IR 05000261/2014002

IR 05000261-14-002, Duke Energy Progress, Inc.: 1/01/2014-3/31/2014; H.B. Robinson Steam Electric Plant, Unit 2; Fire Protection, Inservice Inspection Activities, Maintenance Effectiveness, Operability Determinations

ML14119A278
Person / Time
Site:	Robinson
Issue date:	04/29/2014
From:	Hopper G NRC/RGN-II/DRP/RPB4
To:	William Gideon Carolina Power & Light Co
References
IR-14-002
Download: ML14119A278 (34)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION ril 29, 2014

SUBJECT:

H.B. ROBINSON STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT 05000261/2014002

Dear Mr. Gideon,

On March 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your H. B. Robinson Steam Electric Plant, Unit 2. On April 10, 2014, the NRC inspectors discussed the results of this inspection with Mr. M. Glover and other members of your staff.

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

NRC inspectors documented two NRC-identified findings and two self-revealing findings of very low safety significance (Green). Two of these findings involved a violation of NRC requirements. The NRC is treating these violations as non-cited violations (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest the violation or significance of the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington DC 20555-0001; 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 the H.B. Robinson Plant.

Additionally, as we informed you in the most recent NRC integrated inspection report, cross-cutting aspects identified in the last six months of 2013 using the previous terminology were being converted in accordance with the cross-reference in Inspection Manual Chapter 0310.

Section 4OA5 of the enclosed report documents the conversion of these cross-cutting aspects which will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review. If you disagree with the cross cutting aspect assigned, 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 H.B. Robinson Plant. 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 05000261/2014002 w/Attachment: Supplemental Information

REGION II==

Docket No: 50-261 License No: DPR-23 Report No: 005000261/2014002 Facility: H. B. Robinson Steam Electric Plant, Unit 2 Location: 3581 West Entrance Road Hartsville, SC 29550 Dates: January 1, 2014 through March 31, 2014 Inspectors: K. Ellis, Senior Resident Inspector C. Scott, Resident Inspector B. Collins, Reactor Inspector (1R08)

M. Bates, Sr. Operations Engineer (1R11)

Approved by: George T. Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000261/2014002, Duke Energy Progress, Inc.: 1/01/2014-3/31/2014; H.B. Robinson

Steam Electric Plant, Unit 2; Fire Protection, Inservice Inspection Activities, Maintenance Effectiveness, Operability Determinations.

The report covered a three-month period of inspection by resident inspectors and announced inspections by reactor inspectors. Four 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, Aspects Within the Cross-Cutting Areas dated December 19, 2013. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated January 28, 2013. The NRCs program for overseeing the safe operations of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision

Cornerstone: Initiating Events

Green.

A self-revealing Green finding (FIN) was identified for the licensees failure to perform adequate preventive maintenance (PM) in accordance with, licensee procedure ADM-NGGC-107, Equipment Reliability Process, for 4 KV Breaker 52/7, Unit Auxiliary to 4 KV Bus 1. As a result, while transferring loads from the start-up transformer, a broken operating rod for breaker 52/7 prevented the breaker from closing and caused an automatic reactor trip.

The finding was more than minor because it was associated with the Initiating Events cornerstone attribute of Equipment Performance, and it adversely affected the associated 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 performance deficiency resulted in breaker 52/7 failing to close and subsequently causing an automatic reactor trip from 19 percent power operations on November 5, 2013. Using IMC 0609, Appendix A, issued June 19, 2012,

The Significance Determination Process (SDP) for Findings At-Power, the inspectors determined that this finding is of very low safety significance (Green) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment or functions would not be available. The performance deficiency had a cross-cutting aspect of Resolution in the area of Problem Identification and Resolution, because the licensee failed to take effective corrective actions to address a similar failure of an operating rod for the A circulating water (CW) pump breaker in 2011. (P.3)

(Section 1R12)

Green.

A self-revealing Green FIN was identified for the licensees failure to thoroughly inspect and remove foreign material from feedwater piping after initial breach of the pipe, as required by licensee procedure MNT-NGGC-0007, Foreign Material Exclusion Program. As a result, foreign material entered the C Steam Generator (SG) and damaged a tube which created a primary-to-secondary leak condition.

This finding was more than minor because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone, and it adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

Specifically, foreign material entered the SG and damaged a SG tube, which increased the likelihood of a SG tube rupture (SGTR) and challenged the reactor coolant system (RCS) integrity safety function during shutdown. The inspectors used IMC 0609,

Significance Determination Process, Attachment 0609.04, issued June 19, 2012, Initial Characterization of Findings, and Appendix A, issued June 19, 2012, The Significance Determination Process (SDP) for Findings At-Power, and determined that the finding was of low safety significance (Green) because testing showed that the affected SG tube could sustain three times the differential pressure across the tube during normal full power and that the SG did not violate the accident leakage performance criterion. The performance deficiency had a cross-cutting aspect of Challenge the Unknown in the area of Human Performance because the licensee did not stop when faced with the unknown or evaluate and manage risk before proceeding. Specifically, the licensee should have evaluated and addressed the FME issue resulting from the pipe spring condition during the initial breach of the feedwater piping before continuing. (H.11)

(Section 1R08)

Cornerstone: Mitigating Systems

Green.

