IR 05000395/2013005

IR 05000395-13-005 & 05000395-13-502; 10/01/2013 - 12/31/2013: Virgil C. Summer Nuclear Station, Unit 1; Other Activities

ML14041A474
Person / Time
Site:	Summer
Issue date:	02/10/2014
From:	Mark King NRC/RGN-II/DRP/RPB5
To:	Gatlin T South Carolina Electric & Gas Co
References
IR-13-005, IR-13-502
Download: ML14041A474 (30)

Text

UNITED STATES bruary 10, 2014

SUBJECT:

VIRGIL C. SUMMER NUCLEAR STATION, UNIT 1 - NRC INTEGRATED INSPECTION REPORT 05000395/2013005 and 05000395/2013502

Dear Mr. Gatlin:

On December 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Virgil C. Summer Nuclear Station, Unit 1. On February 5, 2014, the NRC inspectors discussed the results of this inspection with you and members of your staff.

Inspectors documented the results of this inspection in the enclosed inspection report.

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.

NRC inspectors documented in this report one NRC-identified finding of very low safety significance (Green) and which involved violations of NRC requirements. The NRC is treating the violation as a non-cited violation (NCV) consistent with Section 2.3.2.a of the NRC 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 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, Unit 1.

Additionally, if you disagree with a cross-cutting aspect assignment or a finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at the Virgil C. Summer Nuclear Station, Unit 1. As a result of the Safety Culture Common Language Initiative, the terminology and coding of cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting aspects identified in CY 2014 will be coded under the latest revision to IMC 0310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment review.

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/

Michael King, Chief Reactor Projects Branch 5 Division of Reactor Projects Docket No.: 50-395 License No.: NPF-12

Enclosure:

NRC Integrated Inspection Report 05000395/2013005 w/Attachment: Supplemental Information

REGION II==

Docket No. 50-395 License No. NPF-12 Report No. 05000395/2013005 and 05000395/2013502 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, 2013, through December 31, 2013 Inspectors: J. Reece, Senior Resident Inspector E. Coffman, Resident Inspector R. Williams, Senior Reactor Inspector (Section 1R07)

D. Bacon, Senior Operations Engineer (Section 1R11.3)

J. Laughlin, Emergency Preparedness Inspector (Section 1EP4)

Approved by: Michael King, Chief Reactor Projects Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000395/2013005; 10/01/2013 - 12/31/2013: Virgil C. Summer Nuclear Station, Unit 1;

Other Activities The report covered a three month period of inspection by resident inspectors and three health physicists from the region. One NRC-identified finding was identified and determined to be a Green, non-cited violation (NCV). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). The cross-cutting aspects were 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: Barrier Integrity

• Green: An NRC-identified Green non-cited violation of 10 CFR 50, Appendix B,

Criterion V, Instructions, Procedures, and Drawings,was identified for the licensees failure to prescribe an adequate procedure for control of temporary containment penetration devices. The violation is in the licensees corrective action program as condition report 13-00739.

The inspectors determined that the failure to have an adequate procedure for control of temporary containment penetration devices was a performance deficiency (PD).

The PD is more than minor and therefore a finding because it impacted the barrier integrity cornerstone objective to provide reasonable assurance that physical design barriers such as the containment, protect the public from radionuclide releases caused by accidents or events and the attribute of procedure quality because the affected procedure allowed the use of silicone foam in configurations which did not provide adequate pressure retention capabilities. The inspectors evaluated the finding in accordance with NRC Inspection Manual Chapter 0609, Significant Determination Process, attachment 4, appendix G, and appendix H and determined that an analysis was required by a senior reactor analyst. A regional SRA performed an SDP assessment of this finding. The licensee containment penetration testing and results were reviewed as well as the licensee's risk evaluation. The conclusion was that the finding represented a condition B finding which would only impact large early release fraction (LERF) and not core damage frequency. The test results showed that the finding would not meet the leakage criteria necessary for the finding to be >GREEN per NRC IMC 0609 Appendix H. The conditions necessary to achieve the leakage criteria were determined to be <1E-7 for LERF which represented a GREEN finding of very low safety significance. There are no cross-cutting aspects because the finding was not representative of current licensee performance. (Section 4OA5.2)

