IR 05000395/2014005

IR 05000395/2014005; on 10/01/2014 - 12/31/2014: Virgil C. Summer Nuclear Station, Unit 1; Integrated Inspection Report

ML15034A011
Person / Time
Site:	Summer
Issue date:	02/02/2015
From:	Steven Rose NRC/RGN-II/DRP/RPB5
To:	Gatlin T South Carolina Electric & Gas Co
References
IR 2014005
Download: ML15034A011 (27)

Text

UNITED STATES ruary 2, 2015

SUBJECT:

VIRGIL C. SUMMER NUCLEAR STATION, UNIT 1 - NRC INTEGRATED INSPECTION REPORT 05000395/2014005

Dear Mr. Gatlin:

On December 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Virgil C. Summer Nuclear Station, Unit 1. On January 29, 2015, the NRC inspectors discussed the results of this inspection with Mr. G. Lippard and members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.

No NRC-identified or self-revealing findings were identified during the inspection period.

However, inspectors documented a licensee-identified violation, which was determined to be of very low safety significance, in this report. The NRC is treating this violation as a non-cited violation (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest the violation or significance of the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-001; with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Virgil C. Summer Nuclear Station. In accordance with 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its Enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRCs Agencywide Document Access and management System (ADAMS). ADAMS is accessible from the NRC Website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Steven D. Rose, Chief Reactor Projects Branch 5 Division of Reactor Projects Docket No.: 50-395 License No.: NPF-12

Enclosure:

IR 05000395/2014005 w/Attachment: Supplemental Information

REGION II==

Docket No. 50-395 License No. NPF-12 Report Nos. 05000395/2014005 Licensee: South Carolina Electric & Gas (SCE&G) Company Facility: Virgil C. Summer Nuclear Station, Unit 1 Location: P.O. Box 88 Jenkinsville, SC 29065 Dates: October 1, 2014, through December 31, 2014 Inspectors: J. Reece, Senior Resident Inspector E. Coffman, Resident Inspector D. Bacon, Senior Operations Engineer (Section 1R11.3)

S. Ninh, Senior Project Engineer (Sections 4OA3 and 4OA7)

G. MacDonald, Senior Reactor Analyst (Section 4OA7)

Approved by: Steven D. Rose, Chief Reactor Projects Branch 5 Division of Reactor Projects Enclosure

SUMMARY

IRs 05000395/2014005; 10/01/2014 - 12/31/2014: Virgil C. Summer Nuclear Station, Unit 1;

Integrated Inspection Report.

The report covered a three-month period of inspection by resident inspectors, a senior project engineer, a senior reactor analyst and a senior operations inspector from the region. No NRC-identified or self-revealing findings were identified. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5.

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

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at full Rated Thermal Power (RTP) and operated at or near full RTP through the end of the fourth quarter,

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

.1 Tornado Watch

a. Inspection Scope

On October 14, and November 17, 2014, tornado watches were issued for Fairfield County, and the inspectors performed two reactive weather-related inspections. The inspectors reviewed licensee adverse weather response operations administrative procedure, (OAP)-109.1, Guidelines for Severe Weather, Revision (Rev.) 4A, and related site preparations including work activities that could impact the overall maintenance risk assessments.

b. Findings

No findings were identified.

.2 External Flooding

a. Inspection Scope

The inspectors reviewed the licensees external flood design mitigation plans to determine consistency with design requirements, updated final safety analysis report (UFSAR) and flood analysis documents. The inspectors performed walkdowns of the station to verify flood protection features remained generally as described in the UFSAR and flood analysis documents. Specifically, the inspectors performed visual examinations of the plant yard areas involving non-safety electrical manhole (EMH)-8 and its impact on the safety-related auxiliary building. Documents reviewed are listed in the Attachment.

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 (SOP), 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.

• Partial walkdown of A reactor building (RB) spray pump and related components during scheduled work on B RB spray pump

• Partial walkdown of A and B motor driven emergency feedwater (MDEFW) pumps and related components during scheduled work on turbine driven emergency feedwater (TDEFW) pump

• Partial walkdown of B residual heat removal (RHR) pump and related components during scheduled work on A RHR pump

b. Findings

No findings were identified.

