IR 05000400/2014002

IR 05000400-14-002, Duke Energy Progress, Inc.; on January 1, 2014 - March 31, 2014; Shearon Harris Nuclear Power Plant, Unit 1; Operability Evaluations, Surveillance Testing, and Identification and Resolution of Problems

ML14118A441
Person / Time
Site:	Harris
Issue date:	04/28/2014
From:	Hopper G NRC/RGN-II/DRP/RPB4
To:	Kapopoulos E Duke Energy Progress
References
IR-14-002
Download: ML14118A441 (28)

Text

UNITED STATES ril 28, 2014

SUBJECT:

SHEARON HARRIS NUCLEAR POWER PLANT - NRC INTEGRATED INSPECTION REPORT 05000400/2014002

Dear Mr. Kapopoulos:

On March 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Shearon Harris Nuclear Power Plant Unit 1. The enclosed inspection report documents the inspection results which were discussed on April 23, 2014, with you and other members of your staff.

The inspection examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

Two NRC-identified findings and one self-revealing finding of very low safety significance (Green) were identified during this inspection. Two of these findings were determined to involve violations of NRC requirements. The NRC is treating these findings as non-cited violations (NCV) consistent with Section 2.3.2.a of the Enforcement Policy.

If you contest the subject or severity of any NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Nuclear Regulatory Commission, ATTN.: Document Control Desk, Washington, DC 20555-001; with copies to the Regional Administrator Region II; the Director, Office of Enforcement, United States Nuclear Regulatory Commission, Washington, DC 20555-001; and the NRC Resident Inspector at the Shearon Harris Nuclear Plant.

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 inspection report, with the basis for your disagreement, to the Regional Administrator, Region II, and the NRC Resident Inspector at the Shearon Harris Nuclear 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 (IMC) 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 Shearon Harris Nuclear Plant.

In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390 of the NRC's Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of NRC's Agencywide Document Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site 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.: 50-400 License No.: NPF-63

Enclosure:

NRC Inspection Report 05000400/2014002 w/Attachment: Supplemental Information

REGION II==

Docket No.: 50-400 License No.: NPF-63 Report No.: 05000400/2014002 Licensee: Duke Energy Progress, Inc.

Facility: Shearon Harris Nuclear Power Plant, Unit 1 Location: 5413 Shearon Harris Road New Hill, NC 27562 Dates: January 1, 2014 through March 31, 2014 Inspectors: J. Austin, Senior Resident Inspector P. Lessard, Resident Inspector Approved by: George T. Hopper, Chief Reactor Projects Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000400/2014002: Duke Energy Progress, Inc.; January 1, 2014 - March 31, 2014;

Shearon Harris Nuclear Power Plant, Unit 1; Operability Evaluations, Surveillance Testing, And Identification and Resolution of Problems.

The report covers a three-month period of inspection by resident inspectors. Two NRC-identified and one self-revealing 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, issued June 19, 2012 Significance Determination Process (SDP). The cross-cutting aspects were determined using IMC 0310, Aspects Within 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 was identified for the failure to implement an adequate corrective action to prevent recurrence (CAPR) for a Significant Condition Adverse to Quality (SCAQ) as required by licensee procedure CAP-NGGC-0205, Condition Evaluation and Corrective Action Process, resulting in the failure of the 1D2 transformer on January 18, 2014. Specifically, after the 1E2 transformer failed on August 8, 2013, the licensee determined the event to be a SCAQ, but failed to implement an adequate CAPR to prevent the failure of the 1D2 transformer. The licensee entered this issue into the corrective action program (CAP) as Action Request (AR) #663324. As corrective action, the licensee is replacing the 1D2 transformer and other similar transformers and implemented additional testing to aid in the identification of degradation prior to transformer failure.

The inspectors determined that the failure to implement an adequate CAPR for a SCAQ was a performance deficiency. This finding was more than minor because it was associated with the Initiating Events cornerstone attribute of Equipment Performance, and adversely affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operation. Specifically, a manual reactor trip resulted from the 1D2 failure. Using IMC 0609, Significance Determination Process, Appendix A, Exhibit 1- Initiating Events Screening Questions, the inspectors determined this finding to be of very low safety significance (Green) because the finding did cause a reactor trip but did not result in the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g.,

loss of condenser, loss of feedwater). The finding had a cross-cutting aspect of Resolution, as described in the Problem Identification and Resolution cross-cutting area because the licensee did not implement effective corrective actions to address the issue in a timely manner commensurate with their safety significance. Specifically, the licensees CAPR for the August 8, 2013, event did not resolve the cause for transformer failures. (P.3)

(Section 4OA2.2)

Cornerstone: Mitigating Systems

Green.

