IR 05000261/2014003

IR 05000261-14-003, 4/01/2014 - 6/30/2014; H.B. Robinson Steam Electric Plant, Unit 2; Follow-up of Events and Notices of Enforcement Discretion

ML14202A330
Person / Time
Site:	Robinson
Issue date:	07/21/2014
From:	Hopper G NRC/RGN-II/DRP/RPB4
To:	William Gideon Duke Energy Progress
References
IR-14-003
Download: ML14202A330 (32)

Text

July 21, 2014

SUBJECT:

H.B. ROBINSON STEAM ELECTRIC PLANT - NRC INTEGRATED INSPECTION REPORT 05000261/2014003

Dear Mr. Gideon:

On June 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your H. B. Robinson Steam Electric Plant, Unit 2. On July 17, 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 one self-revealing finding of very low safety significance (Green).

This finding involved a violation of NRC requirements. Additionally, one licensee-identified violation, which was determined to be of very low safety significance, is listed in this report. The NRC is treating these violations as non-cited violations (NCVs) 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 H.B.

Robinson. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the 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 05000261/2014003 w/Attachment: Supplemental Information

REGION II==

Docket No:

50-261 License No:

DPR-23 Report No:

005000261/2014003 Facility:

H. B. Robinson Steam Electric Plant, Unit 2 Location:

3581 West Entrance Road Hartsville, SC 29550

Dates:

April 1, 2014 through June 30, 2014

Inspectors:

K. Ellis, Senior Resident Inspector C. Scott, Resident Inspector J. Dodson, Senior Project Engineer D. Jackson, Project Engineer S. Sanchez, Sr. Emergency Preparedness Inspector M. Speck, Sr. Emergency Preparedness Inspector

Approved by:

George T. Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects

Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000261/2014003, Duke Energy Progress, Inc.; 4/01/2014-6/30/2014; H.B.

Robinson Steam Electric Plant, Unit 2; Follow-up of Events and Notices of Enforcement Discretion.

The report covered a three-month period of inspection by resident inspectors and announced inspections by reactor inspectors. One finding of very low safety significance (Green) was 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. 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.

A self-revealing Green non-cited violation (NCV) was identified for the licensees failure to promptly identify and correct degraded wire labels in the reactor protection cabinets, which were a condition adverse to quality, as required by 10 CFR Part 50,

Criterion XVI, Corrective Action. This resulted in an automatic reactor trip. Immediate corrective actions included inspection of both trains of relay racks to identify and remove any potential foreign material. The licensee also tested both trains of reactor protection relays to verify no foreign material was present. Additionally, the licensee plans to replace the wire labels in the reactor protection and safeguards relay racks during refueling outages 29 and 30. The licensee documented the issue in the corrective action program as CR 654789.

The performance deficiency was more than minor because it was associated with the equipment performance attribute of the initiating events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations.

Specifically, the degraded wire labels became lodged between contact 2-6 on relay LC-496A1-X(B), which set up the half-trip condition to cause a reactor trip, during the surveillance testing. 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 although the finding caused a reactor trip, it did not cause the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding had a cross-cutting aspect of identification in the area of problem identification and resolution because the licensee failed to implement a corrective action program with a low enough threshold for identifying issues in that the licensee process did not recognize, during review of the work requests for the degraded wire labels, that this issue should have been entered into the corrective action program as a nuclear condition report. (P.1) (Section 4OA)

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

REPORT DETAILS

Summary of Plant Status

The unit began the inspection period in a forced outage which began on March 7, 2014. The unit returned to 100 percent power on April 9, 2014, and remained there through the end of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity

==1R01 Adverse Weather Protection

a. Inspection Scope

Hot Weather Preparations:==

The inspectors reviewed the licensees preparations for hot weather to ensure equipment used in the licensees procedures was capable of functioning as intended. This included a field walkdown to assess the material condition and operation of ventilation and cooling equipment and a review of procedures designed to align equipment to support operation during the summer months. Risk-significant systems and areas reviewed included the service water system and supplemental cooling for containment. In addition, the inspectors conducted discussions with operations, engineering, and maintenance personnel to assess the licensees ability to identify and resolve deficient conditions associated with hot weather protection equipment prior to actual hot weather being experienced at the site. Documents reviewed are listed in the Attachment.