.2 Complete System Walkdown

a. Inspection Scope

The inspectors performed a detailed review and walkdown of the A emergency diesel generator (EDG) and support systems to identify any discrepancies between the current operating system equipment lineup and the designed lineup. 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.

b. Findings

No findings were identified.

1R05 Fire Protection

Quarterly Fire Protection Walkdowns

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. Documents reviewed are listed in the Attachment. The inspectors conducted routine inspections of the following seven areas (respective fire zones also noted):

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

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

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

• Auxiliary building 436 elevation (fire zone AB-1.18)

• Intermediate building 436 elevation (fire zones IB-25.5, 25.6.1, 25.6.2 and 25.7)

• Control building 412 and 425 elevations (fire zones CB-1.1, CB-1.2, CB-2, CB-5)

• Control room (fire zone CB-17.1)

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Annual Review of Electrical Manholes

a. Inspection Scope

The inspectors reviewed a licensees periodic inspection of one risk-significant electrical manhole, EMH-2, containing cables for service water (SW) system components, for assessment of leaks, cable supports and structures, and general structural integrity. In addition, the inspectors reviewed several past periodic licensee inspection results for the above mentioned manhole to ensure that any degraded conditions identified were appropriately resolved. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Licensed Operator Requalification

a. Inspection Scope

The inspectors observed an operator requalification exam scenario occurring on October 27, 2014, and involving multiple failures leading to entry into emergency operating procedures in order to combat the problem. The inspectors observed crew performance in terms of communications; ability to prioritize failures in order to take timely and proper actions; prioritizing, interpreting, and verifying alarms; correct use and implementation of procedures, including the alarm response procedures; timely control board operation and manipulation, including high-risk operator actions; and oversight and direction provided by the shift supervisor, including the ability to identify and implement appropriate TS actions and emergency action levels. The inspectors reviewed the licensees critique comments to verify that performance deficiencies were captured for appropriate corrective action.

b. Findings

No findings were identified.

.2 Resident Quarterly Observation of Control Room Operations

a. Inspection Scope

During the inspection period, the inspectors conducted observations of licensed reactor operator activities to ensure consistency with licensee procedures and regulatory requirements. For the two listed activities, the inspectors observed the following elements of operator performance: 1) operator compliance and use of plant procedures including TS;

(2) control board component manipulations; 3) use and interpretation of plant instrumentation and alarms; 4) documentation of activities; 5) management and supervision of activities; and 6) control room communications.

• Review of operator activities during reactor coolant system (RCS) dilutions and miscellaneous tagout discussions

• Review of operator activities during power supply replacement activities for the loose parts monitor and miscellaneous tagout discussions

b. Findings

No findings were identified.

.3 Annual Review of Licensee Requalification Examination Results

a. Inspection Scope

On September 4, 2014, the licensee completed the annual requalification operating examinations required to be administered to all licensed operators in accordance with Title 10 of the Code of Federal Regulations 55.59(a)(2), Requalification Requirements, of the NRCs Operators Licenses. The inspectors performed an in-office review of the overall pass/fail results of the individual operating examinations and the crew simulator operating examinations in accordance with Inspection Procedure (IP) 71111.11, Licensed Operator Requalification Program. These results were compared to the thresholds established in Section 3.02, Requalification Examination Results, of IP 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors evaluated one equipment issue described in the CR listed below to verify the licensees effectiveness with the corresponding preventive or corrective maintenance associated with structure, system, and components (SSCs). The inspectors reviewed Maintenance Rule (MR) implementation to verify that component and equipment failures were identified, entered, and scoped within the MR program. Selected SSCs were reviewed to verify proper categorization and classification in accordance with 10 CFR 50.65. The inspectors examined the licensees 10 CFR 50.65(a)(1) corrective action plans to determine if the licensee was identifying issues related to the MR at an appropriate threshold and that corrective actions were established and effective. The inspectors review also evaluated if maintenance preventable functional failures or other MR findings existed that the licensee had not identified. The inspectors reviewed the licensees controlling procedures consisting of engineering services procedure, (ES)-

514, Rev. 6, Maintenance Rule Program Implementation, and station administrative procedure, (SAP)-0157, Rev. 1, Maintenance Rule Program, to verify consistency with the MR program requirements.

