IR 05000395/2011004

IR 05000395-11-004, on 07/01/2011 - 09/30/2011, Virgil C. Summer Nuclear Station, Routine Integrated Inspection Report, Event Followup

ML113000300
Person / Time
Site:	Summer
Issue date:	10/27/2011
From:	Sandra Walker NRC/RGN-II/DRP/RPB5
To:	Gatlin T South Carolina Electric & Gas Co
References
IR-11-004
Download: ML113000300 (40)

Text

UNITED STATES October 27, 2011

SUBJECT:

VIRGIL C. SUMMER NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000395/2011004

Dear Mr. Gatlin:

On September 30, 2011, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Virgil C. Summer Nuclear Station. The enclosed inspection report documents the inspection results, which were discussed on October 24, 2011, 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 self-revealing finding of very low safety significance (Green) which was determined to be a violation of NRC requirements. However, because of the very low safety significance and because it was entered into your corrective action program, the NRC is treating this finding as a non-cited violation (NCV) consistent with Section 2.3.2.a of the NRCs 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 United States 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 Virgil C. Summer Nuclear Station.

Additionally, if you disagree with the characterization of 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 Resident Inspector at the Virgil C. Summer Nuclear Station.

SCE&G 2 In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs document 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/

Shakur A. Walker, Acting Chief Reactor Projects Branch 5 Division of Reactor Projects Docket No.: 50-395 License No.: NPF-12

Enclosure:

NRC Integrated Inspection Report 05000395/2011004 w/Attachment: Supplemental Information

REGION II==

Docket No.: 50-395 License No.: NPF-12 Report No.: 05000395/2011004 Licensee: South Carolina Electric & Gas (SCE&G) Company Facility: Virgil C. Summer Nuclear Station Location: P.O. Box 88 Jenkinsville, SC 29065 Dates: July 1, 2011 through September 30, 2011 Inspectors: J. Reece, Senior Resident Inspector E. Coffman, Resident Inspector R. Hamilton, Senior Health Physicist (Sections 2RS2, 2RS3, 2RS4, 2RS5, 4OA1.2)

M. Meeks, Operations Engineer (Section 1R11.2)

R. Kellner, Health Physicist (Section 4OA3.2)

Approved by: Shakur A. Walker, Acting Chief Reactor Projects Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000395/2011004; 07/01/2011 - 09/30/2011: Virgil C. Summer Nuclear Station; Routine

Integrated Inspection Report. Event Followup.

The report covered a 3 month period of inspection by resident inspectors and reactor inspectors from the region. One 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). The cross-cutting aspect was determined using IMC 0310, Components Within the Cross Cutting Areas. Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 4, dated December 2006.

Cornerstone: Mitigating System

Green.

A self-revealing, non-cited violation was identified for the failure to comply with Technical Specification 6.8.1 to adequately implement a main steam operating procedure during manipulation of the C main steam isolation valve (MSIV) resulting in excessive steam generator line differential pressure and subsequent safety injection. The issue was entered into the licensees corrective action program as condition report CR-11-03001.

The failure to implement a procedure for manipulation of the C MSIV was a performance deficiency (PD). The PD was more than minor and therefore a finding because it impacted the initiating events cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown and the related attribute of human performance because the licensee failed to properly implement a procedure controlling the manipulation of a MSIV. In accordance with Inspector Manual Chapter 0609, Significant Determination Process, the inspectors performed a Phase 1 analysis and determined the finding was of very low safety significance or Green because the finding did not contribute to both the likelihood of both a reactor trip and the unavailability of mitigation equipment and associated functions. This finding involved the cross-cutting area of human performance, the component of the resources, and the aspect of procedure use and adherence, H.4(b), because the licensee failed to adequately follow procedures.

(Section 4OA3.1)

Licensee-Identified Violations

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

REPORT DETAILS

Summary of Plant Status

The unit began the inspection period at full Rated Thermal Power (RTP) and operated at or near full RTP for the remainder of the quarter.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

==1R01 Adverse Weather Protection

.1 External Flooding

a. Inspection Scope

==

The inspectors reviewed the licensees external flood design mitigation plans to determine consistency with design requirements, updated final safety analysis report (UFSAR) Sections 2.4.2 through 2.4.10, flood analysis documents, Emergency Plan Procedure (EPP)-015, Revision (Rev.) 17, Natural Emergency, and OAP-109.1, Rev.

3A, Guidelines for Severe Weather. The inspectors performed walkdowns of the station to verify flood protection features remained as described in the FSAR.

Specifically, the inspectors performed visual examinations of the yard storm drain system inside the protected area to verify that drains were not blocked and the ground was properly graded to channel water into the system.

b. Findings

No findings were identified.

