IR 05000395/2011003

IR 05000395-11-003, on 04/01/2011 - 06/30/2011, Virgil C. Summer Nuclear Station, Maintenance Risk Assessments & Emergent Work Control, Refueling & Other Outage Activities; & Identification and Resolution of Problems

ML112160535
Person / Time
Site:	Summer
Issue date:	08/04/2011
From:	Gerald Mccoy Reactor Projects Region 2 Branch 6
To:	Gatlin T South Carolina Electric & Gas Co
References
IR-11-003
Download: ML112160535 (46)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION ust 4, 2011

SUBJECT:

VIRGIL C. SUMMER NUCLEAR STATION - NRC INTEGRATED INSPECTION REPORT 05000395/2011003

Dear Mr. Gatlin:

On June 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 July 12, 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 apparent violation that has potentially greater than very low safety significance. The apparent violation is associated with the failure to adequately test 10 CFR 50, Appendix R fire protection local control transfer switches. Although this apparent violation has potential safety significance, it did not represent an immediate safety concern because the local control transfer switches have since been appropriately tested.

In addition, the report documents two NRC-identified findings of very low significance (Green)

which were determined to involve violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2 of the NRC Enforcement Policy because of the very low significance of the violations and because they were entered into your corrective action program. 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.

SCE&G 2 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 North Anna Power Station. The information you provide will be considered in accordance with Inspection Manual Chapter 0305.

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 Web site 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 05000395/2011003 w/Attachment: Supplemental Information

REGION II==

Docket No.: 50-395 License No.: NPF-12 Report No.: 05000395/2011003 Licensee: South Carolina Electric & Gas (SCE&G) Company Facility: Virgil C. Summer Nuclear Station Location: P.O. Box 88 Jenkinsville, SC 29065 Dates: April 1, 2011 through June 30, 2011 Inspectors: J. Zeiler, Senior Resident Inspector E. Coffman, Resident Inspector R. Hamilton, Senior Health Physicist (Sections 2RS1, 4OA1.2 and 4OA5.4)

A. Sengupta, Reactor Inspector (Section 1R08)

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

SUMMARY OF FINDINGS

IR 05000395/2011003; 04/01/2011 - 06/30/2011: Virgil C. Summer Nuclear Station;

Maintenance Risk Assessments and Emergent Work Control; Refueling and Other Outage Activities; and Identification and Resolution of Problems.

The report covered a 3-month period of inspection by resident inspectors and announced inspections by a senior health physicist and a reactor inspector. This report contains one apparent violation (AV) with potential safety significance greater than Green and two findings, which were non-cited violations (NCVs). 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: Initiating Events

Green.

The inspectors identified a Green non-cited violation (NCV) of 10 CFR 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, for the failure to perform an adequate risk assessment and implement approved high risk management contingency plans for work in the stations electrical switchyard. Specifically, on April 21, 2011, operations work control personnel failed to adequately assess the impact of work activities in the switchyard involving the use of vehicles, resulting in outage high risk management actions that prohibited the movement of vehicles during lowered reactor coolant system (RCS) inventory conditions from being implemented. Following the inspectors identification of this issue, the licensee adequately assessed and managed the increase in risk for the activities. The issue was entered into the licensees corrective action program as condition report CR-11-01908.

The failure to perform an adequate risk assessment and implement high risk evolution contingency plans for work in the stations switchyard was a performance deficiency within the licensees ability to foresee and correct. This finding was associated with the Initiating Events Cornerstone and affected the cornerstone objective for limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown, such as, loss of offsite power (LOOP) due to trucks damaging critical electrical components in the switchyard. The inspectors determined that the finding is more than minor because it was similar to both the more than minor examples 7.e and 7.g in NRC Inspection Manual Chapter (IMC) 0612, Appendix E, Examples of Minor Issues, because the risk assessment for the switchyard work activity failed to consider the impact of vehicle movements resulting in outage high risk management actions that prohibited the movement of vehicles during lowered RCS inventory conditions from being implemented. A

Significance Determination Process (SDP), Phase 1 screening determined that the performance deficiency represented an increase in the likelihood of a LOOP during shutdown and therefore the risk was estimated using NRC IMC 0609, Appendix G,

Shutdown Operations Significance Determination Process. A Phase 2 SDP risk evaluation was done by a regional senior risk analyst using IMC 0609, Appendix G,

Attachment 2. The major assumptions of the analysis were that the plant was in plant operating state (POS-2) in Mode 6, with the RCS vented and the residual heat removal (RHR) system in service for decay heat removal. Time to boil was estimated at 35 minutes with an estimated time to core damage of 8.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The exposure period was approximately 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The LOOP initiating event likelihood was increased by one order of magnitude due to the impact of the performance deficiency. Multiple (i.e., three) qualified sources of offsite power and both onsite emergency diesel generators were available when the vehicles were moved into the switchyard. Recovery credit for restoration of offsite power was included. The dominant sequence was a LOOP with failure of emergency power sources causing a loss of RHR and failure to recover offsite power or emergency power prior to core damage ensuing. The risk was mitigated by the short exposure period and the availability of mitigating system equipment. The result of the analysis was a core damage frequency risk increase of <1E-6/year, a finding of very low safety significance (Green). The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, because personnel did not appropriately plan and coordinate switchyard work activities consistent with nuclear safety by incorporating appropriate outage risk insights and risk management contingency plans H.3(a). (Section 1R13)

Cornerstone: Mitigating System

• TBD. The NRC identified an apparent violation (AV) of the Virgil C. Summer Nuclear Station Operating License Condition 2.C.(18), Fire Protection System, related to the licensee's failure to implement and maintain in effect all provisions of the approved fire protection program as described in the Final Safety Analysis Report (FSAR).

Specifically, the licensee failed to adequately test the isolation function of all 10 CFR 50 Appendix R isolation local control transfer switches (fire switches), including the B EDG fire switch, designed to assure isolation of safe shutdown equipment from the control room in the event of a control room evacuation due to a fire. This resulted in the licensee not identifying a wiring discrepancy that had existed in the B EDG fire switch circuitry since original plant startup until its discovery on April 29, 2010, that would have defeated the Appendix R isolation function during a design basis fire event requiring evacuation from the Control Room. The issue was entered into the licensees corrective action program as condition report CR-10-01814.

The failure to demonstrate proper Appendix R isolation capability of safe shutdown equipment controlled from remote shutdown locations during surveillance testing of Appendix R fire switches is a performance deficiency that was within the licensees ability to foresee and correct. The inspectors determined that the finding is more than minor because it was associated with both the procedure quality and protection against external events (i.e., fire) attributes of the Mitigating Systems cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to adequately test Appendix R isolation contacts associated with fire switches contributed to not identifying a wiring discrepancy in the B EDG fire switch circuitry that defeated its Appendix R isolation function. This condition could have led to the improper operation of the switch or prevented the B EDG output breaker from automatically closing during certain fire scenarios due to fire damage of the electrical circuitry. In accordance with NRC IMC 0609, Significance Determination Process, the inspectors performed a Phase 1 screening analysis and determined that since the finding affected the fire protection defense-in-depth strategies involving post fire safe shutdown systems, the finding required a significance evaluation under IMC 0609, Appendix F, Fire Protection Significance Determination Process. Using Appendix F, Attachment 1, Fire Protection SDP Phase 1 Worksheet, the inspectors determined that the category of post fire safe shutdown was affected and the finding required a Phase 2 analysis by a senior reactor analyst. The significance of this finding is to be determined pending completion of the Phase 2 analysis. A cross-cutting aspect was not identified because the finding does not represent current licensee performance. (Section 4OA2.3)

Cornerstone: Barrier Integrity

Green.