REPORT DETAILS

Summary of Plant Status

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

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness

1R01 Adverse Weather Protection

Seasonal Weather Susceptibilities

a. Inspection Scope

The inspectors performed one seasonal extreme weather inspection for readiness of cold weather for two risk significant components. The inspectors verified the licensee had implemented applicable sections of operations administrative procedure (OAP)-

109.1, Revision (Rev.) 3F, Guidelines for Severe Weather. The inspectors reviewed preparations for extreme cold weather and walked down the refueling water storage tank (RWST) and associated outside emergency core cooling system (ECCS) piping and walked down the sodium hydroxide (NaOH) tank and associated outside piping to assess whether the equipment was adequately protected from cold weather and would function as expected during an accident event. Also, the inspectors reviewed the licensees corrective action program (CAP) database to verify that freeze protection problems were being identified at the appropriate level, entered into the CAP, and appropriately resolved.

b. Findings

No findings were identified.

1R04 Equipment Alignment

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 (WO) and related condition reports (CR) to verify that the licensee had properly identified and resolved equipment alignment problems that could lead to the initiation of an event or impact mitigating system availability. Documents reviewed are listed in the Attachment.

• Partial walkdown of B residual heat removal (RHR) train during planned maintenance on A RHR train

• Partial walkdown of B motor driven emergency feedwater (MDEFW) and turbine driven emergency feedwater (TDEFW) components during planned maintenance on A MDEFW pump

• Partial walkdown of A and B MDEFW components during planned maintenance on the TDEFW pump

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 five areas (respective fire zones also noted):

• Charging pump rooms (fire zones AB-1.5, 1.6 and 1.7)

• Control room (fire zones CB-17.1)

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

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

• Intermediate building 412 elevation (fire zones IB-1, IB-2, IB-3, IB-4, IB-5 and IB-27)

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Internal Flooding

a. Inspection Scope

The inspectors reviewed and walked down the control building CB-436 feet, 448 feet and 463 feet elevations regarding internal flood protection features and equipment to determine consistency with design requirements, final safety analysis report (FSAR),and flood analysis documents. Risk significant structures, systems, and components (SSCs) in these areas included the nuclear steam support system (NSSS) relays, NSSS process cabinets, solide state protection system (SSPS) cabinets, and the main control board. 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. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R07 Heat Sink Performance

Triennial Review of Heat Sink Performance

a. Inspection Scope

The inspectors reviewed operability determinations, completed surveillances, vendor manual information, associated calculations, performance test results, and cooler inspection results associated with the service water (SW) pump A motor cooler, the reactor building cooling unit (RBCU) A and the charging/safety injection (SI) pump oil cooler. These heat exchangers/coolers were chosen based on their risk significance in the licensees probabilistic safety analysis, their important safety-related mitigating system support functions and their relatively low margin.

For the SW pump A motor cooler and the RBCU A, the inspectors determined whether testing, inspection, maintenance, and monitoring of biotic fouling and macrofouling programs were adequate to ensure proper heat transfer. This was accomplished by determining whether the test method used was consistent with accepted industry practices, or equivalent, the test conditions were consistent with the selected methodology, the test acceptance criteria were consistent with the design basis values, and reviewing results of heat exchanger performance testing. The inspectors also determined whether the test results appropriately considered differences between testing conditions and design conditions, the frequency of testing based on trending of test results was sufficient to detect degradation prior to loss of heat removal capabilities below design basis values, and test results considered test instrument inaccuracies and differences.

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

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

The inspectors determined whether the performance of ultimate heat sinks (UHS), and their subcomponents such as piping, intake screens, pumps, valves, etc., was appropriately evaluated by tests or other equivalent methods, to ensure availability and accessibility to the in-plant cooling water systems. The inspectors determined whether the licensees inspection of the UHS was thorough and of sufficient depth to identify degradation of the shoreline protection or loss of structural integrity. This included determination whether vegetation present along the slopes was trimmed, maintained, and was not adversely impacted the embankment. In addition, the inspectors determined whether the licensee ensured sufficient reservoir capacity by trending and removing debris, or sediment buildup, in the UHS. The inspectors reviewed the licensees performance testing of service water system and UHS results. This included a review of the licensees performance test results for key components and service water flow balance test results. In addition, the inspectors compared the flow balance results to system configuration and flow assumptions during design basis accident conditions. The inspectors also determined whether the licensee ensured adequate isolation during design basis events, consistency between testing methodologies and design basis leakage rate assumptions, and proper performance of risk significant non-safety related functions.