The inspectors identified a Green non-cited violation (NCV) of Technical Specification (TS) 6.8.1.a, Procedures and Programs, for the licensees failure to have an adequate surveillance test to implement the requirements of SR 4.8.1.1.2.c, as required by Regulatory Guide (RG) 1.33, Quality Assurance Program Requirements, Appendix A,

Section 8.b. Specifically, licensee procedure RST-209, Technical Specification Surveillance of New Diesel Fuel Oil (DFO), did not adequately ensure a representative sample of the DFO to confirm the required properties prior to addition to the B diesel fuel oil storage tank (DFOST). This created the potential for DFO of an unacceptable quality to be introduced to the B emergency diesel generator (EDG) on December 4, and 6, 2013. The licensee took corrective action by testing the fuel oil in the A and B DFOSTs and EDG day tanks to verify that the DFO met the required properties as outlined in TS. Additionally, the licensee planned to revise RST-209 and established interim actions to prevent adding new fuel oil prior to obtaining a representative sample.

The inspectors determined that the failure to have an adequate surveillance test to implement the requirements of SR 4.8.1.1.2.c. on December 4, and 6, 2013 was a performance deficiency. Specifically, this created the potential for fuel oil of an unacceptable quality to be introduced to the B EDG. This finding was more than minor because, if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern in that it could have affected operability of the EDGs. Using IMC 0609, Significance Determination Process, Appendix A, Exhibit 2 - Mitigating Systems Screening Questions, the inspectors determined this finding to be of very low safety significance (Green) because the finding is not a deficiency affecting the design or qualification and does not represent an actual loss of system and/or function. The finding had a cross-cutting aspect of Resources, as described in the Human Performance cross-cutting area because the licensee failed to ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety. Specifically, procedure RST-209 Revision 23 inappropriately permitted the use of data from a sample that was 20 months old to meet SR 4.8.1.1.2.c. (H.1) (Section 1R22)

Green.

The inspectors identified a Green NCV of TS 3.11.2.5, Explosive Gas Mixture, for the failure to implement the actions of the limiting condition for operation (LCO).

Specifically, during shutdown plant operations in November 2013, the licensee identified oxygen concentrations in the gaseous radwaste treatment system (GRTS) of greater than two percent oxygen, with hydrogen concentration greater than four percent and did not enter nor take the actions of TS LCO 3.11.2.5. The licensee entered the issue into their CAP as AR #651188 and reduced the oxygen concentration to less than two percent on December 11, 2013.

The licensees failure to enter and implement the actions of TS LCO 3.11.2.5, once oxygen concentrations exceeded two percent, with hydrogen concentrations greater than four percent within the GRTS was a performance deficiency. The performance deficiency was determined to be more than minor in accordance with IMC 0612, Appendix B, because if left uncorrected, it would have the potential to lead to a more significant safety concern such as an explosive gas mixture. Specifically, on November 11, 2013, SR 4.11.2.5 was performed unsatisfactorily; Operations was unaware of the results and did not implement the actions of TS LCO 11.2.5. Using IMC 0609, SDP, Appendix A, Exhibit 2-External Event Mitigation Systems Screening Questions, the inspectors determined this finding to be of very low safety significance (Green) because it was a deficiency that did not result in a degradation or loss of system function. The finding had a cross-cutting aspect of Procedure Adherence, as described in the Human Performance cross-cutting area because the licensee failed to comply with RST-202, Hydrogen and Oxygen Surveillance of the GRTS, and notify Operations of the unsatisfactory test result. (H.8) (Section 4OA2.3)

REPORT DETAILS

Summary of Plant Status

Unit 1 operated at or near rated thermal power (RTP) for the entire inspection period with the following exception. On January 18, 2014, Unit 1 was shutdown in response to the failure of a transformer which is discussed in more detail in Sections 4OA2.2 and 4OA3.1 of this report.

