SCAQs, the measures shall assure that the cause of the condition is determined and corrective action taken to preclude repetition. Contrary to the above, the licensee had failed to develop and implement corrective actions to preclude repetition for a SCAQ associated with the E-MAX safety-related breakers. Specifically, no corrective actions were developed to address future E-MAX breaker installations to insure that the top right-hand screw was removed prior to installation. This condition lasted from 4/30/2011 to 5/18/2011. Because this violation was of very low safety significance and was entered into the licensees CAP (CR 332562), it is being treated as an NCV, consistent with Section VI.A.1 of the NRC Enforcement Policy. (NCV 05000424,425/2011004-01, Installation of Non-Conforming Safety-Related Breakers due to a Failure to Implement Corrective Action To Prevent Recurrence to Address a Significant Condition Adverse to Quality.

4OA3 Event Follow-up

.1 (Closed) Licensee Event Report 05000424/2011-001-00: Reactor Trip due to 1A

Reactor Trip Breaker Opening At 1734 on April 20, 2011, Unit 1 tripped from 100% RTP. The plant responded to the trip as expected. Investigation revealed that the reactor trip was caused by the opening of the A reactor trip breaker (RTB). The licensee conducted a root cause investigation, but was unable to identify exactly what caused the RTB to open. The three components that were suspected of causing the trip (RTB itself, under voltage driver board in the solid state protection system (SSPS), and the shunt trip relay) were replaced. The licensee hooked-up numerous data recorders via temporary modifications and monitored the breaker and associated inputs for several weeks with no anomalies noted. The recorders were subsequently removed and the system returned to original pre-trip configuration. The inspectors reviewed the LER, the associated condition report and root cause determination, and subsequent action items. No other findings were identified. This LER is closed.

.2 (Closed) TI 2515/179 Verification of Licensee Responses to NRC Requirement for

Inventories of Materials Tracked in the National Source Tracking System (NSTS)

Pursuant to Title 10, Code of Federal Regulations, Part 20.2207 (10 CFR 20.2207)

a. Scope

The inspectors performed the TI concurrent with IP 71124.01 Radiation Hazard

Analysis.

The inspectors reviewed the licensees source inventory records and identified the sources that met the criteria for reporting to the NSTS. The inspectors visually identified the source contained in the calibration system and verified the presence of the source by direct radiation measurement using a calibrated portable radiation detection survey instrument. The inspectors reviewed the physical condition of the irradiation device.

The inspectors reviewed the licensees procedures for source receipt, maintenance, transfer, reporting and disposal. The inspectors reviewed documentation that was used to report the sources to the NSTS. Documents reviewed are listed in sections 2RS1 of the Attachment.

b. Findings

No findings were identified. This completes the Region II inspection requirements.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

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

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

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

b. Findings and Observations

No findings were identified.

4OA6 Meetings, Including Exit

.1 Exit Meeting

On October 19, 2011, the resident inspectors presented the inspection results to you and other members of your staff, who acknowledged the findings. The inspectors confirmed that proprietary information was not provided or examined during the inspection.

4OA7 Licensee-Identified Violations

The following violations of very low significance (Green) or Severity Level IV were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy, for being dispositioned as a Non-cited Violation.

.1 Loss of Both Trains of Control Room Emergency Filtration System (CREFS) Actuation

Instrumentation Technical Specification (TS) 3.3.7, Limiting Condition for Operation (LCO) Applicability, LCO 3.3.7 Condition P, requires that when four intake radiological gas monitor channels are inoperable, operators must place one CREFS train in each unit in the emergency mode within 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br />. Contrary to the above, on September 22, 2011, the licensee discovered that AHV12153 was closed. This condition prevented air flow past all four radiological gas monitors rendering them inoperable. A review of the plant computer system showed that the valve was closed on September 19, at 2015. Thus for a period of approximately two and half days, Unit 1 & 2 were operated in a condition prohibited by TS 3.3.7, which is applicable in Modes 1, 2, 3 and 4. This finding is not greater than green using the IMC 609 Phase 1 worksheet due to the finding only representing a degradation of the radiological barrier function provided for the control room. The licensee has entered this issue into their corrective action program as CR 353533, completed a basic cause determination, drafted LER 05000424,425/2011-003, and immediately restored the valve to its proper position.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

R. Brigdon, Training and Emergency Preparedness Manager

D. Cordis, ISI Engineer

R. Dedrickson, Plant Manager

K. Dyar, Security Manager

M. Hickox, Licensing

S. Khera, Health Physics Foreman

I. Kochery, Health Physics Manager

H. Lunsford, BACCP Owner

W. Malone, ISI Engineer

C. Martin, Chemistry

D. McCary, Operations Manager

K. Molina, Heat Exchanger System Engineer

S. Phillips, Maintenance Manager

D. Puckett, Performance Analysis Supervisor

J. Robinson, Technical Services Manager

T. Smith, Lead Eddy Current Level III

S. Stegall, SG Engineer

S. Swanson, Site Support Manager

T. Tynan, Site Vice-President

NRC personnel

J. Hickey, Chief, Region II Reactor Projects Branch 2

M. Cain, Senior Resident Inspector

J. Dodson, Senior Project Engineer

LIST OF ITEMS

OPENED AND CLOSED OPEN AND CLOSED

05000424,425/2011004-01 NCV Installation of Non-Conforming Safety-

Related Breakers due to a Failure to Implement Corrective Action To Prevent Recurrence to Address a Significant Condition Adverse to Quality (4OA2.2)

CLOSED

05000424/2011-001-00 LER Reactor Trip Due to 1A Reactor Trip Breaker Opening (4OA3)

2515/179 TI Verification of Licensee Responses to NRC Requirement for Inventories of Materials Tracked in the National Source Tracking System (NSTS) Pursuant to Title 10, Code of Federal Regulations, Part 20.2207