IR 05000395/2014003

IR 05000395-14-003; on 04/01/2014 - 06/30/2014: Virgil C. Summer Nuclear Station, Unit 1; Problem Identification and Resolution, and Other Activities

ML14225A404
Person / Time
Site:	Summer  (NPF-012)
Issue date:	08/13/2014
From:	Mark King NRC/RGN-II/DRP/RPB5
To:	Gatlin T South Carolina Electric & Gas Co
References
IR-14-003
Download: ML14225A404 (53)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION ust 13, 2014

SUBJECT:

VIRGIL C. SUMMER NUCLEAR STATION, UNIT 1 - NRC INTEGRATED INSPECTION REPORT 05000395/2014003

Dear Mr. Gatlin:

On June 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Virgil C. Summer Nuclear Station, Unit 1. On July 29, 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 two NRC-identifed findings of very low safety significance (Green),

in this report. One of these findings involved a violation of NRC requirements. Further, inspectors documented a licensee-identified violation which was determined to be of very low safety significance. The NRC is treating these violations as non-cited violation (NCVs)

consistent with Section 2.3.2.a of the NRC Enforcement Policy.

If you contest the violation or significance of the NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the United States Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001, with copies to the Regional Administrator, Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the Virgil C. Summer Nuclear Station, 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. 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 05000395/2014003 w/Attachment: Supplemental Information

REGION II==

Docket No. 50-395 License No. NPF-12 Report No. 05000395/2014003 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: April 1, 2014, through June 30, 2014 Inspectors: J. Reece, Senior Resident Inspector E. Coffman, Resident Inspector P. Cooper, Reactor Inspector (Section 4OA.5)

R. Hamilton, Senior Health Physicist (Sections 2RS2, 4OA1.2, 4OA1.3)

R. Kellner, Health Physicist (Section 2RS5)

J. Rivera, Health Physicist (Sections 2RS1, 2RS3, 2RS4)

A. Sengupta, Reactor Inspector (Section 1R08)

J. Rivera-Ortiz, Senior Reactor Inspector (Section 1R08)

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

SUMMARY

IR 05000395/2014003; 04/01/2014 - 06/30/2014: Virgil C. Summer Nuclear Station, Unit 1;

Problem Identification and Resolution, and Other Activities The report covered a three-month period of inspection by resident inspectors, three health physicists and three reactor inspectors from the region. Two NRC-identified findings were identified; one was characterized as a Green, non-cited violation (NCV) and the other as a Green finding (FIN). The significance of most findings is indicated by their color (Green, White,

Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011. The cross-cutting aspects were determined using IMC 0310, Components Within the Cross Cutting Areas, dated December 19, 2013. Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated July 9, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 5.

Cornerstone: Barrier Integrity

Green.

An NRC-identified NCV of 10 CFR 50, Appendix B, Criterion V, "Instructions,

Procedures, and Drawings," was identified for the licensees failure to accomplish a general test procedure, GTP-302, requirement to determine the cause and correct the conditions leading to two failures of reactor building spray system relief valve, XVR03026-SP. The licensee entered the problem into their corrective action program (CAP) as condition report (CR) 14-03079.

The licensees failure to accomplish GTP-302 to determine and correct the cause of failures occurring in 2006 and 2012 was a performance deficiency (PD) which was within their ability to foresee and correct based on the available vendor documentation. The inspectors reviewed IMC 0612, Power Reactor Inspection Reports, Appendix B, and determined the PD was more than minor and therefore a finding, because it affected the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers such as containment protect the public from radionuclide releases caused by accidents or events and the respective attribute of human performance because the availability and reliability of XVR03026-SP was not ensured by a failure to accomplish procedure requirements to determine the cause of two previous failures and correct. The inspectors evaluated the finding in accordance with NRC IMC 0609, Significant Determination Process, attachment and appendix A, and determined that the finding was of very low safety significance,

Green, because it did not represent an actual physical open pathway in containment. The inspectors reviewed IMC0310, Aspects Within the Cross-cutting Areas, and determined the cause of the finding involved the cross-cutting area of problem identification and resolution and the respective aspect of complete and thorough evaluation, P.2, because the licensee failed to determine the cause of the relief valve failures for adequate corrective actions.

(Section 4OA2.4)

Cornerstone: Mitigating System

Green.

An NRC-identified FIN was identified for the failure of the licensee to accomplish station procedures for development, review, and performance of adequate post modification testing of the alternate seal injection (ASI) system. The problem is in the licensees CAP as CR 13-00642.

The inspectors determined that the failure to accomplish station procedures to develop, review and implement adequate post modification testing in accordance with station procedures was a PD, and was within the licensees ability to foresee and correct based on their existing knowledge of ASI designs at other plants. The inspectors reviewed IMC 0612 and determined the PD is more than minor and therefore a finding because if left uncorrected it would have the potential to result in a more significant safety event.

Specifically, loss of the ASI system would lead to a reactor coolant pump seal loss of coolant accident during those events involving a loss of normal seal cooling such as a station blackout or fire. The inspectors reviewed IMC 0609, Attachment 4 and Appendix A, for the significance determination and determined the finding was of very low safety significance, or Green, because it did not involve a design deficiency and was not an actual loss of function. The inspectors reviewed IMC 0310 for cross-cutting aspects and determined the cause of the finding involved the area of human resources and the aspect of H.11, challenge the unknown, because the licensee did not identify the appropriate post modification testing when using a, first-for-the-station, ASI design. (Section 4OA5.1)

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

REPORT DETAILS

Summary of Plant Status

The unit began the inspection period at Rated Thermal Power (RTP) and operated at or near RTP until the start of a refueling outage on April 5, 2014. Unit 1 returned to service on May 31, 2014, and continued on line for the remainder of the quarter at or near RTP.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

.1 Offsite and Alternate Alternating Current (AC) Power

a. Inspection Scope

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

b. Findings

No findings were identified.

.2 Seasonal Weather Susceptibilities

a. Inspection Scope

The inspectors performed one adverse weather inspection for readiness of hot weather conditions and walked down two safety-related areas, emergency diesel generators (EDGs) and service water (SW) pump house, to verify the proper operation of cooling systems for these areas. Specifically, the inspectors verified the licensee had implemented applicable sections of operations administrative procedure (OAP)-109.1, Revision (Rev.) 3, Change C, Guidelines for Severe Weather. Additionally, the inspectors reviewed licensee plant computer data associated with the aforementioned areas to ensure that temperatures were within their expected operational range to prevent any challenge to equipment operation. The inspectors also verified the licensee took appropriate actions for temperatures exceeding administrative limits. The inspectors reviewed the licensees CAP database to verify that high temperature weather related problems were being identified at the appropriate level, entered into the CAP, and appropriately resolved. Other documents reviewed are listed in the

.

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 (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 B train emergency core cooling system (ECCS) due to A train chilled water system (VU) non-functional during A chiller troubleshooting

• Partial walkdown of B motor driven emergency feedwater (MDEFW) and turbine driven emergency feedwater (TDEFW) during inoperability of the A MDEFW pump

• Partial walkdown of B EDG during tagout of A EDG for planned work on a 51V relay

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 six areas (respective fire zones also noted):

• Turbine building (fire zone TB-1)

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

• Auxiliary building switchgear room (fire zone AB-1.10)

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

• Reactor building (fire zone RB-1.2)

• Diesel Generator Rooms A and B (fire zones DG-1.1, 1.2, 2.1 and 2.2)

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Internal Flooding

a. Inspection Scope

The inspectors reviewed and walked down the EDG building regarding internal flood protection features and equipment to determine consistency with design requirements, Updated Final Safety Analysis Report (UFSAR), and flood analysis documents. Risk significant structures, systems, and components (SSCs) in these areas included the EDGs and related support components. 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.