The inspectors identified a Green NCV of 10 CFR Part 50.55a, Codes and Standards, involving the licensees failure to properly apply Subsection IWE of ASME Section XI for conducting general visual examinations of the metal-to-metal pipe plugs installed in the containment liner channel weld leak chase test connections that provide a moisture barrier to the containment liner seam welds.

Following the inspectors identification of this issue, the licensee conducted the visual examinations and found missing pipe plugs and water in four of the leak chase test connection zones. The licensee adequately assessed and corrected the deficiencies prior to entering Mode 4 (Hot Shutdown) to ensure the integrity of containment was maintained. The issue was entered into the licensees corrective action program as condition report CR-11-02834.

The failure to conduct a general visual examination of 100 percent of the moisture barriers intended to prevent intrusion of moisture against inaccessible areas of the containment liner at metal-to-metal interfaces which are not seal welded, was a performance deficiency that was within the licensees ability to foresee and correct.

This finding was of more than minor significance because the failure to conduct required visual examinations and identify the degraded moisture barriers which allowed the intrusion of water into the four liner leak chase channels, if left uncorrected, could have resulted in more significant corrosion degradation of the containment liner or associated liner welds. The finding was associated with the design control attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events.

Specifically, visual examinations of the containment metal liner provide assurance that the liner remains capable of performing its intended safety function. The inspectors used IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, and determined that the finding was of low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of the reactor containment.

A cross-cutting aspect was not identified because the finding does not represent current licensee performance. (Section 1R20)

Licensee-Identified Violations

None.

REPORT DETAILS

Summary of Plant Status

The unit began the inspection period at full rated thermal power (RTP) and operated at full power until April 13, 2011, when power was reduced to 80 percent RTP to conduct scheduled lift setpoint testing of the main steam line code safety valves. On April 14 power was reduced to approximately 35 percent RTP in response to the unexpected trip of the main generator breaker cooling water pumps. On April 15 a planned shutdown was commenced from 40 percent RTP to start the nineteenth refueling outage (RF-19). The reactor was restarted from RF-19 on May 29 and full RTP was reached on June 2. The unit remained at or near full RTP for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

.1 Offsite and Alternate Alternating Current (AC) Power

a. Inspection Scope

The inspectors evaluated the readiness of the offsite and alternate AC power systems by reviewing the licensees procedures that address measures to monitor and maintain the availability and reliability of the offsite and alternate AC power systems. The procedures reviewed included those involved with the communication protocols between the plant and transmission system operator to verify that the appropriate information was being exchanged when issues arose that could impact the offsite power system. In addition, the inspectors performed a walkdown of electrical equipment in the switchyard and associated relay control building to ensure any degradations or adverse material conditions were identified in the licensees corrective action (CAP) and were being appropriately addressed in a manner commensurate with their significance. The documents reviewed during this inspection are listed in the attachment.

b. Findings

No findings were identified.

.2 Seasonal Weather Susceptibilities

a. Inspection Scope

The inspectors performed one adverse weather inspection for readiness of hot weather.

The inspectors verified the licensee had implemented applicable sections of operations administrative procedure (OAP)-109.1, Revision (Rev.) 3B, Guidelines for Severe Weather. The inspectors walked down risk-significant equipment areas including the A and B 7.2 kilovolt (KV) safety-related switchgear rooms and verified the proper operation of cooling systems for these areas. Also, the inspectors reviewed licensee plant computer data associated with stator temperatures of operating safety-related and important non-safety related large electric motors (including the service water pumps, circulating water pumps, condensate pumps, and feedwater booster pumps) to ensure that temperatures were within their expected operational range to prevent any challenge to equipment operation. The inspectors reviewed the results of the licensees hot weather readiness meeting conducted on June 16, 2011, as well as, the licensees CAP database to verify that high temperature weather related problems were being identified at the appropriate level, entered into the CAP, and appropriately resolved.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial System Walkdowns

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 (SOPs), and technical specifications (TS). The inspections included review of outstanding maintenance work orders (WOs) and related condition reports (CRs) 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.

• B motor driven emergency feedwater (MDEFW) pump while A MDEFW pump was out of service for scheduled electrical and motor lubrication preventive maintnenance

• B and C charging pumps while A charging pump was OOS for scheduled gear box replacement

• A emergency diesel generator (EDG) while the B EDG was out of service for scheduled refueling outage bus maintenance

b. Findings

No findings were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors performed a detailed review and walkdown of the residual heat removal (RHR) system to identify any discrepancies between the current operating system equipment lineup and the designed lineup. This walkdown included accessible areas of the RHR system and the equipment alignment configuration as indicated from valves, pumps, and control room equipment status lights. In addition, the inspectors reviewed SOPs, applicable sections of the final safety analysis report (FSAR), design basis document, plant drawings, completed surveillance procedures, outstanding WOs, system health reports, and related CRs to verify that the licensee had properly identified and resolved equipment problems that could affect the availability and operability of the system. Documents reviewed are listed in the attachment to this report.

b. Findings

No findings were identified.

1R05 Fire Protection

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 and 1DB switchgear rooms (fire zones IB-16, IB-17, IB-20 and IB-22.2)

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

• A and B chilled water pump rooms (fire zones IB-7.2, IB-9 and IB-23.1)

• Turbine driven emergency feedwater (TDEFW) pump room (fire zone IB-25.2)

• A, B and C charging pump rooms (fire zones AB-1.5, AB-1.6 and AB-1.7)

b. Findings

No findings were identified.

1R06 Flood Protection Measures

a. Inspection Scope

The inspectors reviewed and walked down portions of the intermediate building elevations 412, 436 and 451 and reviewed the associated flood design calculations for these areas as listed under the attached documents. Risk significant structures, systems, and components (SSCs) in these areas included 1DB switchgear (the 1DB bus gives power to the B and portions of the C trains for key safety related equipment),service water booster pumps, component cooling water pumps, and emergency feedwater pumps. The inspectors reviewed the licensees CAP database to verify that internal flood protection problems were being identified at the appropriate level, entered into the CAP, and appropriately resolved.

b. Findings

No findings were identified.

1R08 Inservice Inspection (ISI) Activities (Unit 1)

.1 Non-Destructive Examination (NDE) Activities and Welding Activities

a. Inspection Scope

The inspectors reviewed the implementation of the licensees Risk Informed Inservice Inspection (ISI) program for monitoring degradation of the reactor coolant system (RCS)boundary and risk significant piping boundaries. The inspectors activities consisted of an on-site review of NDE and welding activities to evaluate compliance with the applicable edition of the ASME Boiler and Pressure Vessel Code (BPVC),Section XI (Code of record: 1998 Edition through the 2000 Addenda, and IWE:2001 Edition through 2003 Addenda) and that indications and defects (if present) were appropriately evaluated and dispositioned in accordance with the requirements of the ASME Code,Section XI acceptance standards.

The inspectors directly observed the NDE activities listed below and reviewed examination procedures, NDE reports, equipment and consumables certification records, personnel qualification records, and calibration reports (as applicable) for the following examinations:

• UT examination of weld # 15 and #16 under WO 1006874-003, Pressrizer Relief, RCS Cold Leg Nozzle (ASME Class 1)

• Liquid Penetrant Testing (PT) of weld fabricated under WO 1103681-003, (ASME Class 2)

The inspectors also reviewed documentation for the following NDE activities:

• Radiography Inspection (RT) of weld fabricated under WO # 1002436-001

• Liquid Penetrant Testing (PT) of weld fabricated under WO # 0800045-001

• Liquid Penetrant Testing (PT) of weld fabricated under WO # 1103681-003 With regard to the disposition of relevant NDE indications since the last Unit outage, the licensee did not identify any relevant indications that were analytically evaluated and accepted continued service.

