IR 05000395/2012004

IR 05000395-12-004 and 05000395-12-502, 07/01/2012 - 09/30/2012, Virgil C. Summer Nuclear Station, Identification and Resolution of Problems; Other Activities

ML12312A124
Person / Time
Site:	Summer
Issue date:	11/07/2012
From:	Gerald Mccoy NRC/RGN-II/DRP/RPB5
To:	Gatlin T South Carolina Electric & Gas Co
References
Download: ML12312A124 (46)

Text

UNITED STATES ber 7, 2012

SUBJECT:

VIRGIL C. SUMMER NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000395/2012004 AND 05000395/2012502

Dear Mr. Gatlin:

On September 30, 2012, 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 18, 2012, 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.

Two NRC-identified findings of very low safety significance (Green) were identified during this inspection. Both of these findings were determined to involve a violation of NRC requirements, and one of these findings was determined to be associated with a traditional enforcement Severity Level IV violation. The NRC is treating these violations as non-cited violations (NCVs)

consistent with Section 2.3.2 of the Enforcement Policy. Further, two licensee-identified violations which were determined to be of very low safety significance are listed in this report.

The NRC is treating these violations as NCVs consistent with Section 2.3.2 of the Enforcement Policy. If you contest the violations or the significance of these NCVs, 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 a cross-cutting aspect assignment 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. 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 Agencywide Document Access and management System (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Gerald J. McCoy, Chief Reactor Projects Branch 5 Division of Reactor Projects Docket No.: 50-395 License No.: NPF-12

Enclosure:

NRC Integrated Inspection Report 05000395/2012004 and 05000395/2012502 w/Attachment: Supplemental Information

REGION II==

Infamy Docket No. 50-395 License No. NPF-12 Report No. 05000395/2012004 and 05000395/2012502 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, 2012 through September 30, 2012 Inspectors: J. Reece, Senior Resident Inspector E. Coffman, Resident Inspector R. Kellner, Health Physicist (Sections 2RS7 and 4OA1)

R. Hamilton, Senior Health Physicist (Section 2RS8)

C. Dykes, Health Physicist (Section 2RS6)

J. Dodson, Senior Project Engineer (Sections 1EP2, 1EP3, 1EP5, 4OA1 and 4OA6)

D. Berkshire, Emergency Preparedness Inspector (Sections 1EP2, 1EP3, 1EP5, 4OA1 and 4OA6)

C. Fontana, Emergency Response Coordinator (Sections 1EP2, 1EP3, 1EP5, 4OA1 and 4OA6)

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

SUMMARY OF FINDINGS

IRs 05000395/2012004 and IR 05000395/2012502; 07/01/2012 - 09/30/2012: Virgil C. Summer

Nuclear Station; Identification and Resolution of Problems; Other Activities The report covered a three month period of inspection by resident inspectors, health physicists, a senior project engineer, an emergency preparedness inspector, and an emergency response coordinator from RII. Two findings were identified and were determined to be one Severity Level (SL) IV/Green non-cited violation (NCV) and one Green 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 Systems

• Green/SL IV: A Green, severity level (SL) IV, non-cited violation was identified by the NRC for the failure of the licensee to update the updated final safety analysis report (UFSAR) for a modification to the sodium hydroxide (NaOH) portion of the reactor building spray system. This modification installed recirculation and feed components primarily consisting of a feed tank and pump for makeup to the tank, a recirculation pump, and associated valves and piping. This violation is in the licensees corrective action program as condition report 12-03644.

The failure to update the UFSAR to describe adequate facility operation for the aforementioned NaOH modification as required by 10 CFR 50.71(e) was a performance deficiency (PD). The PD is more than minor and therefore a finding because if left uncorrected it would have the potential to lead to a more significant safety concern.

Additionally, the violation is considered for traditional enforcement because not having an updated UFSAR hinders the licensees ability to perform adequate 10 CFR 50.59 evaluations and can impact the NRCs ability to perform its regulatory function such as license amendment reviews and inspections. This violation is also a finding which is evaluated by the significance determination process (SDP) to assess the effect on safety. However, the SDP does not specifically consider the effect on the regulatory process. Consequently, given the common regulatory concern different processes are used to correctly reflect both the regulatory importance of the violation and the safety significance of the associated finding. The inspectors evaluated the finding in accordance with NRC Inspection Manual Chapter 0609, Significant Determination Process, attachment 4 and appendix A and determined that the finding was of very low safety significance or Green because it was not a design deficiency, did not result in the loss of a system function, or have an impact on components needed to mitigate a seismic, flooding or severe weather initiating event. Additionally, this finding was determined to be a SL-IV violation using Section 6.1 of the NRCs Enforcement Policy because the inaccurate information was not used to make an unacceptable change to the facility or procedures. There are no cross-cutting aspects because the finding was not representative of current licensee performance and cross-cutting aspects are not assigned to traditional enforcement violations. (Section 4OA2.3)

Green.

A non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions,

Procedures and Drawings, was identified by the NRC for the failure to accomplish the installation of Unit 1 service water (SW) piping and supports in accordance with prescribed drawings which resulted in no contact between piping and pipe support,

SSWH-245, and caused an operable but degraded and nonconforming condition. The licensee entered this problem into their corrective action program as condition report 12-00771.

A performance deficiency (PD) was identified by the NRC for the failure to adequately install a Unit 1 SW pipe support in accordance with prescribed drawings. This PD had a credible impact on safety due to a reasonable doubt of operability during a seismic event and the resultant engineering evaluations to conclude that a complete loss of functionality would not occur. The PD was more than minor and therefore a finding, because it impacted the mitigating systems cornerstone objective to ensure the reliability and capability of systems which respond to initiating events and the related attribute of equipment performance because the reliability of the support configuration had been impacted by the reduction in design margin. In accordance with NRC Inspection Manual Chapter 0609, Significant Determination Process, attachment 4 and appendix A the inspectors determined the finding was of very low safety significance or Green because the design deficiency was confirmed not to result in a loss of operability or functionality. The finding had no cross-cutting aspects because it was not representative of current licensee performance. (Section 4OA5.3)

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 respective corrective action tracking numbers 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

1R04 Equipment Alignment

Partial System Walkdowns

a. Inspection Scope

The inspectors conducted four 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.