Evaluation of Summer Readiness of Offsite and Alternate AC Power Systems: The inspectors reviewed the licensees procedures used to respond to changing offsite grid conditions which included the implementation procedures protecting mitigating systems from adverse weather when notified that a Real Time Contingency Analysis (RTCA)shows inadequate post trip voltage. The inspectors also reviewed the procedural guidance for monitoring switchyard voltage and frequency when the RTCA is non-functional. The assessment of plant risk for maintenance activities that could affect grid reliability or offsite activities which could affect the transmission systems ability to provide adequate offsite power was discussed with the appropriate plant personnel. The inspectors also reviewed related work orders and performed a walkdown of the plant switchyards to verify the material condition of the offsite power sources. Documents reviewed are listed in the Attachment.

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 Corrective Action Program (CAP). Documents reviewed are listed in the

.

• Emergency Diesel Generator (EDG) B while EDG A was out of service for planned maintenance

• Motor Driven Auxiliary Feedwater (MDAFW) System

• Dedicated Shutdown Diesel Generator (DSDG)

• Service water pumps (SWPs) A and B while SWPs C and D were out of service for planned maintenance

b. Findings

No findings were identified.

==1R05 Fire Protection

a. Inspection Scope

Fire Area Tours:==

For the five 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:

• 4kv Switchgear Room

• Auxiliary Building 1st floor hallway

• Turbine Building Ground Level

• Unit 2 Control Room

• 115kV/230kV Switchyard

b. Findings

No findings were identified.

==1R07 Heat Sink Performance

a. Inspection Scope

==

The inspectors observed the inspection of the B Auxiliary Feedwater System (AFW)lube oil cooler to verify that inspection results were appropriately categorized against the pre-established acceptance criteria described in procedure CM-201, Safety Related and Non-Safety Related Heat Exchanger Maintenance, Rev. 55. The inspectors also verified that the frequency of inspection was sufficient to detect degradation prior to loss of heat removal capability below design basis values.

b. Findings

No findings were identified.

==1R11 Licensed Operator Requalification

a. Inspection Scope

==

Routine Operator Requalification Review: On May 14, 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 scenario consisted of a loss of E-1 normal feeder breaker, feedwater line break upstream of the feed regulating valves, loss of feedwater flow and loss of heat sink.

Observation of Operator Performance: The inspectors observed main control room crew performance during the Unit 2 reactor startup from the forced outage on April 7, 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.

b. Findings

No findings were identified.

==1R12 Maintenance Effectiveness

a. Inspection Scope

==

The inspectors reviewed the licensees effectiveness in performing the following three 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 structures, systems, and components (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.

• Process/Area Radiation Monitoring System Condition Monitoring and Maintenance

• AR 275449275449 RHR Pump Seal Leakage

• AR 685133685133 TSC/EOF/Security Diesel tripped on overspeed

b. Findings

No findings were identified.

==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:

• Yellow risk condition for the A EDG being out of service during power ascension

• Week of 4/28-5/2/14, Service water pump D, Service water booster pump B, HVH-7A, Component Cooling water pump C and RHR pump B out of service for preplanned maintenance

• Yellow risk condition for the motor driven fire pump being out of service for maintenance

• Review of the Complex Activity Plan associated with the A EDG 10-year Preventive Maintenance Outage

• Review of protected equipment scheme following the loss of offsite power to the Technical Support Center and Emergency Operations Facility

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 676605676605 Bladder found in refueling water storage tank

• AR 676609676609 Emergency control station test methodology

• AR 682232682232 Cable vault system check valve installed backwards

• AR 680049680049 SI Switch found bad during re-instate of safeguards

• AR 689887689887 Dedicated Shutdown Diesel Fan B tripped on thermal overload

b. Findings

No findings were identified.

==1R19 Post Maintenance Testing

a. Inspection Scope

==

The inspectors reviewed the following eight 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.