A Green

NRC-Identified

non-cited violation (NCV) of Facility Operating License DPR-23, Condition 3.E, Fire Protection Program, was identified for the licensees failure to identify, critique, and develop corrective actions for fire brigade performance weaknesses during two fire drills as required by procedure TPP-219, Fire Protection Training Program. Upon identification of these weaknesses by the inspectors, the licensee entered them into the corrective action program (CAP), performed an apparent cause evaluation, and revised procedure TPP-219 to further define the roles and responsibilities of the drill controllers as well as the standards used to critique the fire brigade.

The licensees failure to identify, critique, and develop appropriate actions for fire brigade performance weaknesses during two fire drills as required by procedure TPP-219 was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external factors attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using IMC 0609, Appendix A, issued June 19, 2012, The Significance Determination Process (SDP) for Findings At-Power,

Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to be of very low safety Significance (Green) in accordance with question D.1 because although the finding involved fire brigade training requirements, the fire brigade demonstrated the ability to meet the required times for fire extinguishment for the fire drill scenarios and the finding did not significantly affect the fire brigades ability to respond to a fire. The performance deficiency had a cross-cutting aspect of Consistent Process in the area of Human Performance, because the licensee failed to use a consistent, systematic approach during conduct of fire brigade drills and during the subsequent critique process. (H.13) (Section 1R05)

Green.

The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B,

Criterion III, Design Control, because the licensee failed to provide adequate design control measures to ensure appropriate specifications were translated into procedures for diesel fuel oil (DFO) to ensure that the DFO temperatures remained above the DFO cloud point. The licensee entered this into the CAP as action request (AR) 664223 and took immediate corrective actions to change the cloud point acceptance criteria from 23 degrees to 10 degrees Fahrenheit and revise procedure OP-925, Cold Weather, to install temporary heaters if outside temperatures fell below 15 degrees Fahrenheit.

The licensees failure to provide design control measures to ensure that the DFO temperature was maintained such that the cloud point was not reached was a performance deficiency. This finding is more than minor because it is associated with the protection against external factors attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, during periods of cold weather the DFO temperature could have been allowed to fall below its cloud point and affect operation of the emergency diesel generator (EDG) and/or the dedicated shutdown diesel generator operation due to the DFO transfer system becoming inoperable. The inspectors evaluated the significance of this finding using IMC 0609 Appendix A, dated June 19, 2012, The Significance Determination Process (SDP) for Findings at Power,

Exhibit 2, Mitigating Systems Screening Questions. The inspectors determined that this finding was of very low safety significance (Green) because the finding is a deficiency affecting the design or qualification of a mitigating SSC; however, the SSC maintained its operability or functionality since the design conditions were not actually reached. The performance deficiency had a cross-cutting aspect of Design Margins in the area of Human Performance because the licensee failed to recognize that additional actions were required to maintain operability of the DFO system when ambient temperatures are below the maximum administrative limit even though samples are reviewed monthly per the DFO Testing Program. (H.6) (Section 1R15)

REPORT DETAILS

Summary of Plant Status

The unit began the inspection period at 100 percent power. The unit tripped on January 9, 2014, during testing of steam generator water level protection. The unit returned to 100 percent power on January 13, 2014. On March 7, 2014, the unit entered a forced outage to identify and repair a tube leak on the C steam generator. The unit remained shutdown through the end of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

1R01 Adverse Weather Protection

a. Inspection Scope

Actual Adverse Weather: The inspectors conducted a site walkdown during periods of freezing temperatures on January 7, 2014, and prior to a winter storm on January 28, 2014, to verify that the plants design features and implementation of procedures were sufficient to protect plant systems from the effects of adverse weather.

b. Findings

No findings were identified.

1R04 Equipment Alignment

a. Inspection Scope

Partial System Walkdowns: The inspectors performed the four 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 EDG during testing of the A EDG

• Walkdown of systems required to mitigate steam generator tube rupture (SGTR) with elevated primary to secondary side leakage

• Spent fuel pool cooling with core located in spent fuel pool

• Residual heat removal (RHR) system during reduced inventory Complete System Walkdown: The inspectors conducted a detailed review of the alignment and condition of the C Auxiliary Feedwater (AFW) 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) section listed in the

. 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 six 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 Updated Final Safety Analysis Report (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:

• Dedicated Shutdown Diesel Generator Enclosure (fire zone 25D)

• AFW Pump Room (fire zone 6)

• Service Water Intake Structure (fire zone 29)

• Unit 2 Cable Spreading Room (fire zone 19)

• Containment (fire zone 24)

• Emergency Switchgear Room (E1/E2) (fire zone 20)