• Cross-train walkdown of A train reactor building (RB) spray pump during planned maintenance of the B train RB spray pump

• Cross-train walkdown of B emergency diesel generator (EDG) during planned maintenance on A EDG and associated components

• Cross-train walkdown of A and B emergency feedwater (EFW) pumps during planned maintenance on the turbine driven EFW pump

• Cross-train walkdown of A and B EDGs and remaining offsite circuit during planned maintenance of emergency auxiliary transformers 31 and 32

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 five areas (respective fire zones also noted):

• 1DA switchgear room (fire zone IB-20)

• Control building cable spreading rooms 425 and 448 elevations (fire zones CB-4 and CB-15)

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

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

• Turbine building (fire zone TB-1)

b. Findings

No findings were identified.

.2 Annual Fire Brigade Drill Observation

a. Inspection Scope

The inspectors observed the performance of an unannounced fire brigade drill on September 27, 2012. The inspectors evaluated the readiness of licensee personnel to respond and fight fires including the following aspects:

• Observe whether turnout clothing and self-contained breathing apparatus equipment were properly worn

• Determine whether fire hose lines were properly laid out and nozzle pattern simulated being tested prior to entering the fire area of concern

• Verify that the fire area was entered in a controlled manner

• Review if sufficient firefighting equipment was brought to the scene by the fire brigade to properly perform their firefighting duties

• Verify that the fire brigade leaders fire fighting directions were thorough, clear and effective, and that, if necessary, offsite fire team assistance was requested

• Verify that radio communications with plant operators and between fire brigade members were efficient and effective

• Confirm that fire brigade members checked for fire victims and fire propagation into applicable plant areas

• Observe if effective smoke removal operations were simulated

• Verify that the fire fighting pre-plans were properly utilized and were effective

• Verify that the licensee pre-planned drill scenario was followed, drill objectives met the acceptance criteria, and deficiencies were captured in post drill critiques

b. Findings

No findings were identified.

1R07 Heat Sink

a. Inspection Scope

The inspectors selected the risk significant service water (SW) reservoir which is used as the licensees ultimate heat sink and reviewed documentation associated with the licensees implementation of biofouling controls. Procedures and records were also reviewed to verify that they were consistent with Generic Letter 89-13 licensee commitments and Electric Power Research Institute Heat Exchanger Performance Monitoring Guidelines for water treatment and to verify that biofouling controls were effective. Documents reviewed are listed in the Attachment to this report.

b. Findings

The enforcement aspects of a licensee identified finding are discussed in Section 4OA7 of this report.

1R11 Licensed Operator Requalification Program

.1 Resident Quarterly Review of Operator Requalification

a. Inspection Scope

The inspectors observed two annual operator requalification simulator exams occurring on August 7, 2012 and on August 15, 2012. The first scenario involved the failures of a pressurizer level transmitter, a balance of plant (BOP) transformer, stuck control rods on reactor trip, a small break loss of coolant accident, a failure to start of an emergency diesel generator (EDG) and the turbine driven emergency feedwater pump, and a failure of a containment isolation valve to close. The second scenario involved a trip of a component cooling water (CCW) pump and failure of the standby CCW pump to start, a main turbine control valve failure leading to a reactor trip, a pressurizer power operated relief valve failed open, and a station blackout due to loss of engineered safeguards and BOP power, and both EDGs. 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 supervisor, including the ability to identify and implement appropriate TS actions and when required, emergency action levels as the Site Emergency Director. The inspectors reviewed the licensees critique comments to verify that performance deficiencies were captured for appropriate corrective action.

b. Findings

No findings were identified.

.2 Resident Observation of Control Room Operations

a. Inspection Scope

During the inspection period, the inspectors conducted observations of licensed reactor operator activities to ensure consistency with licensee procedures and regulatory requirements. For the following activities, the inspectors observed the following elements of operator performance:

(1) operator compliance and use of plant procedures including technical specifications;

(2) control board component manipulations;

(3) use and interpretation of plant instrumentation and alarms;

(4) documentation of activities;

(5) management and supervision of activiites; and

(6) control room communications.

• RCS dilutions to maintain reactor power and testing of the alternate seal injection system

• Surveillance testing of the RCS loop A wide range cold leg temperature instrumentation

• RCS lithium addition and RWST level instrument calibrations

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 System, Structures, and Components (SSC). 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 or other MR findings existed that the licensee had not identified.

The inspectors reviewed the licensees controlling procedures consisting of engineering services procedure (ES)-514, Rev. 5, Maintenance Rule Program Implementation, and station administrative procedure (SAP)-0157, Rev. 0, Change A, Maintenance Rule Program, to verify consistency with the MR program requirements.

• CR-12-02371, NaOH tank inoperable due to recirculation pump seal leak

• CR-12-03971, transition of diesel generator system to Maintenance Rule (a)(1)status due to A EDG exciter failure

b. Findings

The enforcement aspects related to CR-12-02371 are discussed in section 4OA2.3 of this report.

1R13 Maintenance Risk Assessment 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 2012-31, risk assessments for scheduled maintenance on A EDG and switchyard upgrade activities

• Work Week 2012-32, risk assessments for switchyard upgrade activities and A SW pump maintenance

• Work Week 2012-34, risk assessments for switchyard upgrade activities, Parr Hydro activities and B EDG scheduled maintenance

• Work Week 2012-35, risk assessments for B EDG unscheduled maintenance

• Work Week 2012-38, risk assessments for planned maintenance on emergency auxiliary transformers 31 and 32 resulting in the loss of one TS required offsite circuit

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed six 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. 0, Change F, Operability Determination Process, and SAP-999, Rev. 9, Change B, Corrective Action Program.