• EDG A slow speed start following replacement of the automatic voltage regulator control rheostat

• Main steam safety valve testing following repair of S1-4A, Safety Relief Valve

• Manual start check of safety injection pump B following inspection of pump bearings and cooler

• MDAFW system component test train B test following maintenance on pump cooler

• MDAFW system component test train A test following preventive maintenance on AFW-V2-12C, AFW header discharge to steam generator C

• Control room emergency ventilation system train B test following corrective maintenance on water cooled condensing unit 1B

• Containment fan coolers component test following replacement of V6-33D, SW booster supply to HVH-4

• MDAFW system A train testing following testing of the critical system relays

b. Findings

No findings were identified.

==1R20 Refueling and Outage Activities

a. Inspection Scope

Unit 2 Forced Outage:==

For the outage that began on March 7, 2014, and ended on April 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.

• 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.

• 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.

• 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.

• 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 six 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-409-2, EDG Fast Speed Start, Rev. 59

• OST-402-2, EDG B Diesel Fuel Oil System Flow Test, Rev.36

• OST-252-1, RHR Pump B Component Test, Rev. 30

• OST-908-3, Component Cooling Water Pump B Test, Rev. 03

• EST-082, In-service Inspection Pressure Testing of Auxiliary Feedwater System, Rev. 27

In-Service Tests

• OST-206, Comprehensive Flow Test for the Steam Driven Auxiliary Feedwater Pump, Rev. 60

b. Findings

No findings were identified.

1EP2 Alert and Notification System Evaluation

a. Inspection Scope

The inspectors evaluated the adequacy of the licensees methods for testing the alert and notification system in accordance with NRC Inspection Procedure 71114, 02, Alert and Notification System (ANS) Testing. The applicable planning standard, 10 CFR Part 50.47(b)(5) and its related 10 CFR Part 50, Appendix E, Section IV.D requirements were used as reference criteria. The criteria contained in NUREG-0654, Criteria for Preparation and Evaluation of Radiological Emergency Response Plans and Preparedness in Support of Nuclear Power Plants, Revision 1, were also used as a reference.

The inspectors reviewed various documents which are listed in the Attachment.

Inspectors interviewed personnel involved with siren system maintenance, observed a silent test of the siren system, and observed the condition of a sample of siren installations. This inspection activity satisfied one inspection sample for the alert and notification system on a biennial basis.

b. Findings

No findings were identified.

1EP3 Emergency Preparedness Organization Staffing and Augmentation System

a. Inspection Scope

The inspectors reviewed the licensees Emergency Response Organization (ERO)augmentation staffing requirements and process for notifying the ERO to ensure the readiness of key staff for responding to an event and timely facility activation. The qualification records of key position ERO personnel were reviewed to ensure all ERO qualifications were current. A sample of problems identified from augmentation drills or system tests performed since the last inspection was reviewed to assess the effectiveness of corrective actions.

The inspection was conducted in accordance with NRC Inspection Procedure 71114, 03, Emergency Preparedness Organization Staffing and Augmentation System. The applicable planning standard, 10 CFR 50.47(b)(2), and its related 10 CFR Part 50, Appendix E requirements were used as reference criteria.

The inspectors reviewed various documents which are listed in the Attachment. This inspection activity satisfied one inspection sample for the ERO staffing and augmentation system on a biennial basis.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

a. Inspection Scope

Since the last NRC inspection of this program area, changes were made to the Radiological Emergency Plan and Emergency Action Levels (EALs). The licensee determined that, in accordance with 10 CFR 50.54(q), the changes made in these revisions resulted in no reduction in the effectiveness of the Plan, and that the Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The inspectors conducted a review of the changes made between September 2013, and March 2014, to evaluate for potential reductions in the effectiveness of the Plan.

However, this review was not documented in a Safety Evaluation Report and does not constitute formal NRC approval of the changes. Therefore, these changes remain subject to future NRC inspection in their entirety.

The inspection was conducted in accordance with NRC Inspection Procedure 71114, 04, Emergency Action Level and Emergency Plan Changes. The applicable planning standards of 10 CFR 50.47(b), and its related requirements in 10 CFR Part 50, Appendix E, were used as reference criteria.

The inspectors reviewed various documents that are listed in the Attachment to this report. 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.