==1R04 Equipment Alignment

a. Inspection Scope

==

The inspectors conducted three partial equipment alignment walkdowns which are listed below, to evaluate the operability of selected redundant trains or backup systems with the other train or system inoperable or out of service (OOS). Correct alignment and operating conditions were determined from the applicable portions of drawings, system operating procedures (SOP), and technical specifications (TS). The inspections included review of outstanding maintenance work orders (WO) and related condition reports (CR) to verify that the licensee had properly identified and resolved equipment alignment problems that could lead to the initiation of an event or impact mitigating system availability. Documents reviewed are listed in the Attachment.

• A and B component cooling water (CCW) during planned maintenance on the C CCW pump

• A emergency feedwater (EFW) and turbine driven emergency feedwater (TDEFW)during planned maintenance on the B EFW pump

• B reactor building spray (RBS) pump during planned maintenance on the A RBS pump

b. Findings

No findings were identified.

==1R05 Fire Protection

.1 Fire Protection Tours

a. Inspection Scope

==

The inspectors reviewed recent CRs, WOs, and impairments associated with the fire protection system. The inspectors reviewed surveillance activities to determine whether they supported the operability and availability of the fire protection system. The inspectors assessed the material condition of the active and passive fire protection systems and features, and observed the control of transient combustibles and ignition sources. The inspectors conducted routine inspections of the following eight areas (respective fire zones also noted):

• Control room (fire zone CB-17.1)

• Turbine building (fire zone TB-1)

• Control building cable spreading rooms (fire zones CB-4, CB-15)

• Intermediate building 412 elevation (fire zones IB-25.1.1, 1.2, 1.3, 1.5)

• Diesel generator rooms A and B (fire zones DG-1.1/1.2, DG-2.1/2.2)

• Control building cable spreading rooms (fire zones CB-1.1, CB-1.2, CB-2, CB-5)

• Battery and charger rooms A and B (fire zones IB-2, 3, 4, 5, 6)

• Control building 482 elevation (fire zones CB-22, CB-23)

b. Findings

No findings were identified.

==1R11 Licensed Operator Requalification Program

.1 Quarterly Resident Inspector Observations

==

a. Inspection Scope

The inspectors observed an operator requalification simulator scenario which involved a failure of main turbine first stage pressure, a failure of a nuclear instrumentation channel, a large break loss of coolant accident, a failure of the reactor to automatically trip, a failure of safety injection to automatically initiate, and a failure of the A emergency diesel generator to automatically start. The inspectors observed crew performance in terms of communications; ability to prioritize failures in order to take timely and proper actions; prioritizing, interpreting, and verifying alarms; correct use and implementation of procedures, including the alarm response procedures; timely control board operation and manipulation, including high-risk operator actions; and oversight and direction provided by the shift manager, including the ability to identify and implement appropriate TS actions and when required, emergency action levels as the Site Emergency Manager. The inspectors observed the post training critique to determine that weaknesses or improvement areas revealed by the training were captured by the instructor, reviewed with the operators, and appropriate corrective actions initiated.

b. Findings

No findings were identified.

.2 Biennial Licensed Operator Requalification Inspection

a. Inspection Scope

The inspectors reviewed the facility operating history and associated documents in preparation for this inspection. During the week of August 8 - 12, 2011, the inspectors reviewed documentation, interviewed licensee personnel, and observed the administration of operating tests associated with the licensees operator requalification program. Each of the activities performed by the inspectors was done to assess the effectiveness of the facility licensee in implementing requalification requirements identified in 10 CFR Part 55, Operators Licenses. The evaluations were also performed to determine if the licensee effectively implemented operator requalification guidelines established in NUREG-1021, Operator Licensing Examination Standards for Power Reactors, and Inspection Procedure 71111.11, Licensed Operator Requalification Program. The inspectors also evaluated the licensees simulation facility for adequacy for use in operator licensing examinations using ANSI/ANS-3.5-1985, American National Standard for Nuclear Power Plant Simulators for use in Operator Training and Examination. The inspectors observed three crews during the performance of the operating tests. Documentation reviewed included written examinations, Job Performance Measures (JPMs), simulator scenarios, licensee procedures, on-shift records, simulator modification request records, simulator performance test records, operator feedback records, licensed operator qualification records, remediation plans, watchstanding records, and medical records. The records were inspected using the criteria listed in Inspection Procedure 71111.11. Documents reviewed during the inspection are documented in the List of Documents Reviewed.

b. Findings

No findings were identified.

==1R12 Maintenance 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 procedures, i.e., engineering services procedure (ES)-514, Rev. 5, Maintenance Rule Implementation, and station administrative procedure (SAP)-0157, Rev. 0A, Maintenance Rule Program, to verify consistency with the MR requirements.

• CR-11-02684, B service water (SW) booster pump discharge check valve, XVC03135B-SW, stuck open

• CR-11-02734, on starting B SW booster pump the respective discharge valve, XVB03107B-SW, did not open

b. Findings

No findings were identified.