• CR-11-02978, low lube oil pressure trip of turbine driven emergency feedwater (TDEFW) did not occur at expected speed

• CR-12-01029, missing fasteners for cover on terminal box, XPN5504, associated with start and shutdown circuits for B EDG

• CR-12-01884, received annunciator for reactor coolant pump (RCP) buses undervoltage or underfrequency repeatedly

• CR-12-03537, two inches of water found in pull-box containing safety-related cables

• CR-12-01836, through wall leak in SW screen wash and cooling coil piping

• CR-12-02082 and CR-12-02780, degraded A and B CCW heat exchanger performance, respectively

b. Findings

The enforcement aspects relating to CRs 12-01836, 12-02082 and 12-02780 are discussed in section 4OA7 of this report.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed one temporary modification, engineering change request (ECR), install temporary electrical jumper per STP-124.004, to evaluate the change for adverse effects on system availability, reliability, and functional capability. Documents reviewed included ECR implementation procedures, modification design and implementation packages, engineering calculations, WOs, site drawings, applicable sections of the FSAR, supporting 10 CFR 50.59 evaluations, TS, and design basis information. The inspectors evaluated the change documents and associated 10 CFR 50.59 reviews against the system design basis documentation and FSAR to verify that the changes did not adversely affect the safety function of safety systems. The inspectors also reviewed any related CRs to confirm that problems were identified at an appropriate threshold, were entered into the corrective action program (CAP), and appropriate corrective actions had been initiated.

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

For the six 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. 5, Change B, Post Maintenance Testing Guideline.

• WO 1207893, refueling water storage tank (RWST) level transmitter Channel IV failed high (CR-12-02912)

• WO 1203237, refurbish A EDG SW return header relief valve following relief valve test failure

• WO 1208711, rework TDEFW pump trip/throttle valve low oil pressure mechanism

• WO 1204117, replace termal overload assembly for B EDG supply fan A

• WO 1200399, remove, bench test and re-install the A residual heat removal (RHR)pump component cooling supply header relief valve

• WO 1207626, check for leaks and proper flow following replacement of SW pump motor A lower bearing flow indicator

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-225.001C, Diesel Generator Support Systems Comprehensive Pump and Valve Test, Rev. 1, Change B

• STP-205.003, Charging/Safety Injection Pump and Valve Test, Rev. 7

• STP-222.002, Component Cooling Pump Test, Rev. 9, Change D Other:

• STP-106.001, Moveable Rod Insertion Test, Rev. 5, Change F

• STP-124.004, Control Room Emergency Unfiltered Air Inleakage Testing, Rev. 0, Change B

• STP-395.057, Refueling Water Storage Tank Level Instrument ILT00993 Operational Test, Rev. 6

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP2 Alert and Notification System Evaluation

a. Inspection Scope

The inspectors evaluated the adequacy of the licensees methods for testing the alert and notification system in accordance with NRC Inspection Procedure 71114, 02, Alert and Notification System (ANS) Evaluation. The applicable planning standard, 10 CFR Part 50.47(b)(5) and its related 10 CFR Part 50, Appendix E, Section IV.D requirements were used as reference criteria. The criteria contained in NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, were also used as a reference.

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

b. Findings

No findings were identified.

1EP3 Emergency Preparedness Organization Staffing and Augmentation System

a. Inspection Scope

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

The inspection was conducted in accordance with NRC Inspection Procedure 71114, 03, Emergency Preparedness Organization Staffing and Augmentation System. The applicable planning standard, 10 CFR 50.47(b)(2), and its related 10 CFR 50, Appendix E requirements were used as reference criteria.

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

b. Findings

No findings were identified.

1EP5 Maintenance of Emergency Preparedness

a. Inspection Scope

The inspectors reviewed the corrective actions identified through the Emergency Preparedness program to determine the significance of the issues, the completeness and effectiveness of corrective actions, and to determine if issues were recurring. The licensees post-event after action reports, self-assessments, and audits were reviewed to assess the licensees ability to be self-critical, thus avoiding complacency and degradation of their emergency preparedness program. The inspectors toured facilities and reviewed equipment and facility maintenance records to assess licensees adequacy in maintaining them. In addition, the inspectors reviewed licensee procedures and training for the evaluation of changes to the emergency plans.

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

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

b. Findings

No findings were identified.

1EP6 Drill Evaluation

a. Inspection Scope

On August 22, 2012, the inspectors reviewed and observed the performance of an emergency preparedness drill that involved an earthquake related circulating water pipe rupture and subsequent turbine/reactor trip on loss of condenser vacuum. Aftershocks resulted in reactor fuel failure, steam generator tube leakage and a steam safety valve failure and other component failures ultimately resulting in a loss of all three major barriers. The scenario involved entries into all of the emergency action levels from Notification of Unusual Event to 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.

RADIATION SAFETY

(RS)

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

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

a. Inspection Scope

Event and Effluent Program Reviews: The inspectors reviewed the 2010 and 2011 Annual Radiological Effluent Release Report (ARERR) documents for consistency with requirements in the Offsite Dose Calculation Manual (ODCM) and Technical Specifications (TS). Routine and abnormal effluent release results and reports, as applicable, were reviewed and discussed with responsible licensee representatives.

Status of the radioactive gaseous and liquid effluent processing and monitoring equipment, and applicable equipment changes, as described in the Updated Final Safety Analysis Report (UFSAR) and current ODCM were discussed with responsible staff.

Equipment Walk downs: The inspectors walked-down and discussed selected components of the Unit 1 (U1) gaseous and liquid waste processing and discharge systems to ascertain material condition, configuration and alignment. The walk-downs included visual inspection of 10 of the 11 liquid radiation monitors and 5 of the 13 atmospheric radiation monitors. The inspectors observed the material condition of selected in-service gaseous and liquid waste processing equipment for indications of degradation or leakage that could constitute a possible release pathway to the environment. The inspector walk-downs included discussions with radiation protection and chemistry personnel concerning evaluation of observed leaks, material condition, and configuration control associated with waste processing and monitor tanks and pumps, gas decay tanks, and associated piping and valves. The inspectors discussed operability of the particulate and iodine monitors with plant personnel, and reviewed effluent radiation monitoring system health reports.