1R08 Inservice Inspection Activities

a. Inspection Scope

Non-Destructive Examination Activities and Welding Activities: From April 14, 2014, through April 25, 2014, the inspectors conducted an onsite review of the implementation of the licensees inservice inspection (ISI) program for monitoring degradation of the reactor coolant system, emergency feedwater systems, risk-significant piping and components, and containment systems in Unit 1. The inspectors activities included a review of non-destructive examinations (NDEs) to evaluate compliance with the applicable edition of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (BPVC),Section XI (Code of Record: 2007 Edition with 2008 Addenda; first outage, first period of the fourth interval; IWE with 2001 Edition with 2003 Addenda; first outage, third period of second interval), and to verify that indications and defects (if present) were appropriately evaluated and dispositioned, in accordance with the requirements of the ASME Code,Section XI, acceptance standards.

The inspectors directly observed the following NDEs mandated by the ASME Code to evaluate compliance with the ASME Code Section XI and Section V requirements, and if any indications and defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

• Ultrasonic Testing (UT) on drainline / RCS, Work Order 1309893-027

• Visual Testing (VT)-2 on drainline / RCS, Work Order 1309893-027

• Penetrant Testing (PT) on Residual Heat (RH) Heat Exchanger A tube side vent valve, Work Order 1205870-001 The inspectors reviewed records of the following NDEs mandated by the ASME Code to evaluate compliance with the ASME Code Section XI and Section V requirements, and if any indications and defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

• UT on drainline / RCS, Work Order 1309893-027

• VT-2 on drainline / RCS, Work Order 1309893-027

• PT on RH Heat Exchanger A tube side vent valve, Work Order 1205870-001

• PT on control rod drive mechanism (CRDM) penetration latch housing DM Weld, Work Order 1200461-016

• UT on weld CGE-1-4304-2 (C loop letdown line), Work Order 1200465-020

• VT-2 on weld CGE-1-4308-3 and -4 (C loop letdown line), Work Order 1200465-025

• VT-2 on BMI Nozzles (N-722-1), Work Order 1200461-020 The inspectors observed the welding activities referenced below and reviewed associated documents in order to evaluate compliance with procedures and the ASME Code. The inspectors reviewed the work order, including the weld data sheets, welding procedures, procedure qualification records, and welder performance qualification records.

• Work Order 1205870-001, RH Heat Exchanger A tube side vent valve , Class 2 In addition, the inspectors reviewed the following work orders for the weld packages, including weld data sheets, welding procedures, procedure qualification records, and welder performance qualification records.

• Work Order 1108125-001, Welding of Cold Leg Injection Header Vent Valve, ASME Class 2

• Work Order 1205870-001, Welding of RH Heat Exchanger A tube side vent valve, Class 2 During non-destructive surface and volumetric examinations performed since the previous refueling outage, the licensee did not identify any relevant indications that were analytically evaluated and accepted for continued service. Therefore, no NRC review was completed for this inspection procedure attribute.

Pressurized Water Reactor Vessel Upper Head Penetration Inspection Activities: For the Unit 1 vessel head, a bare metal visual (BMV) examination was required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D). The inspectors observed portions of the Unit 1 BMV and ultrasonic (UT) examinations and reviewed NDE records for all penetrations for the BMV and penetration Nos. 37, 19, 31, 52, 51, 9, 27, and 43 for the UT examinations, to evaluate if the activities were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). In particular, the inspectors evaluated if the required visual examination and UT examination scope/coverage was achieved and limitations (if applicable) were recorded, in accordance with the licensee procedures. Additionally, the inspectors evaluated if the licensees criteria for visual and UT examination quality and instructions for resolving interference and masking issues were consistent with 10 CFR 50.55a.

The inspectors reviewed records of welded repairs on upper head penetrations 9, 43, 51, 15, and 22 completed during the current outage, to evaluate if the licensee applied the pre-service NDEs and acceptance criteria required by the NRC-approved Code relief request, and the ASME Code Section XI. In addition, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to evaluate if the weld procedure(s) used were validated, in accordance with the Construction Code and the ASME Code Section IX requirements.

The inspectors reviewed failure of the top flange of reactor vessel head (RVH)part-length thermal sleeves and the licensees associated corrective actions. The licensee identified a total of four part-length thermal sleeves which appeared to have been affected by the failure mechanism. During a robotic UT inspection of the reactor vessel CRDM nozzles, the part-length thermal sleeve at location #18 fell out of its penetration after a minor impact with the J-groove weld inspection equipment. The licensee found that the failure was caused by flow-induced movement, and resulting mechanical wear through of the thermal sleeve top flange which hangs from the top of the CRDM head penetration. The licensee completed inspections with a laser scan, robotic camera, and boroscope to determine if there were any issues with the other thermal sleeves. The inspection results showed that three additional part-length thermal sleeve had moved (#21 -1/4 inch, #20 - 1/2 inch, and #1 - 3 1/2 inch movement). In addition, the thermal sleeve at penetration #1 showed a drop distance greater than what would be expected for a sleeve with a flange still intact. Based on licensee evaluations of the thermal sleeve degradation for penetrations #1 and #18, the licensee designed and installed a 'cap' on the bottom of the penetrations with part-length thermal sleeves to ensure portions of the thermal sleeves remaining in the penetrations do not escape into the RVH upper head area as loose parts. The design of the cap will allow for reactor coolant communication between the upper head plenum and the penetration housing, permit access to the penetration housing for J-groove weld inspection/repair while ensuring no impact to the structural integrity or dynamic response of associated components, such as the penetration housing and J-groove weld.

Boric Acid Corrosion Control Inspection Activities: The inspectors reviewed the licensees boric acid corrosion control (BACC) program activities to ensure implementation with commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary, and applicable industry guidance documents. Specifically, the inspectors performed an onsite record review of procedures and the results of the licensees containment walkdown inspections performed during the current spring refueling outage (RF21). The inspectors also interviewed the BACC program owner, conducted an independent walkdown of containment to evaluate compliance with licensees BACC program requirements, and verified that degraded or non-conforming conditions, such as boric acid leaks, were properly identified and corrected in accordance with the licensees BACC and corrective action programs (CAPs).

The inspectors reviewed the following condition reports (CRs) and associated corrective actions related to evidence of boric acid leakage to evaluate if the corrective actions completed were consistent with the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B, Criterion XVI.

• 13-01333, Boric Acid Leak of Reactor Cavity Drain Liner Drain Isolation Valve

• 13-01297 Boric Acid Residue in RH Inlet Header Relief Valve

• 14-01585 Boric Acid Leak in Test Connection Leak The inspectors reviewed the following engineering evaluations completed for evidence of boric acid leakage to determine if degraded components were documented in the CAP. The inspectors also evaluated corrective actions for any degraded components to determine if they met the ASME Section XI Code.