==1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

==

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

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

(2) the management of risk;

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

(4) that emergent work problems were adequately identified and resolved. The inspectors evaluated the licensees work prioritization and risk characterization to determine, as appropriate, whether necessary steps were properly planned, controlled, and executed for the planned and emergent work activities.

• Work Week 2011-29: risk assessments for B emergency diesel generator (EDG)maintenance and kW meter calibration resulting in a Yellow risk status

• Work Week 2011-34: risk assessment for B train SW pump related component maintenance resulting in a Yellow risk status

• Work Week 2011-35: risk assessments for scheduled maintenance on A EDG and related components resulting in a Yellow risk status

• Work Week 2011-36: risk assessment for scheduled maintenance on TDEFW resulting in Yellow risk status

• Work Week 2011-40: risk assessments for switchyard upgrades and C SW component work resulting in a Yellow risk status

b. Findings

No findings were identified.

==1R15 Operability Evaluations

a. Inspection Scope

==

The inspectors reviewed five operability evaluations listed below, affecting risk significant mitigating systems to assess, as appropriate:

(1) the technical adequacy of the evaluations;

(2) whether operability was properly justified and the subject component or system remained available, such that no unrecognized increase in risk occurred;

(3) whether other existing degraded conditions were considered;

(4) that the licensee considered other degraded conditions and their impact on compensatory measures for the condition being evaluated; and,

(5) the impact on TS limiting conditions for operations and the risk significance in accordance with the significance determination process. Also, the inspectors verified that the operability evaluations were performed in accordance with SAP-209, Rev. 0E, Operability Determination Process, and SAP-999, Rev. 5, Corrective Action Program.

• CR-11-03323, Chilled water piping not evaluated in flooding calculation for 1DB switchgear room

• CR-11-03505, Air intensifier cycles frequently due to an exhaust air leak on the 1A feedwater isolation valves control block; specifically, Action 1 to evaluate the current valve condition following regulator adjustment

• CR-05-04504, B SW pump vacuum breaker sprays down terminal boxes

• CR-11-04060, Forward leakage through motor driven EFW flow control valves

• CR-11-02173, Reactor vessel head vent system not analyzed for water relief

b. Findings

No findings were identified.

==1R18 Plant Modifications Temporary Modification

a. Inspection Scope

==

For the one equipment change listed below that was considered a temporary modification, the inspectors witnessed aspects of the implementation and evaluated the change for adverse effects on system availability, reliability, and functional capability.

Documents reviewed, as applicable, included associated 10 CFR 50.59 reviews, Engineering Technical Work Records, engineering design calculations, WOs and implementation packages, corrective action documents, applicable sections of the UFSAR, TS, and design basis information.

• Bypass Authorization Request (BAR) 11-01, install jumper to disable the A chiller low SW flow alarm.

b. Findings

No findings were identified.

==1R19 Post Maintenance Testing

a. Inspection Scope

==

For the five maintenance activities listed below, the inspectors reviewed the associated post-maintenance testing (PMT) procedures and either witnessed the testing and/or reviewed test records 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) test 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 its safety function. The inspectors verified that these activities were performed in accordance with general test procedure (GTP)-214, Rev.

5A, Post Maintenance Testing Guideline.

• WO 1102730, PMT for maintenance and calibration of CCW B pump

• WO 1100801, PMT for inspection/replacement of components on the SW pump B vacuum breaker

• WO 1110441, Upsize overloads for EDG supply fan A then run fan and take thermography

• WO 1005376, Replace 9 and 9C movable contact on A EDG local, remote and maintenance switch

• WO 1113791, Replace faulty expansion valve on the A chiller

b. Findings

No findings were identified.

==1R22 Surveillance Testing

a. Inspection Scope

==

The inspectors observed and/or reviewed the six surveillance test procedures (STPs)listed below to verify that TS or risk significant surveillance requirements were followed and that test acceptance criteria were properly specified to ensure that the equipment could perform its intended safety function. The inspectors verified that proper test conditions were established as specified in the procedures, that no equipment preconditioning activities occurred, and that acceptance criteria were met.

In-Service Tests:

• STP-220.001, Motor Driven Emergency Feedwater Pump and Valve Test, Rev. 9

• STP-205.004, RHR Pump and Valve Operability Test, Rev. 7 Other Surveillance Tests:

• STP-125.002B, Diesel Generator B Operability Test, Rev. 2

• STP-125.013A, Diesel Generator A Semi-Annual Operability Test, Rev. 0

• STP-345.037, Solid State Protection System Actuation Logic and Master Relay Test Train A, Rev. 18

• STP-345.077, Engineered Safety Feature Actuation Slave Relay Test for Train B XPN-7021, Rev. 5

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation Emergency Preparedness Drill

a. Inspection Scope

On August 31, 2011, the inspectors reviewed and observed the performance of a emergency preparedness drill that involved a steam generator tube rupture, fuel failure, a trip of an emergency diesel generator, and a main feedwater pipe break which required entry into increasing emergency action levels starting with an Alert and ending in a General Emergency. The inspectors assessed abnormal and emergency procedure usage, emergency plan classifications, protective action recommendations, respective notifications and the adequacy of the licensees drill critique. The inspectors verified that drill deficiencies were captured into the licensees corrective action program.

b. Findings

No findings were identified.