Annual Fire Protection Drill Observation: To evaluate the readiness of personnel to fight fires, the inspectors observed fire brigade performance during an announced drill near the generator hydrogen dryer on the mezzanine deck of the Unit 2 turbine building on January 27, 2014, and during an unannounced drill on February 5, 2014, in the emergency switchgear room. This included observing the pre-drill briefing for the drill controllers, dress out of the fire brigade members in the fire locker, fire brigade performance at the fire scene, and the post-drill critiques for the controllers and the fire brigade. The inspectors evaluated the fire brigade performance to verify that they responded to the fire in a timely manner, donned proper protective clothing, used self-contained breathing apparatus, and had the equipment necessary to control and extinguish the fire. The inspectors also assessed the adequacy of the fire brigades fire fighting strategy including entry into the fire area, communications, search and rescue, and equipment usage.

b. Findings

Introduction:

A Green NRC-Identified NCV of Facility Operating License DPR-23, Condition 3.E, Fire Protection Program, was identified for the licensees failure to identify, critique, and develop corrective actions for fire brigade performance weaknesses during two fire drills as required by procedure TPP-219, Fire Protection Training Program.

Description:

The inspectors observed fire drills on January 27, 2014, and February 5, 2014, from various locations including the main control room, fire brigade staging area and command post, and the simulated fire location. A licensee drill controller was also present at these locations. The inspectors noted several performance weaknesses during the drill including the following:

• An individual attempted to enter the fire area without their personal protection equipment being properly donned.

• While the use of the thermal imaging camera was discussed as critical during the pre-drill briefing, it was not used to assess the fire location or combat the fire.

• There were multiple weaknesses in the fire brigade leaders command and control including leaving the area without a turnover and failing to refer to the fire preplan schematic to combat the fire.

• Although identified during the pre-drill brief as a critical attribute, control room personnel did not determine the emergency classification of the drill.

• Control room personnel sent a first responder into a confirmed fire area with a known halon discharge, placing the individual in harms way (an Immediately Dangerous to Life or Health (IDLH) environment).

These identified issues were required by procedure TPP-219 to be assessed by the licensee drill controllers and were required to be documented on the critique sheet. The inspectors observed that these performance weaknesses were not discussed during the post drill critiques and were not documented in the condition report (CR) database to ensure the appropriate corrective actions for fire brigades performance weaknesses were developed. Procedure TPP-219, Section 8.6.10, required that all drills be critiqued to determine the effectiveness in meeting the drill objectives and that performance weaknesses shall be noted and appropriate corrective actions taken. Upon identification of these weaknesses by the inspectors, the licensee entered them into the CAP, performed an apparent cause evaluation, and revised procedure TPP-219 to further define the roles and responsibilities of the drill controllers as well as the standards used to critique the fire brigade.

Analysis:

The licensees failure to identify, critique, and develop appropriate actions for fire brigade performance weaknesses during two fire drills as required by procedure TPP-219 was a performance deficiency. The performance deficiency was more than minor because it was associated with the protection against external factors attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Using IMC 0609, Appendix A, issued June 19, 2012, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, the finding was determined to be of very low safety Significance (Green), in accordance with question D.1, because although the finding involved fire brigade training requirements, the fire brigade demonstrated the ability to meet the required times for fire extinguishment for the fire drill scenarios and the finding did not significantly affect the fire brigades ability to respond to a fire. The performance deficiency had a cross-cutting aspect of Consistent Process in the area of Human Performance, because the licensee failed to use a consistent, systematic approach during conduct of fire brigade drills and during the subsequent critique process. (H.13)

Enforcement:

Facility Operating License DPR-23, Condition 3.E, Fire Protection Program, requires in part, that the licensee shall implement and maintain in effect all provisions of the approved fire protection program as described in the UFSAR. UFSAR Appendix 9.5.1B, Fire Protection Program Description and Review, states that fire brigade training is provided in accordance with plant administrative procedure TPP-219.

Procedure TPP-219 requires a post drill critique for personnel participating in the drill, that performance weaknesses be identified, and appropriate corrective actions be put in place. Contrary to the above, on January 27, 2014, and February 5, 2014, inspectors identified five performance weaknesses during two drills which were not identified, critiqued, or placed into the CAP. Corrective actions included the performance of an apparent cause evaluation and a revision to procedure TPP-219 to further define the roles and responsibilities of the drill controllers as well as the standards used to critique the fire brigade. Because this violation was of very low safety significance (Green) and was entered into the CAP as CR 668755, this violation is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy. (NCV 05000261/2014002-01: Failure to Adequately Critique Fire Brigade Drills)

1R06 Flood Protection Measures

Underground Cable Inspection

a. Inspection Scope

The inspectors walked down two underground cable manholes/bunkers to verify the following:

• The cable was not submerged in water;

• The condition of any cable splices;

• The condition of any cable support structures; and

• The condition of any dewatering devices, if applicable.

The following cable/locations were inspected:

• A and B Service Water Pump location M-35

• C and D Service Water Pump location M-36

b. Findings

No findings were identified.