Effluent Processing: The inspectors observed weekly routine liquid waste sampling from RM-L5 (Liquid Waste Effluent Monitor) and reviewed the liquid waste monitor tank sample analysis results and liquid waste release permit with Chemistry personnel. The reviews included review and discussion of selected dose calculation summaries, maximum release flowrate, and required release point dilution flowrate. Inspectors also reviewed release permits for past continuous gaseous releases. Release quantities and dose impacts were reviewed and discussed. The inspectors reviewed 10 CFR 61 analysis data for expected nuclide distributions used to quantify effluents, treatment of hard to detect nuclides, and determination of appropriate calibration nuclides for effluent analysis instruments. The inspectors reviewed the calculated public dose results for any indications of higher than anticipated or abnormal releases. Inter-laboratory comparison results were reviewed under IP 71124.06.

Ground Water Protection: The licensees implementation of the Industry Ground Water Protection Initiative was reviewed for changes since the last inspection. Groundwater sampling results obtained since the last inspection were reviewed. Licensee response, evaluation, and follow-up to spills and leaks since the last inspection were reviewed in detail. Records reviewed are listed in Section 2RS7 of the Attachment.

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

The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with procedure SAP-0999, Corrective Action Program, Rev. 9. The inspectors also discussed the scope of the licensees internal audit program and reviewed recent assessment results.

Effluent process and monitoring activities were evaluated against the details and requirements documented in UFSAR Sections 9 and 11; ODCM; 10 CFR Part 20; Appendix I to 10 CFR Part 50; and approved licensee procedures. In addition, ODCM and UFSAR changes since the last onsite inspection were reviewed against the guidance in NUREG-1301 and Regulatory Guide (RG) 1.109, RG 1.21, and RG 4.1.

Records reviewed are listed in Sections 2RS6 and 2RS7 of the Attachment.

The inspectors completed all specified line-items detailed in Inspection Procedure (IP)71124.06 (sample size of 1).

b. Findings

No findings were identified.

2RS7 Radiological Environmental Monitoring Program (REMP)

a. Inspection Scope

REMP Status and Results: The inspectors reviewed and discussed changes to the ODCM and results presented in the Annual Radiological Environmental Operating Report (AREOR) documents issued for calendar year (CY) 2010 and CY 2011. REMP laboratory inter-comparison cross-check program results, and current procedural guidance for offsite collection, processing and analysis of airborne particulate and iodine, broadleaf vegetation, and surface water samples were reviewed and discussed. The AREOR environmental measurement results were reviewed for consistency with licensee effluent data and evaluated for radionuclide concentration trends. The inspectors independently verified detection level sensitivity requirements for selected environmental media analyzed in the on-site environmental counting room.

Equipment Walk-down: The inspectors observed implementation of selected REMP monitoring and sample collection activities for atmospheric and Thermoluminescent Dosimeters (TLDs) as specified in the current ODCM and applicable procedures. The inspectors observed equipment material condition and verified operability, including verification of flow rates and total sample volume results for the weekly airborne particulate filter and iodine cartridge change-outs at six atmospheric sampling stations.

In addition, the inspectors discussed broadleaf vegetation sampling. Use of proportional water sampling equipment was observed and discussed. Thermo-luminescent dosimeter material condition and placement were verified by direct verification at select ODCM locations. Land use census results, actions for missed samples including compensatory measures, sediment sample collection/processing activities, and availability of replacement equipment were discussed with environmental technicians and knowledgeable licensee staff. In addition, calibration and maintenance surveillance records for the installed environmental air sampling stations were reviewed.

Procedural guidance, program implementation, quantitative analysis sensitivities, and environmental monitoring results were reviewed against 10 CFR Part 20; Appendix I to 10 CFR Part 50; TS Sections 6.8, Procedures and Programs, 6.8.4.e, Radioactive Effluent Controls Program, 6.8.4.f, Radiological Environmental Monitoring Program, and 6.9, Reporting Requirements; AREOR; ODCM, Rev. 28; RG 4.15, Quality Assurance for Radiological Monitoring Programs (Normal Operation) - Effluent Streams and the Environment; and the Branch Technical Position, An Acceptable Radiological Environmental Monitoring Program - 1979. Documents reviewed are listed in Section 2RS7 of the Attachment.

Meteorological Monitoring Program: The inspectors toured the primary and backup meteorological towers and observed local data collection equipment readouts. The inspectors observed the physical condition of the towers and their instruments and discussed equipment operability, maintenance history, and backup power supplies with responsible licensee staff. The inspectors evaluated transmission of locally generated meteorological data from the primary meteorological tower to the main control room operators. For the meteorological measurements of wind speed, wind direction, and temperature, the inspectors reviewed applicable tower instrumentation calibration records and evaluated meteorological measurement data recovery for CY 2010 and CY 2011.

Licensee procedures and activities related to meteorological monitoring were evaluated against: ODCM; UFSAR; RG 1.23, Meteorological Monitoring Programs for Nuclear Power Plants, and ANSI/ANS-2.5-1984, Standard for Determining Meteorological Information at Nuclear Power Sites. Documents reviewed are listed in Section 2RS7 of the Attachment.

Problem Identification and Resolution: The inspectors reviewed selected CAP documents in the areas of environmental and meteorological monitoring. The inspectors evaluated the licensees ability to identify, characterize, prioritize, and resolve the identified issues in accordance with SAP-0999, Corrective Action Program, Rev. 9.

The inspectors also discussed the scope of the licensees internal audit program and reviewed recent assessment results. Documents reviewed are listed in the Attachment.

The inspectors completed all specified line-items detailed in IP 71124.07 (sample size of 1).

b. Findings

No findings were identified.

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

Transportation

a. Inspection Scope

Radioactive Material Storage: During walk-downs of selected indoor and outdoor radioactive material storage areas to include the radwaste building, auxiliary building, and yard areas, the inspectors observed the physical condition and labeling of storage containers and the posting of radioactive material areas. The inspectors also reviewed licensee procedural guidance for storage and monitoring of radioactive material.

Waste Processing and Characterization: During inspector walk-downs, accessible sections of the liquid and solid radwaste processing systems were assessed for material condition and conformance with system design diagrams. Inspected equipment included radwaste storage tanks; resin transfer piping, resin and filter packaging components; and abandoned evaporator equipment. The inspectors discussed component function, processing system changes, and radwaste program implementation with licensee representatives. The inspectors observed the sluice of spent fuel pool cleanup resin to a resin liner.