2RS2 As Low As Reasonably Achievable (ALARA)

a. Inspection Scope

ALARA Program Status The inspectors reviewed and discussed plant exposure history and current trends including the sites three-year rolling average (TYRA) collective exposure history for calendar year (CY) 2007 through CY 2009. Current and proposed activities to manage site collective exposure and trends regarding collective exposure were evaluated through review of previous TYRA collective exposure data and review of the licensees 5-year ALARA program implementing plan. Current ALARA program guidance and recent changes, as applicable, regarding estimating and tracking exposure were discussed and evaluated.

Radiological Work Planning The inspectors reviewed planned work activities and their collective exposure estimates for U1RFO19 (Unit 1 Refueling Outage 19) work activities and the subsequent actual exposures. For the selected tasks, the inspectors reviewed dose mitigation actions and the established dose goals. During the inspection, use of remote technologies, including teledosimetry and remote visual monitoring, were verified as specified in RWP or procedural guidance. Collective dose data for selected tasks were compared with estimates and, where applicable, changes to established estimates were discussed with responsible licensee ALARA planning representatives. The inspectors reviewed previous post-job reviews conducted for the cycle 18 and 19 refueling outages and verified that the items were entered into the licensees CAP for evaluation. The licensees use of a reference outage for estimating plant exposures and decreasing or increasing the plants dose goals based on trend point survey data was reviewed.

Verification of Dose Estimates and Exposure Tracking Systems The inspectors reviewed select ALARA work packages and discussed assumptions with responsible planning personal regarding the bases for the current estimates. The licensees on-line RWP cumulative dose data bases used to track and trend current personal and cumulative exposure data and/or to trigger additional ALARA planning activities in accordance with current procedures were reviewed and discussed.

Source Term Reduction and Control The inspectors reviewed historical dose rate trends for shutdown chemistry, cleanup, and resultant chemistry and RP trend-point data against the recent U1RFO19 data. The inspectors reviewed the correlation of the exposure trends to the various exposure reduction initiatives taken over the years with historical data.

Problem Identification and Resolution The inspectors reviewed and discussed selected CRs associated with ALARA program implementation. The reviewed items included CRs, self-assessments, and quality assurance audit documents. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with licensee procedure SAP-0999, Corrective Action Program, Rev. 7.

The licensees ALARA program activities and results were evaluated against the requirements of UFSAR Section 12; TS Sections 6.8 Procedures and Programs, 6.11 Radiation Protection, and 6.12 High Radiation Areas; 10 CFR Parts 19 and 20; and approved licensee procedures. Records reviewed are listed in Sections 2RS1 and 2RS2 of the report Attachment.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

Engineering Controls The inspectors reviewed the use of temporary and permanent engineering controls to mitigate airborne radioactivity inside the auxiliary building and radioactive waste processing building. The inspectors reviewed and discussed the use of negative pressure units (NPUs) and vacuums to control contamination, observed physical controls in place to prevent unauthorized use of NPUs and vacuums, and reviewed NPU testing records. The inspectors also reviewed ventilation flow, charcoal, and High Efficiency Particulate Air (HEPA) filter test records for the Control Room Emergency Filter and Reactor Building Ventilation Systems. The inspectors evaluated the effectiveness of continuous air monitors and air samplers placed in work area breathing zones to provide indication of increasing airborne levels. In addition, plant guidance and its implementation for the monitoring of potential airborne beta-gamma and alpha-emitting radionuclides were reviewed and discussed with licensee representatives.

Respiratory Protection Equipment The inspectors reviewed the use of respiratory protection devices to limit the intake of radioactive material. This included review of program guidance for issuance and use of respiratory protection devices, discussion with responsible licensee representatives, and review of devices used for routine tasks and devices stored for use in emergency situations. Selected whole-body count (WBC) routine and investigative analysis results for occupational workers were reviewed and discussed.

The inspectors toured selected onsite air compressors available for supplying breathing air for and filling of Self-Contained Breathing Apparatus (SCBA) bottles and reviewed recent air quality sampling results. Training, fit testing, and medical qualifications for selected HP, maintenance, operations and support staff were reviewed. The inspectors observed administration of a negative pressure respirator (NPR) fit test and SCBA qualification practical factor. The inspectors reviewed the current status, operability and availability of selected SCBA equipment maintained within the technical support center, control room, and fire brigade staging facilities. This review included material condition, number of units, number of spare masks and bottles, the last two years maintenance records and compliance with various regulatory requirements.