The inspectors review of welding activities specifically covered the welding sample listed below in order to evaluate compliance with procedures and the ASME Code. The inspectors reviewed WOs, repair and replacement plans, weld data sheets, welding procedures, procedure qualification records, welder qualification records, and NDE reports.

• Direct observation of in-process welding of alternate seal injection piping weld, WO 1103681-003 (ASME Class 2)

• Welding package, WO 0800045-001 (ASME Class 2)

b. Findings

No findings were identified.

.2 PWR Vessel Upper Head Penetration (VUHP) Inspection Activities

a. Inspection Scope

The licensee completed a direct visual examination of the bare-metal outer surface of the Unit 1 reactor vessel upper head in the 2008 refueling outage. The inspectors reviewed visual examination records to evaluate if the activities were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). Specifically, the inspectors evaluated if the required visual examination scope and coverage was achieved and limitations (if applicable) were recorded in accordance with licensee procedures. The inspectors also evaluated if the licensees criteria for visual examination quality and instructions for resolving interference and masking issues were consistent with the regulatory requirements.

The licensee did not identify any indications that required weld repair in the vessel upper head penetrations since the beginning of the last outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control (BACC) Inspection Activities

a. Inspection Scope

The inspectors reviewed the licensees BACC program activities to ensure implementation with commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary, and applicable industry guidance documents. Specifically, the inspectors performed an on-site record review of procedures and the results of the licensees containment walkdown inspections performed during the Unit 1 spring 2011 outage. The inspectors also interviewed the BACC program owner and conducted an independent walkdown of the reactor building to evaluate compliance with licensees BACC program requirements and verify that degraded or non-conforming conditions, such as boric acid leaks identified during the containment walkdown, were properly identified and corrected in accordance with the licensees BACC and CAP.

The inspectors reviewed a sample of engineering evaluations completed for evidence of boric acid found on systems containing borated water to verify that the minimum design code required section thickness had been maintained for the affected components. The inspectors selected the following evaluations for review:

• Evaluation No. CR-10-00612, Evaluation performed on Charging/SI Pump A Discharge Valve, February 9, 2010

• Evaluation No. CR-10-00373, Evaluation performed on Heat Exchanger Letdown Inlet Valve, January 26, 2010

b. Findings

No findings were identified.

.4 Steam Generator (SG) Tube Inspection Activities

No steam generator inspection was conducted.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI-related problems, including welding, BACC, that were identified by the licensee and entered into the CAP as CRs. The inspectors reviewed the CRs to confirm that the licensee had appropriately described the scope of the problem and had initiated corrective actions. The review also included the licensees consideration and assessment of operating experience events applicable to the plant.

The inspectors performed this review to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the report attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Resident Inspector Observations

AND Operating Experience Smart Sample (OpESS) FY 2010-02 Sample Selections for Reviewing Licensed Operator Examinations and Training Conducted on the Plant-Reference Simulator

a. Inspection Scope

On June 13, 2011, the inspectors observed the performance of senior reactor operators and reactor operators on the plant simulator during licensed operator requalification training. The scenario involved a C feedwater flow transmitter failure and A steam generator pressure transmitter failure followed by a stuck open steamline power operated relief valve, pressurizer instrument line break and an anticipated transient without scram event (LOR-SA-033B). While this scenario was not formally considered or intended to be a complex training exercise, the scenario provided the inspectors insight into how the operating crew would respond to a complicated event demonstrating the following aspects of the OpESS FY 2010-02 smart sample:

• Changing plant/system parameters with a consequence for operator inaction

• Loss of instrumentation and alarms normally used for event diagnosis

• Coordination and concurrent use of multiple procedures

• Require prioritization of multiple alarms or instrument readings

• Require operators to take manual control of automatic functions The inspectors assessed overall crew performance, communications, oversight of supervision, and the evaluators' critique. The inspectors verified that any significant training issues were appropriately captured in the licensees CAP.

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 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-10-03286, A pressurizer spary valve PCV-444D failed closed due to transistor failure on 7300 process cabinet circuit control card

• CR-11-00203, C reactor coolant pump upper oil reservoir level indicated high due to bent sensing line

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 2011-15: risk assessment for scheduled A charging pump gear box replacement; A MDEFW pump preventive maintenance; control room pressure boundary breach during control room ventilation preventive maintenance; A EDG and fuel oil pump testing; A RHR pump and valve testing; A containment spray pump testing; and, A train solid state protection system actuation testing

• Work Week 2011-16: risk assessment for scheduled A charging pump gear box replacement; switchyard relay house replacement activities (Yellow Risk); power reduction to 80 percent for main steam safety valve testing; B EDG testing; A main feedwater pump overhaul; control room pressure boundary breach for cable installation; emergent repair of A boric acid pump discharge valve; and plant shutdown to begin scheduled refueling outage

• Review of outage shutdown risk and contingency plans during RCS draindown, lack of steam generators as a heat sink, and A train integrated safeguards testing

• Review of outage shutdown risk and contingency plans for RCS inventory at nine inches below the reactor vessel flange

• Review of outage shutdown risk and contingency plans for reactor core offload/reload, single train of offsite power source available, and single train of engineered safety features equipment available

b. Findings

Introduction.

The inspectors identified a Green NCV of 10 CFR 50.65(a)(4) involving the licensees failure to perform an adequate risk assessment and implement approved high risk management contingency plans for work in the stations electrical switchyard.

Description.

On April 21, 2011, the inspectors identified electrical switchyard work activities being conducted that was contrary to the licensees approved high risk evolution contingency planning. At the time, the unit was in Mode 6, Refueling, with the reactor vessel head detensioned, but not yet removed. The RCS was in lowered inventory level conditions, i.e., stable at approximately 9 inches below the reactor vessel flange, with a RCS time to boil of approximately 35 minutes. In recognition of this high risk evolution configuration, the licensees High Risk Activity document (for RCS at 9 inches below the reactor vessel flange) had specified the following requirements related to electrical power defense in depth:

• Maintain three sources of engineered safety features (ESF) power available

• Ensure no vehicles are moved in the switchyard during lowered inventory conditions Contrary to the licensees electrical risk configuration requirements, the inspectors identified that several vehicles (i.e., three large bucket trucks and several service related pickup trucks) had been moved into the switchyard sometime that morning. The work activities associated with the vehicle entries involved the replacement of lightning arrestors on the de-energized 230 KV electrical Bus #1. The inspectors immediately contacted the operations Shift Supervisor, who was unaware that any authorization had been given to conduct switchyard electrical work involving the movement of vehicles in the switchyard. SAP-703, Control of Switchyard/Transformer Yard Activities, requires operations approval prior to work being permitted in the switchyard. During subsequent interviews with the work control center senior reactor operator (WCC SRO), the inspectors learned that the lightning arrestor work was approved by the WCC SRO; however, the individual was unaware that the work involved vehicles entering the switchyard. The inspectors determined that this lack of understanding occurred due to poor communications between the WCC SRO and the outage switchyard oversight supervisor, who requested work authorization of the lightning arrestor activity on the morning of April 21. Based on inspector interviews with the outage switchyard oversight supervisor, the individual was unaware that the plant was still in lowered RCS inventory conditions where switchyard vehicle movements needed to be restricted. Due in part to this misunderstanding, he had not considered it important to discuss details associated with the vehicles entering the switchyard when the work authorization was requested.