The 2011 ARERR and radionuclide characterizations from 2011 - 2012 for each major waste stream were reviewed and discussed with cognizant licensee representatives.

For primary resin, reactor coolant system filters, and dry active waste (DAW) the inspectors evaluated analyses for hard-to-detect nuclides, reviewed the use of scaling factors, and examined quality assurance comparison results between licensee waste stream characterizations and outside laboratory data. Waste stream mixing, concentration averaging, and waste form stabilization (dewatering) for resins and filters was evaluated and discussed with radwaste staff. The inspectors also reviewed the licensees procedural guidance for monitoring changes in waste stream isotopic mixtures.

Transportation: The inspectors were able to observe an outbound shipment of empty fuel canisters and an inbound shipment receipt of new fuel. The inspectors discussed with selected shipping representatives procedures regarding surveys, marking and placarding of shipping packages, and other related Department of Transportation (DOT)regulations. Selected shipping records were reviewed for consistency with licensee procedures and compliance with NRC and DOT regulations. The inspectors reviewed emergency response information, DOT shipping package classification, waste classification, radiation survey results, and evaluated whether receiving licensees were authorized to accept the packages. Licensee procedures for opening and closing shipping casks were compared to recommended vendor protocols and Certificate of Compliance requirements.

Problem Identification and Resolution: The inspectors reviewed CAP documents in the areas of radwaste processing, material storage, and transportation. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure SAP-0999, Corrective Action Program, Rev. 9. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Radwaste processing, radioactive material handling, and transportation activities were reviewed against the requirements contained in the licensees Process Control Program, UFSAR Chapter 11, 10 CFR Part 20, 10 CFR Part 61, 10 CFR Part 71, and 49 CFR Parts 172-178. Licensee activities were also evaluated against guidance provided in the Branch Technical Position on Waste Classification (1983) and NUREG-1608, Categorizing and Transporting Low Specific Activity Materials and Surface Contaminated Objects. Documents reviewed during the inspection are listed in Section 2RS8 of the Attachment.

The inspectors completed all specified line-items detailed in IP 71124.08 (sample size of 1).

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

.1 Mitigating Systems Cornerstone

a. Inspection Scope

The inspectors verified the accuracy of the licensees PI submittals listed below for the period July 2011 through June 2012. 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 Occupational 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 PI data collected from July 2011 thru June 2012, for the Occupational Exposure Control Effectiveness PI.

For the reviewed period, the inspectors assessed CAP records to determine whether High Radiation Area (HRA), Very HRA, or unplanned exposures, resulting in TS or 10 CFR 20 non-conformances, had occurred during the review period. In addition, the inspectors reviewed electronic dosimeter alarms for cumulative doses and/or dose rates exceeding established set-points. Documents reviewed are listed in Section 4OA1 of the Attachment.

Public Radiation Safety Cornerstone: The inspectors reviewed the Radiological Control Effluent Release Occurrences PI results for the Public Radiation Safety Cornerstone from July 2011 thru June 2012. For the assessment period, the inspectors reviewed cumulative and projected doses to the public and PIP documents related to Radiological Effluent TS/ODCM issues. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents reviewed are listed in Section 4OA1 of the Attachment.

The inspectors completed all specified line-item samples associated with the Occupational and Public Radiation Safety Cornerstones detailed in IP 71151 (sample size of 2).

b. Findings

No findings were identified.

.3 Emergency Preparedness Cornerstone

a. Inspection Scope

The emergency preparedness inspectors sampled licensee submittals relative to the PIs listed below for the period March 31, 2011 through June 30, 2012. For the specified review period, the inspector examined data reported to the NRC, procedural guidance for reporting PI information, and records used by the licensee to identify potential PI occurrences. The inspectors verified the accuracy of the PI for ERO drill and exercise performance through review of a sample of drill and event records. The inspectors reviewed selected training records to verify the accuracy of the PI for ERO drill participation for personnel assigned to key positions in the ERO. The inspectors verified the accuracy of the PI for alert and notification system reliability through review of a sample of the licensees records of periodic system tests. The inspectors also interviewed the licensee personnel who were responsible for collecting and evaluating the PI data. To verify the accuracy of the PI data reported during that period, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, was used to confirm the reporting basis for each data element.

Licensee procedures, records, and other documents reviewed within this inspection area are listed in the Attachment. This inspection satisfied three inspection samples for PI verification on an annual basis.

• EP01: Drill/Exercise Performance (DEP)

• EP02: Emergency Response Organization (ERO) Readiness

• EP03: ANS Reliability

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 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.

.2 Annual Operator Work-Around Review

a. Inspection Scope

The inspectors reviewed the licensees list of identified operator workarounds (OWA)associated with mitigating system equipment to determine whether any new items since the previous review conducted in 2011 would adversely affect any mitigating system function or affect the operators ability to implement abnormal or emergency operating procedures. In addition, the inspectors performed an independent review of outstanding control board WOs and known problems with mitigating system equipment to identify any potential workarounds that had not been formally identified and evaluated by the licensee.

b. Findings

No findings were identified. As a follow up to the Notification of Unusual Event (NOUE)described in section 4OA3.1 of this report, the inspectors reviewed in detail the number of existing work orders on smoke detectors located in containment and not associated with an upgraded fire detection system referred to as the Simplex system. The inspectors review of the Simplex system determined that the licensee had not updated the respective Design Bases Document (DBD). However, the inspectors noted that the UFSAR and Fire Protection Evaluation Report was updated. The licensee initiated CR-12-04324 to correct the DBD.

In regards to the older model smoke detectors within containment, the inspectors noted the following work orders and associated initiation dates from a review of the control room heating & ventilation control boards:

• 0915724, December 12, 2009

• 1000424, January 11, 2010

• 1106418, May 23, 2011

• 1106615, May 26, 2011

• 1107496, June 19, 2011

• 1202857, March 4, 2012

• 1207644, July 8, 2012 The inspectors reviewed the licensees operator workaround data sheet and noted that the smoke detector problems and associated control room alarms were listed as operator burdens but not identified as OWAs. The inspectors reviewed operations administrative procedure (OAP) 113.1, Operator Workaround and Dark Board Program, Revision 3, and noted that the purpose of this procedure is to assess the individual and cumulative effects of degraded condition(s) on operator performance and station safety/reliability. The inspectors further noted that the definition of an OWA states in part that it has the potential to complicate emergency response or contribute to the significance of a plant transient. However, OAP-113.1 has more focus on the impact to implementation of abnormal or emergency operating procedures as opposed to the effects on general operator response to an emergency, i.e., implementation of the emergency plan.