SCBA for Emergency Use Maintenance activities for selected respiratory protective equipment, e.g., compressed gas cylinders, regulators, valves, and hose couplings, by certified vendor technicians was evaluated for selected SCBA units. For selected control room operators, the inspectors discussed annual hands-on SCBA training activities including donning, doffing and functionally checking SCBA equipment and availability of corrective lens, as applicable, for on-shift personnel.

Problem Identification and Resolution CRs associated with airborne radioactivity mitigation and respiratory protection were reviewed and assessed. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure SAP-0999, Corrective Action Program, Rev. 7. Documents reviewed are listed in Section 2RS3 of the Attachment to this report.

Licensee activities associated with the use of engineering controls and respiratory protection equipment and airborne radioactivity monitoring and controls were evaluated against details and requirements documented in UFSAR Sections 11 and 12; TS Section 6.8, Procedures; 10 CFR Part 20; Regulatory Guide 8.15, Acceptable Programs for Respiratory Protection; and approved licensee procedures. Documents reviewed are listed in Section 2RS3 of the report Attachment.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

External Dosimetry The inspectors reviewed National Voluntary Laboratory Accreditation Program (NVLAP) certification data (including TLD testing for neutron, gamma, and beta exposures) and discussed program guidance for storage, processing, and results for active and passive personnel dosimeters currently in use. Comparisons between ED and personnel dosimeter data were discussed in detail.

Internal Dosimetry Program guidance (including derived air concentration (DAC)-hr tracking), instrument detection capabilities, and assessment results for internally deposited radionuclides were reviewed in detail. The inspectors reviewed selected routine and investigative in vivo (Whole Body Count) analyses from January 2010 to June 2011. In addition, capabilities for collection and analysis of special bioassay samples were evaluated and discussed with licensee staff.

Special Dosimetric Situations The inspectors evaluated the licensees use of multi-badging, extremity dosimetry, and dosimeter relocation within non-uniform dose rate fields and discussed worker monitoring in neutron areas with licensee staff. The inspectors also reviewed records of monitoring for declared pregnant workers from January 2009 to June 2011 and discussed monitoring guidance with licensee staff. In addition, the adequacy of shallow dose assessments for selected Personnel Contamination Events occurring between January 2010 and June 2011 were reviewed and discussed.

Problem Identification and Resolution The inspectors reviewed and discussed selected CAP documents associated with occupational dose assessment. The inspectors evaluated the licensees ability to identify and resolve the identified issues in accordance with procedure SAP-0999, Corrective Action Program, Rev. 7. The inspectors also discussed the scope of the licensees internal audit program and reviewed recent assessment results.

HP program occupational dose assessment activities were evaluated against the requirements of UFSAR Section 12.3; TS Section 6.8; 10 CFR Parts 19 and 20; and approved licensee procedures. Records reviewed are listed in Section 2RS4 of the report Attachment.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

Radiation Monitoring Instrumentation: During tours of the auxiliary building, spent fuel pool areas, and RCA exit point, the inspectors observed installed radiation detection equipment including the following instrument types: area radiation monitors (ARM),continuous air monitors (CAM), liquid and gaseous effluent monitors, personnel contamination monitors (PCM), small article monitors (SAM), and portal monitors (PM).

The inspectors observed the physical location of the components, noted the material condition, and compared sensitivity ranges with UFSAR requirements.

In addition to equipment walk-downs, the inspectors observed source checks and alarm setpoint testing of various portable and fixed detection instruments, including ion chambers, telepoles, PCM, SAM, and PM. For the portable instruments, the inspectors observed the use of a high-range calibrator and discussed periodic output value testing with a radiation protection technician. The inspectors reviewed the last two calibration records and evaluated alarm setpoint values for selected ARM, PCM, PM, SAM, effluent monitors, laboratory counting systems, and WBC systems. This included a sampling of instruments used for post-accident monitoring such as containment high-range ARMs, and effluent monitor high-range noble gas and iodine channels. Radioactive sources used to calibrate selected ARMs and effluent monitors were evaluated for traceability to national standards. Calibration stickers on portable survey instruments and air samplers were noted during inspection of storage areas for equipment available for issue. The most recent 10 CFR Part 61 analysis for dry active waste (DAW) was reviewed to determine if calibration and check sources are representative of the plant source term.

The inspectors also reviewed countroom quality assurance records for alpha and gamma ray spectroscopy equipment.

Effectiveness and reliability of selected radiation detection instruments were reviewed against details documented in the following: Applicable parts of TS Section 3.4; UFSAR Chapters 11 and 12; and applicable licensee procedures. Documents reviewed during the inspection are listed in Section 2RS5 of the report Attachment.