1EP5 Maintenance of Emergency Preparedness

a. Inspection Scope

The inspectors reviewed the corrective actions identified through the Emergency Preparedness program to determine the significance of the issues, the completeness and effectiveness of corrective actions, and to determine if issues were recurring. The licensees post-event action reports, self-assessments, and audits were reviewed to assess the licensees ability to be self-critical, thus avoiding complacency and degradation of their emergency preparedness program. Inspectors reviewed the licensees 10 CFR 50.54(q) change process, personnel training, and selected screenings and evaluations to assess adequacy. The inspectors toured facilities and reviewed equipment and facility maintenance records to assess licensees adequacy in maintaining them. The inspectors evaluated the capabilities of selected radiation monitoring instrumentation to adequately support EAL declarations.

The inspection was conducted in accordance with NRC Inspection Procedure 71114.05, Maintenance of Emergency Preparedness. The applicable planning standards, related 10 CFR Part 50, Appendix E requirements, and 10 CFR 50.54(q) and

(t) were used as reference criteria.

The inspectors reviewed various documents which are listed in the Attachment. This inspection activity satisfied one inspection sample for the maintenance of emergency preparedness on a biennial basis.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

a. Inspection Scope

On May 21, 2014, the inspectors observed an emergency preparedness drill to verify licensee self-assessment of classification, notification, and protective action recommendation development in accordance with 10 CFR Part 50, Appendix E. The inspectors also attended the post-drill critique to verify that the licensee properly identified failures in classification, notification and protective action recommendation development activities.

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.

Initiating Events Cornerstone

• Unplanned Power Changes per 7,000 Critical Hours

Cornerstone: Mitigating Systems

• Safety System Functional Failures

• Emergency AC Power System

Cornerstone: Barrier Integrity

• Reactor Coolant System Specific Activity

For the period from April 2013 through March 2014, the inspectors reviewed Licensee Event Reports (LERs), records of inoperable equipment, and Maintenance Rule records, condition reports (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.

Emergency Preparedness Cornerstone

• Emergency Response Organization (ERO) Drill/Exercise Performance

• ERO Drill Participation

• Alert and Notification System Reliability

For the period April 1, 2013, through March 31, 2014, the inspectors examined data reported to the NRC, procedural guidance for reporting PI information, and records used by the licensee to identify potential PI occurrences. The inspectors verified the accuracy of the PI for ERO drill and exercise performance through review of a sample of drill and event records. The inspectors reviewed selected training records to verify the accuracy of the PI for ERO drill participation for personnel assigned to key positions in the ERO.

The inspectors verified the accuracy of the PI for alert and notification system reliability through review of a sample of the licensees records of periodic system tests. The inspectors also interviewed the licensee personnel who were responsible for collecting and evaluating the PI data. Licensee procedures, records, and other documents reviewed within this inspection area are listed in the Attachment. This inspection satisfied three inspection samples for PI verification on an annual basis.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 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.

.2 Annual Follow-up of Selected Issues

a. Inspection Scope

Sample Review of AR #524561: In addition to the routine review, the inspectors selected to review AR 524561524561 fire piping in contact with service water discharge lines, 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.

Sample Review of AR #632237: Trending for DSDG Battery Data Show Cell #23 Degrading, for detailed review. The inspectors reviewed this report to verify that the licensee identified the full extent of the issue, performed an appropriate evaluation, and specified and prioritized appropriate corrective actions. The inspectors evaluated the report against the requirements of the licensees CAP as delineated in procedure CAP-NGGC-0200, Condition Identification and Screening Process, and 10 CFR Part 50, Appendix B.

The inspectors reviewed the following ARs associated with this area to verify that the licensee identified and implemented appropriate corrective actions:

• AR #558425, Missed having Trending Identify End of Life for DS Battery

• AR #621014, DS System Battery and Inverter Loading Discrepancy

• AR #644842, DSDG Corrosion on Cable Terminals Connecting to Battery Bank

b. Observations and Findings

No findings were identified.

.3 Semi-annual Trend Review

a. Inspection Scope

As required by IP 71152, Identification and Resolution of Problems, the inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screenings discussed in section 4OA2.1 above, licensee trending efforts, licensee human performance results and inspector observations made during in-plant inspections and walk-downs. The inspectors review primarily considered the six-month period of January 2014 through June 2014, although some examples expanded beyond those dates when the scope of the trend warranted. The review also included issues documented outside the normal CAP in major equipment problem lists, plant health reports, Independent Nuclear Oversight reports, self-assessment reports, and maintenance rule reports. The inspectors compared and contrasted their results with the results contained in the licensees latest quarterly trend reports. Corrective actions associated with a sample of the issues identified in the licensees trend report were reviewed for adequacy.

b. Observations and Findings

No findings were identified. In general, the licensee performs adequate monitoring of their programs for adverse trends. The inspectors reviewed corrective actions associated with problem identification reports for potential trends and noted the corrective actions were adequate to address the trends.