• 13-01301 Boric Acid Leak Evaluation of Excess Letdown Heat Exchanger

• 13-01880 Boric Acid Leak Evaluation of RH Pump A Suction Header Drain Valve

• 13-01295 Boric Acid Leak Evaluation of Reactor Coolant Drain Tank Heat Exchanger Steam Generator Tube Inspection Activities: The inspectors reviewed the eddy current (EC) examination activities performed in Unit 1 steam generators (SGs) A, B, and C during the End-of-Cycle 21 refueling outage to verify compliance with the licensees Technical Specifications, ASME BPVC Section XI, and Nuclear Energy Institute (NEI)97-06, Steam Generator Program Guidelines. The inspectors interviewed licensee personnel and vendor staff responsible for the SG inspection project, and reviewed documentation associated with the SG inspections and integrity assessments as described further in this report section.

The inspectors reviewed the scope of the EC examinations to verify that known and potential areas of tube degradation were inspected. The inspectors also verified that inspection scope expansion criteria were implemented based on inspection results as directed by the Electric Power Research Institute (EPRI) Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7.

The inspectors reviewed documentation for a sample of EC data analysts, EC probes, and EC testers to verify that personnel and equipment were qualified to detect the existing and potential degradation mechanisms applicable to VC Summer SG tubes, in accordance with the EPRI Examination Guidelines. This review included a sample of site-specific Examination Technique Specification Sheets (ETSSs) that were selected based on plant-specific and industry operating experience, to ensure that their qualification and site-specific implementation were consistent with Appendix H or I of the EPRI Examination Guidelines. The selected ETSSs for review consisted of bobbin and rotating probe techniques that were used to detect wear at the tube interface with support structures (i.e., tube support plates, anti-vibration bar (AVB), and flow distribution baffle plate), and wear associated with foreign objects.

The inspectors also reviewed a sample of EC data with a qualified data analyst to confirm that data analysis was performed in accordance with the applicable ETSSs and site-specific analysis guidelines. The inspectors verified that the equipment configuration was consistent with the essential parameters of the applicable technique.

The inspectors also verified that recordable indications were detected and sized in accordance with vendor procedures. As part of the EC data review, the inspectors verified that the EC indications on each selected tube were consistent with historical data relative to the number of indications, location, and size. The sample of EC data selected for review is listed below:

Steam Tube Eddy Current Indication Type Generator Row/Column Probe C R32/C89 Bobbin Distorted Support Signal C R110/C73 Bobbin Distorted Support Signal C R9/C52 Bobbin Distorted Support Signal C R52/C19 Rotating Probe Wear C R30/C137 Rotating Probe Wear The inspectors selected a sample of degradation mechanisms (i.e., wear at tube support plates and AVBs) from the Unit 1 Steam Generator Degradation Assessment and verified that the in-situ pressure testing criteria were determined in accordance with the EPRI Tube Integrity Guidelines. Additionally, the inspectors reviewed EC indication reports to determine whether tubes with relevant indications were appropriately screened for in-situ pressure testing.

The inspectors compared the recent EC examination results with the last Condition Monitoring and Operational Assessment report for Unit 1 SGs to assess the licensees prediction capability for maximum tube degradation and number of tubes with indications. The inspectors verified that the licensees evaluation was conservative and that current examination results were bound by the Operational Assessment projections.

The inspectors also compared past examination results discussed in the latest Degradation Assessment with the recent EC examination results to verify that new degradation mechanisms, if any, were identified and evaluated before plant startup. The review of EC examination results included the disposition of potential loose part indications on the SG secondary side to verify that corrective actions for evaluating and retrieving loose parts were consistent with the EPRI Guidelines. The inspectors also reviewed a sample of primary-to-secondary leakage data for Unit 2 to confirm that operational leakage in all SGs remained below the action level threshold during the previous operating cycle.

Based on the review of the final EC examination results for all SGs and interviews with the licensee, the inspectors confirmed that no EC scope expansion was required, and none of the SG tubes examined met the criteria for plugging or in-situ pressure testing.

Furthermore, the inspectors interviewed licensee staff and reviewed a sample of secondary side visual inspection results for the SG C main steam nozzle and feedwater ring, to verify that potential areas of degradation based on site-specific operating experience were inspected, and appropriate corrective actions were taken to address degradation indications. This review included the results of Foreign Object Search and Retrieval (FOSAR) activities in all SGs and an evaluation for loose parts in the secondary side of SG A.

Identification and Resolution of Problems: The inspectors performed a review of a sample of ISI-related problems that were identified by the licensee, and entered into the CAP as CRs. The inspectors reviewed the CRs to confirm the licensee had appropriately described the scope of the problem and had initiated adequate corrective actions. The CRs selected for review also included the licensees assessment of applicable operating experience information. The inspectors performed these reviews to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, and applicable ASME Code requirements. The corrective action documents reviewed by the inspectors are listed in the report Attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

.1 Resident Quarterly Review of Operator Requalification

a. Inspection Scope

The inspectors observed an operator requalification training exam scenario occurring on June 23, 2014, which involved multiple component failures subsequently requiring entry into their emergency procedures. The specifics are withheld due to exam security requirements. 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 three 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 actions in response to entering TS action for quadrant power tilt ratio exceeding the limit

• Review of operator activities associated with unit shutdown and main turbine overspeed trip test

• Review of operator activities regarding reactor core off-load and problem with refueling bridge manipulator crane

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors evaluated two equipment issues described in the CRs listed below to verify the licensees effectiveness with the corresponding preventive or corrective maintenance associated with SSCs. The inspectors reviewed Maintenance Rule (MR)implementation to verify that component and equipment failures were identified, entered, and scoped within the MR program. Selected SSCs were reviewed to verify proper categorization and classification in accordance with 10 CFR 50.65. The inspectors examined the licensees 10 CFR 50.65(a)(1) corrective action plans to determine if the licensee was identifying issues related to the MR at an appropriate threshold and that corrective actions were established and effective. The inspectors review also evaluated if maintenance preventable functional failures 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-14-03191, Maintenance Rule (a)(1) goal setting is established on the component cooling system due to failures of XVG09627A/B-CC

• CR-14-03037, Maintenance Rule inspection of the reactor building structure during RF-21

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 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.

• Yellow risk condition for alignment of B spent fuel pump to alternate power as a risk management action for refueling outage activities

• Yellow risk condition for reactor coolant system (RCS) drained to lowered inventory status to support reactor vessel (RV) head removal activities

• Yellow risk condition for power availability during activities involving emergency bus 1DA and switchgear 1DX

• Yellow risk condition for RCS drained to lowered inventory to support RV head installation

• Yellow risk condition for A EDG removed from service for planned relay maintenance

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-13-01372, XVR03026-SP, bonnet relief valve for B reactor building spray containment isolation valve did not pass leak rate test

• CR- 13-05139, SW pond RBCU 1A and ZA return isolation valve operability during a safety injection (SI) assuming slow valve closure

• CR-14-02746, B EDG trip on high jacket water temperature following loaded operation with no service water cooling

• CR-14-01926, B component cooling water (CCW) past operability evaluation following failure of the associated SW-CCW cross-connect valve to open during testing

• CR-14-01807, non-conforming condition relating to spacer grids in fuel assemblies

b. Findings

The enforcement aspects associated with CR-13-01372 are discussed in Section 4OA2.4 of this report.