Problem Identification and Resolution: The inspectors reviewed and discussed selected Corrective Action Program (CAP) documents associated with radiological instrumentation. The reviewed items included CRs, self-assessment, and quality assurance audit documents. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve identified issues in accordance with licensee procedure, SAP-0999, Corrective Action Program, Rev. 7. Documents reviewed are listed in Section 2RS5 of the Attachment to this report.

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

.1 Cornerstone Mitigating Systems

a. Inspection Scope

The inspectors verified the accuracy of the licensees PI submittals listed below for the period July 2010 through June 2011. The inspectors used the performance indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Rev. 6, Regulatory Assessment Performance Indicator Guideline, and licensee procedure SAP-1360, Rev. 1, NRC and INPO/WANO Performance Indicators, to check the reporting of each data element. The inspectors sampled licensee event reports (LERs),operator logs, plant status reports, CRs, and performance indicator data sheets to verify that the licensee had properly reported the PI data. Also, the inspectors discussed the PI data with the licensee personnel associated with the performance indicator data collection and evaluation.

• Mitigating System Performance Index (MSPI) - Emergency AC Power System

• MSPI - High Head Safety Injection System

• MSPI - Residual Heat Removal System

b. Findings

No findings were identified.

.2 Public Radiation Safety Cornerstone

a. Inspection Scope

The inspectors reviewed the Radiological Effluent Technical Specification/Offsite Dose Calculation Manual Radiological Effluent Occurrences PI results from January 2010 through May, 2011. The inspectors reviewed CAP documents, effluent dose data, and licensee procedural guidance for classifying and reporting PI events. Reviewed documents are listed in Section 4OA1 of the Attachment.

The inspectors completed one of the required samples specified in Inspection Procedure 71151.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

Review of Items Entered into the Corrective Action Program

a. Inspection Scope

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 CAP. 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.

b. Findings

No findings were identified.

4OA3 Event Followup

.1 (Closed) LER 05000395/2011-003-00: Inadvertent Safety Injection During Reactor

Startup Due to Excessive Differential Steam Line Pressure and URI 2011003-04:

Inadvertent Safety Injection in Mode 3 Due to Opening C Main Steam Isolation Valve

a. Inspection Scope

On May 27, 2011, during a refueling outage Unit 1 was in Mode 3 with the reactor coolant system (RCS) at normal temperature and pressure when a control room operator was requested to open the C main steam isolation valve (MSIV).

Subsequently, the C steam generator (SG) line pressure reduced to greater than 97 psig as compared to the A and B SG line pressures causing a dual train safety injection. The licensee entered this problem into their CAP as CR-11-03001; the NRC opened a related unresolved item (URI) in NRC integrated report 05000395/2011003.

The enforcement aspects are discussed below. This LER and the related URI are closed.

b. Findings

Introduction:

A self-revealing, non-cited violation was identified for the failure to comply with Technical Specification 6.8.1 to adequately implement a main steam (MS) operating procedure during the manipulation of the C MSIV resulting in excessive steam line differential pressure and subsequent safety injection.

Description:

On May 27, 2011, during a refueling outage Unit 1 was in Mode 3 with the RCS at normal temperature and pressure. Additionally, the licensee had performed stroke time testing of the MSIVs in which C MSIV did not pass. The operators left the MSIVs closed and additionally, closed the MSIV bypass valves to maintain RCS normal operating temperature and pressure. During this time the MS header pressure decreased and was not maintained close to the individual SG line pressures. Later in the shift a control room operator, who had briefly relieved the normal control room operator, was requested to open the C MSIV for troubleshooting. Subsequently, the C SG line pressure reduced to greater than 97 psig as compared to the A and B SG line pressures causing a dual train safety injection. The licensee entered this problem into their CAP as CR-11-03001, and the inspectors completed a review of the associated root cause evaluation (RCE). The inspectors noted that the RCE identified the root cause as the failure to implement or utilize a procedure during manipulation of the C MSIV. The inspectors reviewed the licensees system operating procedure, SOP-102, Main Steam System, and noted that step 2.15 of Section II, required that MS header pressure is within 25 psig of individual SG header pressures before opening the MSIVs in step 2.17. The inspectors also noted that TS 6.8.1 requires the implementation of procedures as recommended by Regulatory Guide 1.33, Revision 2, of which section 3.i addresses the main steam system. The inspectors concluded the licensee failed to comply with the requirement to adequately implement the respective procedure, SOP-102.