The inspectors performed a system walkdown on service water and/or closed cooling water systems to determine whether the licensees assessment on structural integrity was adequate. In addition, the inspectors reviewed available licensees testing and inspections results, licensee's disposition of any active thru wall pipe leaks, and the history of thru wall pipe leakage to identify any adverse trends since the last NRC inspection. For closed cooling water systems, the inspectors reviewed operating logs or interviewed operators or system engineer, to identify adverse make-up trends that could be indicative of excessive leakage out of the closed system. For buried or inaccessible piping, the inspectors reviewed the licensee's pipe testing, inspection, or monitoring program to determine whether structural integrity was ensured and that any leakage or degradation was appropriately identified and dispositioned by the licensee.

The inspector performed a system walkdown of the service water intake structure to determine whether the licensees assessment on structural integrity and component functionality was adequate and that the licensee ensured proper functioning of traveling screens and strainers, and structural integrity of component mounts. In addition, the inspectors determined whether service water pump bay silt accumulation was monitored, trended, and maintained at an acceptable level by the licensee, and that water level instruments were functional and routinely monitored. The inspectors also determined whether the licensees ability to ensure functionality during adverse weather conditions was adequate. In addition, the inspectors reviewed condition reports related to the heat exchangers/coolers and heat sink performance issues to determine whether the licensee had an appropriate threshold for identifying issues and to evaluate the effectiveness of the corrective actions. Documents reviewed are listed in the Attachment. These inspection activities constituted four heat sink inspection samples as defined in IP 71111.07-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Resident Quarterly Review of Operator Requalification

a. Inspection Scope

The inspectors observed an operator requalification exam validation occurring on December 2, 2013. The inspectors observed crew performance in terms of communications; ability to prioritize failures in order to take timely and proper actions; prioritizing, interpreting, and verifying alarms; correct use and implementation of procedures, including the alarm response procedures; timely control board operation and manipulation, including high-risk operator actions; and oversight and direction provided by the shift supervisor, including the ability to identify and implement appropriate TS actions and when required, emergency action levels as the Site Emergency Director. The inspectors reviewed the licensees critique comments to verify that performance deficiencies were captured for appropriate corrective action.

b. Findings

No findings were identified.

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

• Observation of B train solid state protection system (SSPS) surveillance test and respective pre-job brief; reactor coolant system (RCS) dilutions

• Observation of alternate seal injection (ASI) performance testing

b. Findings

No findings were identified.

.3 Annual Review of Licensee Requalification Examination Results

a. Inspection Scope

On August 15, 2013, the licensee completed the comprehensive biennial requalification written examinations and 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 and Licensed Operator Performance. The 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 two equipment issues described in the CRs 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-12-01982 and CR-12-05975, steam generator (SG) power operated relief valves (PORVs) in (a)(1) for exceeding reliability criteria

• CR-13-00054 and CR-13-01781, maintenance preventable functional failure of instrument air compressor to pressurizer PORVs exceeds reliability performance criteria and results in (a)(1) status

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 four 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 46, yellow risk condition for Parr 115kV line out of service, A and B emergency alternating current (AC) buses tied to a common source

• Work Week 48, yellow risk condition due to TDEFW planned maintenance

• Work Week 51, yellow risk condition due to ASI being out of service

• Work Week 51, yellow risk condition for scheduled maintenance on A SW pump and associated components

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. 11, Corrective Action Program.

• CR-12-02152, NRC identified PVC based material melted on stainless steel RHR valves and piping, Rev. 1

• CR-13-01027, NRC identified a seimic issue with the B safety-related incoming 7.2 kV breaker cubicle door being open

• CR-13-01755, B train wide range reactor vessel level indication has signs of signal degradation

• NND-AP-0029, Review of control room habitability impact from chemicals used at Units 2 and 3 construction

• CR-13-03468, B component cooling water (CCW) heat exchanger performance degraded

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed one temporary modification and completed review of two permanent plant modifications or engineering change requests (ECR) as noted below 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 FSAR, supporting 10 CFR 50.59 evaluations, TS, and design basis information. The inspectors evaluated the change documents and associated 10 CFR 50.59 reviews against the system design basis documentation and FSAR to verify that the changes did not adversely affect the safety function of safety systems. The inspectors also reviewed any related CRs to confirm that problems were identified at an appropriate threshold, were entered into the CAP, and appropriate corrective actions had been initiated. Other documents reviewed are listed in the attachment.