• CR-14-05198, Maintenance Rule (a)(1) status established on condensate demineralization system due to failure of XVB09210-WI to open resulting in unit trip

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessment and Emergent Work Control

a. Inspection Scope

The inspectors performed risk assessments, as appropriate, for the five scheduled work activities involving a yellow risk condition for the associated components as 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 41, B EDG and emergent work associated with B SW pump motor lower bearing cooling flow

• Work week 44, TDEFW pump

• Work week 45, B EDG

• Work week 47, A SW pump

• Work week 50, A RHR pump

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

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. The inspectors also verified that the operability evaluations were performed in accordance with SAP-209, Rev. 1, Operability Determination Process, and SAP-999, Rev. 12A, Corrective Action Program. Documents reviewed are listed in the Attachment.

• CR-14-03624, gas accumulation in B train RHR system

• CR-14-04456, SW pond reactor building cooling units (RBCU) 1B and 2B return isolation valve failed its surveillance

• CR-14-02740, ES-120 for CR-13-01492 did not address steam generator tube rupture dose analysis or emergency feedwater flow

• CR-14-05735, cable tray in direct contact with A RB spray pump suction piping

• CR-14-03208, SW pond RBCU 1A and 2A return isolation valve failed its surveillance

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed one procedure-controlled temporary modification associated with WO 1406050, open/close links and install/remove jumpers to support STP-125.017, Diesel Generator A Loss of Offsite Power Test, Rev. 6, to evaluate the change for adverse effects on system availability, reliability, and functional capability. Documents reviewed included engineering calculations, WOs, site drawings, applicable sections of the UFSAR, 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 UFSAR to verify that the changes did not adversely affect the safety function of safety systems. The inspectors also reviewed any related CRs to confirm that problems were identified at an appropriate threshold, were entered into the corrective action program (CAP), and appropriate corrective actions had been initiated.

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

For the four 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, Post Maintenance Testing Guideline, Rev. 5, Change C.

• WO-1406503, change oil in bearings on B reactor building spray pump

• WO-1407820, replace oil filter on TDEFW pump

• WO-1407491, retest SW pond RBCU 1B and 2B return isolation valve following STP failure

• WO-1402759, repair C component cooling water (CCW) pump casing drain valve

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed and/or reviewed two 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-123.003B, Train B Service Water System Valve Operability Test, Rev. 6I Other

• STP-125.008, Diesel Generator A 24 Hour Load Test, Rev. 7

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

.1 Exercise Drill

a. Inspection Scope

On October 15, 2014, the inspectors reviewed and observed the performance of an exercise drill that involved a weather related loss of offsite power and resultant reactor trip and loss of an EDG with the opposite train EDG previously out of service for maintenance. The events required entry into Emergency Action Levels (EAL)culminating with a General Emergency. The inspectors assessed abnormal and emergency procedure usage, emergency plan classifications, protective action recommendations, respective notifications and the adequacy of the licensees drill critique. The inspectors verified that drill deficiencies were captured into the licensees corrective action program.

b. Findings

No findings were identified.

.2 Simulator Drill

a. Inspection Scope

On November 12, 2014, the inspectors reviewed the performance of a simulator drill that involved a loss of offsite power event which required declaration of a Site Area Emergency. The inspectors assessed abnormal and emergency procedure usage, emergency plan classifications, protective action recommendations, respective notifications and the adequacy of the licensees drill critique. The inspectors verified that drill deficiencies were captured into the licensees corrective action program.

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

Mitigating Systems Cornerstone

a. Inspection Scope

The inspectors verified the accuracy of the licensees PI submittals listed below for the period July 2013 through June 2014. The inspectors used the performance indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Rev. 7, 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.

• Mitigating System Performance Index (MSPI) - Heat Removal System

• MSPI - Cooling Water Systems

• Safety System Functional Failures

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

.1 Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As required by IP 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 CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The review 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. 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. Findings

No findings were identified. In general, the licensee has identified trends and has addressed the trends within their CAP. The inspectors reviewed a trend CAP document, CR-14-05766, documenting problems involving scaffolding contacting plant equipment.

