IR 05000261/2013005

IR 05000261-13-005 and 05000261-13-502, on 10/01/2013 - 12/31/2013; H.B. Robinson Steam Electric Plant, Unit 2; Adverse Weather Protection, Refueling and Outage Activities, and Radiological Hazard Assessment and Exposure.

ML14031A371
Person / Time
Site:	Robinson
Issue date:	01/31/2014
From:	Hopper G NRC/RGN-II/DRP/RPB4
To:	William Gideon Duke Energy Progress
References
IR-13-005, IR-13-502
Download: ML14031A371 (42)

Text

UNITED STATES anuary 31, 2014

SUBJECT:

H.B. ROBINSON STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT 05000261/2013005 AND 05000261/2013502

Dear Mr. Gideon,

On December 31, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your H. B. Robinson Steam Electric Plant, Unit 2. On January 16, 2014, the NRC inspectors discussed the results of this inspection with you and other members of your staff.

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

Two NRC identified findings and one self-revealing finding of very low safety significance (Green) were identified during this inspection. The findings were determined to involve a violation of NRC requirements. The NRC is treating this violation as non-cited violation (NCV)

consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violation or significance of the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; with copies to the Regional Administrator, Region II, the Director, Office of Enforcement, U.S.

Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at H. B. Robinson Steam Electric Plant, Unit 2.

In addition, if you disagree with the cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at H.B.

Robinson. As a result of the Safety Culture Common Language Initiative, the terminology and coding of crosscutting 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 2.790 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 Publically Available Records (PARS) component of NRCs document 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/

George T. Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects Docket No.: 50-261 License No.: DPR-23

Enclosure:

Inspection Report 05000261/2013005, 05000261/2013502 w/Attachment: Supplemental Information

REGION II==

Docket No: 50-261 License No: DPR-23 Report No: 005000261/2013005 and 05000261/2013502 Facility: H. B. Robinson Steam Electric Plant, Unit 2 Location: 3581 West Entrance Road Hartsville, SC 29550 Dates: October 1, 2013 through December 31, 2013 Inspectors: K. Ellis, Senior Resident Inspector C. Scott, Resident Inspector S. Herrick, Project Engineer, 1R04 B. Collins, Reactor Inspector, 1R08 J. Rivera-Ortiz, Senior Reactor Inspector, 1R08 M. Coursey, Reactor Inspector, 1R08 J. Laughlin, Emergency Preparedness Inspector, 1EP4 A. Nielsen, Senior Health Physicist, 2RS8 W. Pursley, Health Physicist, 2RS1, 4OA1 M. Riley, Reactor Inspector, 4OA5.3 Approved by: George Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000261/2013005 and 05000261/2013502, Duke Energy Progress, Inc.: on 10/01/2013 -

12/31/2013; H.B. Robinson Steam Electric Plant, Unit 2; Adverse Weather Protection, Refueling and Outage Activities, and Radiological Hazard Assessment and Exposure Controls.

The report covered a three month period of inspection by resident inspectors and announced inspections by reactor inspectors. Three findings of very low safety significance (Green) were identified. 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 02, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within the Cross-Cutting Areas dated October 28, 2011. Findings for which the SDP does not apply may be Green or be assigned a severity level after NRC management review.

Cornerstone: Initiating Events

Green.

The inspectors identified a Green non-cited violation (NCV) of Technical Specification 5.4.1 for the licensees failure to implement freeze protection requirements specified in station procedures. Specifically the inspectors found that the required temporary enclosures were not installed and work orders for freeze protection circuits were not repaired prior to November 1, 2013, in accordance with procedure OP-925,

Cold Weather Operation. The licensee initiated CR 645333 and took immediate corrective actions to install the necessary enclosures and to verify the proper operation of freeze protection circuits for safety related and fire protection equipment.

The licensees failure to implement freeze protection requirements as required by procedure OP-925 was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the protection against external factors attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

Specifically, the failure to implement the requirements of procedure OP-925 could limit the sites ability to detect, respond to, or mitigate the consequences of an accident. The finding was determined to be of very low safety significance (i.e. Green) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. More specifically, the site had not experienced freezing weather conditions of sufficient magnitude to challenge plant systems during this time period. The finding involved the cross-cutting area of Human Performance under the Work Control component in that the licensee failed to appropriately plan work activities by incorporating risk insights to ensure the activities required to prepare the plant for cold weather conditions were completed prior to the onset of cold weather. H.3(a)(1R01)

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green non-cited violation of Technical Specification (TS) 5.4.1 for the failure to properly implement procedure PLP-006, Containment Vessel Inspection Closeout, prior to startup following RFO 28. The improper closeout resulted in various tools as well as bags of consumable items and debris left in containment that could impact the containment sump strainer following an accident. The licensee initiated CR 640903, removed the items identified by the inspectors, and re-performed procedure PLP-006, Containment Vessel Inspection/Closeout, to further identify materials that should have been previously removed.

The failure to remove debris and various temporary materials as required by procedure PLP-006 was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the reliability and availability of ECCS equipment would be degraded by the introduction of material in to the containment that would impact and reduce the available area on the recirculation sump strainer. The inspectors determined that this finding is of very low safety significance (Green) because the finding did not represent an actual loss of function of one or more non-Tech Spec Trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This finding had a cross-cutting aspect in the Work Practices component of the Human Performance area, because the licensee failed to ensure that supervisor and management oversight of procedure PLP-006 ensured that debris was removed as required during containment closeout prior to reactor startup. H.4(c) (1R20)

Cornerstone: Occupational Radiation Safety

Green.

A self-revealing, Green, non-cited violation (NCV) of TS 5.7.1, High Radiation Area, was identified for an unauthorized entry into a High Radiation Area (HRA).

Specifically, two workers entered the residual heat removal pump room without knowledge of current radiological conditions and without wearing the prescribed electronic dosimetry for the area. The licensee entered this issue into the Corrective Action Program as Nuclear Condition Report 524523 and took immediate corrective actions including restriction of the workers from access to the Radiologically Controlled Area.

This finding was determined to be greater than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of Human Performance and adversely affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. The finding was evaluated using the Occupational Radiation Safety Significance Determination Process. The finding was not related to As Low As Reasonably Achievable planning, nor did it involve an overexposure or substantial potential for overexposure, and the ability to assess dose was not compromised. Therefore, the inspectors determined the finding to be of very low safety significance (Green). This finding involved the cross-cutting aspect of Human Performance, Work Practices because the HRA event was a direct result of inadequate pre-job briefings and a lack of self and peer checking on the part of the work crew.