1R18 Plant Modifications

a. Inspection Scope

The inspectors reviewed one procedure controlled temporary modification associated with A and B spent fuel pumps temporary power and one permanent modification for engineering change request (ECR) 50800, NFPA 805 - new 1DX 7.2 kv feed to 1DA 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 CAP, and appropriate corrective actions had been initiated.

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

For the six maintenance activities listed below, the inspectors reviewed the associated post-maintenance testing (PMT) procedures and either witnessed the testing and/or reviewed test records to assess whether: 1) the effect of testing on the plant had been adequately addressed by control room and/or engineering personnel; 2) testing was adequate for the maintenance performed; 3) test acceptance criteria were clear and adequately demonstrated operational readiness consistent with design and licensing basis documents; 4) test instrumentation had current calibrations, range, and accuracy consistent with the application; 5) tests were performed as written with applicable prerequisites satisfied; 6) jumpers installed or leads lifted were properly controlled; 7) test equipment was removed following testing; and, 8) equipment was returned to the status required to perform its safety function. The inspectors verified that these activities were performed in accordance with general test procedure (GTP)-214, Post Maintenance Testing Guideline, Rev. 5, Change B.

• WO 1303823-001, motor operated valve actuator testing (MOVAT) test of control rod drive mechanism (CRDM) cooling water inlet containment isolation valve following torque setting adjustment

• WO 1404764-002/5, Intermittent loading of vital inverter, XIT5903

• WO 1307878-001, retest for SW system outlet header to B CCW cross connect valve following valve work

• WO 1307909-001, retest for SW booster pump discharge valve following valve work

• WO 1405102-001, disassemble and replace parts for steam generator B TDEFW pump supply header

• WO 1402807-001, troubleshoot and repair cause of intermittent fail indications on steam line high range gamma monitor

b. Findings

No findings were identified.

1R20 Refueling Outage and Other Outage Activities

a. Inspection Scope

On April 5, 2014, the unit was shut down to commence refueling outage (RF)-21. The outage was completed on May 31, 2014. The inspectors used inspection procedure (IP)71111.20, Refueling and Outage Activities, to complete the inspections described below.

Documents reviewed are listed in the Attachment.

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

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

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

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

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

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

• Spent Fuel (SF) cooling operations to verify that outage work was not impacting the ability of the operations staff to operate the SF cooling system during and after core offload. The inspectors also reviewed the licensees calculation results of SF and reactor vessel heat up rates in case of a potential loss of cooling event

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

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

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

• Plant shutdown activities

• Decay heat removal system operations

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

• Electrical power availability controls

• Reactivity controls

• Reactor vessel defueling and refueling operations

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

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

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

In-Service Tests:

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

13D

• STP-203.006A, ECCS/Charging Pump Operability Testing, Rev. 8A

• STP-130.003A, Emergency Feedwater Check Valve Testing, Rev. 3B Containment Isolation Valve (CIV):

• STP-215.002A, Containment Isolation Valve Leakage Test for the AH, SA, IA and NG Systems, Rev. 6 Other

• STP-125.013A, Diesel Generator A Semiannual Operability Test, Rev. 1

• STP-125.021, Periodic Testing of the Alternate AC Power Supply, Rev. 3

b. Findings

No findings were identified.

RADIATION SAFETY

[RS]

2RS1 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

Hazard Assessment and Instructions to Workers During facility tours, the inspectors directly observed labeling of radioactive material and postings for radiation areas, high radiation areas (HRAs), and airborne radioactivity areas established within the radiologically controlled area (RCA) of the auxiliary building and radioactive waste (radwaste) processing and storage locations. The inspectors independently measured radiation dose rates or directly observed conduct of licensee radiation surveys for selected RCA areas. The inspectors reviewed survey records for several plant areas including surveys for alpha emitters, airborne radioactivity, gamma surveys with a range of dose rate gradients, and pre-job surveys for several U1RFO21 (Unit 1 Refueling Outage 21) outage tasks, including fuel handling machine gripper preventive maintenance, reactor head inspections, and steam generator eddy current robot installations. The inspectors also discussed changes to plant operations that could contribute to changing radiological conditions since the last inspection. For selected work activities, the inspectors observed HRA pre-job briefings and reviewed radiation work permit (RWP) details to assess communication of radiological control requirements and current radiological conditions to workers.

Hazard Control and Work Practices The inspectors evaluated access barrier effectiveness for selected Locked High Radiation Area (LHRA) locations and discussed changes to procedural guidance for LHRA and Very High Radiation Area (VHRA)controls with health physics (HP) supervisors. The inspectors observed and evaluated controls for the storage of irradiated material within the spent fuel pool (SFP).

Established radiological controls (including airborne controls) were evaluated for selected work activities. In addition, the inspectors reviewed and discussed licensee controls for areas where dose rates could change significantly.

Through direct observations and interviews with licensee staff, the inspectors evaluated occupational workers adherence to selected RWPs and HP technician (HPT) proficiency in providing job coverage. Electronic dosimeter (ED) alarm set points and worker stay times were evaluated against area radiation survey results for selected U1RFO21 work activities. The inspectors reviewed the use of personnel dosimetry (extremity dosimetry and multibadging in high dose rate gradients) for the reactor head inspection work completed during U1RFO21. The inspectors also evaluated worker response to dose and dose rate alarms during selected work activities.

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

Problem Identification and Resolution The inspectors reviewed CAP documents associated with radiological hazard assessment and exposure control. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with Station Administrative Procedure SAP-0999, Corrective Action Program, Rev. 11.

The inspectors evaluated radiation protection activities against the requirements and guidance of the UFSAR Chapter 12; TS Sections 6.8 Procedures and Programs, 6.11 Radiation Protection, and 6.12 High Radiation Areas; 10 CFR Parts 19 and 20; Regulatory Guide (RG) 8.38, Control of Access to High and Very High Radiation Areas in Nuclear Power Plants; and approved licensee procedures. Licensee programs for monitoring materials and personnel released from the RCA were evaluated against 10 CFR Part 20 and IE Circular 81-07, Control of Radioactively Contaminated Material.

Documents reviewed are listed in Section 2RS1 of the report Attachment.

The inspectors completed one sample as required by IP 71124.01 (sample size of 1).

b. Findings

No findings were identified.

2RS2 As Low As Reasonably Achievable (ALARA)

a. Inspection Scope

ALARA Program Status. The inspectors reviewed and discussed plant exposure history and current trends including the sites three-year rolling average (TYRA) collective exposure history for calendar year (CY) 2010 through CY 2012. Current and proposed activities to manage site collective exposure and trends regarding collective exposure were evaluated through review of previous TYRA collective exposure data and review of the licensees 5-year ALARA program implementing plan. Current ALARA program guidance and recent changes, as applicable, regarding estimating and tracking exposure were discussed and evaluated.

Radiological Work Planning The inspectors reviewed planned work activities and their collective exposure estimates for U1RFO21 (Unit 1 Refueling Outage 21) work activities including the reactor vessel head inspection, refueling activities, and steam generator eddy current testing. For the selected tasks, the inspectors reviewed dose mitigation actions and the established dose goals. The use of remote technologies including teledosimetry and remote visual monitoring were reviewed as specified in RWP or procedural guidance. Collective dose data for selected tasks were compared with estimates and, where applicable, changes to established estimates were discussed with responsible licensee ALARA planning representatives. The inspectors reviewed previous post-job reviews conducted for the U1RFO21 tasks and reviewed items entered into the licensees CAP and referred to the ALARA Committee for evaluation.