Installed scaffolding contacting sensitive plant components can create adverse conditions during seismic events, or during movement of components during normal system operation. Additionally, scaffolding in close proximity to components may interfere with equipment operation such as the opening of a valve that involves extension of the valve stem that impacts scaffolding located in the stem path. The inspectors noted the following five CRs documented in the trend CR:

• CR-14-05058, NRC Resident Inspector identified that scaffold Tag Number 3887 was in contact with a safety-related pipe support.

• CR-14-05692, During the scaffold walkdown outlined in CR-14-05446 the following scaffold was identified as impacting (touching) plant equipment.

• CR-14-05694, During the scaffold walkdown outlined in CR-14-05446 the following scaffold was identified as impacting (touching) plant equipment.

• CR-14-05695, During the scaffold walkdown outlined in CR-14-05446 the following scaffold was identified as impacting (touching) plant equipment.

• CR-14-05696, During the scaffold walkdown outlined in CR-14-05446 the following scaffold was identified as impacting (touching) plant equipment.

The inspectors noted that CR-14-05446 was a NRC identified issue regarding installed scaffolding for greater than 90 days without a 10 CFR 50.59 evaluation, and that the additional CRs identified did not involve safety-related equipment. The enforcement aspects of NRC-identified scaffold issues were documented in NRC inspection report 05000395/2014007.

The inspectors performed an additional review of scaffolding related CRs in 2014 and noted some additional related problems not included in the trend CR.

• CR-14-02651, PVT08878A (safety injection accumulator A fill inlet valve) - While stroking valve for relative position indication on STP 130.004A when the valve stroked open the top of the valve came in contact with a scaffold pole

• CR-14-05307, Scaffold contacting pipe on TB 412 by low pressure condenser

• CR-14-05484, Scaffolding in IB-412 is built too close to the B Train CCW Discharge Header; there is marking on the pipe that shows the scaffolding was touching the pipe at some point The inspectors discussed the above with the licensee and continue to monitor the licensees scaffolding program and related installations.

.3 Annual Sample Review of CR-14-02746

a. Inspection Scope

The inspectors reviewed CR-14-02746, B EDG Trip on High Coolant Temperature, dated May 15, 2014, in detail to evaluate the effectiveness of the licensees corrective actions for important safety issues. 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, Corrective Action Program, Rev. 11.

b. Findings

No findings were identified. CR-14-02746 was initiated following a trip of the B EDG on high coolant temperature that occurred during a surveillance test in accordance with STP-125.002B, Diesel Generator B Operability Test, Rev. 2E. The inspectors review noted that the EDG had been in operation for approximately 29 minutes before the trip occurred. Additionally, the B train SW pump was not in service prior to start of the EDG because a previously completed surveillance test had secured the pump during the previous shift. The inspectors reviewed the licensees apparent cause evaluation (ACE)and noted the following:

• The cause was adequate SW flow to the EDG was not verified prior to start. The inspectors reviewed STP and noted step 5.2 stated, Diesel Generator B is aligned for automatic operation per SOP-306. The inspectors reviewed system operating procedure, SOP-306, Emergency Diesel Generator, Rev. 19C, and noted step 1.4 of the initial conditions stated, Service Water is operating and aligned to supply the Diesel Generator per SOP-117, and requires a check-off.

• The evaluation of the cause concluded there was

(1) less than adequate situational awarenss by members of the operations crew; and

(2) less than adequate procedural guidance in SOP-306. The licensee stated that the less than adequate procedural guidance was due to SOP-306 not requiring the recording of data. Corrective actions were created for all procedures involving EDG runs to have action steps to ensure SW flow is verified.

• In their extent of condition review, the licensee identified other systems using SW for cooling flow and created corrective actions for reviews to determine any vulnerabilities.

• Corrective actions were created for multiple training requests to ensure operator fundementals are reinforced and this internal operating experience is captured in the various operator training programs.