• WO1300346, Main control room 3-phase display of transformer, XTF31, high side currents for open phase event detection

• ECR-50780, ASI system installation

• ECR-50825, Burial of the Parr 115kV Line Segment

b. Findings

Introduction:

An unresolved item (URI) regarding ECR-50780 was identified by the inspectors for a performance deficiency associated with inadequate post modification testing for the ASI system.

Description:

During the Fall, 2012 refueling outage, the licensee completed ECR-50780 and placed the ASI system in service to provide a backup for reactor coolant pump (RCP) seal injection in the event of a station blackout (SBO) or other events resulting in low normal RCP seal injection flow. The inspectors noted during their review that the ASI system has a mission time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> with no operator action required and consists of a positive displacement pump powered by a dedicated diesel generator, valves,piping, flow transmitters, and other components. The inspectors noted that the RWST provides the suction source, and the discharge of the ASI system ties in to the chemical volume control system (CVCS) upstream of the normal seal water injection filters (SWIFs) of which there are two in parallel, one normally in service and manual operator action required to realign on high differential pressure. The inspectors also noted that the filters used for normal operation are sized at

.1 micron. The inspectors review of post

modification testing identified that the potential clogging of the SWIFs was not considered as an impact on the mission time. The licensee initiated CR-13-000642 for an evaluation and initiated a Special Order for heightened awareness of a SWIF differential pressure annunciator occurring during those events resulting in actuation of the ASI system.

The inspectors also reviewed technical work record (TWR) 14809 dated December 10, 1997, which allowed the use of

.1 micron filters via the licensees equal to - better than

process (ETBT) #157A and respective 50.59 screening. The inspectors determined that the impact of filter clogging during a design basis accident was not considered. The licensee initiated CR-13-01853, to evaluate this problem. Pending completion of evaluations in determining related PDs and their characterization, this issue is identified as URI 05000395/2013005-01, Seal Water Injection Filter Impact on Alternate Seal Injection System and Design Basis Accidents.

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 B.

• WO 1306266-001, remove and replace C SW pump motor bearing cooling spool pieces

• WO 1306139-001, calibrate, leak check and stroke time test B main steam header power operated relief valve

• WO 1313581-001, adjust seal for the inboard bearing on the A CCW pump and verify no external leakage

• WO 1313389-001, retest of A accumulator test line isolation valve following striker and regulator work

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

The inspectors observed and/or reviewed four 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- 205.004, RHR Pump and Valve Operability Test, Rev. 7A

• STP- 205.003, Charging/Safety Injection Pump and Valve Test, Rev. 7, for C SI pump and associated valves Reactor Coolant System:

• STP-114.002, Operational Leakage Calculation, Rev. 12 Other:

• STP-345.074, Solid State Protection System Actuation Logic and Master Relay Test, Train B, Rev. 13A

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

The NSIR headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures (EPIPs) and the Emergency Plan located under ADAMS accession numbers ML13010A516, ML12307A085, ML13207A411, and ML13259A278, as listed in the Attachment.

The licensee determined that in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, these revisions are subject to future inspection. Documents reviewed are listed in the Attachment. This inspection activity satisfied one inspection sample for the emergency action level and emergency plan changes on an annual basis.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

a. Inspection Scope

On November 20, 2013, the inspectors reviewed and observed the performance of an emergency preparedness training drill that involved a hostile attack on the station. The inspectors assessed the emergency procedure usage, emergency plan classifications, notifications, and protective action recommendation development. The inspectors evaluated the adequacy of the licensees conduct of the drill and critique performance.

The inspectors verified that the drill critique identified drill performance weaknesses and entered these items into the licensees CAP. Additional information is also documented in NRC Inspection Report 05000395/2013503.

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Mitigating Systems Cornerstone

a. Inspection Scope

The inspectors verified the accuracy of the licensees PI submittals listed below for the period July 2012 through June 2013. 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. Also, the inspectors discussed the PI data with the licensee personnel associated with the performance indicator data collection and evaluation.

• Mitigating System Performance Index (MSPI) - 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 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 was expanded to include the past two years.