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

Source Term Reduction and Control The inspectors reviewed historical dose rate trends for shutdown chemistry, cleanup, and resultant chemistry and RP trend-point data against the recent U1RFO21 data. The inspectors reviewed the correlation of the exposure trends to the various exposure reduction initiatives taken over the years with historical data and discussed with licensee staff.

Radiation Worker Performance The inspectors observed briefings at the RCA control point and interviewed workers and HPTs for understanding and awareness of the sites current ALARA campaign. In interviews with HPTs, the inspectors evaluated their understanding of their role in the use of remote technologies to reduce dose including teledosimetry and remote visual monitoring. The inspectors observed remote coverage of dye penetrant testing on penetrations into the lower surface of the reactor head, setup and subsequent maintenance on eddy current equipment. Used fuel inspection was also observed briefly. Radiation worker performance was also evaluated as part of IP 71124.01.

Problem Identification and Resolution The inspectors reviewed and discussed selected CAP documents associated with ALARA program implementation. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with licensee procedure SAP-0999, Corrective Action Program, Rev. 11. The inspectors also evaluated the scope and frequency of the licensees self-assessment program and reviewed recent assessment results.

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

The inspectors completed one sample as required by IP 71124.02 (sample size of 1).

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

a. Inspection Scope

Engineering Controls The inspectors reviewed the use of temporary and permanent engineering controls to mitigate airborne radioactivity in the control room and auxiliary building, and during seal table room thimble removal activities. The inspectors evaluated the effectiveness of continuous air monitors and air samplers placed in work area breathing zones to provide indication of increasing airborne levels.

Respiratory Protection Equipment The inspectors reviewed the use of respiratory protection devices to limit the intake of radioactive material. This included review of devices used for routine tasks and devices stored for use in emergency situations. The inspectors discussed ALARA evaluations with licensee staff for the use of respiratory protection devices. Selected Self-Contained Breathing Apparatus (SCBA) units and negative pressure respirators (NPRs) staged for routine and emergency use in the Main Control Room and other locations were inspected for material condition, SCBA bottle air pressure, number of units, and number of spare masks and air bottles available. The inspectors reviewed maintenance records for selected SCBA units and evaluated SCBA and NPR compliance with National Institute for Occupational Safety and Health certification requirements. The inspectors also reviewed records of air quality testing for supplied-air devices and SCBA bottles.

The inspectors reviewed the process for issuing respiratory protection devices to workers, including verification of training and medical qualifications. The inspectors discussed fit testing procedures for NPR and SCBA masks and training curricula for SCBA bottle change-outs with licensee staff. The inspectors also evaluated the use of corrective lens inserts for masks. Respirator qualification records and medical fitness records were reviewed for selected personnel. In addition, qualifications for individuals responsible for testing and repairing SCBA vital components were evaluated through review of training records.

Problem Identification and Resolution CRs associated with airborne radioactivity mitigation and respiratory protection were reviewed and assessed. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with Station Administrative Procedure SAP-0999, Corrective Action Program, Rev. 11.

Licensee activities associated with the use of engineering controls and respiratory protection equipment were reviewed against 10 CFR Part 20; UFSAR Chapter 12; the guidance in Regulatory Guide 8.15, Acceptable Programs for Respiratory Protection; and applicable licensee procedures. Documents reviewed are listed in Sections 2RS1 and 2RS3 of the report Attachment.

The inspectors completed one sample as required by IP 71124.03 (sample size of 1).

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

a. Inspection Scope

External Dosimetry: The inspectors reviewed the licensees National Voluntary Accreditation Program (NVLAP) certification data for accreditation for 2013-2014 Ionizing Radiation Dosimetry. The inspectors reviewed program procedures for processing active personnel dosimeters (ED)s and onsite storage of Thermo Luminescent Dosimeters (TLDs). Comparisons between ED and TLD results, including correction factors, were discussed in detail. The inspectors also reviewed dosimetry occurrence reports regarding alarming dosimeters.

Internal Dosimetry: The inspectors reviewed and discussed the in vivo bioassay program with the licensee. The inspectors reviewed procedures that addressed methods for determining internal or external contamination, releasing contaminated individuals, the assignment of dose, and the frequency of measurements depending on the nuclides. The inspectors reviewed and evaluated Whole Body Counter (WBC)sensitivity, count time and libraries. The inspectors evaluated the licensees program for in vitro monitoring, however there were no dose assessments using this method to review. There were no internal dose assessments for internal exposure greater than 10 millirem committed effective dose equivalent to review.

Special Dosimetric Situations: The inspectors reviewed records for two currently declared pregnant workers (DPW)s and discussed guidance for monitoring and instructing DPWs. The inspectors reviewed the licensees practices for monitoring external dose in areas of expected dose rate gradients, including the use of multi-badging and extremity dosimetry. The inspectors evaluated the licensees neutron dosimetry program and reviewed records for two neutron dose assessments for containment-at-power entry using neutron survey instrumentation.

Problem Identification and Resolution: The inspectors reviewed and discussed licensee CAP documents associated with occupational dose assessment. Inspectors evaluated the licensees ability to identify and resolve the identified issues in accordance with Station Administrative Procedure SAP-0999, Corrective Action Program, Rev. 11.

HP program occupational dose assessment activities were evaluated against the requirements of UFSAR Chapter 12; TS Section 6.11 Radiation Protection; 10 CFR Parts 19 and 20; and approved licensee procedures. Records reviewed are listed in Section 2RS4 of the report Attachment.

The inspectors completed one sample as required by IP 71124.04 (sample size of 1).

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

a. Inspection Scope

The inspectors reviewed the licensees radiation monitoring instrumentation programs to verify the accuracy and operability of radiation monitoring instruments used to monitor areas, materials, and workers to ensure a radiologically safe work environment and to detect and quantify radioactive process streams and effluent releases.

Walkdowns and Observations During tours of the turbine building, auxiliary building, SFP areas, and RCA exit point, the inspectors observed installed radiation detection equipment including the following instrument types: area radiation monitors (ARM),continuous air monitors (CAM), liquid and gaseous effluent monitors, personnel contamination monitors (PCM), small article monitors (SAM), and portal monitors. The inspectors observed the physical location of the components, noted the material condition, and compared sensitivity ranges with UFSAR requirements. In addition, the inspectors observed placement and use of various portable survey instruments throughout the protected area.

Calibration and Testing Program In addition to equipment walk-downs, the inspectors observed or discussed source checks and alarm setpoint testing of various instruments, including friskers, hand and foot monitors, and airborne radioactivity monitors. For portable instruments, the inspectors reviewed the calibration records for selected contamination, dose rate, and air sampling instruments; observed use of the electronic dosimeter calibrator; discussed periodic output testing (source recertification) and use of the high-range calibrator; and observed source checking of various portable dose rate instruments. The inspectors reviewed the last two calibration records and evaluated alarm setpoint values for selected ARM, PCM, portal monitors, SAM, effluent monitors, laboratory counting systems, and WBC systems. This included a sampling of instruments used for post-accident monitoring such as containment high-range ARMs, and effluent monitor high-range noble gas and iodine channels. Radioactive sources used to calibrate selected ARMs and effluent monitors were evaluated for traceability to national standards. Calibration and source check stickers were noted on portable survey instruments and air samplers during inspection of storage areas for ready-to-use equipment. The inspectors also noted separate storage location(s) and out of service tags on equipment not ready for use. The most recent 10 CFR Part 61 analysis for DAW was reviewed to determine if calibration and check sources are representative of the plant source term. The inspectors also reviewed count room quality assurance records for gamma ray spectroscopy and gross alpha/beta counting equipment.