1R08 Inservice Inspection (ISI) Activities (IP 71111.08P, Unit 2)

a. Inspection Scope

Steam Generator (SG) Tube Inspection Activities: The inspectors observed the following activities and/or reviewed the following documentation and evaluated them against the licensees technical specifications, commitments made to the NRC, ASME Section XI, and Nuclear Energy Institute 97-06 (Steam Generator Program Guidelines):

• Reviewed the licensees in-situ SG tube pressure testing screening criteria. In particular, the inspectors assessed whether assumed NDE flaw sizing accuracy was consistent with data from the EPRI examination technique specification sheets (ETSS) or other applicable performance demonstrations.

• Verified that the appropriate tube (31-15) was in-situ pressure tested.

• Reviewed plans for and observed in-situ pressure testing activities and verified that testing was performed in accordance with EPRI In-Situ Pressure Test Guidelines, Revision 4.

• Verified in-situ pressure testing results conformed with the performance criteria.

• Compared the numbers and sizes of SG tube flaws/degradation identified against the licensees previous outage Operational Assessment .

• Reviewed the SG tube eddy current testing (ET) examination scope and expansion criteria.

• Evaluated if the licensees SG tube ET examination scope included potential areas of tube degradation identified in prior outage SG tube inspections and/or as identified in NRC generic industry operating experience applicable to the licensees SG tubes.

• Reviewed the licensees implementation of their extent-of-condition inspection scope and repairs for new SG tube degradation mechanism(s). No new degradation mechanisms were identified during the EC examinations.

• Reviewed the licensees repair criteria and processes.

• Verified that the licensee identified a reasonable cause for the SG leakage, and that corrective actions were taken or planned to address the cause.

• Evaluated if the ET equipment and techniques used by the licensee to acquire data from the SG tubes were qualified or validated to detect the known/expected types of SG tube degradation in accordance with Appendix H, Performance Demonstration for Eddy Current Examination, of EPRI Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7.

• Observed the licensees secondary side SG Foreign Object Search and Retrieval activities.

• Reviewed five samples of eddy current data, specifically including tube 31-15.

• Reviewed ET personnel qualifications.

Identification and Resolution of Problems: The inspectors reviewed a sample of ISI-related problems which were identified by the licensee and entered into the CAP as ARs and CRs. The inspectors reviewed the ARs and CRs to confirm the licensee had appropriately described the scope of the problem, and had initiated corrective actions.

The review also included the licensees consideration and assessment of operating experience events applicable to the plant. The inspectors performed this review to ensure compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. Documents reviewed are listed in the Attachment.

b. Findings

Introduction.

A self-revealing FIN was identified for the licensees failure to thoroughly inspect and remove foreign material from feedwater piping after initial breach of the pipe, as required by licensee procedure MNT-NGGC-0007, Foreign Material Exclusion Program. As a result, foreign material entered the C SG and damaged a tube which created a primary-to-secondary leak condition.

Description.

On Thursday, February 27, 2014, the C SG showed indications of a primary-to-secondary tube leak. Due to the increased trend of the leakage rate, on March 7, 2014, the licensee shut down the plant to repair the leak. Once the plant was shut down, the licensee identified that the leak was caused by a loose part which made a circumferentially-oriented cut through tube 31-15. The loose part was then removed and the tube was tested to verify that it continued to meet structural integrity and accident leakage criteria. Following the test, a plug repair was performed on the tube.

The licensee performed a metallurgical analysis, and the report stated that the loose part was a metal shaving composed of plain carbon steel. The licensee performed a complete inspection of the C SG for foreign objects and removed all items identified.

In parallel, the licensee conducted a cause evaluation and determined that the foreign material was introduced during replacement of feedwater piping upstream of the C SG during the Fall 2013 refueling outage. During cutting of the feedwater piping, the piping unexpectedly sprung open and the licensee failed to conduct an adequate initial breach inspection which allowed metal shavings to go undetected and ultimately, to be transported to the C SG. Licensee procedure MNT-NGGC-0007, Foreign Material Exclusion Program, Paragraph 1.1.1 stated that one of the purposes of the FME program was to Prevent introduction of foreign material into systems and components that could degrade nuclear fuel or plant equipment. Attachment 5 required an initial breach inspection of this section of feedwater piping because foreign material introduced in this location cannot be easily retrieved. Additionally, Paragraph 9.13.2.k stated that the licensee should consider using a boroscope or other method to verify final cleanliness if direct visual inspection cannot be accomplished. The licensee did not implement these control measures, further contributing to the failure to meet the stated purpose of the FME program.

Analysis.

The licensees failure to thoroughly inspect and remove foreign material from feedwater piping after initial breach of the pipe, as required by licensee procedure MNT-NGGC-0007, Foreign Material Exclusion Program, was a performance deficiency.