4OA3 Follow-up of Events and Notices of Enforcement Discretion

.1 Declaration of a Notice of Unusual Event Following

a. Inspection Scope

The inspectors responded to the Unit 2 control room following the declaration of a Notice of Unusual Event (NOUE) on June 6, 2014, due to a fire alarm in containment that was not verified within 15 minutes. The fire brigade responded to the event and verified there was no fire within 30 minutes and the NOUE was terminated. The inspectors observed the operators response to the event and provided updates to management. The inspectors also monitored the licensees activities that took place following the NOUE and verified that the containment fire detection system remained adequate after removal of four containment fire detectors alarm capability. The event was documented as AR 691748691748 Unusual Event Declared for Fire Alarm in Containment. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

.2 (Closed) LER 2013-001-00, Non-Environmentally-Qualified Splice Rendered Post

Accident Monitoring (PAM) Instrumentation Channel Inoperable.

On October 6, 2013, during work to replace the limit switches of the CVC-204B, letdown line isolation valve, the licensee discovered that a non-environmentally qualified butt splice was installed on a wire for the closed limit switch. The improper wiring for the limit switch did not meet EQ requirements and rendered the PAM instrumentation function of containment isolation valve position indication inoperable. The licensees cause investigation determined that the improper splice was installed in 1992 and that on multiple occasions the function was inoperable for a period of time greater than allowed by TS 3.3.3, PAM Instrumentation Limiting Condition of Operation (LCO). The licensee determined that the cause of this event was a human performance event in which a technician failed to use the proper heat shrink insulators as directed by licensee procedure CM-309, Sealing Low Voltage Electrical Splices for Environmentally Qualified or Safety Related Splices. The licensee entered this issue in the corrective action program as NCR 640902 and replaced the improper splice with the appropriate material.

The inspectors reviewed the corrective actions and determined that they were adequate.

The enforcement aspects of this finding are discussed in Section 4OA7. This LER is closed.

.3 (Closed) LER 2014-001-00, Reactor Trip Due to a Two-Out-of-Three Logic Signal from

Steam Generator Water Level Protection Train B Logic Matrix.

a. Inspection Scope

On January 9, 2014, with the Unit in Mode 1 at 100 percent power, a turbine trip and an automatic reactor trip occurred during the performance of surveillance test procedure MST-013, Steam Generator Water Level Protection Channel Testing. The reactor trip occurred during Step 8.2.85 of MST-013, when the bistable switch was placed in the test position (opens the two LC-494A1-X contacts). One channel contact (contact 2-6 on relay LC-496A1-X(B)) was unknowingly open due to foreign material lodged between the contact faces. This half-trip condition did not show on the control room annunciator panel. When the two LC-494A1-X contacts opened, the two-out-of-three logic was completed. For corrective actions, the licensee inspected both trains of relay racks to identify and remove any potential foreign material. The licensee also tested both trains of reactor protection relays to verify no foreign material was present. Additionally, the licensee plans to replace the wire labels in the reactor protection and safeguards relay racks during the next two refueling outages. 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 below. This LER is closed.

b. Findings

Introduction.

A self-revealing Green NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified for the licensees failure to promptly identify and correct degraded wire labels in the reactor protection cabinets which were a condition adverse to quality.

Description.

On November 1, 2013, near the end of refueling outage 28, the licensee identified degraded wire labels in the safeguards and reactor protection relay cabinets.

Work requests, and subsequently, work orders, were initiated to have the wire labels replaced in the next two refueling outages (RFO-29 and RFO-30). The licensee did not enter this issue into the corrective action program as a condition adverse to quality.