Effectiveness and reliability of selected radiation detection instruments were reviewed against details documented in the following: 10 CFR Part 20; NUREG-0737, Clarification of TMI Action Plan Requirements; UFSAR Chapters 12; and applicable licensee procedures. Documents reviewed during the inspection are listed in Section 2RS5 of the report Attachment.

Problem Identification and Resolution The inspectors reviewed and discussed selected CAP documents associated with radiological instrumentation. The reviewed items included CRs, self-assessment, and quality assurance audit documents. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with procedure SAP-999 Corrective Action Program, Rev. 11. Documents reviewed are listed in Section 2RS5 of the Attachment to this report.

The inspectors completed one sample as required by IP 71124.05 (sample size of 1).

b. Findings

No findings were identified.

4OA1 Performance Indicator Verification

.1 Cornerstone: Reactor Safety Barrier Integrity

a. Inspection Scope

The inspectors verified the accuracy of the licensees PI submittals listed below for the period April, 2013, through March, 2014. The inspectors used the performance indicator definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Rev. 6, Regulatory Assessment Performance Indicator Guideline, and licensee procedure SAP-1360, Rev. 2, NRC and INPO/WANO Performance Indicators, to check the reporting of each data element. The inspectors sampled licensee event reports (LERs),operator logs, plant status reports, CRs, and performance indicator data sheets to verify that the licensee had properly reported the PI data. Also, the inspectors discussed the PI data with the licensee personnel associated with the performance indicator data collection and evaluation.

• RCS Specific Activity

• RCS Identified Leak Rate

b. Findings

No findings were identified.

.2 Cornerstone: Occupational Radiation Safety

a. Inspection Scope

The inspectors reviewed the Occupational Exposure Control Effectiveness PI results for the Occupational Radiation Safety Cornerstone from October 2013 through March 2014.

For the assessment period, the inspectors reviewed ED alarm logs and selected CRs related to controls for exposure significant areas. The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents reviewed are listed in Sections 2RS1 and 4OA1 of the report Attachment.

b. Findings

No findings were identified.

.3 Cornerstone: Public Radiation Safety Cornerstone

a. Inspection Scope

The inspectors reviewed the Radiological Control Effluent Release Occurrences PI results for the Public Radiation Safety Cornerstone from October 2013 through March 2014. For the assessment period, the inspectors reviewed cumulative and projected doses to the public contained in liquid and gaseous release permits and CRs related to Radiological Effluent Technical Specifications/Offsite Dose Calculation Manual issues.

The inspectors also reviewed licensee procedural guidance for collecting and documenting PI data. Documents reviewed are listed in Section 4OA1 of the report

.

The inspectors completed two of the required samples specified in IP 71151.

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 focused on the first half of 2014. 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. However, inspectors identified 43 CRs relating to problems associated with radition monitors (RMs) during the approximate first six months of 2014.

A listing of the CRs reviewed are listed in Section 4OA2 of the report Attachment.

The inspectors discussed the issue with the licensee who initiated CR-14-03708 to document the adverse trend.

.3 (Closed) Unresolved Item (URI)05000395/2013003-01, Modification Leads to Auxiliary

Building Flood Vulnerability

a. Inspection Scope

The inspectors opened the above URI in NRC Integrated Inspection Report (IIR)05000395/2013003 to allow further review for determination of any applicable PD and if the significance was more than minor. The inspectors also reviewed additional flooding concerns identified during NRC Temporary Instruction 2515/190, Inspection of Proposed Interim Actions Associated with Near-Term Task Force (NTTF)

Recommendation 2.1 Flooding Hazard Evaluations, which was documented in IIR 05000395/2013005. The inspectors have completed their review of the aforementioned URI which is hereby closed as discussed below.

b. Findings

No findings were identified. Non-safety related electrical manhole (EMH) 8, is located in the yard and within the protected area of the unit. The inspectors reviewed in detail those CAP documents related to EMH-8 in regards to the historical flooding challenges to auxiliary building (AB) and identified longstanding issues with EMH-8 impact to the AB relative to water intrusion. Specifically, conduits carrying non-safety related cables are routed underground between the AB elevation 412, north wall behind the SF pump area and EMH-8. Additional conduits then carry cables to other structures such as the circulating water pump intake structure and hydrogen storage area. Consequently, water directly entering EMH-8 or other yard areas with conduits leading to EHM-8 result in the ability of accumulated water in EHM-8 to transverse to the AB via the interconnecting conduits. Previously, the conduits on the AB side were sealed in an attempt to stop the water intrusion, however, with limited success based on continued events as documented in CRs. The residents identified the 13 CRs regarding AB water intrusion from a search of the CAP. A listing of the CRs reviewed are listed in Section 4OA2 of the report Attachment.

The inspectors noted that the problem documented in CR-13-02022, During excavation activities associated with the ISFSI project, a condition was created [specifically yard trenching that collected and routed rain water adjacent to EMH-8] which allowed rain water to enter the Auxiliary Building via EMH-8 with specifics noted in CR-13-01917 and CR-13-01973, resulted from a vulnerability in the licensees independent spent fuel storage installation (ISFSI) modification program that involved a failure to review those activities that challenge existing plant configurations relative to design and licensing basis. The licensee subsequently revised engineering checklist, EC-01, Design Input Development, to add Attachment V, Interim Alterations Considerations. Additionally, the EMH-8 flooding problem was identified as a Top Plant Issue in July, 2013, and during the second quarter of 2014, resulted in the installation of robust mechanical seals in the conduits originating in EHM-8 and leading to the AB.

The inspectors noted that CR-13-03949 was initiated due to the inspectors identification of no documented evaluation for the flood path described above and also identified as an unidentified plant flood pathway (UPFP) during the licensees post-Fukushima walk-downs. The licensee subsequently performed the evaluation, TWR JG40733, "CR-13-03949 Flooding UPFP Evaluations," with later revisions to address discrepancies identified by the inspectors. The inspectors compared the rate of floor drain tank (FDT)input from previous heavy rainfall events to the necessary flooding rate to reach the licensees AB basement elevation flood volume limit of 68,202 gallons, which assumes sump pumps removing accumulated water to the FDT are unavailable. The inspectors concluded that the licensees existing EMH-8 conduit seal configuration on the AB side as previously noted was sufficient to preclude an AB flood exceeding the limit for a significant PMP event. Consequently, the inspectors determined that the failure to seal conduits exiting the plant buildings and exposed to environmental intrusion of water as required by drawing, E-215-001, and specifically those conduits associated with EMH-8, was a performance deficiency (PD) of minor significance.

.4 Annual Sample Review of CR-12-05211

a. Inspection Scope

The inspectors reviewed CR-12-05211, XVR03026-SP failed to lift at the maximum test pressure, dated November 12, 2012, in detail to evaluate the effectiveness of the licensees corrective actions for 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. 12A.

b. Findings

Introduction:

An NRC-identified Green, non-cited violation (NCV) of 10 CFR 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," was identified for the licensees failure to accomplish a general test procedure, GTP-302, requirement to determine the cause and correct the conditions of two failures of reactor building spray system relief valve, XVR03026-SP.