H.4.a] (2RS1)

REPORT DETAILS

Summary of Plant Status

The unit began the inspection period shutdown for a planned refueling outage. The unit returned to on-line status on November 5, 2013. The unit tripped on November 5, 2013, during the transfer of auxiliaries. The unit returned to 100 percent power on November 11, 2013, and operated at full power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

Winter Seasonal Readiness Preparations: The inspectors conducted a review of the licensees preparations for winter conditions to verify that the plants design features and implementation of procedures were sufficient to protect plant systems from the effects of adverse weather. Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. Cold weather protection systems, such as heat tracing and area heaters, were verified to be in operation where applicable. The inspectors also reviewed Corrective Action Program (CAP) items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures. Documents reviewed are listed in the Attachment. The inspectors reviews focused specifically on the following plant systems due to their risk significance or susceptibility to cold weather issues:

• Service Water System

• Steam Driven Auxiliary Feedwater External Flooding: The inspectors verified that flood protection barriers and procedures for coping with external flooding were appropriate. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and related flood analysis documents to identify those areas that can be affected by external flooding. The inspectors also reviewed problem reports and corrective actions for past flooding events, including the heavy rain event on May 2011. Inspectors conducted a walkdown of the site boundary to further assess the adequacy of the design features relied upon to mitigate the effects of external flooding. In addition, the inspectors met with site engineering to discuss the status of planned modifications to the site topography and their impact on external flood mitigation. Documents reviewed are listed in the Attachment.

b. Findings

Introduction:

The inspectors identified a Green non-cited violation (NCV) of Technical Specification (TS) 5.4.1 for the licensees failure to implement station procedures used to implement freeze protection requirements. Specifically the inspectors found that the required temporary enclosures were not installed and work orders for freeze protection circuits were not repaired prior to November 1, 2013, in accordance with procedure OP-925, Cold Weather Operation.

Description:

Licensee procedure OP-925, Cold Weather Operations, provides guidance to protect plant equipment from the effects of freezing and ensure that the freeze protection system is operating prior to November 1st. On November 8, 2013, the inspectors performed a walkdown to verify that the licensee was adequately prepared for cold weather operation. During the walkdown the inspectors identified that the freeze protection enclosures and enclosure heaters were not installed around equipment important to safety, as directed by procedure OP-925. The enclosures protected the following equipment that if, not protected, could cause a plant transient: Main Steam Pressure Transmitters, turbine first stage pressure transmitters, condenser level transmitters, hydrogen seal oil pumps, main steam and feed water piping penetration area, outside instrument air compressor and the security diesel generator enclosure air inlet screens. The inspectors also discovered that the licensee failed to test all freeze protection circuits for safety related and fire protection equipment prior to the required date. In addition, work orders were initiated to repair freeze protection circuits for fire water booster pump piping, engine driven fire pump, motor driven fire pump piping and A service water pump. A review of these work orders revealed that the repair for these freeze protection circuits were not complete prior to November 1st, per procedure OP-925. The licensee entered these issues into the CAP as AR 645333 and AR 652737. The licensee took immediate corrective actions to install the necessary enclosures and to verify the proper operation of freeze protection circuits for safety related and fire protection equipment. Additional programmatic corrective actions are being developed by the licensee to address weaknesses in the implementation of procedure OP-925 and ensure that work orders for cold weather preparations are appropriately scheduled.

Analysis:

The licensees failure to implement freeze protection requirements as required by procedure OP-925 was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the protection against external factors attribute of the initiating events cornerstone and adversely affected the cornerstone objective to limit the likelihood of those events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

Specifically, the failure to implement the requirements of procedure OP-925 could limit the sites ability to detect, respond to, or mitigate the consequences of an accident. The inspectors evaluated the significance of the finding using Inspection Manual Chapter (IMC) 0609, Significance Determination Process, Attachment 4, Phase 1 - Initial Screening and Characterization of Findings, and determined the finding to be of very low safety significance (i.e. Green) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigation equipment or functions will not be available. More specifically, the site had not experienced freezing weather conditions of sufficient magnitude to challenge plant systems during this time period.

The finding involved the cross-cutting area of Human Performance under the Work Control component in that the licensee failed to appropriately plan work activities by incorporating risk insights to ensure the activities required to prepare the plant for cold weather conditions were completed prior to the onset of cold weather. H.3(a)

Enforcement:

TS 5.4.1.a requires, in part, that written procedures be established, implemented, and maintained covering the activities specified in Appendix A, Typical Procedures for Pressurized Water Reactors and Boiling Water Reactors, of Regulatory Guide (RG) 1.33, Quality Assurance Program Requirements (Operations), Revision 2, dated February 1978. RG 1.33, Appendix A, Section 6, Procedures for Combating Emergencies and Other Significant Events, required procedures for acts of nature, including freezing conditions. The licensee used procedure OP-925 Cold Weather Operation, and associated implementing work orders to protect against freezing conditions to implement this requirement.

Contrary to the above, on November 1, 2013, the licensee had not implemented applicable sections of procedure OP-925, to ensure that plant equipment was protected against the effects of freezing conditions. Specifically, the licensee failed to ensure that freeze protection circuits were operating and that temporary enclosures were installed to protect plant equipment. The licensee took immediate corrective actions to install the necessary enclosures and to verify the proper operation of freeze protection circuits for safety related and fire protection equipment. Because the finding was of very low safety significance and has been entered into the licensees corrective action program as AR 645333, this violation is being treated as an NCV, consistent with the Section 2.3.2.a of the NRC Enforcement Policy: (NCV 05000261/2013005-01) Inadequate Preparation for Cold Weather Conditions.

1R04 Equipment Alignment

a. Inspection Scope

Partial System Walkdowns: The inspectors performed the three partial walkdowns listed below to assess the operability of redundant or diverse trains and components when safety related equipment was inoperable or out-of-service and to identify any discrepancies that could impact the function of the system potentially increasing overall risk. The inspectors reviewed applicable operating procedures and walked down system components, selected breakers, valves, and support equipment to determine if they were correctly aligned to support system operation. The inspectors reviewed protected equipment sheets, maintenance plans, and system drawings to determine if the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP. Documents reviewed are listed in the Attachment.