However, the purpose of licensee procedure MNT-NGGC-0007, Foreign Material Exclusion Program, is, in part, to establish a program to prevent introduction of foreign material into systems and components that could degrade nuclear fuel or plant equipment; and to provide guidelines for the prevention of foreign material intrusion into plant systems/components, which will help prevent unscheduled plant outages and outage extensions. In accordance with MNT-NGGC-0007, the licensee should have identified the degraded wire labels as a condition adverse to quality in accordance with the purpose of their foreign material exclusion (FME) program.

On December 2, 2013, the licensee performed surveillance test procedure MST-021, Reactor Protection Logic Train B At Power. Relay LC-496A1-X(B) passed the surveillance test. On January 9, 2014, during surveillance test procedure MST-013, Steam Generator Water Level Protection Channel Testing, the B reactor trip breaker opened as a result of the two out of three steam generator lo-lo level input logic being completed. One channel contact (contact 2-6 on relay LC-496A1-X(B)) was unknowingly open due to foreign material lodged between the contact faces. This half-trip condition did not show on the control room annunciator panel. The second channel contact was opened during the channel testing, in accordance with MST-013, Step 8.2.85, when the bistable switch was placed in the test position (opens the two LC-494A1-X contacts). The opening of the B reactor trip breaker resulted in a turbine trip, which resulted in a reactor trip. The licensee documented this issue as CR 654789.

Analysis.

The licensees failure to promptly identify the degraded wire labels as a condition adverse to quality, as required by 10 CFR Part 50, Criterion XVI, Corrective Action, was a performance deficiency. The performance deficiency was more than minor because it was associated with the equipment performance attribute of the initiating events cornerstone and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the degraded wire labels became lodged between contact 2-6 on relay LC-496A1-X(B), which set up the half-trip condition to cause a reactor trip, during the surveillance testing. 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 although the finding caused a reactor trip, it did not cause the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition. This finding had a cross-cutting aspect of identification in the area of problem identification and resolution because the licensee failed to implement a corrective action program with a low enough threshold for identifying issues in that the licensee process did not recognize, during review of the work requests for the degraded wire labels, that this issue should have been entered into the corrective action program as a nuclear condition report. (P.1)

Enforcement.

Appendix B to 10 CFR Part 50, Criterion XVI, Corrective Action, states, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances, are promptly identified and corrected. Contrary to this, from November 1, 2013, to January 9, 2014, a condition adverse to quality was not promptly identified and corrected. Specifically, the licensee failed to identify the degraded material of the wire labels as a condition adverse to quality or correct the issue by replacing the labels, which led to foreign material becoming lodged between two contacts, and resulted in a reactor trip. Immediate corrective actions included inspection of both trains of relay racks to identify and remove any potential foreign material. The licensee also tested both trains of reactor protection relays to verify no foreign material was present. Additionally, the licensee plans to replace the wire labels in the reactor protection and safeguards relay racks during refueling outages 29 and 30. 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 as AR 654789654789

(NCV 05000261/2014003-01, Failure to Identify and Correct Degraded Wire Labels in the Reactor Protection Relay Cabinets)

.4 (Closed) LER 2013-002-00, Automatic Actuation of the Auxiliary Feedwater System due

to Main Feed Pump Trip.

On November 5, 2013, with the Unit in Mode 2 and startup low-power physics testing in progress, there was an inadvertent automatic actuation of the AFW System due to an 'A' Main Feed Pump (MFP) trip. While placing the Condensate Polishers in service, the Auxiliary Operator closed the primary Condensate Polisher bypass valve manually, which secured flow to the running A MFP. The A MFP then tripped on low suction pressure coincident with low flow. Both motor driven AFW Pumps started due to both MFP breakers being open simultaneously. Steam generator water levels were maintained by the AFW flow. The B MDAFW pump was secured following its automatic start to stabilize steam generator water levels and Reactor Coolant System temperature.

After successful restart of the A MFP, the A AFW pump was secured. The inspectors reviewed operator logs, plant computer data, and plant procedures and verified that the operator response to the event was appropriate. The root cause investigation into the cause of this event determined that this was an individual operator error resulting from inadequate utilization of the procedure use and adherence process. Corrective action consisted of completion of confidential personnel actions for the Makeup Water Treatment/Condensate Polisher Auxiliary Operator responsible for the event and increased supervisory oversight of risk significant evolutions. During review of this LER no findings or violations of NRC requirements were identified. This LER is closed.