Description:

XVR03026-SP is a relief valve designed to prevent pressure locking of the reactor building spray (SP) system train B containment isolation valve, XVG03004B-SP..The LER discussed in section 4OA3 of this report, which documents a Fall 2012 refuelling outage failure of this valve, stated the apparent cause of the failure to lift during bench testing was bonding of the valve disc and nozzle seats due to normal aging and slight internal misalignment. The licensee also documented corrosion and wear on the valve seats, and determined that the bonding was due to the 6 year service interval.

The inspectors reviewed historical CAP documents relating to the problem described in the LER and noted that XVR03026-SP had also failed its surveillance test in 2006 as documented by CR-06-03903. The licensees 10 CFR 21 evaluation contained in this CR stated: the prolonged length of time between lubrication/refurbishment of the valve internals allowed light corrosion to form on the seating surfaces that prevented the valve from lifting. Inspectors noted that CR-06-03903 also documented observed seat leakage.

The inspectors observed that the similar relief valve, XVR03025-SP, on the A train of the SP system had not exhibited the same issues with seat leakage, seat bonding, and test failures as with XVR03026-SP. The inspectors performed a walk-down of the field configurations of both the A train and B train relief valves which revealed that the B train relief valve discharge piping had a pronounced upward slope. However, the discharge piping for the A train valve had a flat to very slight upward slope.

The inspectors researched available vendor information, listed in Section 4OA2 of the report Attachment, on the proper installation of Crosby relief valves and determined that the valve was not installed in accordance with available vendor guidance. The inspectors discussed the vendor related information with the licensee who acknowledged that the discharge piping is incorrectly installed in that borated water can collect in the discharge side of the relief valve and initiated CR-14-03079. The inspectors reviewed the licensees safety-related, general test procedure, GTP-302, Inservice Testing of Valves Third Ten Year Interval, Rev 15, dated October 09, 2006, step 5.4.2, Test Frequency, Class 2 and 3 Pressure Relief Devices, E.5.b states, For any valve exceeding its stamped set pressure by +/-3% or Owner specified acceptance criteria the following shall occur: The cause of the failure shall be determined and corrected.

The inspectors concluded that the licensee had not reasonably determined the cause of the 2006 and 2012 test failures attributed to seat bonding. Specifically, the ongoing issues of minor seat leakage coupled with the drain pipe configuration allowing the accumulation of corrosive borated water led to seat corrosion and seat bonding.

Consequently, the inspectors also concluded that the licensee had not effectively accomplished GTP-302, step 5.4.2.E.5.b. to correct the faulty piping configuration.

Analysis:

The licensees failure to accomplish GTP-302 to determine and correct the cause of the failures occurring in 2006 and 2012 was a PD which was within their ability to foresee and correct based on the available vendor documentation. The inspectors reviewed Inspector Manual Chapter (IMC) 0612, Power Reactor Inspection Reports, Appendix B, and determined the PD was more than minor and therefore a finding, because it affected the Barrier Integrity cornerstone objective to provide reasonable assurance that physical design barriers such as containment protect the public from radionuclide releases caused by accidents or events and the respective attribute of human performance because the availability and reliability of XVR03026-SP was not ensured by a failure to accomplish procedure requirements to determine the cause of two previous failures and correct. The inspectors evaluated the finding in accordance with IMC 0609, Significant Determination Process, attachment 4 and appendix A, and determined that the finding was of very low safety significance, Green, because it did not represent an actual physical open pathway in containment. The inspectors reviewed IMC 0310, Aspects Within the Cross-cutting Areas, and determined the cause of the finding involved the cross-cutting area of problem identification and resolution and the respective aspect of complete and thorough evaluation, P.2, because the licensee failed to determine the cause of the relief valve failures for adequate corrective actions.

Enforcement:

10 CFR 50, Appendix B, Criterion V requires, in part, that activities affecting quality shall be accomplished by documented procedures of a type appropriate to the circumstances. Contrary to the above, on November 10, 2006, and November 7, 2012, procedure GTP-302 was not adequately accomplished to determine the cause and correct the problems of the failures of XVR03026-SP in 2006 and 2012. This violation is in the licensees corrective action program as CR-14-03079, and is being treated as a NCV, consistent with Section 2.3.2.a of the Enforcement Policy: NCV 05000395/2014003-01, Failure to Accomplish Procedure to Determine Cause and Correct Failures of Reactor Building Spray System Relief Valve.

4OA3 Event Followup

(Closed) LER 05000395/2013-004-00: Relief Valve Failure to Lift at Required Setpoint Renders the Reactor Building Spray System Inoperable On September 30, 2013, the licensee issued LER 05000395/2013-004-00 based on a relief valve that failed to lift at the required setpoint and was subsequently determined as past inoperable. The details and enforcement aspects are discussed in Section 4OA2.4 of this report. This LER is closed.

4OA5

OTHER ACTIVITIES

.1 (Closed) URI 05000395/2013005-01, Seal Water Injection Filter Impact on Alternate Seal

Injection System and Design Basis Accidents

a. Inspection Scope

The inspectors opened the above URI in NRC IIR 05000395/2013005 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 FIN was identified for the failure of the licensee to accomplish station procedures for development, review, and performance of adequate post modification testing of the ASI system.

Description:

Specific details of URI 05000395/2013005-001 are discussed in NRC IIR000395/2013005. The inspectors review of the licensees procedures for post modification testing identified the following requirements.

• Station administrative procedure, SAP-1202, Statement of Responsibilities, Engineering Services, Enclosure 7.4, Engineering Services Major Functional Interface Matrix, states for Design Engineering responsibilities for interfacing with Maintenance, Specify Post Mod Testing requirements.

• Engineering services procedure, ES-455, Design Control: Plant Modification, step 6.6.2 states, Engineering personnel shall review revised and/or new post modification test procedures to ensure adequacy to perform post-modification tests.

• SAP-133, Design Control Implementation and Interface, Attachment X, Design Review Meeting Agenda, states, Review of the post modification check out and functional testing plan including: a) Adequacy of the instructions included in the design package, b) Responsible Group(s), c) Test procedures to be developed or revised, and d) If scope of testing may challenge design validation, obtain management concurrence.

The inspectors reviewed an engineering technical work record (TWR) WW90551 which correlated historical RCS total suspended solids (TSS) sample results with seal water injection filter (SWIF) differential pressure data to demonstrate that ASI functionality would be assured during plant operation. The inspectors reviewed chemistry procedure, CP-116, Determination of Total Suspended Solids, Rev. 8, and noted that the process uses a

.45 micron filter to collect suspended solids. The inspectors determined that

particles less than

.45 microns but greater than .1 micron which is the size filter used for

SWIFs would not appear in the licensees sampling. Additionally, interviews of the filter vendor personnel indicated that submicron size particles would have a greater impact on performance of a filter as compared to larger micron size particles. Consequently, the inspectors concluded the licensees technical basis for ASI functionality was inadequate.