Unit 1 was restored to RTP on January 23,

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather Condition

a. Inspection Scope

On January 28, 2014, extreme low temperatures and a significant snow and ice storm occurred in the plant area and inspectors reviewed the licensees overall preparations for impending adverse weather conditions. The inspectors walked down areas of the plant susceptible to these conditions. The inspectors evaluated the licensee staffs preparations against the sites procedures to determine if the staffs actions were adequate. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors evaluated operator and security staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

The inspectors performed three partial system walkdowns of the following risk-significant systems:

• The A Emergency Diesel Generator (EDG) while it was protected and providing power to the 1A-SA safety bus on January 18, 2014;

• The B Essential Services Chilled Water (ESCW) system while the B ESCW system was unavailable due to planned maintenance on January 30, 2014; and

• Select portions of the electrical switchyard while the A EDG was unavailable due to a maintenance outage on February 26, 2014.

The inspectors selected these systems based on their risk-significance relative to the reactor safety cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, applicable portions of the UFSAR, TS requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that 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 with the appropriate significance characterization.

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

On March 31, 2014, the inspectors performed a complete system alignment inspection of the control room emergency ventilation system to verify the functional capability of the system. This system was selected because it was considered risk significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment line ups, electrical power availability, system pressure and temperature indications, component labeling, component lubrication, component and equipment cooling, hangers and supports, operability of support systems, and to ensure that auxiliary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Quarterly Resident Inspector Tours

a. Inspection Scope

The inspectors conducted six fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:

• Termination Cabinet Room

• Rod Control Cabinet Room

• Main Control Room, Auxiliary Relay Room and Computer Room

• Process Instrument Cabinet Room

• Turbine Building 261 foot Elevation

• Transformer Yard The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and had implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event. Using the documents listed in the attachment, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed, that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Quarterly Review

a. Inspection Scope

On February 4, 2014, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification examinations to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems and training was being conducted in accordance with licensee procedures. The training scenario evaluated the operators ability to respond to an unisolable steam leak and steam generator tube rupture. The inspectors evaluated the following areas:

• Licensed operator performance

• Crews clarity and formality of communications

• Ability to take timely and conservative actions

• Prioritization, interpretation, and verification of annunciator alarms

• Correct use and implementation of abnormal and emergency procedures

• Control board manipulations

• Oversight and direction from supervisors

• Ability to identify and implement appropriate TS actions and emergency plan actions and notifications The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements.

b. Findings

No findings were identified.

.2 Licensed Operator Performance in the Actual Plant/Main Control Room

a. Inspection Scope

On January 18, 2014, the inspectors observed operators in the plants main control room during an Alert event caused when the 1D2 transformer failed and the plant was manually tripped by the operators. The inspectors evaluated the following areas:

• Operator compliance and use of plant procedures, including procedure entry and exit, performing procedure steps in the proper sequence, procedure place-keeping, and TS entry and exit;

• Control board/in-plant component manipulations;

• Communications between crew members;

• Use and interpretation of plant instruments, indications, and alarms; diagnosis of plant conditions based on instruments, indications, and alarms;

• Use of human error prevention techniques, such as pre-job briefs and peer checking;

• Documentation of activities, including initials and sign-offs in procedures, control room logs, TS entry and exit, entry into out-of-service logs; and

• Management and supervision of activities, including risk management and reactivity management.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

a. Inspection Scope

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment. The inspectors evaluated degraded performance issues involving the following risk significant components:

• AR #663979, Breaker PP-16-3 for Pressurizer Heater (PP-C-1C) would not reset during testing

• AR #648090, Battery Charger (1B-SB) Tripped during 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> Equalize Charge

• AR #649335, A Reactor Coolant Pump Seal Water Injection Check Valve (1CS-344) failed Local Leak Rate Testing The inspectors focused on the following attributes:

• Implementing appropriate work practices;

• Identifying and addressing common cause failures;

• Scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;

• Characterizing system reliability issues for performance;

• Counting unavailability time during performance of maintenance;

• Trending key parameters for condition monitoring;

• Ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and

• Verifying appropriate performance criteria for structures, systems, and components (SSCs)/functions classified as (a)(2) are appropriate and adequate goals and corrective actions for systems classified as (a)(1).