• B Residual Heat Removal while in Shutdown Cooling mode

• B Spent Fuel pool Cooling while the core was located in the spent fuel pool

• A EDG Electrical Lineup and SD AFW Pump during testing of the B EDG Complete System Walkdown: The inspectors conducted a detailed review of the alignment and condition of the containment spray system to verify that the existing alignment of the system was consistent with the correct alignment. To determine the correct system alignment, the inspectors reviewed the procedures, drawings, and the Updated Final Safety Analysis Report (UFSAR). The inspectors also walked down the system. During the walkdown, the inspectors reviewed the following:

• Valves were correctly positioned and did not exhibit leakage that would impact the functions of any given valve.

• Electrical power was available as required.

• Major system components were correctly labeled, lubricated, cooled, ventilated, etc.

• Hangers and supports were correctly installed and functional.

• Essential support systems were operational.

• Ancillary equipment or debris did not interfere with system performance.

• Tagging clearances were appropriate.

• Valves were locked as required by the locked valve program.

The inspectors reviewed the documents listed in the Attachment to verify that the ability of the system to perform its functions could not be affected by outstanding design issues, temporary modifications, operator workarounds, adverse conditions, and other system-related issues tracked by the engineering department.

b. Findings

No findings were identified.

1R05 Fire Protection

a. Inspection Scope

Fire Area Tours: For the four areas identified below, the inspectors reviewed the control of transient combustible material and ignition sources, fire detection and suppression capabilities, fire barriers, and any related compensatory measures to verify that those items were consistent with UFSAR Section 9.5.1, Fire Protection System, and UFSAR Appendix 9.5.A, Fire Hazards

Analysis.

The inspectors walked down accessible portions of each area and reviewed results from related surveillance tests to verify that conditions in these areas were consistent with descriptions of the areas in the UFSAR.

Documents reviewed are listed in the Attachment.

The following areas were inspected:

• Auxiliary Building Second Level and Adjoining Rooms (fire zone 7)

• North Cable Vault (fire zone 9)

• Hagan Room and CCW Surge Tank Room (fire zone 23 and 36)

• HVAC Equipment Room for Control Room (fire zone 17)

b. Findings

No findings were identified.

1R06 Flood Protection Measures

a. Inspection Scope

Internal Flooding: The inspectors reviewed the following area because it contains risk-significant SSCs which are susceptible to flooding from postulated pipe breaks. The inspectors walked down the area to verify that the physical configuration, features, and equipment functions were consistent with the descriptions and assumptions used in Calculation RNP-F/PSA-0009, Assessment of Internally Initiated Flooding Events, and in the supporting basis documents listed in the Attachment. The inspectors reviewed the operator actions credited in the analysis to verify that the desired results could be achieved using the plant procedures listed in the Attachment.

• Battery Room

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

a. Inspection Scope

Non-Destructive Examination (NDE) Activities and Welding Activities: From September 23, 2013, through December 2, 2013, the inspectors conducted an on-site review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system (RCS), steam generator (SG) tubes, risk-significant piping and components and containment systems. The inspectors activities included a review of 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 through 2008 Addenda), 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 observed the following NDEs mandated by the ASME Code Section XI to evaluate compliance with the ASME Code Section XI and Section V requirements and, if any indications or defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

Radiographic Testing (RT)

• RT on weld numbers 12, 13 and 14 on SI-880B, Containment Spray Pump A

• Discharge Valve, 6.625 inche Outer Diameter (OD), ASME Class 2 The inspectors also reviewed records of the following non-destructive examinations mandated by the ASME Code Section XI to evaluate compliance with the ASME Code Section XI and Section V requirements and, if any indications or defects were detected, to evaluate if they were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement.

• Ultrasonic Testing (UT)o UT of Unit 2 Safe End-to-Nozzle Weld 107-14DM, ASME Class 1

• Visual Examination (VE)o VE of Unit 2 Reactor Pressure Vessel Bottom-Mounted Instrumentation Nozzles, ASME Class 1

• Liquid Penetrant Testing (PT)o PT on weld numbers 12, 13 and 14 on SI-880B, Containment Spray Pump A Discharge Valve, 6.625 OD, ASME Class 2 During non-destructive surface and volumetric examinations performed since the previous refueling outage, the licensee did not identify any recordable indications that were accepted for continued service. Therefore, no NRC review was completed for this inspection procedure attribute.

The inspectors observed the following pressure boundary welds completed for risk-significant systems during the Unit 2 refueling outage to evaluate if the licensee applied the preservice non-destructive examinations and acceptance criteria required by the Construction Code. In addition, the inspectors reviewed the welding procedure specification, welder qualifications, welding material certification and supporting weld procedure qualification records, to evaluate if the weld procedures were qualified in accordance with the requirements of Construction Code and the ASME Code Section IX.

• Weld numbers 12, 13 and 14 on SI-880B, Containment Spray Pump A Discharge Valve, 6.625 inches OD, ASME Class 2 PWR Vessel Upper Head Penetration (VUHP) Inspection Activities: For the Unit 2 vessel head, a bare metal visual examination was not required this outage pursuant to 10 CFR 50.55a. The licensee did not perform any inspections or repairs on the VUHP this outage. Therefore, no NRC review was completed for this inspection procedure attribute.

Boric Acid Corrosion Control (BACC) Inspection Activities: The inspectors reviewed the licensees BACC program activities to ensure implementation with commitments made in response to NRC Generic Letter 88-05, Boric Acid Corrosion of Carbon Steel Reactor Pressure Boundary, and applicable industry guidance documents. Specifically, the inspectors performed an on-site record review of procedures and the results of the licensees containment walk-down inspections performed during the current fall refueling outage (RO28). 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.

The inspectors reviewed the following condition reports 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.

• AR 522941, SI-892D Dry White Boric Acid at Packing

• AR 572225, SI-888A Has Dry Brown Boric Acid and Rust Around Stem

• AR 626539, SI-851B Dry Boric Acid The inspectors reviewed the following licensee evaluations of RCS components with boric acid deposits to evaluate if degraded components were documented in the corrective action system. The inspectors also evaluated the corrective actions for any degraded RCS components against the component ASME Code Section XI, and other licensee-committed documents:

• AR 539975, Quick Cause Evaluation: SA #497574, Boric Acid Control Program Management

• AR 516141, Cavity Leakage in RO-027 Steam Generator (SG) Tube Inspection Activities. The inspectors conducted an in-office review of documentation associated with the eddy current examination activities performed in Unit 2 steam generators during refueling outage RO28 to verify compliance with the licensees Technical Specifications, ASME Section XI, and Nuclear Energy Institute (NEI) 97-06, Steam Generator Program Guidelines. The inspectors interviewed licensee personnel responsible for the steam generator inspection project and reviewed documentation associated with the steam generator inspections and integrity assessments as described below.