The inspectors did not have any concerns regarding corrective actions planned or completed. However, the inspectors concluded that SOP-306, step 1.4 was adequate but was not implemented in accordance with TS 6.8.1a which requires that written procedures be implemented covering the activities in Appendix A of Regulatory Guide 1.33, Rev. 2, and that this was a performance deficiency (PD). However, the inspectors determined that the PD was minor because it did not impact a mitigating systems component required for operability in the existing condition of plant status of Mode 6.

Additionally, the inspectors review of the licensees risk program determined that the loss of the B EDG did not result in an increase in their qualitative risk assessment. The inspectors concluded that this failure to comply with TS 6.8.1a constitutes a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy.

4OA3 Event Followup

.1 (Closed) LER 05000395/2013-002-01: Component Cooling System Emergency Makeup

Valve Failed to Stroke Open Rendering Train of Component Cooling Inoperable On October 31, 2012, during a Unit 1 refueling outage surveillance test, the normally closed CCW system emergency makeup valve XVG09627B-CC failed to open. The licensee entered this problem into their CAP under CR-12-05011 and CR-13-00930 and identified that XVG09627B-CC was inoperable for a period of time greater than allowed by Technical Specification 3.7.3, Component Cooling Water System.

After examining the valve during the 2014 refueling outage, the licensee submitted LER 2013-002-01 as a revision to the original LER 2013-002-00 with updated information detailing the causes of the event. The enforcement aspects of the original LER 2013-002-00 were previously processed as an NRC identified Non-Cited Violation (NCV)05000395/2013003-02, which was closed in Inspection Report 05000395/2013003.

Since, the licensees examination in 2014 attributed causes similar to two more recent failures of the XVG09627B-CC and XVG09627A-CC, respectively discussed in Sections 4OA3.2 and 4OA3.3 of this report, the enforcement aspects of LER 2013-002-01 and the two additional LERs will be collectively discussed in Section 4OA7 of this report. This LER is closed.

.2 (Closed) LER 05000395/2014-001-00: Component Cooling System Emergency Makeup

B Valve Failed to Stroke Open Rendering Train of Component Cooling Inoperable On April 14, 2014, during a Unit 1 refueling outage surveillance test, the normally closed CCW system emergency makeup valve XVG09627B-CC failed to open. The licensee entered this problem into their CAP under CR-14-01926 and identified that XVG09627B-CC was inoperable for a period of time greater than allowed by Technical Specification 3.7.3, Component Cooling Water System. In a separate LER 2014-003-00, discussed in Section 4OA3.3 of this report, it was later discovered that the XVG09627A-CC was also inoperable during a concurrent period. Without manual operator action, the licensee determined that XVG09627A and XVG09627B may not have performed their safety function during an event. The enforcement aspects of LER 2014-001-00 will be discussed in Section 4OA7 of this report. This LER is closed.

.3 (Closed) LER 05000395/2014-003-00: Component Cooling System Emergency Makeup

A Valve Failed to Stroke Open Rendering Train of Component Cooling Inoperable On April 26, 2014, during a Unit 1 refueling outage surveillance test, the normally closed CCW system emergency makeup valve XVG09627A-CC failed to open. The licensee entered this problem into their CAP under CR-14-02282 and identified that XVG09627A-CC was inoperable for a period of time greater than allowed by Technical Specification 3.7.3, Component Cooling Water System. In a separate LER 2014-001-00, discussed in Section 4OA3.2 of this report, it was discovered that the XVG09627B-CC was also inoperable during a concurrent period. Without manual operator action, the licensee determined that both XVG09627A and XVG09627B may not have performed their safety function during an event. The enforcement aspects of LER 2014-003-00 will be discussed in Section 4OA7 of this report. This LER is closed.

.4 (Closed) LER 05000395/2014-004-00: Condensate System Bypass Valve Failure and a

Procedure Deficiency Cause Loss of Feedwater and Automatic Reactor Trip On July 22, 2014, Virgil C. Summer Nuclear Station (VCSNS) Unit 1 automatically tripped due to low-low water level in the C SG. The trip occurred following a loss of condensate flow and resultant decrease in deaerator tank level with subsequent main feedwater pump trips.