4OA5 Other Activities

.1 Institute of Nuclear Power Operations Report Review

In accordance with Executive Director of Operations Procedure 0220, Coordination with the Institute of Nuclear Power Operations, the inspectors reviewed the most recent INPO evaluation and accreditation reports dated April 2, 2014, to determine if those reports identified safety or training issues not previously identified by NRC evaluations.

The report contained no safety issues that were not already known by the NRC.

.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): Defective Motor Operated Potentiometer Causes

Failure of the DSDG During Surveillance Testing

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. A URI was opened to provide for additional inspection of the equipment issues that led to the failure. Engineering determined that the diesel trip was a result of a degraded 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. The defective components were sent back to the vendor for additional analysis. The inspectors reviewed the vendors analysis and concluded that a performance deficiency did not exist because the failure of the DSDG was the result of the manufacturing defect and not within the licensees ability to foresee and correct. URI 05000261/2014001-05; Defective Motor Operated Potentiometer causes failure of the DSDG during surveillance testing is closed.

4OA6 Meetings, Including Exit

On July 17, 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.

4OA7 Licensee-Identified Violations

The following finding of very low significance was identified by the licensee and is a violation of NRC requirements, and, consistent with the NRC Enforcement Policy, is being dispositioned as an NCV.

Section 50.49 of 10 CFR, Environmental Qualification of electric equipment important to safety for nuclear power plants, states that each licensee shall establish a program for qualifying specified electric equipment. Section (a)(3) of 10 CFR 50.49 specifies the environmental qualification requirements for post-accident monitoring equipment.

Section

(f) of 10 CFR 50.49 requires, in part, that each item of electric equipment important to safety must be qualified by testing an identical item of equipment under identical conditions. Contrary to the above, since May 1992, the licensee failed to maintain the qualification of the limit switches for CVC-204B, letdown line isolation, in accordance with the tested configuration of the equipment which rendered the Post Accident Monitoring Instrumentation function inoperable. The licensee documented this condition in AR 640902640902and AR 633207633207 The cause was determined to be associated with a human performance event in which the licensee failed to use the proper heat shrink insulators per procedure CM-309, Sealing Low Voltage Electrical Splices for Environmentally Qualified or Safety Related Splices. Following discovery of this condition, the licensee replaced the non-environmental qualified splice and returned the equipment to the test configuration. 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-Technical Specification 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 />.

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

T. Cosgrove, Plant General Manager

S. Connelly, Licensing

H. Curry, Training Manager

D. Douglas, Maintenance Manager

R. Gideon, Vice President

M. Glover, Director - Site Operations

D. Hoffman, Nuclear Oversight Manager

K. Holbrook, Operations Manager

C. Sherman, Radiation Protection Superintendent

J. Kammer, Engineering Director

K. Moser, Outage & Scheduling Manager

S. Williams, Chemistry Manager

M. Austin, Fleet Emergency Preparedness

N. Baker, Emergency Preparedness

C. Caudell, Regulatory Affairs

L. Godbold, Sr. Telecommunications Technician

L. Grant, Emergency Preparedness

L. Hall, Emergency Preparedness

R. Hightower, Manager, Regulatory Affairs

G. LaGarde, Emergency Preparedness

T. Pilo, Emergency Preparedness Supervisor

W. Stover, Emergency Preparedness

C. Thompson, Emergency Preparedness

NRC Personnel

G. Hopper, Chief, Reactor Projects Branch 4

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened &

Closed

05000261/2014003-01

NCV Failure to Identify and Correct Degraded Wire Labels in the Reactor Protection Relay Cabinets

Closed

05000261/2013-001-00 LER Non-Environmentally-Qualified Splice Rendered Post Accident Monitoring (PAM) Instrumentation Channel Inoperable

05000261/2014-001-00

LER Reactor Trip Due to a Two-Out-of-Three Logic Signal from Steam Generator Water Level Protection Train B Logic Matrix

05000261/2013-002-00

LER Automatic Actuation of the Auxiliary Feedwater System due to Main Feed Pump Trip

05000261/2014002-05 URI Defective Motor Operated Potentiometer causes failure of the DSDG during surveillance testing (Section 4OA5)