The inspectors reviewed the scope of the eddy current 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 selected a sample of degradation mechanisms from the Unit 2 Steam Generator Degradation Assessment report (i.e. anti-vibration bar wear and outside diameter stress corrosion cracking (ODSCC) at the top of the tubesheet) and verified that the in-situ pressure testing criteria were determined in accordance with the EPRI Guidelines. Additionally, the inspectors reviewed eddy current indication reports for all three steam generators to determine whether tubes with relevant indications were appropriately screened for in-situ pressure testing. The inspectors review of eddy current indications included the implementation of tube repair criteria and repair methods to verify they were consistent with plant Technical Specifications and industry guidelines. The inspectors also reviewed tube plugging results for two tubes plugged in steam generator A and two tubes plugged in steam generator C to determine if the licensee repaired the appropriate tubes in accordance with the applicable procedures.

The inspectors compared the recent eddy current examination results with the last Condition Monitoring and Operational Assessment report for the steam generators 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 with the recent eddy current examination results to verify that new degradation mechanisms were identified and evaluated before plant startup. The review of eddy current examination results included the disposition of potential loose part indications on the steam generator 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 the last Unit 2 operating cycle to obtain reasonable assurance that operational leakage in all three steam generators remained below the detection or action level thresholds during the previous operating cycle.

Additionally, the inspectors reviewed documentation for a sample of eddy current data analysts, eddy current probes, and eddy current testers to verify these were qualified to detect the existing and potential degradation mechanisms applicable to Unit 2 steam generator tubes. This review included a sample of site-specific Examination Technique Specification Sheets (ETSSs) to ensure that their qualification and site-specific implementation were consistent with Appendix H or I of the EPRI Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7. The selected ETSSs for review were based on degradation mechanisms of interest to the inspectors based on plant-specific and industry operating experience. The inspectors selected bobbin probe ETSSs qualified for detection of wear at tube supports; wear at anti-vibration bars; and axial ODSCC at tube supports, sludge pile region, and freespan regions. The inspectors also reviewed a sample of eddy current data with a qualified data analyst to verify that indications were dispositioned in accordance with the ETSSs and site-specific analysis guidelines. The sample of eddy current data selected for review consisted of the following tubes:

Steam Tube Tube Eddy Current Data Type Generator Row Column A 23 14 Array Probe - Tubesheet on Hot Leg Side A 41 53 Array Probe - Tubesheet on Hot Leg Side B 4 48 Bobbin Probe B 4 43 Array Probe - Tube Support 03C C 3 91 Array Probe - Tubesheet on Hot Leg Side C 39 41 Array Probe - Tube Support 03H Based on the review of eddy current examination results and interviews with the licensee, the inspectors confirmed that no new degradation mechanisms were identified, no eddy current scope expansion was required, none of the SG tubes examined met the criteria for in-situ pressure testing, and none of the indications left in-service required repair.

Furthermore, the inspectors reviewed the inspection plan described in the Unit 2 Degradation Assessment report for the steam generators secondary side internals and discussed the inspection results with licensee staff 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.

Identification and Resolution of Problems: The inspectors performed a review of a sample of ISI- and SGISI-related problems which were identified by the licensee and entered into the corrective action program as action requests (ARs). The inspectors reviewed the ARs to confirm that the licensee had appropriately described the scope of the problem, and had initiated corrective actions. The review also included the licensees consideration and assessment of operating experience events applicable to the plant. The inspectors performed this review to ensure compliance with 10CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification

a. Inspection Scope

Routine Operator Requalification Review: On November 19, 2013, the inspectors observed operators in the plants simulator during licensed operator requalification training to verify that the operator performance was adequate, evaluators were identifying and documenting crew performance issues and training was being conducted in accordance with station procedures. The inspectors observed a shift crews response to the scenario listed below. Documents reviewed are listed in the Attachment.

• This scenario consisted of an injured person, loss of an instrument buss, loss of bus duct cooling, and loss of service water to the turbine building followed by a faulted steam generator, loss of the start-up transformer, and loss of auxiliary feed water.

Observation of Operator Performance: The inspectors observed main control room crew performance during the Unit 2 reactor startup from a planned refueling outage on November 4-5, 2013. The inspectors reviewed the operator performance and adherence to the operating procedures for pull to critical and various other portions of the unit startup. Operator response to main control room annunciators was evaluated during the observation to ensure the operators were referencing appropriate procedures.

Communication among the crew was evaluated for conformance to the licensees standard.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the licensees effectiveness in performing the following one corrective maintenance activity. These reviews included an assessment of the licensees practices pertaining to the identification, scoping, and handling of degraded equipment conditions, as well as common cause failure evaluations. For each activity selected, the inspectors performed a detailed review of the problem history and surrounding circumstances, evaluated the extent of condition reviews as required, and reviewed the generic implications of the equipment and/or work practice problem. For those SSCs scoped in the Maintenance Rule per 10 CFR 50.65, the inspectors verified that reliability and unavailability were properly monitored and that 10 CFR 50.65(a)(1)and 10 CFR 50.65(a)(2) classifications were justified in light of the reviewed degraded equipment condition.

The problems/conditions and their corresponding ARs were:

• AR 625392, Breaker 52/32A (Normal Feed to Dedicated Shutdown Bus) Failed to Close Switch

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Evaluation

a. Inspection Scope

For the two samples listed below, the inspectors reviewed risk assessments and related activities to verify that the licensee performed adequate risk assessments and implemented appropriate risk-management actions when required by 10 CFR 50.65(a)(4). For emergent work, the inspectors also verified that any increase in risk was promptly assessed, and that appropriate risk-management actions were promptly implemented. Documents reviewed are listed in the Attachment. Those periods included the following:

• Yellow Risk Condition during Lower Inventory Conditions with C Charging Pump out of service for maintenance; on October 24, 2012

• Yellow Risk Condition while the Steam Driven Auxiliary Feedwater Pump is out-of-service for maintenance; on December 17, 2013

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following five operability evaluations or functionality assessments affecting risk significant systems to assess: 1) the technical adequacy of the evaluations; 2) whether continued system operability was warranted; 3) whether other existing degraded conditions were considered; 4) if compensatory measures were involved, whether the compensatory measures were in place, would work as intended, and were appropriately controlled; and 5) where continued operability was considered unjustified, the impact on Technical Specifications (TS) limiting condition for operations.