The inspectors interview with licensee shift operations personnel revealed that the older design smoke detectors had presented a long-standing problem based on the location of the detectors within ventilation fan ductwork, the accumulation of small debris within the detector during operation, and the resultant invalid smoke alarm. While there were no formal compensatory actions, the control room operators had been instructed to declare a NOUE if an alarm could not be cleared . The inspectors also noted the during decision making process that led to the NOUE, there were no other indications of a fire in containment; e.g., none of the Simplex system smoke detectors in the area of the B SG cubicle were in alarm. Additionally, the breaker for the respective fan motor had not tripped as might be expected due to a motor fault. A review of the event by NRC regional and headquarters personnel concluded the classification issue was of minor significance not warranting any additional action relative to 10 CFR 50.47(b)(4) for emergency classification. The inspectors concluded that the licensees overall response to the long-standing problems of smoke detector reliability was not timely resulting in the inability of the control room operators to successfully address fire alarms for the affected category of smoke detectors within containment. The licensee has entered this problem in their CAP as CRs 12-02915 and 12-03054.

.3 Annual Sample Review

a. Inspection Scope

The inspectors reviewed CR-11-06124, dated December 11, 2011, and CR-12-02371, dated June 10, 2012, of which both document seal leaks on the non-safety related sodium hydroxide (NaOH) recirculation pump which resulted in a decrease in NaOH tank level below the TS limit and inoperability of the NaOH system. The CRs were reviewed by the inspectors in detail to evaluate the effectiveness of the licensees corrective actions for important safety issues. The inspectors also assessed whether the issue was properly identified, documented accurately and completely, properly classified and prioritized, adequately considered extent of condition, generic implications, common cause, and previous occurrences, adequately identified root causes/apparent causes, and identified appropriate and timely corrective actions. Also, the inspectors verified the issues were processed in accordance with procedure, SAP-999, Corrective Action.

b. Findings

Introduction:

A Green, severity level (SL) IV, non-cited violation (NCV) was identified by the NRC for the failure of the licensee to update the UFSAR in accordance with 10 CFR 50.71(e) for a modification to the NaOH portion of the reactor building spray system.

This modification installed recirculation and feed components primarily consisting of a feed tank and pump for makeup to the tank, a recirculation pump, and associated valves and piping.

Description:

The inspectors reviewed licensee corrective actions for CR-12-02371 and CR-11-06124, both of which involved seal leaks on the non-safety related NaOH recirculation pump, which resulted in a decrease in NaOH tank level below the TS limit and inoperability of the NaOH system. The inspectors determined that in each case as well as previous activities involving recirculation of the NaOH tank, the licensee did not declare the system inoperable due the direct connection of the safety related NaOH tank to non-safety related recirculation components. The inspectors performed a review of the UFSAR, Section 6.2.2, Reactor Building Heat Removal Systems, and other related sections and determined that although a flow diagram showed the components installed, the modification, MRF-20168, was not discussed or described in the text to adequately reflect normal facility operation as required by 10 CFR 50.71(e). The inspectors review of the respective system operating procedure, SOP-116, Reactor Building Spray System, Rev. 16, determined that the likelihood of recirculation beyond the respective TS limiting condition for operation (LCO) time of 72 hours8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> was very low due to the stipulation of a minimum recirculation time of 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. However, the procedure did not preclude recirculation time of longer than 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, and if a change of NaOH concentration was required, an additional 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br /> of recirculation would be possible.

Consequently, the inspectors sampled the control room logs to determine if recirculation periods exceeded the TS LCO time but did not identify any examples. The licensee entered this problem into their CAP as CR-12-03644.

Analysis:

The failure to update the UFSAR to describe adequate facility operation for the aforementioned NaOH modification as required by 10 CFR 50.71(e) was a performance deficiency (PD). The PD is more than minor and therefore a finding because if left uncorrected it would have the potential to lead to a more significant safety concern. Additionally, the violation is considered for traditional enforcement because not having an updated UFSAR hinders the licensees ability to perform adequate 10 CFR 50.59 evaluations and can impact the NRCs ability to perform its regulatory function such as license amendment reviews and inspections. This violation is also a finding which is evaluated by the significance determination process (SDP) to assess the effect on safety. However, the SDP does not specifically consider the effect on the regulatory process. Consequently, given the common regulatory concern different processes are used to correctly reflect both the regulatory importance of the violation and the safety significance of the associated finding.

The inspectors evaluated the finding in accordance with NRC Inspection Manual Chapter 0609, Significant Determination Process, attachment 4 and appendix A and determined that the finding was of very low safety significance or Green because it was not a design deficiency, did not result in the loss of a system function, or have an impact on components needed to mitigate a seismic, flooding or severe weather initiating event.

Additionally, this finding was determined to be a SL-IV violation using Section 6.1 of the NRCs Enforcement Policy because the inaccurate information was not used to make an unacceptable change to the facility or procedures. There are no cross-cutting aspects because the finding was not representative of current licensee performance and cross-cutting aspects are not assigned to traditional enforcement violations.

Enforcement:

10 CFR 50.71(e) requires, in part, that licensees shall periodically update the FSAR originally submitted as part of the application for the operating license to assure that the information included in the report contains the latest information developed. This submittal shall include the effects of all changes made in the facility or procedures as described in the FSAR. Contrary to the above, from November, 1987, to August 27, 2012, the licensee had not updated the UFSAR to include the latest information developed because UFSAR changes for a 1987 modification to the NaOH addition system were not implemented. This violation is in the licensees corrective action program as CR-12-03644, and is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy: NCV 05000395/2012004-01, Failure to Update the UFSAR for a Modification to the Sodium Hydroxide System.