Analysis:

The inspectors determined that the failure to implement a procedure for manipulation of the C MSIV was a performance deficiency (PD). The PD was more than minor and therefore a finding because it impacted the initiating events cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown and the related attribute of human performance because the licensee failed to properly implement a procedure controlling the manipulation of a MSIV. In accordance with Inspector Manual Chapter (IMC) 0609, Significant Determination Process, the inspectors performed a Phase 1 analysis and determined the finding was of very low safety significance or Green because the finding did not contribute to both the likelihood of both a reactor trip and the unavailability of mitigation equipment and associated functions. This finding involved the cross-cutting area of human performance, the component of the resources, and the aspect of procedure use and adherence, H.4(b), because the licensee failed to adequately follow procedure SOP-102 for the manipulation of the C MSIV.

Enforcement:

TS 6.8.1, Procedures and Programs, requires in part that written procedures be implemented covering the activities recommended in Appendix A of Regulatory Guide 1.33, Revision 2, section 3.i, Main Steam System. Contrary to the above, on May 27, 2011, the licensee failed to adequately implement procedure SOP-102 while opening the C MSIV which resulted in a SG line differential pressure and subsequent safety injection. Because this finding is of very low safety significance and has been entered into the licensees corrective action program as condition report CR-11-03001, this violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000395/2011004-01, Failure to Implement a Procedure for Manipulation of the C Main Steam Isolation Valve.

.2 On-Site Liquid Effluent Line Leak

a. Inspection Scope

On July 8, 2011, the licensee submitted a non-emergency report (Event Number 47039)to the NRC in accordance with 10 CFR Part 50.72(b)(2)(xi) due to offsite notification of other government agencies regarding an onsite spill of radioactive material. The voluntary notification was made to state and local officials for an on-site leak that may exceed 100 gallons, in accordance with the industrys Groundwater Protection Initiative (NEI 07-07). The report described the July 7, 2011, discovery of a leak in the liquid radwaste discharge line connecting the liquid waste processing system to the discharge point at the Fairfield Pump Storage Facility. Water from the leak in the discharge line collected on the top of the concrete structure of the Fairfield Pump Storage Facility before traveling to the surrounding soil. Analysis of samples of the water identified a Tritium concentration of 2.3 x 104 pCi/L, which is in excess of the NEI 07-07 voluntary reporting level of 2.0 x 104 pCi/L, but significantly below NRC and Federal regulatory limits established to prevent adverse affects on the health and safety of the public and the environment.

The licensee has taken corrective actions which included draining the liquid from the enclosure for return to the plant for disposal, repair of the liquid radwaste line leak, remediation of the soil around the leak location, entering the event into the decommissioning file as required by 10 CFR Part 50.75(g), and submitting a 30-Day Special Report to the NRC (ML11216A230) per the NEI 07-07 guidance. The licensee has documented the event in their corrective action program (CR-11-03667) and is in the process of evaluating the event to determine the root cause and corrective actions to prevent recurrence. The inspectors reviewed the details surrounding the event and discussed the issue with licensee staff. The inspectors noted that the leak was contained within the owner controlled area and was not expected to migrate to the offsite environs. The NRC has designated groundwater contamination as an issue of agency-wide concern and has implemented requirements to document the review of voluntary reports concerning spills and leaks.

b. Findings

No findings were identified.

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 review and inspection activities.

b. Findings

No findings were identified.

.2 (Closed) VIO 05000395/2010004-01, Failure to Notify the Commission of a Change in

Medical Status This violation identified that from September 9, 2009, to August 26, 2010, the facility licensee failed to notify the Commission within 30 days of learning of the diagnosis that a licensed operator had developed a permanent physical or medical condition, as required. Specifically, the licensed operator was placed in a no solo status by the facility licensees medical review officer due to a permanent change in the individuals medical condition without notifying the Commission. This violation was entered into the facility licensee corrective action program as CR-10-00348. The licensee formally responded to the violation in a letter from Mr. T. Gatlin to the NRC dated 11/22/2010.

The facility licensee has implemented corrective actions including hiring a full-time medical coordinator, revising licensee procedures associated with licensed operator medical conditions, and conducting an audit of all licensed operator medical records to determine the extent of condition.

The inspectors reviewed the licensees actions associated with this violation. The inspectors determined that the programmatic improvements should prove effective in preventing a recurrence of this issue. The inspectors also conducted an independent review of a random sample of licensed operator medical records and verified that improvements in the quality of licensed operator medical records were noted. Additional inspection activity associated with this violation was documented in Integrated Inspection Report 050000395/2011002 (Section 4OA2.2). This violation is closed.

.3 (Closed) AV 2011003-03, Failure to Conduct Adequate Testing of Appendix R Fire

Switches The inspectors issued apparent violation (AV) 2011003-03, Failure to Conduct Adequate Testing of Appendix R Fire Switches, in NRC integrated inspection report 05000395/2011003 pending completion of a risk review by NRC regional senior reactor analysts. This review was completed, and the enforcement aspects are discussed in section 4OA7 of this report.