• AR 641066, SV-14A (Main Steam Safety) Valve Leak

• AR 634442, Diesel Fuel Oil Odor in Soil

• AR 637960, RCS Vent Path LTOP Operability

• AR 635016, Leak under Transfer Canal

• AR 644307, B Emergency Diesel Generator low temperature limit with recirculation damper locked closed

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

Permanent Modification: The inspectors reviewed the permanent modification listed below, to verify that the modification design, implementation, and testing did not degrade the design basis, and performance capabilities of risk significant equipment and did not place the plant in an unsafe or unanalyzed condition. The inspectors verified the modification satisfied the requirements of Procedure EGR-NGGC-005, Engineering Change, and 10 CFR 50, Appendix B, Criterion III, Design Control. Documents reviewed are listed in the Attachment.

• Engineering Change 79670, Additional Fourth Train of Auxiliary Feedwater Pump

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following three post-maintenance test procedures and/or test activities to assess if: 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) acceptance criteria were clear and 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. Documents reviewed are listed in the Attachment.

• Cycle Breaker 52/32A, Feed to 480V Bus BS IAW with OST-948, Auto-start of Dedicated Shutdown Diesel Generator following breaker replacement

• A Emergency Diesel Generator Fast Start Surveillance IAW with OST-409-1, following EC 89063, EDG Governor and Booster Tubing Upgrade

• HVS-5 stroke test following installation of stroke limiter on the recirculation damper

b. Findings

No findings were identified.

1R20 Refueling and Outage Activities

a. Inspection Scope

Unit 2 Refueling Outage: For the outage that began on September 14, 2013, and ended on November 6, 2013 the inspectors evaluated licensee outage activities as described below to verify that the licensee considered risk in developing outage schedules, adhered to administrative risk reduction methodologies they developed to control plant configuration, and adhered to operating license and technical specification requirements that maintained defense-in-depth. The inspectors also verified that the licensee developed mitigation strategies for losses of key safety functions. Documents reviewed are listed in the Attachment.

• Reviewed the licensees responses to emergent work and unexpected conditions to verify that resulting configuration changes were controlled in accordance with the outage risk control plan.

• Periodically reviewed the setting and maintenance of containment integrity to establish that the RCS and containment boundaries were in place and had integrity when necessary.

• Observed fuel handling operations during reactor core reload to verify that those operations and activities were being performed in accordance with TS and procedural guidance.

• Reviewed the videotape of core loading verification and alignment with Reactor Engineering personnel.

• Reviewed system lineups and/or control board indications to verify that TS, license conditions, and other requirements, commitments, and administrative procedure prerequisites for mode changes were met prior to changing modes or plant configurations.

• Conducted a containment walkdown to inspect for overall cleanliness and material condition of plant equipment after the licensee completed their closeout inspection prior to restart.

• Observed the approach to criticality, placing the main generator on-line which completed the refueling outage and portions of the power ascension activities.

• Reviewed the items that had been entered into the CAP to verify that the licensee had identified outage related problems at an appropriate threshold.

• Reviewed waiver requests, self-declarations and fatigue assessments to verify the licensee is managing fatigue.

• Observed activities to verify that the licensee maintained defense-in-depth commensurate with the outage risk control plan for key safety functions and applicable TS when taking equipment out of service.

Unit 2 Forced Outage: For the unscheduled outage that began on November 6 and ended on November 11 the inspectors evaluated licensee outage activities to verify that the licensee considered risk in developing outage schedules, adhered to administrative risk reduction methodologies they developed to control plant configuration, and adhered to operating license and technical specification requirements that maintained defense-in-depth. An inspector accompanied licensee personnel on a containment walkdown prior to unit start-up to assess the material condition of safety related and risk significant SSCs. The inspectors also observed the approach to criticality, placing the main generator on-line and portions of the power ascension activities. Inspectors reviewed the items entered into the licensees CAP to establish that the licensee identified problems related to the outage at an appropriate threshold and entered them into their CAP. Documents reviewed are listed in the Attachment.

b. Findings

Introduction:

The inspectors identified a Green non-cited violation of Technical Specification (TS) 5.4.1 for the failure to properly implement procedure PLP-006, Containment Vessel Inspection Closeout, prior to startup following RFO 28. The improper closeout resulted in various tools as well as bags of consumable items and debris left in containment that could interact with the containment sump strainer following an accident.

Description:

On November 5, 2013, the licensee completed procedure PLP-006, Containment Vessel Inspection Closeout, to ensure that all equipment not identified in the procedure was removed and that latent debris was left at an acceptable level prior to reactor startup following the refueling outage. Following the licensees completion of this procedure the inspectors performed a containment closeout inspection prior to reactor startup. During this inspection, the inspectors noted various tools, bags of consumable items, and a bag of debris in containment that should have been removed by the licensee. The licensee subsequently initiated a CR 640903, removed the items identified by the inspectors, and re-performed procedure PLP-006 to further identify materials that should have been previously removed. During the licensees additional inspection, hundreds of additional items were removed from containment.

The licensee performed an evaluation of the total amount of materials and determined that a combination of the volume and type of material would not have caused the containment sump to be rendered inoperable had an accident occurred.

Analysis:

The failure to remove debris and various temporary materials as required by procedure PLP-006 was a performance deficiency. The performance deficiency was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the reliability and availability of ECCS equipment would be degraded by the introduction of material into the containment that would interact and reduce the available area on the recirculation sump strainer. Using IMC 0609, Appendix A, issued June 19, 2012, The SDP for Findings At-Power, the inspectors determined that this finding is of very low safety significance (Green) because the finding did not represent an actual loss of function of one or more non-Tech Spec Trains of equipment designated as high safety-significant in accordance with the licensees maintenance rule program for greater than 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. This finding had a cross-cutting aspect in the Work Practices component of the Human Performance area, because the licensee failed to ensure that supervisor and management oversight of procedure PLP-006 ensured that debris was removed as required during containment closeout prior to reactor startup. H.4(c)

Enforcement:

Technical Specification 5.4.1 requires in part, that written procedures be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, February 1978.

Section 2.b of Regulatory Guide 1.33, Revision 2, Appendix A requires procedures for plant startup from hot stand-by to minimum load. Section 8.1.a of Procedure GP-003, Normal Plant Startup from Hot Shutdown to Critical, requires that a containment closeout inspection be performed in accordance with PLP-006, Containment Vessel Inspection Closeout, prior to startup. Procedure PLP-006 requires that the licensee remove all equipment not identified in the procedure and ensure that latent debris is left at an acceptable level prior to reactor startup following a refueling outage.