The inspectors reviewed the LER and noted that the loss of condensate flow occurred during removal of the condensate polishing system from service. When the associated bypass valve failed to open due to a failed solenoid valve, a faulty procedure allowed continuation of the removal process which isolated each of the polishing cells leading to the loss of condensate flow. A review by NRC regional operations licensing inspectors determined that there were no performance deficiencies. Additional information is in Section 4OA5 of this report. This LER is closed.

4OA5 Other Activities

(Closed) URI 05000395/2014004-01, Operator Actions Associated with Unit 1 Automatic Reactor Trip on July 22, 2014 In NRC Integrated Inspection Report 05000395/2014004 the inspectors opened unresolved item (URI)05000395/2014004-01, Operator Actions Associated with Unit 1 Automatic Reactor Trip on July 22, 2014. The inspectors reviewed the associated CAP document, CR-14-04039, and the following two CRs initiated for additional evaluations:

• CR-14-04176, Evaluate the operator response to the failure of XVB09210-WI to open and the subsequent Reactor Trip

• CR-14-04626, Evaluate the operator response to the loss of feedwater and subsequent reactor trip on Lo-Lo steam generator level The inspectors noted that the ACE for CR-14-04176 stated: The procedure provided vague guidance. SOP-203 Section III.F. 2.1.a requires the operator to Place XVB9210-WI, WI System Condensate Bypass Valve Control Switch to Open. The procedure never had the operator verify the valve was open prior to closing the condensate polisher vessel isolation valves. Additionally, the licensee found that the related pre-job brief and supervisory oversight were not adequate and that assumptions were made on how the bypass valve was supposed to operate.

The inspectors noted that the ACE for CR-14-04626 was coverted to a quick cause evaluation which stated that the most probable cause of an automatic reactor trip versus a more conservative manual reactor trip was:

• Less than adequate guidance in abnormal operating procedure (AOP)-214.1, Turbine Trip, for turbine trips occurring due to or in coincidence with a total loss of feedwater flow.

• Less than adequate monitoring of steam generator water levels as they approached 40 percent narrow range.

The inspectors performed an independent review of all of the feedwater/condensate AOPs prior to reviewing CR-14-04174 and CR-14-04626 and noted that, AOP-208.1, Condensate Pump Trip, had been revised on January 13, 2014, to include the following caution, IF at any time during the performance of this procedure, the Deaerator Storage Tank Wide Range level decreases to 4 feet, THEN trip the reactor and GO TO EOP1.0, REACTOR TRIP/SAFETY INJECTION ACTUATION. The inspectors noted the following regarding AOP-208.1:

• The procedure change was communicated to the operating crews via their required reading process and documented complete in March, 2014, in Action 363 of CR-10-00097 which is used to document required reading.

• The caution was added due to simulator validation.

• The caution had not been included in other AOPs as applicable.

• The conditions of the event, loss of condensate flow to the deaerator tank, were similar to a loss of all condensate pumps.

The inspectors reviewed the time line of events and noted that 4 feet in the deaerator storage tank occurred just over 2 minutes prior to the automatic reactor trip.

The circumstances surrounding this reactor trip were reviewed by NRC regional operator licensing inspectors who concluded that the licensees procedures were adequate and that no more than minor PD was identified. This URI is closed.

4OA6 Meetings, Including Exit

On January 29, 2015, the resident inspectors presented the integrated inspection report results to Mr. G. Lippard and other members of the licensee staff. The licensee acknowledged the results of these inspections. The inspectors confirmed that inspection activities discussed in this report did not contain proprietary material.

4OA7 Licensee-Identified Violations

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

10 CFR Part 50 Criterion XVI, Corrective Actions, requires in part that measures be established to assure that conditions adverse to quality are promptly identified and corrected. Contrary to this, the licensee failed to correct the valve packing friction and the degradation of the valve opening springs associated with the SW system outlet header component cooling loop B cross-connect Valve, XVG090627B-CC after the valve failed surveillance testing on October 30, 2012. In addition, the licensee failed to correct this condition adverse to quality during a mini-outage on March 30, 2013. This degraded condition resulted in the failure to stroke open of both valves XVG090627B-CC and XVG09627A-CC during the 2014 refueling outage and resulted in violations of Technical Specifications 4.0.5, Inservice Testing Surveillance, 3.7.3, Component Cooling Water System, and 3.7.4, Service Water System. The conditions adverse to quality were identified by the licensee and entered in the licensees corrective action program as CR-13-00930, CR-14-01926, and CR-14-02282.