Specifically, the licensee failed to conduct an adequate initial breach inspection after cutting into the piping, and verify final cleanliness by visual inspection or other controlled measures (boroscope or fiber optics). This finding was of more than minor significance because it was associated with the Equipment Performance attribute of the Initiating Events cornerstone, and it adversely affected the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, foreign material entered the SG and damaged a SG tube, which increased the likelihood of a SGTR and challenged the reactor coolant system (RCS) integrity safety function during shutdown. The inspectors used IMC 0609, Significance Determination Process, Attachment 0609.04, issued June 19, 2012, Initial Characterization of Findings, and Appendix A, issued June 19, 2012, The Significance Determination Process (SDP) for Findings At-Power, and determined that the finding was of low safety significance (Green) because testing showed that the affected SG tube could sustain three times the differential pressure across the tube during normal full power and that the SG did not violate the accident leakage performance criterion. The performance deficiency had a cross-cutting aspect of Challenge the Unknown in the area of Human Performance because the licensee did not stop when faced with the unknown or evaluate and manage risk before proceeding.

Specifically, the licensee should have evaluated and addressed the FME issue resulting from the pipe spring condition during the initial breach of the feedwater piping before continuing. (H.11)

Enforcement.

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. Because this finding does not involve a violation and is of very low safety or security significance, it is identified as FIN 05000261/2014002-02, Steam Generator Tube Leak Resulting from Foreign Material.

1R11 Licensed Operator Requalification

a. Inspection Scope

Routine Operator Requalification Review: On March 28, 2014, 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 just in time training consisted of transferring auxiliary loads to the start-up transformer, taking the turbine generator offline, placing the residual heat removal system in service and maintaining control of the plant with a primary to secondary leak on the C SG.

Observation of Operator Performance: The inspectors observed main control room crew performance during the Unit 2 reactor startup from the forced outage on January 11, 2014. 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.

Annual Review of Licensee Requalification Examination Results: On February 7, 2014, the licensee completed the annual requalification operating examinations required to be administered to all licensed operators in accordance with 10 CFR 55.59(a)(2),

Requalification requirements, of the NRCs Operators Licenses. The inspectors performed an in-office review of the overall pass/fail results of the individual operating examinations and the crew simulator operating examinations in accordance with IP 71111.11, Licensed Operator Requalification Program and Licensed Operator Performance. The results were compared to the thresholds established in Section 3.02, Requalification Examination Results, of IP 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors reviewed the licensees effectiveness in performing the following two corrective maintenance activities. 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 653370653370 Dedicated Shutdown Diesel Generator (DSDG) Motor Operated Potentiometer Replacement following failure on December 31

• AR 642282642282 Robinson trip on 4 KV Bus under voltage while transferring loads

b. Findings

(Opened) Unresolved Item (URI): Defective Motor Operated Potentiometer causes failure of the DSDG during surveillance testing

Introduction:

An URI was identified regarding the trip of the DSDG, on December 31, 2013, during monthly surveillance testing. The URI is being opened to provide for additional inspection of the equipment issues that led to the failure and to review the results of the vendors analysis of a defective motor operated potentiometer to determine if a performance deficiency exists.

Description:

On December 31, 2013, during monthly testing of the DSDG in accordance with licensee procedure OST-910, Dedicated Shutdown Diesel Generator (Monthly), the output breaker tripped open on overcurrent while the operators were attempting to adjust DSDG output voltage. Operators in the field noted erratic voltage indication prior to the failure. Engineering identified that the likely cause was a failure of the motor operated potentiometer (MOP). The licensee replaced the MOP with a new part from stock and performed post maintenance testing. The MOP that was removed was sent offsite for forensic analysis. During examination, the licensee identified a manufacturing defect for the MOP. The licensees extent of condition investigation found the same manufacturing defect on the MOP installed in the DSDG and in a MOP in storage. The licensee replaced the MOP in the DSDG with a MOP that was verified to be acceptable.

Engineering has sent the defective components back to the vendor for additional analysis. This issue will be identified as URI 05000261/2014002-05; Defective Motor Operated Potentiometer causes failure of the DSDG during surveillance testing.

Inadequate Preventive Maintenance on 4 KV Breaker 52/7 Results in an Automatic Reactor Trip

Introduction:

A self-revealing Green finding was identified for the licensees failure to perform adequate preventive maintenance (PM) in accordance with licensee procedure ADM-NGGC-107, Equipment Reliability Process, for 4 KV Breaker 52/7, Unit Auxiliary to 4 KV Bus 1. As a result, while transferring loads from the start-up transformer, a broken operating rod for breaker 52/7 prevented the breaker from closing and caused an automatic reactor trip.

Description:

On November 5, 2013, reactor operators were transferring loads from the start-up transformer to the auxiliary transformer as part of power ascension following refueling outage (RFO) 28. During the breaker operation, 4 KV breaker 52/7 failed to close as expected and resulted in the actuation of two undervoltage relays. This undervoltage condition caused an automatic reactor trip. Following the trip, the licensee entered the issue into the CAP as AR 642282642282 The licensees investigation found that the phenolic operating rods for breaker 52/7 failed, which prevented the breaker from closing.