Contrary to the above, on November 5, 2013, the licensee left various tools, bags of consumable items, and debris in containment that would have impacted the availability and reliability of the containment ECCS sump. Following the discovery of this issue, the licensee entered this issue into their corrective action program and re-performed procedure PLP-006. Because this violation was of very low safety significance (Green)and it was entered into the licensees corrective action program (CAP) as AR 604323, this violation is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. (NCV 05000261/2013005-02), Transient Materials Not Removed from Containment Prior to Reactor Startup.

1R22 Surveillance Testing

a. Inspection Scope

For the three surveillance tests listed below, the inspectors witnessed testing and/or reviewed the test data to verify that the systems, structures, and components involved in these tests satisfied the requirements described in the TS, the UFSAR, and applicable licensee procedures, and that the tests demonstrated that the SSCs were capable of performing their intended safety functions. Documents reviewed are listed in the

.

Routine Surveillances

• FMP-017, Core Mapping Following Fuel Loading, Rev. 11 In-Service Tests

• OST-163, Safety Injection Test and Emergency Diesel Generator Auto Start on Loss of Power and Safety Injection (Refueling), Rev. 66 Containment Isolation Valve Testing

• OST-933-2, Penetration 24, CVC Charging line (CVC-282, CVC-204A, CVC-309A)

Leakage Test, Rev.4

b. Findings

No findings were identified.

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 ML13009A376, ML13039A274, ML130870518, ML131680017, ML123630065, ML13310A668, and ML13331A408, 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.

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 (RAs),

High Radiation Areas (HRAs), and airborne radioactivity areas established within the Radiologically Controlled Area (RCA) of the auxiliary building, reactor containment 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, discrete radioactive particles, airborne radioactivity, gamma surveys with a range of dose rate gradients, and pre-job surveys for upcoming tasks. The inspectors also discussed changes to plant operations that could contribute to changing radiological conditions since the last inspection. For selected outage jobs, the inspectors attended 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. Changes to procedural guidance for LHRA and Very High Radiation Area controls were discussed with health physics (HP) supervisors. Controls and their implementation for storage of irradiated material within the spent fuel pool were reviewed and discussed in detail.

Established radiological controls (including airborne controls) were evaluated for selected online work including the Waste Holdup Tank filter change and a reactor building entry at-power. In addition, licensee controls for areas where dose rates could change significantly as a result of plant shutdown and refueling operations were reviewed and discussed.

Occupational workers adherence to selected RWPs and HP technician (HPT)proficiency in providing job coverage were evaluated through direct observations and interviews with licensee staff. Electronic dosimeter (ED) alarm set points and worker stay times were evaluated against area radiation survey results for filter replacement and a reactor building at-power entry. Procedures for the use of personnel dosimetry (ED alarms, extremity dosimetry, multibadging in high dose rate gradients, etc.) were reviewed as well as 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 discussed equipment sensitivity, alarm setpoints, and release program guidance with licensee staff.

The inspectors compared recent 10 CFR Part 61 results for the Dry Active Waste (DAW)radioactive waste stream with radionuclides used in calibration sources to evaluate the appropriateness and accuracy of release survey instrumentation. The inspectors also reviewed records of leak tests on selected sealed sources and discussed nationally tracked source transactions with licensee staff.

Problem Identification and Resolution: Nuclear Condition Reports (NCR)s associated with radiological hazard assessment and control were reviewed and assessed. The inspectors evaluated the licensees ability to identify and resolve the issues in accordance with licensee procedures. The inspectors also evaluated the scope of the licensees internal audit program and reviewed recent assessment results.

Radiation protection activities were evaluated against the requirements of Updated Final Safety Analysis Report (UFSAR) Section 12; Technical Specifications (TS) Sections 5.4 and 5.7; 10 CFR Parts 19 and 20; and approved licensee procedures. Licensee programs for monitoring materials and personnel released from the RCA were evaluated against 10 CFR Part 20 and IE Circular 81-07, Control of Radioactively Contaminated Material. Documents reviewed are listed in the report Attachment.

b. Findings

Introduction:

A self-revealing, Green, Non-cited Violation (NCV) of TS 5.7.1, High Radiation Area, was identified when two workers entered a HRA without proper authorization. Specifically, the workers entered a HRA without receiving a briefing on radiological conditions and without the required dosimetry.

Description:

On March 15, 2012, two auxiliary operators (AO)s were tasked with removing the Residual Heat Removal (RHR) system from service, which required manual actions in the RHR heat exchanger room. The plant was in startup and radiological conditions were changing. Specifically, dose rates in the RHR heat exchanger room had increased to the point that it was upgraded from RA to HRA with dose rates up to 400 mrem/hr at 30 cm from a pipe. The AOs were briefed by the control room that plant conditions were changing and they were told to contact HP prior to entering the area. However, when the AOs attempted to enter the RCA, there was no HPT available at the control point. Rather than wait for the HPT to return, they proceeded to the staging area inside the RCA without receiving a briefing on updated radiological conditions. They had previously been in the RCA and were still signed in on RWP number 6095 with normal, non-vibrating EDs. RWP 6095 had ED alarm setpoints of 16 mrem (dose) and 120 mrem/hr (dose rate); a stop-work hold point for general area dose rates of 120 mrem/hr or greater; and a requirement to use vibrating teledosimetry in HRAs. While awaiting control room authorization to begin work, one of the AOs had an informal discussion with an HPT on tasks to be performed in the RHR heat exchanger room. However, this conversation resulted in no action taken by either the AOs or HP to verify HRA entry requirements would be met. Without heeding the upgraded radiological posting (HRA), the AOs entered the RHR heat exchanger room to perform the task. During work inside the room, one of the AOs received a dose rate alarm indicating he entered a radiation field of 175 mrem/hr. The alarm was not acknowledged by him or the other AO until they exited the RCA and attempted to log out.

Analysis:

The inspectors determined that the unauthorized entry into a HRA was a performance deficiency. This finding was determined to be greater than minor because it was associated with the Occupational Radiation Safety Cornerstone attribute of Human Performance and adversely affected the cornerstone objective of ensuring adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian nuclear reactor operation. Workers who enter HRAs without adequate knowledge of current radiological conditions, and without proper electronic dosimetry, could receive unintended occupational exposures. The finding was evaluated using the Occupational Radiation Safety Significance Determination Process.