Conversely, the WCC SRO failed to specifically ask whether vehicles would be entering the switchyard in support of the work. Due to this miscommunication error, the inspectors determined that an adequate risk assessment was not conducted by the licensee when the switchyard work activity was authorized on April 21, resulting in high risk management contingency action plans involving the restriction of vehicle movements in the switchyard during lowered RCS inventory conditions not being implemented.

The licensee initiated CR-11-01908 to document this issue. The immediate corrective actions taken to address the problem included the following:

• All ongoing switchyard work was halted and unauthorized vehicles in the switchyard were removed under the direct supervision of station management and operations personnel

• The switchyard oversight supervisor and power delivery substation personnel were coached and a stand down was conducted to discuss details of the incident

• Switchyard oversight personnel were required to brief outage management prior to obtaining the switchyard gate access key from operations

• All subsequent outage switchyard activities were reviewed to ensure none were scheduled in high risk periods

• Immediate procedural enhancements (via Rev. 1E, dated 4/22/11) were made to SAP-703 to provide greater management oversight of switchyard activities

Analysis.

The failure to perform an adequate risk assessment and implement high risk evolution contingency plans for work in the stations switchyard was a performance deficiency within the licensees ability to foresee and correct. The inspectors determined that this finding was associated with the Initiating Events Cornerstone and affected the cornerstone objective for limiting the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown, such as, loss of offsite power (LOOP) due to trucks damaging critical electrical components in the switchyard. The inspectors determined that the finding is more than minor because it was similar to both the more than minor examples 7.e and 7.g in NRC Inspection Manual Chapter (IMC)0612, Appendix E, Examples of Minor Issues, because the risk assessment for the switchyard work activity on the morning of April 21, failed to consider the impact of vehicle movements in the switchyard, resulting in outage high risk management actions that prohibited the movement of vehicles during lowered RCS inventory conditions from being implemented. A Significance Determination Process (SDP), Phase 1 screening determined that the performance deficiency represented an increase in the likelihood of a LOOP during shutdown and therefore the risk was estimated using NRC IMC 0609, Appendix G, Shutdown Operations Significance Determination Process. A Phase 2 SDP risk evaluation was done by a regional senior risk analyst using IMC 0609, Appendix G, Attachment 2. The major assumptions of the analysis were that the plant was in plant operating state (POS-2) in Mode 6, with the RCS vented and the RHR system in service for decay heat removal. Time to boil was estimated at 35 minutes with an estimated time to core damage of 8.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br />. The exposure period was approximately 2.5 hours5.787037e-5 days <br />0.00139 hours <br />8.267196e-6 weeks <br />1.9025e-6 months <br />. The LOOP initiating event likelihood was increased by one order of magnitude due to the impact of the performance deficiency. Multiple (i.e., three)qualified sources of offsite power and both onsite emergency diesel generators were available when the vehicles were moved into the switchyard. Recovery credit for restoration of offsite power was included. The dominant sequence was a LOOP with failure of emergency power sources causing a loss of RHR and failure to recover offsite power or emergency power prior to core damage ensuing. The risk was mitigated by the short exposure period and the availability of mitigating system equipment. The result of the analysis was a core damage frequency risk increase of <1E-6/year, a finding of very low safety significance (GREEN). The inspectors determined that this finding had a cross-cutting aspect in the area of Human Performance, because personnel did not appropriately plan and coordinate switchyard work activities consistent with nuclear safety by incorporating appropriate outage risk insights and risk management contingency plans H.3(a).

Enforcement.

10 CFR 50.65(a)(4), Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, requires, in part, that before performing maintenance activities (including, but not limited to, surveillance, post-maintenance testing, and corrective and preventive maintenance), the licensee shall assess and manage the increase in risk that may result from the proposed maintenance activities.

Contrary to the above, on April 21, 2011, the licensee failed to adequately assess and manage the increase in risk associated with maintenance activities in the electrical switchyard. Because this finding is of very low safety significance and has been entered into the licensees corrective action program as condition report CR-11-01908, this violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000395/2011003-01, Failure to Adequately Assess and Manage Risk of Switchyard Maintenance Activities During Lowered RCS Inventory Conditions.

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. 7, Corrective Action Program.

• CR-11-01458, Missing parts in slow speed switches of service water pump motor breakers

• CR-11-01615, Westinghouse notification of a non-conforming condition related to zircaloy barstock flaws

• CR-11-01659, Main steam safety valve XVS02806F-MS lifted low due to setpoint drift

• CR-11-01712, Scaffold erected in B RHR pump room was not built to scaffolding erection procedures

• CR-11-02962, TDEFW low lube oil pressure trip function failed to enable during testing

b. Findings

No findings were identified.

1R18 Plant Modifications

The inspectors reviewed one permanent modification to evaluate the change for adverse effects on system availability, reliability, and functional capability. Documents reviewed included engineering change request (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 witnessed aspects of the modification implementation during RF-19.

The permanent modification and the associated attributes reviewed are as follows:

ECR 50695, EFW System Flow Control Enhancements (Cured-in-Place-Piping);

• Licensing Basis

• Failure Modes

• Materials/Replacement Components

• Operations

• Flow paths

• Pressure Boundary

• Structural

• Implementation

• Operability/Surveillance Testing The inspectors also reviewed selected CRs associated with the modification to confirm that problems were identified at an appropriate threshold, were entered into the 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.

5A, Post Maintenance Testing Guideline.

• WOs 1006396 and 1100955, PMT following scheduled preventive maintenance on the A MDEFW pump

• WOs 0615067 and 1016043, PMT following scheduled A charging pump gearbox replacement

• WO 1007505, PMT following overhaul and reinstallation of control pack for C main steam isolation valve (MSIV)

• WO 1106207, PMT following auxiliary contactor replacement on service water (SW)booster pump discharge valve

• WO 1106631, PMT following troubleshooting for emergent stroke time failure of C MSIV

• WOs 0815897 and 0815898, PMT following overhaul of TDEFW turbine and governor replacement

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

Refueling Outage RF-19

a. Inspection Scope

On April 15, 2011, the unit was shutdown to commence RF-19. The planned 29 day outage was completed in 45 days on May 31, 2011. The inspectors used inspection procedure 71111.20, ARefueling and Outage Activities,@ to complete the inspections described below. Documents reviewed are listed in the Atachment to this report.

Prior to and during the outage, the inspectors reviewed the licensee=s outage risk assessments and controls for the outage schedule to verify that the licensee had appropriately considered risk, industry experience and previous site specific problems, and to confirm that the licensee had mitigation/response strategies for losses of any key safety functions.

In the area of licensee control of outage activities, the inspectors reviewed equipment removed from service to verify that defense-in-depth was maintained in accordance with applicable TS and that configuration changes due to emergent work and unexpected conditions were controlled in accordance with the outage schedule and risk control plan.

The inspectors reviewed selected components which were removed from service to verify that tag outs were properly installed and that associated equipment was appropriately configured to support the function of the clearance.