4OA6 Meetings, Including Exit

On October 24, 2011, the resident inspectors presented the integrated inspection results to Mr. T. Gatlin and other members of the licensee staff. The licensee acknowledged the results of these inspections. The inspectors confirmed that inspection activities discussed in this report did not contain proprietary material.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by the licensee and is a violation of NRC requirements which meets the criteria of Section 2.3.2 of the NRC Enforcement Policy, for being dispositioned as an NCV.

• License Condition 2.C.(18), Fire Protection System, of the Virgil C. Summer Operating License NPF-12 requires, in part, that the licensee implement and maintain in effect all provisions of the approved fire protection program as described in the FSAR, and as approved in applicable Safety Evaluation Reports related to the fire protection program. FSAR Section 9.5.1 states in part, that the provisions of 10 CFR 50, Appendix R, Sections III.G, III.J, III.O, and III.L apply to the fire protection program requirements, as well as the Virgil C. Summer Fire Protection Evaluation Report (FPER), which is considered a part of the FSAR. The FSAR and FPER require Virgil C. Summer to comply with Appendix A to BTP APCSB 9.5-1, Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1, 1976, to satisfy the fire protection requirements of 10 CFR 50.48. Appendix A to BTP APCSB 9.5-1, Position C.5, Test and Test Control, requires in part, that a test program be established and implemented to assure that testing is performed and verified by inspection to demonstrate conformance with the design and system readiness requirements. Contrary to these requirements, the licensee failed to implement and maintain in effect all provisions of the approved fire protection program as described in the FSAR for the facility, in that, the Appendix R fire switch test program did not adequately verify that the switches were capable of performing their required isolation function. This finding has been entered into the licensees corrective action program as condition report CR-10-01814.

The finding affected safe shutdown and was judged to represent moderate degradation. Because the finding involved main control room (MCR) fire scenarios and scenarios in multiple fire areas, a phase 3 SDP analysis was performed by a regional senior reactor analyst. The finding was determined to have existed since 1983 when a modification temporarily installed the jumper wire; therefore a one year exposure period was utilized for the analysis. Only fires which could lead to MCR abandonment requiring use of the B EDG isolation switch and which also would damage the B EDG output breaker control circuit would contribute to the risk of the performance deficiency. Only fire scenarios in the MCR (within the main control board (MCB)) and in the cable spreading room which impacted the cable tray and main termination cabinet associated with the B EDG represented credible fire scenarios which could lead to risk from the PD. Factors which mitigated the risk from the PD included: the few credible fire ignition sources, use of thermoset cables, the low cable loading in the specific MCB section housing the EDG and offsite power circuit breaker control switches, detection in the main termination cabinet, and the proceduralized actions for local operation of the B EDG breaker. The dominant sequence was a fire in either the MCR or cable spreading room damaging the EDG and offsite power breaker controls requiring MCR abandonment coupled with failure of the B EDG breaker to operate due to the PD and failure of the operator to locally close the B EDG breaker resulting in core damage from inadequate core cooling.

The SDP phase 3 evaluation determined that the risk of the finding was an increase in core damage frequency of <1E-6/year, a Green finding of low safety significance.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Archie, Senior Vice President, Nuclear Operations

A. Barbee, Director, Nuclear Training

L. Bennett, Manager, Plant Support Engineering

L. Blue, Manager, Nuclear Training

M. Browne, Manager, Quality Systems

M. Coleman, Manager, Health Physics and Safety Services

G. Douglass, Manager, Nuclear Protection Services

M. Fowlkes, General Manager, Engineering Services

T. Gatlin, Vice President, Nuclear Operations

M. Harmon, Manager, Chemistry Services

R. Haselden, General Manager, Organizational / Development Effectiveness

R. Justice, Manager, Nuclear Operations

G. Lippard, General Manager, Nuclear Plant Operations

D. Shue, Manager, Maintenance Services

W. Stuart, Manager, Design Engineering

B. Thompson, Manager, Nuclear Licensing

R. Williamson, Manager, Emergency Planning

S. Zarandi, General Manager, Nuclear Support Services

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000395/2011004-01 NCV Failure to Implement a Procedure for Manipulation of the C Main Steam Isolation Valve (Section 4OA3.1)

Closed

05000395/2011-003-00 LER Inadvertent Safety Injection During Reactor Startup Due to Excessive Differential Steam Line Pressure (Section 4OA3.1)

05000395/2011003-04 URI Inadvertent Safety Injection in Mode 3 Due to Opening C Main Steam Isolation Valve (Section 4OA3.1)

05000395/2010004-01 VIO Failure to Notify the Commission of a Change in Medical Status (Section 4OA5.2)

05000395/2011003-03 AV Failure to Conduct Adequate Testing of Appendix R Fire Switches (Section 4OA5.3)

Discussed

None