The finding was not related to As Low As Reasonably Achievable planning, nor did it involve an overexposure or substantial potential for overexposure, and the ability to assess dose was not compromised. Therefore, the inspectors determined the finding to be of very low safety significance (Green). This finding involved the cross-cutting aspect of Human Performance, Work Practices H.4.a] because the HRA event was a direct result of inadequate pre-job briefings and a lack of self and peer checking on the part of the work crew.

Enforcement:

TS 5.7.1, High Radiation Area, requires individuals entering HRAs to meet one or more of the following criteria: 1) be provided with a survey meter; 2) wear an ED and be made aware of radiological conditions in the area; or 3) be escorted by an HPT. Contrary to the above, on March 15, 2012, two workers entered a HRA without a survey meter, without the correct ED, without being made aware of radiological conditions in the area, and without HPT escort. Upon identification, the licensee immediately implemented RCA access restrictions on the workers. This violation is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. The violation was entered into the licensees Corrective Action Program (CAP) as NCR 00524523. (NCV 05000261/2013005-03, Unauthorized Entry Into a HRA).

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

Transportation

a. Inspection Scope

Waste Processing and Characterization: During inspector walk-downs, accessible sections of the liquid and solid radwaste processing systems were assessed for material condition and conformance with system design diagrams. Inspected equipment included radwaste storage tanks, resin transfer piping, resin and filter packaging components, temporary outside processing systems, and abandoned evaporator equipment. The inspectors discussed component function, processing system changes, and radwaste program implementation with licensee staff.

The 2012 Radioactive Effluent Report and radionuclide characterizations from 2010 -

2013 for each major waste stream were reviewed and discussed with radwaste staff.

For primary resin and DAW the inspectors evaluated analyses for hard-to-detect nuclides, reviewed the use of scaling factors, and examined quality assurance comparison results between licensee waste stream characterizations and outside laboratory data. Waste stream mixing, concentration averaging methodology for resin and filter waste streams were evaluated and discussed with radwaste staff. The inspectors also reviewed the licensees procedural guidance for monitoring changes in waste stream isotopic mixtures.

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

Transportation: Selected shipping records were reviewed for consistency with licensee procedures and compliance with NRC and Department of Transportation (DOT)regulations. The inspectors reviewed emergency response information, DOT shipping package classification, waste classification, and radiation survey results. Licensee procedures for opening and closing Type B shipping casks were compared to Certificate of Compliance requirements. The inspectors reviewed training records of shipping technicians in-lieu of actual shipment observations. No shipments were available to observe during the week of inspection.

Problem Identification and Resolution: The inspectors reviewed CAP documents in the areas of shipping and radwaste processing. The inspectors evaluated the licensees ability to identify and resolve the identified issues. The inspectors also reviewed recent self-assessment results.

Radwaste processing, radioactive material handling, and transportation activities were reviewed against the requirements contained in the licensees Process Control Program, UFSAR Chapter 11, 10 CFR Part 20, 10 CFR Part 61, 10 CFR Part 71, and 49 CFR Parts 172-178. Licensee activities were also evaluated against guidance provided in the Branch Technical Position on Waste Classification (1983) and NUREG-1608.

Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

The inspectors verified the PIs identified below. For each PI, the inspectors verified the accuracy of the PI data that had been previously reported to the NRC by comparing those data to the actual data, as described below. The inspectors also compared the licensees basis in reporting each data element to the PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Indicator Guideline, Rev. 6. In addition, the inspectors interviewed licensee personnel associated with collecting, evaluating, and distributing these data.

Mitigating Systems Cornerstone

• Mitigating Systems Performance Index (MSPI), Heat Pressure Injection For the period from October 2012 through September 2013, the inspectors reviewed Licensee Event Reports (LERs), records of inoperable equipment, and Maintenance Rule records, CRs, Consolidated Derivation Entry Reports, and System Health Reports to verify that the licensee had accurately accounted for unavailability hours that the subject systems had experienced during the subject period. The inspectors also reviewed the number of hours those systems were required to be available and the licensees basis for identifying unavailability hours.

Occupational Radiation Safety Cornerstone The inspectors reviewed the Occupational Exposure Control Effectiveness PI results for the Occupational Radiation Safety Cornerstone from January 2012 through October, 2013. For the assessment period, the inspectors reviewed ED alarm logs and NCRs related to controls for exposure significant areas. Documents reviewed are listed in the

.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

a. Inspection Scope

Routine Review of Action Requests (ARs): To aid in the identification of repetitive equipment failures or specific human performance issues for follow-up, the inspectors performed frequent screenings of items entered into the CAP. The review was accomplished by reviewing daily AR reports.

Semi-Annual Trend Review: The inspectors performed a review of the CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.1, licensee trending efforts, and licensee human performance results.

The inspectors review nominally considered the six month period of July 2013, through December, 2013, although some examples may expand beyond those dates when the scope of the trend warranted. The reviews included issues documented outside the normal CAP in major equipment problem lists, repetitive and rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments.

The inspectors compared and contrasted their results with the results contained in the latest monthly and quarterly trend reports. Corrective actions associated with a sample of the issues identified in the trend reports were reviewed for adequacy. Documents reviewed are listed in the Attachment.

The inspectors also evaluated the trend reports against the requirements of the CAP as specified in 10 CFR 50, Appendix B, Criterion XVI, and in Procedures CAP-NGGC-0200, Corrective Action Program, and CAP-NGGC-0206, Corrective Action Program Trending and

Analysis.

Operator Workarounds: The inspectors reviewed the cumulative effects of deficiencies that constituted operator workarounds to determine whether or not they could: affect the reliability, availability, and potential for misoperation of a mitigating system; affect multiple mitigating systems; or affect the ability of operators to respond in a correct and timely manner to plant transients and accidents. The inspectors also assessed whether operator workarounds were being identified and entered into the licensees corrective action program at an appropriate threshold.

b. Observations and Findings

No findings were identified. The inspectors evaluated trending methodology and observed that the licensee had performed a detailed review. The licensee routinely reviewed cause codes, involved organizations, key words, and system links to identify potential trends in their CAP data. The inspectors compared the licensee process results with the results of the inspectors daily screening, and did not identify any discrepancies or potential trends in the CAP data that the licensee had failed to identify.