In 2011, Robinson experienced a similar failure of an operating rod for the A circulating water (CW) pump breaker. Corrective actions for the 2011 failure included revising the PM procedure for 4 KV breakers with the results from a material analysis. The material analysis identified stress cracking on an operating rod with the use of magnification equipment and noted that the cracks were not apparent through visual examination.

However, the licensee revised the PM to include inspection of the operating rods for stress cracks without the use of magnification equipment. Prior to the failure, during RFO 28, breaker 52/7 was inspected per the revised PM procedure and no issues associated with operating rods were noted. Following the reactor trip, the licensee re-inspected all the Westinghouse Type 50DH350E 4 KV breakers used in the fast bus transfer , including breaker 52/7, using magnification equipment and noted minor stress cracks on several operating rods, which were then replaced. Breaker 52/7 is classified as a critical component in accordance with licensee procedure ADM-NGGC-107, Equipment Reliability Process. As such, efforts are to be made to prevent all failures that are known to occur and are expected to occur at least once in the lifetime of the equipment. Further, critical components must have sufficient monitoring and maintenance coverage in frequency and scope to address a wide spectrum of possible failure mechanisms. The inspectors concluded that the preventive maintenance for breaker 52/7 was not sufficient to address known failures. The licensee took corrective actions to inspect all operating rods that were important to safety, replace the failed operating rods with a newer model, and initiated actions to replace Westinghouse Type 50DH350E 4 KV breakers during the next two refueling outages.

Analysis:

The licensees failure to perform adequate PM on 4 KV Breaker 52/7, in accordance with, licensee procedure ADM-NGGC-107, Equipment Reliability Process, was a performance deficiency. The finding was more than minor because it was associated with the Initiating Events cornerstone attribute of Equipment Performance, and it adversely affected the associated 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 performance deficiency resulted in breaker 52/7 failing to close and subsequently causing an automatic reactor trip from 19 percent power operations on November 5, 2013. Using IMC 0609, Appendix A, issued June 19, 2012, The Significance Determination Process (SDP) for Findings At-Power, the inspectors determined that this finding is of very low safety significance (Green) because the finding did not contribute to both the likelihood of a reactor trip and the likelihood that mitigating equipment or functions would not be available. The performance deficiency had a cross-cutting aspect of Resolution in the area of Problem Identification and Resolution, because the licensee failed to take effective corrective actions to address a similar failure of an operating rod for the A CW pump breaker in 2011. (P.3)

Enforcement:

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. Because the finding does not involve a violation of regulatory requirements and has very low safety significance (Green), it is identified as FIN 05000261/2014002-03, Inadequate Preventive Maintenance on 4 KV Breaker 52/7 Results in an Automatic Reactor Trip.

1R13 Maintenance Risk Assessments and Emergent Work Evaluation

a. Inspection Scope

For the five 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:

• Service Water Pump C and Service Water Booster Pump B out-of-service for maintenance with Winter Storm Watch

• Yellow risk condition while draining reactor coolant system (RCS) to lower inventory conditions, prior to head lift

• Yellow risk condition following failure feed regulator valve C due to freezing condition

• Review of the March 7, 2014, Unit 2 forced outage risk assessment

• Review of protected equipment required for core cooling with RCS time to boil less than one hour following core reload during the forced outage

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following seven 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 654679654679 C AFW Pump Min-flow piping isolation discovered open

• AR 654952654952 Oil discovered on floor of C RCP Pump Bay

• AR 664223664223 EDG Fuel Oil Storage Tank (FOST) Cloud point limit basis

• EC 95260, Engineering evaluation with respect to DFOST and tornado missiles

• AR 674319674319 Missing anchor on HVH-1 Emergency Control Station Enclosure

• AR 665072665072 Fire Water jockey pump replacement issues

• AR 671333671333 Possible primary-to-secondary leakage into SG C

b. Findings

Introduction:

The inspectors identified a Green NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, because the licensee failed to provide adequate design control measures to ensure appropriate specifications were translated into procedures for diesel fuel oil (DFO) to ensure that the DFO temperatures remained above the DFO cloud point.

Description:

On January 21, 2014, due to anticipated cold weather temperatures, the inspectors reviewed the Robinson DFO Testing Program and Information Notice (IN) 94-19, Emergency Diesel Generator Vulnerability to Failure from Cold Fuel Oil.

The inspectors identified that Robinsons DFO system could be susceptible to common mode failure of the EDGs as a result of temperature related changes in the diesel fuel oil system. The Robinson DFO Testing Program states that a maximum cloud point of 23 degrees Fahrenheit, which is verified monthly, was required for operability of the DFO system. During the impending period of cold weather, temperatures were expected to be below the 23 degrees Fahrenheit cloud point. Since the DFO storage tank, transfer pumps, and portions of the fuel lines to the EDGs are located above ground and outside, the inspectors determined that if the site experienced sustained temperatures below the cloud point specification, the DFO filters could become clogged with wax from the fuel and affect the operation of the transfer pumps.