During the outage, the inspectors reviewed and/or observed the following:

• RCS pressure, level, and temperature instruments to verify that those instruments were installed and configured to provide accurate indication

• The status and configuration of electrical systems to verify that those systems met TS requirements and the licensee=s outage risk control plan. The inspectors also evaluated if switchyard activities were controlled commensurate with their risk significance and if they were consistent with the licensee=s outage risk control assessment assumptions

• Spent fuel pool (SFP) cooling operations to verify that outage work was not impacting the ability of the operations staff to operate the SFP cooling system during and after core offload. The inspectors also reviewed the licensee=s calculation results of SFP and reactor vessel heatup rates in case of a potential loss of cooling event

• Heavy load lifts for the reactor vessel head removal and reinstallation to ensure the activities were conducted in a controlled and safe manner. Heavy load lift procedures were reviewed to determine whether past and current practices were within the licensing basis and consistent with guidance in NUREG-0612, AControl of Heavy loads at Nuclear Power Plants@

• The control of containment penetrations and containment entries to verify that the licensee controlled those penetrations and activities in accordance with the appropriate TS and could achieve/maintain containment closure for required conditions

• All accessible areas inside the reactor building prior to reactor startup to verify that debris had not been left which could affect the performance of the containment emergency core cooling system recirculation sumps The inspectors reviewed the following activities for conformance to applicable TS and licensee procedural requirements:

• Plant shutdown activities

• Decay heat removal system operations

• Inventory controls and measures to provide alternate means for inventory addition

• Electrical power availability controls

• Reactivity controls

• Reactor vessel defueling and refueling operations

• Reactor heatup, mode changes, initial criticality, startup and power ascension activities The inspectors reviewed various problems that arose during the outage to verify that the licensee was identifying problems related to outage activities at an appropriate threshold and was entering them in the CAP.

b. Findings

Introduction.

The inspectors identified a Green NCV of 10 CFR Part 50.55a, Codes and Standards, involving the licensees failure to properly apply Subsection IWE of ASME Section XI for conducting general visual examinations of the metal-to-metal pipe plugs installed in the containment liner channel weld leak chase test connections that provide a moisture barrier to the containment liner seam welds.

Description.

While conducting a routine containment walkdown during RF-19, the inspectors noticed degradation to several five-inch square thin metal cover plates that were mounted flush with the concrete containment basement floor. Each of these cover plates were intended to be attached by four small screws, one in each corner of the cover plate. There were numerous cover plates throughout the containment and while only a small number were examined, a number of these had 1-2 missing screws or evidence of minor surface damage and/or denting. Following subsequent inquiries with the licensee on the function of these covers to evaluate the significance of the observations, the inspectors learned that underneath each cover plate was an access (junction) box that housed the test connections for the containment liner channel weld leak chase system. The containment liner channel weld leak chase system consists of three-inch wide channel steel that was welded continuously over the entire bottom liner seam welds located under the four foot thick concrete base mat of the containment. The channels were subdivided into 51 zones and in each zone, a test connection was installed. These test connections consist of a 1/2-inch stainless steel tube that penetrated through the back of the channel steel and was seal-welded to the channel steel. The opposite end of the tube extended up through the base mat concrete and terminated in the aforementioned junction boxes. A stainless steel female threaded coupling was welded to the top of the tubing with a stainless steel 3/8-inch pipe plug installed in the coupling. The purpose of the test connections was to perform pressure tests of the inaccessible liner seam welds after the concrete base mat was originally installed during plant construction in order to ensure the leak tight integrity of the liner.

The pipe plugs were installed following these pressure tests along with the cover plates to the top of the junction boxes. The cover plates only served to house and protect the test connections from traffic during and after initial containment construction; however, the pipe plugs served as a moisture barrier to prevent the intrusion of water into the leak chase channel weld area.

During review of station installation drawings and specifications for the leak chase test connections, the inspectors became concerned that the documentation did not indicate that the pipe plugs were seal welded, torqued, or provided with any sealant material to aid in preventing moisture from getting into the leak chase channel weld area. In addition, the licensee indicated that they had no requirements for removing the cover plates and inspecting the condition inside the junction boxes for evidence of moisture intrusion through the threaded test connection pipe plug. Based on subsequent discussions with ISI knowledgeable personnel in NRC Region II and the Office of Nuclear Reactor Regulation (NRR), it was determined that the ISI inspection requirements for moisture barriers found in ASME Section XI, Subsection IWE, Requirements for Class MC and Metallic Liners of Class CC Components of Light-Water Cooled Plants, was applicable to this configuration. Specifically, Table IWE-2500-1, Category E-A, Containment Surfaces, Item E1.30, Moisture Barriers, requires a general visual examination of 100 percent of moisture barriers. The reference to moisture barriers is further defined in Note

(3) of this table, which states; Examination shall include moisture barrier materials intended to prevent intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete-to-metal interfaces and at metal-at-metal interfaces which are not seal welded. Since the interface between the test connection tubing and pipe plug was a metal-to-metal threaded joint that was not seal welded, and leakage past this interface would allow the intrusion of water to the inaccessible liner seam welds, it represented a moisture barrier and was required to be inspected in accordance with Subsection IWE of ASME Section XI.

On May 21, 2011, following a conference call between licensee and NRC (i.e., Region II and NRR) management to communicate the NRC position regarding the ISI requirements related to the test connections plugs, the licensee initiated actions to conduct the ISI general visual examinations prior to entering Mode 4 (Hot Shutdown).

Of the 51 test connection plugs inspected, four were found with missing pipe plugs and debris in the tubing. The remaining 47 plugs were found in place and secured with unbroken epoxy at the joint. When the debris from the four test connections found without plugs was removed, water was discovered inside the liner weld channels below the concrete base mat. Most of the standing water was removed and attempts were made to conduct boroscopic visual examinations of the leak chase channels; however, due to close tolerances at the bottom of the connection tube to the channel steel, the boroscope could not be traversed past this location. Based on visual examination of the channel surfaces at this one location, only minor indications of corrosion was evident. In lieu of a complete visual inspection, the licensee conducted pressure drop tests of each of the four leak chase weld zones. The leakage measured at these four zones was very minor indicating confidence in the overall leak tightness of the liner weld areas. The inspectors determined that the licensee had taken adequate immediate corrective actions to address the deficiencies identified and to ensure the leak tight integrity of the containment. The licensee planned to reassess the condition of these four zones during the next refueling outage as part of a formal IWE Augmented Inspection program. The licensee initiated condition report CR-11-02834 to address the issues associated with this problem and at the end of the inspection period the licensees causal evaluation was still ongoing.

Analysis.

The failure to conduct a general visual examination of 100 percent of the moisture barriers intended to prevent intrusion of moisture against inaccessible areas of the containment liner, was a performance deficiency that was within the licensees ability to foresee and correct. The inspectors determined that this finding was of more than minor significance because the failure to conduct required visual examinations and identify the degraded moisture barriers which allowed the intrusion of water into the four liner leak chase channels, if left uncorrected, could have resulted in more significant corrosion degradation of the containment liner or associated liner welds. This finding was associated with the Design Control attribute of the Barrier Integrity Cornerstone and affected the cornerstone objective of providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, visual examinations of the containment metal liner provide assurance that the liner remains capable of performing its intended safety function. The inspectors used Inspection Manual Chapter 0609, Significance Determination Process, 0609.04, Phase 1 - Initial Screening and Characterization of Findings, and determined that the finding was of low safety significance (Green) because it did not represent an actual open pathway in the physical integrity of the reactor containment. A cross-cutting aspect was not identified because the finding does not represent current licensee performance.

Enforcement.