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

In general, the licensee has identified trends and has addressed the trends within their CAP. However, inspectors noted that continued problems have existed with a replacement safety-related chiller on the A train installed in August, 2011. Engineering change request (modification) ECR-50585 was originally initiated to replace both the A and B train chillers and the C chiller capable for alignment to either train. The modification was performed for A train, but delayed, for the other two chillers.

Specifically from August 5, 2011, through November, 2013, the inspectors identified the following CRs involving A chiller trips or failure to start:

• CR-11-04585, Low refrigerant suction pressure trip

• CR-11-05225, Apparent lightning strike on 115kV offsite circuit resulted in trip

• CR-12-02364, Chiller trip on circuit 1 high discharge pressure

• CR-12-05003, Chiller trip on circuit 1 high discharge pressure

• CR-12-05414, Chiller would not start during alternate AC testing

• CR-13-00166, Chiller tripped on circuit 2 low oil level

• CR-13-02694, Circuit 1 pump down cycle time limit exceeded results in trip

• CR-13-03124, Trip due to circuit 2 low suction pressure

• CR-13-03952, Trip due to circuit 2 low oil level The inspectors noted that the A chiller has been on the licensees top plant issues list multiple times as defined in station scheduling procedure, SSP-007, T-Week Planning Process, Revision 6, and the subject of LER 05000395/2013-003-00, Trip Setpoint Renders Chiller and Control Room Emergency Filtration Inoperable. The residents issued a previous Green, NCV 05000395/2012002-06, Failure to Promptly Correct Conditions Adverse to Quality for Lightning Induced Trips of Safety-Related Chillers.

And more recently, the above LER was closed to a Green, NCV 05000395/2013008-01, Failure to Design the Safety-related Chiller Modification to Appropriate Quality Standards, in a recent NRC triennial modification inspection documented in report 05000395/2013008. The inspectors noted the A chiller remains inoperable due to the problem leading to the subject LER and has remained as such pending completion of licensee corrective actions. The inspectors continue to follow the licensees actions to return this component to an operable status.

.3 Annual Sample Review of CR-13-02250

a. Inspection Scope

The inspectors reviewed CR-13-02250, NRC identified a nonconforming condition involving submerged cables in pull box, PB-SG-01, dated May 23, 2013, 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. The inspectors reviewed condition reports as far back as CR-01-00888, dated 2001, which found 8.5 of water in PB-SG-01 and noted that the low voltage instrument cables in the pull box have had a history of being periodically submerged. For each condition report, the inspectors noted the licensee would manually pump the water out of the pull box, but the licensee did not promptly identify and correct the source of the water leak. The inspectors reviewed recent CAP documents and identified the following:

• CR-12-01923 - 2.75 inches of water was found in PB-SG-01

• CR-12-03537 - 2 inches of water was found in PB-SG-01

• CR-12-05355 - 2 inches of water was found in PB-SG-01

• CR-13-02004 - NRC identified no CR was initiated as required by the inspection procedure when

.5 inches of water was found in PB-SG-01

The inspectors determined that the affected cables were not qualified for submergence and that two of the nineteen cables are safety-related. The inspectors also determined that the two safety-related cables are post accident monitoring (PAM) system instrumentation cables for emergency feedwater (EFW) wide-range flow to the B and C steam generators. The inspectors noted that CR-13-02250 states in part: failure of the electric cable would result in unreliable wide range flow indication for EFW system supply to "B" or "C" steam generator, and might potentially result in automatic isolation of the associated flow control valve on indicated high flow.

The inspectors reviewed SAP-999 and concluded that cable submergence is a non-conforming condition as well as a condition adverse to quality. The licensee initiated CR-13-02250 to evaluate and concluded that the two safety-related cables are operable, but degraded or non-conforming. The licensee has written WO 1310529 to perform cable testing during the next refueling outage.

The inspectors noted that 10 CFR Part 50, Appendix B, Criterion XVI states in part that measures shall be established to assure that conditions adverse to quality are promptly identified and corrected. The inspectors concluded that the licensees failure to identify and correct the source of the water impacting the safety-related cables was contrary to the Criterion XVI requirement and therefore a performance deficiency (PD). However, the inspectors also determined that the PD was of minor significance because the cables remained functional based on visual inspection showing no indication of degradation, and the cables instrumentation signals showing no sign of noise.