The inspectors had also documented in the URI a concern regarding adequacy of 50.59 evaluations for the licensees process during Unit 1 historical operation to reduce SWIF micron size from an original 23 microns down to the current

.1 micron. Specifically,

those design basis events leading to a Safety Injection result in charging pump suction swap to the RWST which can lead to SWIF clogging and a loss of seal injection. If the event involves either feedwater or steam line ruptures inside containment resulting in a phase B actuation and subsequent isolation of component cooling (CC) water to the reactor coolant pumps (RCP), this would potentially result in the loss of RCP seal cooling due to no CC flow to the RCP thermal barriers and no seal injection flow from SWIF clogging. NRC headquarters personnel reviewed this scenario and determined that the licensees changes from multiple micron sizes to smaller sub-micron SWIFs since original unit startup would not result in a different accident event that would require agency review and approval.

Regional inspection staff performed bounding calculations, assuming worst case allowable TSS and initial SWIF filter differential pressure, and determined that the allowable SWIF differential pressure could be exceeded before reaching the ASI system mission time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. As a result, the inspectors concluded that the licensee did not adequately develop, review and accomplish station procedures for post modification testing to reasonably demonstrate that the ASI system 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 was assured. This issue has been entered into the licensees CAP as CR-13-00642

Analysis:

The inspectors determined that the failure to accomplish station procedures to develop, review, and implement adequate post modification testing in accordance with station procedures was a PD, and was within the licensees ability to foresee and correct based on their existing knowledge of ASI designs at other plants. The inspectors reviewed IMC 0612 and determined the PD is more than minor and therefore a finding because if left uncorrected it would have the potential to result in a more significant safety event. Specifically, loss of the ASI system would lead to a RCP seal loss of coolant accident during those events involving a loss of normal seal cooling such as a station blackout or fire. The inspectors reviewed IMC 0609, Attachment 4 and Appendix A, for the significance determination and determined the finding was of very low safety significance, or Green, because it did not involve a design deficiency and was not an actual loss of function. The inspectors review IMC 0310 for cross-cutting aspects and determined the cause of the finding involved the area of human resources and the aspect of H.11, challenge the unknown, because the licensee did not identify the appropriate post modification testing when using a, first-for-the-station, ASI design.

Enforcement:

The aforementioned licensee station procedures, SAP-1202, ES-455, and SAP-133, require in part that post modification tests are developed, reviewed and performed. Contrary to this, with completion of the refueling outage and ASI modification on December 7, 2012, the licensee failed to accomplish station procedures to adequately develop, review and perform post modification testing to assure the functionality of the ASI system for its mission criteria. Because this finding does not involve a violation of regulatory requirements and has very low safety significance, this finding is identified as FIN 05000395/2014003-02, Failure to Develop Adequate Post Modification Testing for the Alternate Seal Injection System.

.2 Temporary Instruction 2515/189, Inspection to Determine Compliance of Dynamic

Restraint (Snubber) Program with 10 CFR 50.55a Regulatory Requirements for Inservice Examination and Testing of Snubbers

a. Inspection Scope

The inspector conducted an onsite review of the implementation of the licensees snubber program in accordance with Temporary Instruction (TI) 2515/189 to verify that the program was in compliance with the requirements of Title 10 of the Code of Federal Regulations (10 CFR) 50.55a, as discussed in Regulatory Information Summary (RIS)2010-06, Inservice Inspection and Testing of Dynamic Restraints (Snubbers). The inspector reviewed the licensees actions taken as a result of RIS 2010-06, which included a license amendment, submitted to the NRC, for its fourth 10-year Inservice Inspection (ISI) interval pertaining to the examination and testing requirements of snubbers. The inspector interviewed the snubber program owner and conducted an independent walkdown to evaluate compliance with licensees program requirements.

The inspector reviewed the methodology for snubber population selection and selected 12 snubbers to review, based on risk-informed insights, performance history, plant conditions, snubber classification, and accessibility to verify the visual examination of the selected snubbers was performed during every refueling outage of the current 10-year interval. For the selected snubbers, the inspector also reviewed the functional test records during the current 10-year ISI interval to verify these activities were in accordance with the previously approved license amendment. The inspector also observed in-process bench testing of one of the selected snubbers, and verified that the test parameters met the acceptance criteria specified in the procedure. The inspector reviewed the process for snubber service life monitoring and determined that the selected snubbers were being monitored and maintained. Additionally the inspector verified that the current as well as a sample of past degraded or non-conforming conditions were properly identified and corrected in accordance with the licensees corrective action program.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

On July 29, 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.

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 meet the criteria of Section 2.3.2 of the NRC Enforcement Policy for characterization as an NCV:

• VC Summer Nuclear Station TS 6.8.1 states in part that procedures shall be implemented for the Fire Protection Program. Contrary to the above, on May 5, 2014 and May 10, 2014, the licensee failed to implement Fire Protection Program (FPP)procedure, FPP-25, Fire Containment, Revision 4G, in that required fire protection permits were not obtained while Appendix R fire doors were left open without being manned. Specifically, Appendix R fire door DRCB/512 was found open on May 5, 2014, and Appendix R fire doors DRIB/105B and DRCB/134 were found open on May 10, 2014. The PD was more than minor and therefore a finding because it impacted the mitigating systems cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences, and the related attribute of protection against external factors such as fire. The inspectors used IMC 0609, Appendix F, Attachment 1, to determine that the finding was of very low safety significance (Green) because smoke or heat detection was present in all adjacent fire areas. Further, since plant personnel would be alerted in the event of a fire and the doors could then be closed, equipment required for safe shutdown would not be impacted. Fire doors DRIB/105B and DRCB/134 were closed upon discovery as discussed in condition reports CR-14-02658 and CR-14-02655 respectively. Fire door DRCB/512 temporarily remained open as a power cord was being run through it in support of maintenance. However, fire door DRCB/512 was placed on the roving fire watch and an FPP permit was issued to track that it was open in accordance with FPP-25 as discussed in CR-14-02531.

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

W. Colie, ISI Coordinator

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

C. Henderson, Snubber Program

R. Justice, Manager, Nuclear Operations

G. Lippard, General Manager, Nuclear Plant Operations

M. Mosley, Manager, Nuclear Training

D. Perez, Supervisor, Health Physics - Technical Support

D. Petersen, Welding Coordinator

S. Reese, Specialist, Nuclear Licensing

D. Shue, Manager, Maintenance Services

C. Speas, Independent Qualified Data Analyst

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

H. White, Steam Generator Program Owner

R. Williamson, Manager, Emergency Planning

S. Zarandi, General Manager, Nuclear Support Services

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000395/2014003-01 NCV Failure to Accomplish Procedure to Determine Cause and Correct Failures of Reactor Building Spray System Relief Valve (Section 4OA2.4)

05000395/2014003-02 FIN Failure to Develop Adequate Post Modification Testing for the Alternate Seal Injection System (Section 4OA5.1)

Closed

05000395/2013-004-00 LER Relief Valve Failure to Lift at Required Setpoint Renders the Reactor Building Spray System Inoperable (Section 4OA3)

05000395/2013003-01 URI Modification Leads to Auxiliary Building Flood Vulnerability (Section 4OA2.3)

05000395/2013005-01 URI Seal Water Injection Filter Impact on Alternate Seal Injection System and Design Basis Accidents (Section 4OA5.1)

TI 2515/189 TI Inspection to Determine Compliance of Dynamic Restraint (Snubber) Program with 10 CFR 50.55a, "Regulatory Requirements for Inservice Examination and Testing of Snubbers" (Section 4OA5.1)