10 CFR Part 50.55a, Codes and Standards, as modified by NRC Final Rule-Making published in the Federal Register dated August 8, 1996, and October 1, 2004, states in part, that the examination of metal liners in concrete containments shall satisfy the requirements of ASME Section XI, Subsection IWE of the 1992 Edition with the 1992 Addenda or the 1998 Edition through the latest edition and addenda incorporated by reference in paragraph 10 CFR 50.55a(b)(2). The 1992 Edition with the 1992 Addenda of ASME Section XI, Subsection IWE; as well as the current 2001 Edition with the 2003 Addenda required examination of moisture barriers in concrete containments. Specifically, Table IWE-2500-1, Category E-A, Containment Surfaces, Item E1.30, Moisture Barriers, required a general visual examination of 100 percent of moisture barriers that is further defined in Note (3), which states; Examination shall include moisture barrier materials intended to prevent intrusion of moisture against inaccessible areas of the pressure retaining metal containment shell or liner at concrete-to-metal interfaces and at metal-at-metal interfaces which are not seal welded.

Contrary to the above, since initial 10 CFR 50.55a, Subsection IWE requirements were established in 1996 until 2011, the licensee had failed to perform visual examinations of the metal-to-metal non-seal-welded threaded pipe plug at the top of the leak chase channel test connections, thereby, failed to identify defective areas in the moisture barrier, and failed to correct the defects. Because this finding is of very low safety significance and has been entered into the licensees corrective action program as condition report CR-11-02834, this violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy: NCV 05000395/2011003-02, Failure to Perform ISI General Visual Examinations of Containment Moisture Barrier Associated with Containment Liner Leak Chase Test Connection Threaded Pipe Plugs.

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-230.007, Rev. 3, RHR Pump and Check Valve Full Flow Test Reactor Coolant System Leakage Tests:

• STP-114.002, Rev. 12C, Operational Leakage Calculation Containment Isolation Valve (CIV) Tests:

• STP-215.004, Rev. 6E, Containment Isolation Valve Leakage Test for the AC, CC, DN, FS and SW Systems Other Surveillance Tests:

• STP-401.002, Rev. 13, Main Steam Line Code Safety Valves ASME OM Code Test

• STP-125.010, Rev.13, Integrated Safeguards Test Train A

• STP-220.008A, Rev. 7, Turbine Driven Emergency Feedwater Pump Full Flow Test

b. Findings

No findings were identified.

RADIATION SAFETY

(RS)

Cornerstones: Occupational Radiation Safety (OS)

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

Hazard Assessment and Instructions to Workers: During facility tours, the inspectors directly observed labeling of radioactive material and postings for radiation areas and high radiation areas (HRAs) established within the radiologically controlled area (RCA).

The inspectors independently measured radiation dose rates or directly observed conduct of licensee radiation surveys for selected RCA areas. The inspectors reviewed and verified survey records for several plant areas including surveys for alpha emitters, airborne radioactivity, and gamma radiation surveys with a range of dose rate gradients.

The inspectors also discussed changes to plant operations with Radiation Protection (RP) supervisors that could contribute to changing radiological conditions since the last inspection. The inspectors attended a pre-job discussion and reviewed several radiation work permits (RWP) to assess communication of radiological control requirements and current radiological conditions to workers.

Hazard Control and Work Practices: The inspectors evaluated access barrier effectiveness for selected Locked High Radiation Area (LHRA) and Very High Radiation Area (VHRA) locations. Changes to procedural guidance for LHRA and VHRA controls were discussed with RP supervisors. Controls and their implementation for storage of irradiated material within the spent fuel pool were reviewed and discussed. Established radiological controls (including airborne controls) were evaluated for selected tasks including work in auxiliary building HRAs, and radwaste processing and storage. In addition, licensee controls for areas where dose rates could change significantly as a result of plant shutdown and refueling operations were reviewed and discussed.

Occupational workers adherence to selected RWPs and RP technician (RPT)proficiency in providing job coverage was evaluated through direct observations and interviews with licensee staff. Electronic dosimeter (ED) alarm set points and worker stay times were evaluated against area radiation survey results for reviewed RWPs.

Control of Radioactive Material: The inspectors observed surveys of material and personnel being released from the RCA using small article monitor, personnel contamination monitor, and portal monitor instruments. The inspectors also reviewed records of leak tests on selected sealed sources and discussed nationally tracked source transactions with licensee staff.

Problem Identification and Resolution: Condition Reports associated with radiological hazard assessment and control were reviewed and assessed. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure SAP-999, Corrective Action Program, Rev. 7. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

RP activities were evaluated against the requirements of Updated Final Safety Analysis Report (UFSAR) Section 12; TS Sections 6.11 Radiation Protection Program and 6.12 High Radiation Areas; 10 CFR Parts 19 and 20; and approved licensee procedures.

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

.

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

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

.1 Cornerstone: Reactor Safety Barrier Integrity

a. Inspection Scope

The inspectors verified the accuracy of the licensees PI submittals listed below for the period April 2010 through March 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.

• RCS Specific Activity

• RCS Identified Leak Rate

b. Findings

No findings were identified.

.2 Cornerstone: Occupational Radiation Safety

a. Inspection Scope

The inspectors sampled licensee records to verify the accuracy of reported 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, Rev. 6, "Regulatory Assessment Indicator Guideline."

The inspectors reviewed PI data collected from July 10, 2010, through March 31, 2011, for the Occupational Exposure Control Effectiveness PI. For the reviewed period, the inspectors assessed CAP records to determine whether HRA, VHRA, or unplanned exposures, resulting in TS or 10 CFR 20 non-conformances, had occurred during the review period. In addition, the inspectors reviewed selected personnel contamination event data, internal dose assessment results, and ED alarms for cumulative doses and/or dose rates exceeding established set-points. The reviewed documents relative to this PI are listed in Sections 2RS1 and 4OA1 of the Attachment.

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 Semi-Annual Review to Identify Trends

a. Inspection Scope

The inspectors performed a review of the licensees corrective action program and associated documents to identify trends that could indicate the existence of a more significant safety issue. The review was focused on repetitive equipment issues, but also considered trends in human performance errors, the results of daily inspector corrective action item screening discussed in Section 4OA2.1 above, licensee trending efforts, and licensee human performance results. The review nominally considered the six-month period of January 2011 through June 2011. Documents reviewed included licensee monthly and quarterly corrective action trend reports, engineering system health reports, maintenance rule documents, department self-assessment activities, and quality assurance audit reports.

b. Assessment and Observations No findings were identified. In general, the licensee has identified adverse trends and addressed them in their CAP. No new adverse trends were identified this period that had not already been identified by the licensee.

.3 Annual Sample Review

a. Inspection Scope

The inspectors reviewed the issue listed below in detail to evaluate the effectiveness of the licensees corrective actions for important safety issues.

• CR-10-01814, Appendix R - Diesel Generator B Local/Remote/Maintenance Switch Contact Bypass The inspectors 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, Rev. 7, Corrective Action Program.

b. Findings

Introduction.

The inspectors identified an apparent violation (AV) of the Virgil C. Summer Nuclear Station Operating License Condition 2.C.(18), Fire Protection System, for failure to implement and maintain in effect all provisions of the approved fire protection program. Specifically, the licensee failed to adequately test the isolation function of all 10 CFR 50 Appendix R isolation local control transfer switches (fire switches), including the B EDG fire switch, designed to assure isolation of safe shutdown equipment from the control room in the event of a control room evacuation due to a fire.

Description.