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:

• Emergent yellow risk when the Auxiliary Bus 1D2 Transformer faulted on January 19, 2014;

• Planned yellow risk during plant start-up following a forced outage on January 22, 2014;

• Planned maintenance outage on the B Residual Heat Removal (RHR) system on February 19, 2014, risk remained green;

• Planned maintenance outage on the A EDG and A Emergency Service Water (ESW) systems on February 25, 2014, risk remained green; and

• Planned yellow risk condition while the C Feed Regulating Valve was in manual control to support steam generator level instrumentation testing on March 6, 2014.

These activities were selected based on their potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

b. Findings

No findings were identified.

1R15 Operability Evaluations

a. Inspection Scope

The inspectors selected the following five potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and UFSAR to the licensees evaluations, to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors also reviewed a sampling of corrective action documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the Attachment.

• AR #652487, Seismic Monitor Surveillance Overdue

• AR #668248, Effect of Diesel Generator Voltage and Frequency Variation on Motor Operated Valve Torque Capability

• AR #668462, Impact of Harmonic Distortion on the Degraded Grid Voltage Relays

• AR #670645, Inadequate Basis of Starting Air Blowdown Trap Compensatory Measures

• AR #666903, B DFOST Particulate

b. Findings

No findings were identified.

1R18 Plant Modifications

a. Inspection Scope

The following engineering design package was reviewed and selected aspects were discussed with engineering personnel:

• Engineering Change (EC) #95296, Revise Setpoint for the Undervoltage Automatic Transfer Switch for the Dedicated Shutdown Diesel This document and related documentation were reviewed for adequacy of the associated 10 CFR 50.59 safety evaluation screening, consideration of design parameters, implementation of the modification, post-modification testing, and relevant procedures, design, and licensing documents were properly updated. The inspectors observed ongoing and completed work activities to verify that installation was consistent with the design control documents. The modification lowered the setpoint for the automatic transfer switch to preclude spurious starts of the dedicated shutdown diesel.

b. Findings

No findings were identified.

1R19 Post Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following five post-maintenance test (PMT) activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

Procedure Title Related Maintenance Activity Date Emergency Safeguards WO #2262938, Block Number 4 January OPT-1538 Sequencer System Test - Train Replaced Load Relay (2-9, 2014 B Quarterly 9/1157)

Essential Chilled Water Turbopak WO #2091517, Replace The January OPT-1512 Units Quarterly Inspection/Checks VMS-2 (Pre-Rotation Vane)30, 2014 Modes 1-6 Switch WO #1822754, Replace Turbine Driven Auxiliary Hydramotor Actuator 1AF-129 OST-1411 Feedwater (TDAFW) Pump (A TDAFW Outlet Regulator) February and OST- Operability Test Quarterly Interval and WO #13329063, 5, 2014 1080 Mode 1-3 and TDAFW Full Flow Inspect/Repair 1AF-130 (B Test Quarterly Interval Mode 1-3 TDAFW Outlet Regulator)

A Emergency Service Water February OP-139 Service Water System System Maintenance Outage 25, 2014 WO #1956184, Remove, March 6, OP-138 Circulating Water Rebuild and Reinstall A 2014 Circulating Water Pump These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following: the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing, and test documentation was properly evaluated. The inspectors evaluated the activities against TS and the UFSAR to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety.

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 Routine Surveillance Testing

a. Inspection Scope

For the three surveillance tests below, the inspectors observed the surveillance tests and/or reviewed the test results for the following activities to verify the tests met TS surveillance requirements, UFSAR commitments, inservice testing requirements, and licensee procedural requirements. The inspectors assessed the effectiveness of the tests in demonstrating that the SSCs were operationally capable of performing their intended safety functions.