4OA3 Event Follow-up

.1 Declaration of a Notification of Unusual Event (NOUE)

a. Inspection Scope

The inspectors responded to a declaration of a NOUE on July 8, 2012, due to a smoke detector alarm for fan 69A associated with the B steam generator cubicle in the reactor building. The inspectors discussed the event with operations and licensee management personnel to gain an understanding of the event and assess follow-up actions. The inspectors reviewed operator actions taken in accordance with licensee procedures and reviewed unit and system indications to verify that actions and system responses were as expected. The inspectors also reviewed the initial licensee notifications to verify that the requirements specified in NUREG-1022, Event Reporting Guidelines, were met.

a. Findings

No findings were identified. Additional discussion is in Section 4OA2.2 of this report.

.2 (Closed) LERs 05000395/2012-001-00 and 05000395/2012-001-01: Core Exit

Thermocouples Inoperable due to an Inadequate Maintenance Procedure

a. Inspection Scope

On March 16, 2012, the licensee issued a licensee event report (LER) based on their discovery of missing hold-down bolts for the control rod drive cable support bridge in containment due to an inadequate maintenance procedure. The licensees evaluation determined that core exit thermocouple indications would be adversely affected during a loss of coolant accident (LOCA), and a subsequent evaluation leading to issuance of a LER revision on August 3, 2012, determined that the reactor vessel level indication system would also be adversely affected during a LOCA. The licensee issued CR-11-01087 to document this event and determine appropriate corrective actions. The inspectors completed an extensive review of this LER and the related cause evaluation conducted by the licensee, and the enforcement aspects are discussed below. These LERs are closed.

b. Findings

The enforcement aspects of a licensee identified finding are discussed in Section 4OA7 of this report.

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 Review of Institute of Nuclear Power Operations (INPO) Reports

The inspectors reviewed the final report for the INPO plant assessment conducted in November, 2011 to ensure that any issues identified were consistent with NRC perspectives of VC Summer plant performance.

.3 (Closed) URI 05000395/2012002-04, Nonconformance of Service Water Pipe Support,

SWH-245, With Design Documents

Introduction:

A Green, NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures and Drawings, was identified by the NRC for the failure to accomplish the installation of Unit 1 service water (SW) piping and supports in accordance with prescribed drawings which resulted in no contact between piping and pipe support, SWH-245, and caused an operable but degraded and nonconforming condition. URI 05000395/2012002-04, Nonconformance of Service Water Pipe Support, SWH-245, With Design Documents, is closed.

Description:

On February 22, 2012, during a cross-train walk-down the inspectors identified that SWH-245 was not supporting its respective SW pipe (inlet to the A EDG intercooler) due to the existence of an approximate

.125 inch gap between the bottom of

the pipe and the support. Additional details were described in NRC integrated inspection report 05000395/2012002 and resulted in the aforementioned URI. The licensee initiated the following, additional CRs in evaluating this problem:

• CR-12-02013, Perform an apparent cause evaluation for URI 05000395/2012002-04

• CR-12-02534, Inconsistencies identified in calculations DC05600-034, SW52, and SW53 The licensee initiated engineering change request (ECR) 71727 for corrective actions.

The inspectors review noted that installation of the affected piping and SWH-245 was a nonconformance with design drawings, S-321-251 sheets 245A and 245B, and resulted in reasonable doubt of operability. Consequently, the licensee performed several evaluations which included engineering judgment and assumptions to conclude a complete loss of functionality during a seismic event would not occur. The inspectors independent review concluded that although increased stresses on the affected components, nozzle 4 on A EDG intercooler and an adjacent SW pipe support, SWH-226, resulted in reduced margin, functionality was not completely lost.

Analysis:

A PD was identified by the NRC for the failure to adequately install Unit 1 SW piping and SWH-245 in accordance with prescribed drawings. This PD had a credible impact on safety due to a reasonable doubt of operability during a seismic event.

Subsequently, the licensee performed engineering evaluations and concluded that a complete loss of functionality would not occur. The PD was more than minor and therefore a finding, because it impacted the mitigating systems cornerstone objective to ensure the reliability and capability of systems which respond to initiating events and the related attribute of equipment performance because the reliability of the support configuration had been impacted by the reduction in design margin. The inspectors evaluated this finding in accordance with NRC Inspection Manual Chapter 0609, Significant Determination Process, attachment 4 and appendix A and screened it out as Green (very low safety significance) because a design deficiency would not cause a loss of operability or functionality during a seismic event. The finding had no cross-cutting aspects because it was not representative of current licensee performance.

Enforcement:

10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," states in part that activities affecting quality shall be accomplished by documented instructions and procedures. Contrary to the above, on February 22, 2012, the licensee failed to accomplish the correct installation of Unit 1 SW piping and support, SWH-245, in accordance with documented, design drawings which caused a degraded and nonconforming condition. Because the finding is of very low safety significance and it was entered into the licensees CAP as CR-12-00771, this violation is being treated as a Green NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000395/2012004-02, Inadequate Installation of Unit 1 Service Water Piping and Related Pipe Support.

4. (Discussed) NRC Temporary Instruction (TI) 2515/187, Inspection of Near-Term Task

Force Recommendation 2.3 Flooding Walkdowns, and NRC TI 2515/188, Inspection of Near-Term Task Force Recommendation 2.3 Seismic Walkdowns

a. Inspection Scope

Inspectors accompanied the licensee on a sampling basis, during their flooding and seismic walkdowns, to verify that the licensees walkdown activities were conducted using the methodology endorsed by the NRC. These walkdowns are being performed at all sites in response to a letter from the NRC to licensees, entitled Request for Information Pursuant to Title 10 of the Code of Federal Regulations 50.54(f) Regarding Recommendations 2.1, 2.3, and 9.3, of the Near-Term Task Force Review of Insights from the Fukushima Dai-ichi Accident, dated March 12, 2012 (ADAMS Accession No.

ML12053A340).

3 of the March 12, 2012, letter requested licensees to perform seismic walkdowns using an NRC-endorsed walkdown methodology. Electric Power Research Institute (EPRI) document 1025286 titled, Seismic Walkdown Guidance, (ADAMS Accession No. ML12188A031) provided the NRC-endorsed methodology for performing seismic walkdowns to verify that plant features, credited in the current licensing basis (CLB) for seismic events, are available, functional, and properly maintained.