4OA3 Event Follow-up

a. Inspection Scope

Unit 2 Reactor Trip and Safety System Actuation: Following the reactor trip that occurred on November 6, 2013, the inspectors responded to the control room and evaluated the status of mitigating systems and fission product barriers, equipment and personnel performance, and related plant management decisions to assist NRC management in making an informed evaluation of plant conditions. The automatic reactor trip occurred from approximately 18 percent RTP due to a loss of the 4kV bus voltage which also initiated the safety system actuation. As appropriate, the inspectors:

1) observed plant parameters and status, including mitigating systems/components required to maintain the plant in a safe configuration and in accordance with TS requirements; 2) evaluated whether alarms/conditions preceding and following the trip were as expected; 3) evaluated the performance of plant systems and operator actions; and, 4) confirmed proper NRC classification and reporting of the event.

b. Findings

No findings were identified.

4OA5 Other Activities

.1 Quarterly Resident Inspector Observations of Security Personnel and Activities

a. Inspection Scope

During the inspection period, the inspectors observed 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 Operation of an Independent Spent Fuel Storage Installation (ISFSI) (IP 60855.1)

a. Inspection Scope

The inspectors performed a walkdown and external inspection of the two ISFSIs on site (reference dockets 72-3 and 72-60). The inspectors observed the general condition of the structures and passive cooling passages.

b. Findings

No findings were identified.

.3 (Closed) Unresolved Item (URI) 05000261/2013007-07: Questions Regarding License

Basis Design Requirements for Degraded Voltage Relays (ML13182A032)

a. Inspection Scope

During the 2013 H. B. Robinson triennial component design bases inspection (ML13182A032), the team identified an unresolved item regarding the degraded grid voltage relays (DGVRs). Specifically, the effect of system and transient harmonics on proper operation of the DGVRs was not analyzed. The DGVR vendor manual stated that the relay employs a peak voltage detector, and harmonic distortion on the AC waveform can have a noticeable effect on the relay operating point and the measuring instruments used to calibrate the relay. The vendor manual also stated that the relay is available with an internal harmonic filter for applications where waveform distortion is a factor. The inspection team noted that the DGVRs in use at Robinson did not have harmonic filters installed. The team was concerned that harmonics on the 480V system could cause the DGVRs to fail to perform as required by technical specifications (TS).

This item was unresolved pending further inspection to determine if the licensees performance constituted a violation of NRC regulatory requirements. The team determined that additional consultation with the Office of Nuclear Reactor Regulation (NRR) was warranted before reaching a final disposition of the unresolved item.

Following consultation with NRR, the team determined that the licensee was required to evaluate the potential effects of system harmonics as part of their design control process.

The licensee performed an engineering evaluation which concluded that harmonics could potentially cause the DGVRs time delay function to reset; however, harmonics would not adversely impact the degraded grid voltage protection systems ability to perform its intended safety function based on the harmonics recorded during testing and the relay set points contained in procedures. The licensees engineering evaluation also recommended that harmonic filters be installed on the DGVRs to minimize the potential for equipment relay malfunction as a result of harmonics on the electrical distribution system. The team reviewed the licensees engineering evaluation, DGVR calibration procedures, and planned corrective actions and determined they were adequate.

b. Findings

The team identified a performance deficiency and an associated minor violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control. In accordance with Inspection Manual Chapter 0612, minor violations are not routinely documented in inspections reports; however, these may be documented to capture inspection activities and conclusions for closing an unresolved item.

The licensees failure to verify or check the adequacy of design of the DGVRs was a performance deficiency. Specifically, the licensee failed to evaluate the effect of electrical system harmonics on the ability of the DGVRs to perform their safety function as specified in the updated final safety analysis report and TS. The team used Inspection Manual Chapter 0612, Appendix B, Issue Screening, dated September 7, 2012, and determined the performance deficiency to be of minor significance because the total harmonic distortion identified during testing on emergency buses E1 and E2 would not adversely impact the degraded grid voltage protection systems ability to perform its intended safety function, based on the relay set points contained in calibration procedures.

Appendix B of 10 CFR Part 50, Criterion III, Design Control, requires in part, that design control measures shall provide for verifying or checking the adequacy of design, such as by the performance of design reviews, by the use of alternate or simplified calculational methods, or by the performance of a suitable testing program. Contrary to the above, the licensee failed to verify or check the adequacy of design of the DGVRs.

The licensee performed an engineering evaluation which concluded that harmonics could potentially cause the DGVRs time delay function to reset; however, harmonics would not adversely impact the degraded grid voltage protection systems ability to perform its intended safety function based on the harmonics recorded during testing and the relay set points contained in procedures. The licensee entered this issue into their corrective action program as nuclear condition reports 601203 and 652333. The planned corrective actions include installing harmonic filters on the DGVRs to minimize the potential for equipment relay malfunction as a result of harmonics. Because this issue was entered into the licensees corrective action program and was of minor significance, this failure to comply with 10 CFR Part 50, Appendix B, Criterion III, Design Control, constituted a minor violation that is not subject to enforcement action in accordance with NRCs Enforcement Policy. This URI is now closed.

4OA6 Meetings, Including Exit

On January 16, 2014, the resident inspectors presented the inspection results to Mr. R.

Gideon and other members of licensee management. The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

M. Blew, Site ISI Engineer

S. Connelly, Licensing

T. Cosgrove, Plant General Manager

H. Curry, Training Manager

D. Douglas, Maintenance Manager

P. Downing, Duke Steam Generator Integrity

R. Gideon, Vice President

M. Glover, Director - Site Operations

J. Hendrickson, Steam Generator Project Manager

R. Hightower, Licensing/Reg. Programs Supervisor

D. Hoffman, Nuclear Oversight Manager

K. Holbrook, Operations Manager

B. Houston, Radiation Protection Superintendent

L. Martin, Engineering Director

K. Moser, Outage & Scheduling Manager

G. Pizzuti, Site BACC Program Owner

C. Sherman, Radiation Protection Manager

T. Thulien, Duke Qualified Data Analyst, Level III

S. Wheeler, Organizational Effectiveness Manager

S. Williams, Chemistry Manager

NRC personnel

G. Hopper, Chief, Reactor Projects Branch 4

J. Zimmerman, Chief, Electrical Engineering Branch, Office of Nuclear Reactor Regulation

(NRR)

R. Mathew, Team Leader, Electrical Engineering Branch, NRR

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened &

Closed

05000261/2013005-01 NCV Inadequate Preparation for Cold Weather Conditions (Section 1R01)

05000261/2013005-02 NCV Transient Materials Not Removed from Containment Prior to Reactor Startup (Section 1R20)

05000261/2013005-03 NCV Unauthorized Entry Into a HRA (Section 2RS1)

Closed

05000261/2013007-07 URI Questions Regarding License Basis Design Requirements for Degraded Voltage Relays (Section 4OA5.3)