On April 29, 2010, licensee personnel investigating wiring conflicts between electrical drawings discovered an improperly installed jumper wire in the B EDG local control panel. It was determined that this wiring discrepancy bypassed one of the Appendix R isolation contacts (i.e., contact 1-1C) associated with the B EDG fire switch. The impact of bypassing this contact resulted in a section of the remote control circuitry (i.e., main control room operation) not being properly isolated from the local control circuitry (i.e., local operation from the EDG room). Therefore, had an Appendix R design bases fire occurred in certain areas of the control building where the associated control cable is routed, the local control circuitry would have been subject to potential fire related electrical faults which could have prevented proper operation of the fire switch or prevented the B EDG output breaker from automatically closing on a bus undervoltage signal. The Appendix R isolation function for the fire switch was immediately restored upon removal of the jumper wire.

The licensee addressed this issue in CR-10-01814 and submitted LER 05000395/2010-002-00 and LER 05000395/2010-002-01 to document the unanalyzed condition created by the wiring discrepancy. The licensees root cause investigation determined that the jumper wire was temporarily installed during a 1983 plant design modification. Due to weaknesses in the modification instructions and drawing detail information, the temporary jumper wire was not removed as intended upon completion of the modification. The subsequent post-modification testing was not comprehensive in scope to detect the discrepancy.

As a contributing cause, the licensee also identified that the Appendix R fire protection surveillance procedure for the B EDG fire switch (i.e., STP-170.021, Fire Switch Functional Test for XEG0001B Diesel Generator B,), had not been capable of detecting the wiring discrepancy. The Appendix R isolation circuitry for the B EDG fire switch, as well as fire switches for all other safe shutdown equipment, is designed with multiple isolation contacts that together provide the Appendix R isolation function. The Appendix R surveillance procedures were written to verify the functionality of the remote circuit was disabled when the fire switch was taken to local. Based on this, successful test results could be obtained if only one of these isolation contacts opens. While the licensee initiated actions to revise all the Appendix R surveillance procedures to include testing of each Appendix R isolation contact, it was concluded that current procedures met their licensing bases requirements for Appendix R testing. This was based on the procedures being written per the guidance in NRC Generic Letter 81-12, Fire Protection Rule, which did not explicitly state that Appendix R circuitry testing was required at the contact level. Based on this conclusion, the licensee had intended to revise all the Appendix R surveillance tests to incorporate testing at the contact level, however, the date for completing the tests was entered into CR-11-01814 as September 2011.

The inspectors disagreed with the licensees conclusion that NRC Generic Letter 81-12 was intended to provide the only licensing bases requirement for properly testing the functionality of Appendix R fire switches. License Condition 2.C.(18), Fire Protection System, of the V. C. Summer operating license requires that the licensee implement and maintain in effect all provisions of the approved fire protection program as described in the FSAR. FSAR Section 9.5.1 states 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 V. 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 Branch Technical Position (BTP) Auxiliary Power Conversion Systems Branch (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 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. For an uncontrollable fire in the control room, cable spreading rooms, or relay room requiring control room evacuation, the functions of the fire switches are: 1) transfer control of selected equipment to the remote shutdown panel and other local control stations, and 2) isolate the applicable fire area circuits to prevent fire damage from disabling or causing maloperation of equipment. Failure to ensure each fire switch contact opens that is used for Appendix R isolation would leave the control circuit susceptible to fire induced faults and could challenge the ability to safely shut down the reactor. While the existing surveillance procedures adequately tested the transfer control aspect, they failed to adequately verify the Appendix R isolation function, therefore were inadequate representing a violation of the requirements of License Condition 2.C.(18).

Based on the above, the inspectors informed licensee management the determination that they were not in compliance with the testing requirements pursuant to License Condition 2.C.(18), since adequate testing of all fire switches (that verified the status of Appendix R isolation contacts), had not been conducted to date. The licensee agreed to expedite maintenance troubleshooting plans to verify that Appendix R fire switches were functional at the contact level. This testing began in March 2011 and was completed during RF-19 that ended May 29, 2011. The results of this testing confirmed that all isolation contacts associated with Appendix R fire switches were capable of performing their Appendix R safety function and no other wiring discrepancies were identified.

Therefore, the extent of condition for this issue was limited to the original deficiency associated with the B EDG fire switch.

Analysis.

The failure to demonstrate proper Appendix R isolation capability of safe shutdown equipment controlled from remote shutdown locations during surveillance testing of Appendix R fire switches is a performance deficiency that was within the licensees ability to foresee and correct. The inspectors determined that the finding is more than minor because it was associated with both the procedure quality and protection against external events (i.e., fire) attributes of the Mitigating Systems cornerstone and it adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to adequately test Appendix R isolation contacts associated with fire switches contributed to not identifying a wiring discrepancy in the B EDG fire switch circuitry that defeated its Appendix R isolation function. This condition could have led to the improper operation of the switch or prevented the B EDG output breaker from automatically closing during certain fire scenarios due to fire damage of the electrical circuitry. In accordance with NRC IMC 0609, Significance Determination Process, the inspectors performed a Phase 1 screening analysis and determined that since the finding affected the fire protection defense-in-depth strategies involving post fire safe shutdown systems, the finding required a significance evaluation under IMC 0609, Appendix F, Fire Protection Significance Determination Process. Using Appendix F, Attachment 1, Fire Protection SDP Phase 1 Worksheet, the inspectors determined that the category of post fire safe shutdown was affected and the finding required a Phase 2 analysis by a senior reactor analyst. The significance of this finding is to be determined pending completion of the Phase 2 analysis. A cross-cutting aspect was not identified because the finding does not represent current licensee performance.

Enforcement.

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 Branch Technical Position (BTP) Auxiliary Power Conversion Systems Branch (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. Pending determination of the safety significance, this finding is identified as AV 05000395/2011003-03, Failure to Conduct Adequate Testing of Appendix R Fire Switches.

4OA3 Event Followup

.1 Inadvertent Safety Injection (SI) Acutation on Steam Line High Differential Pressure

a. Inspection Scope

On May 27 with the plant in Mode 3 (Hot Standby) at normal operating system and pressure during startup from RF-19, an inadvertent SI actuation occurred due to operators opening the C MSIV with the downstream steam line header depressurized.

Earlier in the shift, the MSIVs and MSIV bypass valves, had been closed to help maintain RCS temperature. Closing these valves allowed the downstream main steam line header to become depressurized. When the C MSIV was subsequently opened at the request of Instrumentation and Control (I&C) personnel who were troubleshooting a suspect limit switch setup issue with the C MSIV, the resulting steam flow depressurized the C steam generator to greater than 97 psig below the A and B steam generators, satisfying the SI actuation logic setpoint criterion.

At the time of the SI actuation, the resident inspectors were onsite and immediately responded to the control room to evaluate plant parameters and status, monitor operator event response actions, independently evaluate the performance of plant safety equipment, confirm the licensee properly classified the event in accordance with emergency action level procedures as applicable, and reviewed NRC event notification requirements in 10 CFR 50.72.

b. Findings

The inspectors confirmed that the operator response to the event was appropriate and consistent with emergency and abnormal operating procedure requirements. Following the SI actuation, all plant systems functioned as designed and emergency core cooling system water was injected into the RCS. The operators were successful in timely termination of unnecessary injection flows and preventing potential pressurizer overfill and adverse RCS overpressure conditions. The plant was effectively stabilized in Mode 3. The licensee correctly determined that no emergency action level entry condition was reached; however, the event was determined to be reportable to the NRC under the 4 hour4.62963e-5 days <br />0.00111 hours <br />6.613757e-6 weeks <br />1.522e-6 months <br /> non-emergency requirement of 10 CFR 50.72(b)(2) for an emergency core cooling system discharge to the RCS. The licensee reported the notification in a timely manner.