The licensee documented the issue of concern in CR 664223, performed an evaluation to determine the minimum temperature for DFO operability, and sampled the DFO to verify that the current DFO cloud point was acceptable based on current ambient temperatures. The evaluation and the DFO sample determined that compensatory measures were required to ensure operability of the DFO system during cold weather.

Specifically, procedure OP-925, Cold Weather, was revised to install temporary heaters around the DFO system during periods of low outside temperatures to ensure the DFO cloud point was not reached. Additionally, the licensee changed the cloud point acceptance criteria for future deliveries of DFO from 23 to 10 degrees Fahrenheit.

Analysis:

The licensees failure to provide design control measures to ensure that the DFO temperature was maintained such that the cloud point was not reached was a performance deficiency. This finding is more than minor because it is associated with the protection against external factors attribute of the Mitigating Systems cornerstone and adversely affected the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences (i.e., core damage). Specifically, during periods of cold weather the DFO temperature could have been allowed to fall below its cloud point and affect operation of the emergency diesel generator (EDG) and/or the dedicated shutdown diesel generator operation due to the DFO transfer system becoming inoperable. The inspectors evaluated the significance of this finding using IMC 0609 Appendix A, dated June 19, 2012, The Significance Determination Process (SDP) for Findings at Power, Exhibit 2, Mitigating Systems Screening Questions. The inspectors determined that this finding was of very low safety significance (Green) because the finding was a deficiency affecting the design or qualification of a mitigating SSC; however, the SSC maintained its operability or functionality since the design conditions were not actually reached. The performance deficiency had a cross-cutting aspect of Design Margins in the area of Human Performance because the licensee failed to recognize that additional actions were required to maintain operability of the DFO system when ambient temperatures are below the maximum administrative limit even though samples are reviewed monthly per the DFO Testing Program. (H.6)

Enforcement:

Appendix B to 10 CFR Part 50, Criterion III, Design Control, states, in part that, measures shall be established to assure that applicable regulatory requirements and the design basis, are correctly translated into specifications, drawings, procedures, and instructions. Contrary to the above, prior to January 21, 2014, the licensee failed to provide measures to ensure appropriate design basis specifications were translated into procedures for the DFO transfer system. As a result, the DFO cloud point temperature could have been above outdoor temperatures during extreme cold weather conditions and impact EDG operability, due to the DFO transfer system being rendered inoperable.

Immediate corrective actions included changing the cloud point acceptance criteria from 23 degrees to 10 degrees Fahrenheit and revising procedure OP-925, Cold Weather, to install temporary heaters if outside temperatures fell below 15 degrees Fahrenheit.

Because this violation was of very low safety significance (Green) and was entered into the CAP as CR 664223, this violation is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy. (NCV 05000261/2014002-004: Failure to Provide Adequate Design Control Measures for Diesel Fuel Oil Cloud Point)

1R18 Plant Modifications

a. Inspection Scope

Permanent Modification: The inspectors reviewed the two permanent modifications 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 modification satisfied the requirements of licensee Procedure EGR-NGGC-005, Engineering Change, and 10 CFR Part 50, Appendix B, Criterion III, Design Control.

Documents reviewed are listed in the Attachment.

• EC 95228, Diesel Fuel Oil Winterization

• EC 95217, Fukushima Plant Modifications

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following five 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.

• Service water (SW) pump C run following preventive maintenance on SW pump C feeder breaker 52/24A

• DSDG surveillance test following replacement of the motor operated potentiometer for the automatic voltage regulator

• Service water pump C surveillance test following replacement of the pump motor

• Calibration of feed regulation valves following thaw of frozen sensing lines

• Testing of reactor protection system (RPS) relay (LC-496A1-X(B)) following replacement due to contact failure

b. Findings

No findings were identified.

1R20 Refueling and Outage Activities

a. Inspection Scope

Unit 2 Forced Outage: For the unscheduled outage that began on January 9, 2014, and ended on January 11, 2014, 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 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.

Unit 2 Forced Outage: For the outage that began on March 7, 2014, 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.

• The inspectors observed power reduction process, removing the reactor from service and portions of the cooldown to ensure that the requirements in the TS and selected licensee commitments were followed. The inspectors conducted a containment entry once Mode 3 had been reached to observe the condition of major, normally-inaccessible equipment and check for indications of previously unidentified leakage from the reactor coolant system.

• 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 offload and reload to verify that those operations and activities were being performed in accordance with TS and procedural guidance.

• Reviewed core loading verification and alignment.

• 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.

• 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.

b. Findings

No findings were identified.

1R22 Surveillance Testing

a. Inspection Scope

For the five 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

• OST-151-2, Safety Injection System Component Test Pump B, Rev. 34

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

• OST-401-1, EDG A Slow Speed Start, Rev. 61 Containment Isolation Valve Testing

• OST-933-15, Penetration 3, Primary Water to RT (RC-519A and RC-519B) Leakage Test, Rev.0 Reactor Coolant System Leakage Surveillance

• CP-014, Primary-to-Secondary Leak Rate Calculation, Rev.31

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, Residual Heat Removal System

• Mitigating Systems Performance Index, Cooling Water Systems For the period from January 2013 through December 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.