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) URI 05000395/2012005-05, Adequacy of Temporary Containment Penetration

Design for Shutdown Operations

a. Inspection Scope

The inspectors opened the above URI in NRC integrated inspection report 05000395/2012005 to allow further review of the identified issue of concern to determine any related performance deficiencies and if the significance was more than minor. The inspectors have completed their review of the aforementioned URI which is hereby closed as discussed below.

b. Findings

Introduction:

An NRC-identified Green non-cited violation of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the licensees failure to prescribe an adequate procedure for control of temporary containment penetration devices. The violation is in the licensees corrective action program as condition report 13-00739.

Description:

On October 18, 2012, during the first 8 days of the refueling outage the inspectors noted that the licensee was using Dow Corning 3-6548 silicone foam as a sealant for a temporary containment penetration fixture installed in penetration, XRP-602, allowing cable pass-through during the refueling outage to support various work activities within containment. The inspectors also identified that the licensee was taking credit for this penetration even though the foam had not cured for 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> as required by the vendors installation instructions. The inspectors reviewed licensee operations administrative procedure, OAP-108.4, Operations Outage Control of Containment Penetrations, Revision 1, of which portions stated the following in part:

• Step 2.3: This procedure is governed by 10CFR50 Appendix B

• Step 4.1: Acceptable Alternate - An approved penetration closure device that may be used in place of installed containment integrity equipment in Modes 5 or 6. A temporary sealant such as silicone sealant would be acceptable for use in a spare penetration.

• Step 4.2: Containment Closure - A containment condition in which all penetrations providing Direct Access from the containment atmosphere to the outside atmosphere are closed by at least one automatic isolation valve, blind flange, or manual valve.

• Step 4.3: Containment Penetrations - Those structures which penetrate the Reactor Building containment for the purpose of allowing piping or tubing to pass through the containment wall while still providing a leak tight barrier.

• Step 4.5: Direct Access - A pathway from the containment atmosphere to the outside atmosphere that presents no obstacle to air movement. Obstacles which prevent this movement may include water loop seals, temporary closure devices or system pressure as with the service air, breathing air, fire protection or other plant system.

The inspectors had knowledge of previous problems involving the use of foam for pressure retention and questioned the licensee on the adequacy of their acceptable alternate design. The licensee subsequently performed testing under CR-13-00739 and documented the results in engineering information request, EIR-81980A. Various prototypes were fabricated and testing done at various stages of foam cure times. The inspectors reviewed the results indicating that the foam started leaking with a pressure as low as 2 psig. However, the foam was generally not expelled from the test rig until an average of 5.5 to 8 psig based on multiple tests performed. The testing also showed that failure pressures generally increased as the cure time increased.

The inspectors were also aware of a unit uprate of 2775 MWth to 2900 MWth and reviewed the respective 50.59 evaluation performed for the respective modification, MRF-90102, and identified that the licensee had failed to account for the increased decay heat in a design calculation, DC00020-006, which determined the increase in containment pressure following a loss of RHR. The licensee initiated CR-13-00490 for an evaluation which resulted in an action to revise the calculation. The inspectors noted that while this action has not yet been completed, the licensee performed an approximation for an evaluation to include with the test results documented in EIR-81980A. This resulted in the conclusion that utilizing one RBCU and one high head charging pump, containment pressure would increase to approximately 2.6 psig. The inspectors observed that this pressure would result in leakage through the foam seals, but not a complete ejection of the foam from the conduits.

The inspectors concluded that leakage past the foam seals did not meet the licensees definition of an obstacle that would prevent air movement through a penetration; consequently, OAP-108.4 was inadequate because it allowed the use of silicone sealant.

The inspectors also concluded the licensees failure to consider the unit uprate impact on core decay heat and resulting impact on containment pressure was of minor significance.

Analysis:

The inspectors determined that the failure to have an adequate procedure for control of temporary containment penetration devices in accordance with 10 CFR 50, Appendix B, Criterion V, was a performance deficiency (PD). The PD is more than minor and therefore a finding because it impacted the barrier integrity cornerstone objective to provide reasonable assurance that physical design barriers such as the containment, protect the public from radionuclide releases caused by accidents or events and the attribute of procedure quality because the affected procedure allowed the use of silicone foam in configurations which did not provide adequate pressure retention capabilities. The inspectors evaluated the finding in accordance with NRC Inspection Manual Chapter 0609, Significant Determination Process, attachment 4, appendix G, and appendix H and determined that an analysis was required by a senior reactor analyst. A regional SRA performed an SDP assessment of this finding. The licensee containment penetration testing and results were reviewed as well as the licensee's risk evaluation. The conclusion was that the finding represented a condition B finding which would only impact large early release fraction (LERF) and not core damage frequency.