The failure to correct a condition adverse to quality related to the service water (SW)system outlet header component cooling water (CCW) system loop cross-connect valves, XVG09627B-CC and XVG09627A-CC was a PD. Both valves XVG09627A-CC and XVG09627B-CC failed surveillance tests and both trains of the CCW system were simultaneously rendered past inoperable during the 2014 refueling outage. The PD was screened in accordance with NRC Inspection Manual Chapter (IMC) 0609.04 and was determined to impact the Mitigating Systems Cornerstone. Significance Determination Process (SDP) screening performed in accordance with NRC IMC 0609, Appendix A, Exhibit 2, determined that the PD represented a loss of system function and required a Detailed Risk Evaluation. A Detailed SDP risk evaluation was performed by a regional SRA in accordance with the guidance of NRC IMC 0609, Appendix A, using the latest NRC Virgil C. Summer SPAR risk model. The major analysis assumptions included:

Both valves considered simultaneously inoperable for a one year exposure period; Random or seismically induced pipe failure in combination with failure of the normal CCW supply, the Demineralized Water (DW) System, would be required to yield a demand for valves XVG09627A/B to open to fill the CCW system; Operator action was credited to identify and isolate leakage and restart the standby CCW train and re-align components per annunciator and abnormal operating procedures; EPRI generic pipe rupture frequency data was utilized. The dominant sequence was a seismic initiator which resulted in a loss of offsite power, loss of the DW system, and seismically induced leakage in the CCW system; failure of the Backup SW fill function due to the PD; failure of the operator to recover the CCW system resulting in a loss of seal cooling which led to a seal loss of coolant accident and core damage. The risk was mitigated by the low probability of the associated rupture initiators and the ability to manually operate the valves or start the alternate CCW train components. The Detailed SDP Risk Evaluation determined that the risk increase due to the PD was an increase in core damage frequency of <1 E-6/year, a GREEN finding of very low safety significance.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

A. Barbee, Director, Nuclear Training

M. Browne, Manager, Quality Systems

M. Coleman, Manager, Health Physics and Safety Services

G. Douglass, Manager, Nuclear Protection Services

T. Gatlin, Vice President, Nuclear Operations

M. Harmon, Manager, Chemistry Services

R. Haselden, General Manager, Organizational / Development Effectiveness

R. Justice, Manager, Nuclear Operations

G. Lippard, General Manager, Nuclear Plant Operations

M. Mosley, Manager, Nuclear Training

S. Reese, Licensing Specialist, Nuclear Licensing

R. Russell, SCE&G Design Engineering

D. Shue, Manager, Maintenance Services

W. Stuart, General Manager, Engineering Services

W. Taylor, Nuclear Licensing Engineer

B. Thompson, Manager, Nuclear Licensing

J. Wasieczko, Manager, Organization Development and Performance

D. Weir, Manager, Plant Support Engineering

B. Wetmore, Design Engineering

R. Williamson, Manager, Emergency Services

S. Zarandi, General Manager, Nuclear Support Services

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Closed

05000395/2013-002-01 LER Component Cooling System Emergency Makeup Valve Failed to Stroke Open Rendering Train of Component Cooling Inoperable (Section 4OA3.1)

05000395/2014-001-00 LER Component Cooling System Emergency Makeup B Valve Failed to Stroke Open Rendering Train of Component Cooling Inoperable (Section 4OA3.2)

05000395/2014-003-00 LER Component Cooling System Emergency Makeup A Valve Failed to Stroke Open Rendering Train of Component Cooling Inoperable (Section 4OA3.3)

05000395/2014-004-00 LER Condensate System Bypass Valve Failure and a Procedure Deficiency Cause Loss of Feedwater and Automatic Reactor Trip (Section 4OA3.4)

05000395/2014-004-01 URI Operator Actions Associated with Unit 1 Automatic Reactor Trip on July 22, 2014 (Section 4OA5)