Barrier Integrity Cornerstone

• Reactor Coolant System Leakage The inspectors reviewed records of daily measures of RCS identified leakage and compared the reported performance indicator data with records developed by the licensee while analyzing previous samples, for the period from January 2013 through December 2013.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

a. Inspection Scope

Routine Review of Action Requests: 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.

Annual Sample Review of Emergency Lighting: In addition to the routine review, the inspectors selected to review AR 655665655665 high number of emergency lighting failures during preventive maintenance test, for a more in-depth review. The inspectors considered the following during the review of the licensees actions: 1) complete and accurate identification of the problem in a timely manner; 2) evaluation and disposition of operability/reportability issues; 3) consideration of extent of condition, generic implications, common cause, and previous occurrences; 4) classification and prioritization of the resolution of the problem; 5) identification of root and contributing causes of the problem; 6) identification of CRs; and 7) completion of corrective actions in a timely manner.

b. Observations and Findings

No findings were identified.

4OA3 Event Follow-up

a. Inspection Scope

Unit 2 Reactor Trip and Safety System Actuation: Following the reactor trip that occurred on January 9, 2014, 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 100 percent RTP as a result of a failed contact in the steam generator lo-lo level trip circuit coupled with steam generator water level protection channel testing. 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.

(Closed) LER 2013-003-00, Reactor Trip on 4 KV Bus Undervoltage during Load Transfer: On November 5, 2013, with the unit at 19 percent power, an automatic reactor trip occurred due to a loss of voltage on 4 KV Buses 1 and 2. The reactor trip occurred while operators were transferring loads from the Start-up transformer to the Auxiliary transformer as part of power ascension, following RFO 28. During the breaker operation, a broken operating rod on breaker 52/7 prevented the breaker from closing and resulted in a momentary loss of power to 4 KV Bus 2 and 4 KV Bus 1. For corrective actions, the licensee replaced the operating rod for the failed breaker and performed post maintenance testing to verify operation, prior to returning the unit to service. The inspectors reviewed the corrective actions and determined that they were adequate. The inspectors also reviewed post-trip activities to verify that the licensee identified and resolved event-related issues prior to restarting the plant. The enforcement aspects of this LER are documented in Section 1R12. This LER is closed.

b. Findings

No findings were identified.

4OA5 Other Activities

Cross-Reference for Transition to New Cross-Cutting Aspects The table below provides a cross-reference from the 2013 and earlier findings and associated cross-cutting aspects to the new cross-cutting aspects resulting from the common language initiative. These aspects and any others identified since January 2014 will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the 2014 mid-cycle assessment review.

Finding Old Cross-Cutting Aspect New Cross-Cutting Aspect 05000261/2013004-01 P.2(b) P.5 05000261/2013005-01 H.3(a) H.5 05000261/2013005-02 H.4(c) H.2 05000261/2013005-03 H.4(a) H.12

4OA6 Meetings, Including Exit

On April 10, 2014, the resident inspectors presented the inspection results to Mr. M. Glover 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

J. Batton, Robinson Steam Generator Maintenance Program Manager

T. Cosgrove, Plant General Manager

S. Connelly, Licensing

H. Curry, Training Manager

D. Douglas, Maintenance Manager

P. Downing, Duke Engineering Support Manager

C. Fletcher, Duke Corporate Nuclear Regulatory Affairs

E. Fonteneau, Duke Steam Generator Maintenance Engineer

R. Gideon, Vice President

M. Glover, Director - Site Operations

R. Hightower, Licensing/Reg. Programs Supervisor

D. Hoffman, Nuclear Oversight Manager

K. Holbrook, Operations Manager

E. Hurley, Duke Steam Generator Maintenance Engineer

L. Martin, Engineering Director

D. Mayes, Duke Steam Generator Maintenance Engineer

K. Moser, Outage & Scheduling Manager

M. Pastva, Jr., Nuclear Regulatory Affairs

C. Sherman, Radiation Protection Superintendent

S. Williams, Chemistry Manager

NRC personnel

G. Hopper, Chief, Reactor Projects Branch 4

E. Murphy, NRR

K. Karwoski, NRR

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened &

Closed

05000261/2014002-01 NCV Failure to Adequately Critique Fire Brigade Drills (Section 1R05)

05000261/2014002-02 FIN Steam Generator Tube Leak Resulting from Foreign Material (Section 1R08)

05000261/2014002-03 FIN Inadequate Preventive Maintenance on 4 KV Breaker 2/7 Results in an Automatic Reactor Trip (Section 1R12)

05000261/2014002-04 NCV Failure to Provide Adequate Design Control Measures for Diesel Fuel Oil Cloud Point (Section 1R15)

Opened

05000261/2014002-05 URI Defective Motor Operated Potentiometer causes failure of the DSDG during surveillance testing (Section 1R12)

Closed

05000261/2013-003-00 LER Reactor Trip on 4 KV Bus Undervoltage during Load Transfer (Section 4OA3)