The test results showed that the finding would not meet the leakage criteria necessary for the finding to be >GREEN per NRC IMC 0609 Appendix H. The conditions necessary to achieve the leakage criteria were determined to be <1E-7 for LERF which represented a GREEN finding of very low safety significance. There are no cross-cutting aspects because the finding was not representative of current licensee performance.

Enforcement:

10 CFR 50, Appendix B, Criterion V requires, in part, that activities affecting quality shall be prescribed by documented procedures of a type appropriate to the circumstances. Contrary to the above, on August 27, 2012, procedure OAP-108.4 did not adequately prescribe the requirements for a temporary containment closure device that resulted in the use of a sealing device which was demonstrated to leak at containment pressures expected following a loss of RHR. This violation is in the licensees corrective action program as CR-13-00739, and is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy: NCV 05000395/2013005-02, Inadequate Procedure for Control of Containment Penetrations.

.3 (Closed) NRC Temporary Instruction 2515/190, Inspection of Proposed Interim Actions

Associated with Near-Term Task Force (NTTF) Recommendation 2.1 Flooding Hazard Evaluations

a. Inspection Scope

The Inspectors verified that the licensees submitted interim actions, associated with the NTTF recommendation 2.1 for flooding hazard evaluations, will perform their intended function for flooding mitigation.

The inspectors conducted an independent verification to confirm the following:

• The procedures or activities can be executed as specified/written, and within available time, if time-dependent.

• Water levels and associated effects, and severe weather conditions would not impair support functions and would not impede performing necessary interim actions

• Equipment availability or staffing issues would not prevent implementation of the interim actions.

• Proposed interim actions do not result in adverse consequences.

Documents reviewed are listed in the Attachment.

b. Findings

The inspectors completed TI-190 but continue to evaluate flooding issues of concern which will be closed to URI 05000395/2013003-01, Modification Leads to Auxiliary Building Flood Vulnerability, in a future report.

4OA6 Meetings, Including Exit

On February 5, 2014, the resident inspectors presented the integrated inspection report results to Mr. T. Gatlin and other members of the licensee staff. The licensee acknowledged the results of these inspections. The inspectors confirmed that inspection activities discussed in this report did not contain proprietary material.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

J. Archie, Senior Vice President, Nuclear Operations

A. Barbee, Director, Nuclear Training

M. Browne, Manager, Quality Systems

M. Coleman, Manager, Health Physics and Safety Services

G. Douglass, Manager, Nuclear Protection Services

T. Gatlin, Vice President, Nuclear Operations

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

D. Perez, Supervisor, Health Physics - Technical Support

S. Reese, Specialist, Nuclear Licensing

J. Rinehart, Supervisor, Health Physics - Field Operations

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

D. Shue, Manager, Maintenance Services

W. Stuart, General Manager, Engineering Services

B. Thompson, Manager, Nuclear Licensing

J. Wasieczko, Manager, Organization Development and Performance

D. Weir, Manager, Plant Support Engineering

B. Wetmore, Design Engineering

R. Williamson, Manager, Emergency Planning

S. Zarandi, General Manager, Nuclear Support Services

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000395/2013005-02 NCV Inadequate Procedure for Control of Containment Penetrations (Section 4OA5.2)

Opened

05000395/2013005-01 URI Seal Water Injection Filter Impact on Alternate Seal Injection System and Design Basis Accidents (Section 1R18)

Closed

05000395/2012005-05 URI Adequacy of Temporary Containment Penetration Design for Shutdown Operations (Section 4OA5.2)

TI 2515/190 TI Inspection of the Licensees Proposed Intermin Actions as a Result of the Near-Term Task Force Recommendation 2.1 Flooding Reevaluation (Section 4OA5.3)

Discussed

05000395/2013003-01 URI Modification Leads to Auxiliary Building Flood Vulnerability (Section 4OA5.3)