4 of the letter requested licensees to perform external flooding walkdowns using an NRC-endorsed walkdown methodology (ADAMS Accession No.

ML12056A050). Nuclear Energy Industry (NEI) document 12-07 titled, Guidelines for Performing Verification Walkdowns of Plant Protection Features, (ADAMS Accession No. ML12173A215) provided the NRC-endorsed methodology for assessing external flood protection and mitigation capabilities to verify that plant features, credited in the CLB for protection and mitigation from external flood events, are available, functional, and properly maintained.

b. Findings

Findings or violations associated with the flooding and seismic walkdowns, if any, will be documented in future reports.

4OA6 Meetings, Including Exit

On August 30, 2012, the inspectors discussed results of the onsite RP inspection with Mr. G. Lippard and other cognizant licensee representatives. The inspectors noted that no proprietary or personally identifiable information was reviewed during the course of the inspection. No findings were identified.

On September 21, 2012, the lead inspector presented the results of the EP inspection to Mr. T. Gatlin, and other members of the staff. The inspector confirmed that proprietary information was not provided or reviewed during the inspection.

On October 18, 2012, the resident inspectors presented the integrated inspection report 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 violations of very low safety significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of Section 2.3.2 of the NRC Enforcement Policy, for disposition as NCVs.

• 10 CFR Part 50, Appendix B, Criterion V, states in part that activities affecting quality shall be prescribed and accomplished by documented procedures. Contrary to the above, on May 2, 2012, May 21, 2012, and July 3, 2012, the licensee failed to adequately accomplish procedure, SAP-1255, Service Water System Reliability Optimization Program, Rev. 0, to preclude adverse biofouling conditions involving a microbiologically influenced corrosion leak on SW piping to the SW intake screen, component cooling water (CCW) heat exchanger A performance degraded below design limits, and CCW heat exchanger B performance degraded below design limits, respectively. This issue is more than minor and therefore a finding because it impacted the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and the attribute of human performance. The inspectors used IMC 0609, Attachment 4 and Appendix A, to determine that the finding was of very low safety significance or Green, because it was not a qualification or design deficiency and did not represent a loss of function impacting TS or non-TS systems with high significance for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This finding has been entered into the licensees CAP as CR-12-01836, CR-12-02082, and CR-12-02780, respectively, for the aforementioned components.

• TS 6.8.1a requires in part that written procedures shall be established covering the activities referenced in Regulatory Guide 1.33, Rev. 2, Appendix A, Section 9, Procedures for Performing Maintenance. Contrary to the above, on April 18, 2011, the licensee failed to adequately establish general maintenance procedure, GMP-100.007, Maintenance Support for Refueling, because the lack of instructions resulted in the failure to ensure hold-down bolts were installed in the control rod drive mechanism cable bridge during the previous refueling outage. This adverse condition resulted in the inoperability of core exit thermocouples and reactor vessel level indication system due to damage sustained to cables and tubing, respectively, during a loss of coolant accident. This issue is more than minor and therefore a finding because it impacted the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and the attribute of procedure quality. The inspectors used IMC 0609, Attachment 4 and Appendix A, and determined the finding would require a detailed risk analysis by a regional senior reactor analyst.

The failure to reinstall the refueling cable bridge hold down bolts was a performance deficiency (PD). The PD was more than minor because it impacted the equipment reliability attribute of systems required for mitigating accidents as the cable bridge could have moved following a loss of coolant accident impacting the core exit thermocouples and the reactor vessel level indicating system. The phase 1 significance determination process screening determined that the PD resulted in a potential loss of a safety function and required a detailed evaluation. A phase 3 SDP risk evaluation was performed by a regional senior reactor analyst using the V. C.

Summer SPAR model. A one year exposure period was used and the human error probability of all Loss of Coolant Accident operator action basic events was increased due to the PD. The result of the risk analysis was an increase in the core damage frequency of < 1 E-6/year, a GREEN finding or very low safety significance.

This finding has been entered into the licensees CAP as CR-11-01807.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Archie, Senior Vice President, Nuclear Operations

A. Barbee, Director, Nuclear Training

M. Browne, Manager, Quality Systems

M. Coleman, Manager, Health Physics and Safety Services

G. Douglass, Manager, Nuclear Protection Services

T. Gatlin, Vice President, Nuclear Operations

K. Gore, Manager, Organization Development and Performance

M. Harmon, Manager, Chemistry Services

R. Haselden, General Manager, Organizational / Development Effectiveness

R. Justice, Manager, Nuclear Operations

G. Lippard, General Manager, Nuclear Plant Operations

M. Mosley, Manager, Nuclear Training

M. Roberts, Supervisor, Health Physics II, New Plant, Environmental, Rad Waste

D. Shue, Manager, Maintenance Services

W. Stuart, General Manager, Engineering Services

B. Thompson, Manager, Nuclear Licensing

D. Weir, Manager, Plant Support Engineering

B. Wetmore, Design Engineering

R. Williamson, Manager, Emergency Planning

S. Zarandi, General Manager, Nuclear Support Services

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000395/2012004-01 NCV Failure to Update the UFSAR for a Modification to the Sodium Hydroxide System (Section 4OA2.3)

05000395/2012004-02 NCV Inadequate Installation of Unit 1 Service Water Piping and Related Pipe Support (Section 4OA5.3)

Closed

05000395/2012-001-00 LER Core Exit Thermocouples Inoperable Due to an Inadequate Maintenance Procedure (Section 4OA3.2)

05000395/2012-001-01 LER Core Exit Thermocouples Inoperable Due to an Inadequate Maintenance Procedure (Section 4OA3.2)

05000395/2012002-04 URI Nonconformance of Service Water Pipe Support, SWH-

245, With Design Documents (Section 4OA5.3)

Discussed

TI 2515/187 TI Inspection of Near-Term Task Force Recommendation 2.3 Flooding Walkdowns TI 2515/188 TI Inspection of Near-Term Task Force Recommendation 2.3 Seismic Walkdowns