Based on interviews with the operators following completion of plant recovery actions, the inspectors noted that the operators had failed to recognize that the main steam line header downstream of the MSIVs had been depressurized when the MSIVs and their bypass valves were closed earlier in the shift. In addition, procedural guidance for stroking the MSIV, such as the stroke test procedure (i.e., STP-130.004D, Rev. 1, Main Steam Isolation Valve Full Stroke Test), was not formally utilized when the valve was opened at the request of I&C. This procedure contained a signoff action to verify current plant conditions will permit performance of the stroke test, and could have provided an opportunity for the operators to have recognized that the main steam line header was depressuried, had this procedure been utilized.

The licensee documented this event in their CAP as CR-11-03001 and planned to submit a LER within 60 days of the event date. At the end of the inspection period, the inspectors were awaiting the completion of the licensees root cause evaluation results to understand and properly characterize the potential performance deficiencies associated with this event. This issue is unresolved pending inspector review of the licensees evaluation, proposed corrective actions, and review of the licensees LER in order to characterize the potential performance deficiencies associated with this event.

This unresolved item (URI) is identified as05000395/2011003-04, Inadvertent Safety Injection in Mode 3 Due to Opening C Main Steam Isolation Valve.

.2 (Closed) LER 05000395/2010002-00 and -01 : Unanalyzed Condition Due to Wiring

Discrepancy in the B Emergency Diesel Generator (EDG) Appendix R Isolation Circuitry The inspectors reviewed the subject LERs, as well as condition report CR-10-01814 associated with this issue to verify the LER accuracy and appropriateness of corrective actions. The supplement to this LER provided the results of the licensees root cause analysis. The enforcement aspects of this event and details of the licensees corrective actions are discussed in Section 4OA2.3 of this report. These LERs are closed.

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) NRC Temporary Instruction 2515/183, Followup to the Fukushima Daiichi

Nuclear Station Fuel Damage Event

a. Inspection Scope

The inspectors assessed the activities and actions taken by the licensee to assess its readiness to respond to an event similar to the Fukushima Daiichi nuclear plant fuel damage event. This included

(1) an assessment of the licensees capability to mitigate conditions that may result from beyond design basis events, with a particular emphasis on strategies related to the spent fuel pool, as required by NRC Security Order Section B.5.b issued February 25, 2002, as committed to in severe accident management guidelines, and as required by 10 CFR 50.54(hh);

(2) an assessment of the licensees capability to mitigate station blackout (SBO) conditions, as required by 10 CFR 50.63 and station design bases;

(3) an assessment of the licensees capability to mitigate internal and external flooding events, as required by station design bases; and

(4) an assessment of the thoroughness of the walkdowns and inspections of important equipment needed to mitigate fire and flood events, which were performed by the licensee to identify any potential loss of function of this equipment during seismic events possible for the site.

b. Findings

Inspection Report 05000395/2011009 (ML111330144) documented detailed results of this inspection activity. Following issuance of the report, the inspectors conducted detailed follow-up on selected issues. No findings were identified during this follow-up inspection.

.3 (Closed) NRC Temporary Instruction 2515/184, Availability and Readiness Inspection of

Severe Accident Management Guidelines (SAMGs)

On May 27, 2011, the inspectors completed a review of the licensees severe accident management guidelines (SAMGs), implemented as a voluntary industry initiative in the 1990s, to determine

(1) whether the SAMGs were available and updated,

(2) whether the licensee had procedures and processes in place to control and update its SAMGs,

(3) the nature and extent of the licensees training of personnel on the use of SAMGs, and

(4) licensee personnels familiarity with SAMG implementation.

The results of this review were provided to the NRC task force chartered by the Executive Director for Operations to conduct a near-term evaluation of the need for agency actions following the Fukushima Daiichi fuel damage event in Japan. Plant-specific results for Summer Station were provided as an Enclosure to a memorandum to the Chief, Reactor Inspection Branch, Division of Inspection and Regional Support, dated June 02, 2011 (ML111530328).

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

Inventories of Materials Tracked in the National Source Tracking System (NSTS) Pursuant to Title 10, Code of Federal Regulations, Part 20.2207 (10 CFR 20.2207)

a. Scope

The inspectors performed the TI concurrent with IP 71124.01 Radiation Hazard

Analysis.

The inspectors reviewed the licensees source inventory records and identified the sources that met the criteria for reporting to the NSTS. The inspectors visually identified the sources contained in various calibration systems and verified the presence of the source by direct radiation measurement using a calibrated portable radiation detection survey instrument. The inspectors reviewed the physical condition of the calibration and radiography sources to include documented source leak checks as appropriate. The inspectors reviewed the licensees procedures for source receipt, maintenance, transfer, reporting and disposal. The inspectors reviewed documentation that was used to report the sources to the NSTS. Documents reviewed are listed in sections 2RS1 of the

.

b. Findings

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

4OA6 Meetings, Including Exit

.1 Quarterly Resident Inspector Exit Meeting

On July 12, 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.

.2 Annual Occupational Radiation Safety Inspection Exit Meeting

On April 22, 2011, the inspectors discussed results of the onsite radiation protection inspections with Mr. T. Gatlin and other responsible staff. The licensee acknowledged the results of these inspections. The inspectors noted that no proprietary information was reviewed during the course of the inspection.

.3 Inservice Inspection Exit Meeting

On April 29, 2011, the inspector discussed the results of the inservice inspection with Mr.

T. Gatlin and other members of the licensee management staff. The licensee acknowledged the results of these inspections. The inspectors noted that no proprietary information was reviewed during the course of the inspection.

.4 Radiation Protection Exit Meeting

On April 22, 2011, the inspectors discussed results of the onsite radiation protection inspections with Mr. T. Gatlin, Vice President Nuclear, and other responsible staff. The inspectors noted that no proprietary information was reviewed during the course of the inspection.

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

05000395/2011003-03 AV Failure to Conduct Adequate Testing of Appendix R Fire Switches (Section 4OA2.3)

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

Opened and Closed

05000395/2011003-01 NCV Failure to Adequately Assess and Manage Risk of Switchyard Maintenance Activities During Lowered RCS Inventory Conditions (Section 1R13)

05000395/2011003-02 NCV Failure to Perform ISI General Visual Examinations of Containment Moisture Barrier Associated with Containment Liner Leak Chase Test Connection Threaded Pipe Plugs (Section 1R20)

Closed

05000395/2515183 TI Followup to the Fukushima Daiichi Nuclear Station Fuel Damage Event (Section 4OA5.2)

05000395/2515184 TI Availability and Readiness of Severe Accident Management Guidelines (SAMGs) (Section 4OA5.3)

05000395/2515179 TI Verification of Licensee Responses to NRC Requirement for Inventories of Materials Tracked in the National Source Tracking System (NSTS) Pursuant of Title 10, Code of Federal Regulations, Part 20.2207 (10 CFR 20.2207)

(Section 4OA5.4)

05000395/2010002-00 LER Unanalyzed Condition Due to Wiring Discrepancy in the B Emergency Diesel Generator (EDG) Appendix R Isolation Circuitry (Section 4OA3.2)

05000395/2010002-01 LER Unanalyzed Condition Due to Wiring Discrepancy in the B Emergency Diesel Generator (EDG) Appendix R Isolation Circuitry (Section 4OA3.2)

Discussed

None