• OST-1042, Seismic Monitoring Surveillance, Monthly Interval on January 16, 2014;

• OST-1122, A Train 6.9 kV Emergency Bus Undervoltage Trip Actuating Device Operational Test and Contact Check Modes 1-6 on March 5, 2014; and

• RST-209, New Diesel Fuel Oil (DFO) Surveillance on December 4 and 6, 2013 (reviewed in first quarter 2014 as a result of AR #666903, B DFOST Particulate).

b. Findings

Introduction:

The inspectors identified a Green NCV of TS 6.8.1.a, Procedures and Programs, for the licensees failure to have an adequate surveillance test to implement the requirements of SR 4.8.1.1.2.c, as required by RG 1.33, Quality Assurance Program Requirements, Appendix A, Section 8.b. Specifically, licensee procedure RST-209, Technical Specification Surveillance of New Diesel Fuel Oil (DFO), did not adequately ensure a representative sample of the DFO to confirm the required properties prior to addition to the B DFOST.

Description:

Surveillance Requirement (SR) 4.8.1.1.2.c requires that a sample of new DFO be taken and tested prior to addition to the DFOST to ensure it is acceptable to support operability of the EDGs. The SR also requires the licensee to test the sample in accordance with ASTM-D975-81, Standard Specification for DFO. ASTM-D975-81 Section 1.2 states, in part, that it prescribes the required properties of DFO at the time and place of delivery. However, on December 4 and 6, 2013, the licensee added new DFO to the B DFOST without taking a representative sample. Instead, when performing SR 4.8.1.1.2.c during receipt of this new DFO, the licensee inappropriately credited the most recent sample that was performed at the vendors facility on April 5, 2012. Although this sample was taken from the same volume of DFO that was delivered, it was approximately 20 months old and had the potential to not be representative of the fuel oil at the time and place of delivery. Specific problems, including water, sediment, and bacteria, can develop in DFO that is stored for a long duration, such as 20 months. The procedure used to implement SR 4.8.1.1.2.c is RST-209. A note in Section 7.1 of RST-209 Revision 23 permitted the use of data from the old sample at the vendors facility to meet SR 4.8.1.1.2.c and was used on December 4 and 6, 2013.

After the inspectors raised this issue, the licensee tested the fuel oil in the A and B DFOSTs and EDG day tanks. This missed SR was determined to not be reportable as a condition prohibited by TS because these tests demonstrated that the fuel oil met the required properties as outlined in TS, and therefore did not affect EDG operability.

Analysis:

The inspectors determined that the failure to have an adequate surveillance test to implement the requirements of SR 4.8.1.1.2.c. on December 4, and 6, 2013 was a performance deficiency. Specifically, this created the potential for fuel oil of an unacceptable quality to be introduced to the B EDG. This finding was more than minor because, if left uncorrected, the performance deficiency had the potential to lead to a more significant safety concern in that it could have affected operability of the EDGs.

Using IMC 0609, Significance Determination Process, Appendix A, Exhibit 2 - Mitigating Systems Screening Questions, the inspectors determined this finding to be of very low safety significance (Green) because the finding is not a deficiency affecting the design or qualification and does not represent an actual loss of system and/or function. The finding had a cross-cutting aspect of Resources, as described in the Human Performance cross-cutting area because the licensee failed to ensure that personnel, equipment, procedures, and other resources are available and adequate to support nuclear safety. Specifically, licensee procedure RST-209 Revision 23 inappropriately permitted the use of data from a sample that was 20 months old to meet SR 4.8.1.1.2.c.

(H.1)

Enforcement:

TS 6.8.1.a requires the licensee to establish, implement, and maintain procedures as recommended in Appendix A of RG 1.33, Revision 2. Section 8.b of Appendix A requires procedures for surveillance tests to ensure that the licensee meets the surveillance requirements in TS. Contrary to this requirement, the licensee failed to establish an adequate procedure RST-209 to obtain a representative sample of new DFO prior to addition to the B DFOST in accordance with SR 4.8.1.1.2.c on December 4 and 6, 2013. The licensee took corrective action by testing the fuel oil in the A and B DFOSTs and EDG day tanks to verify that the DFO met the required properties as outlined in TS. Additionally, the licensee planned to revise licensee procedure RST-209 and established interim actions to prevent adding new fuel oil prior to obtaining a representative sample. Because this violation was of very low safety significance and was entered into the CAP as AR #669494, this violation is being treated as an NCV, consistent with Section 2.3.2.a of the NRC Enforcement Policy.

(NCV 05000400/2014002-01, Failure to Adequately Perform the New Fuel Oil Surveillance Requirement.)

.2 In service Testing (IST) Surveillance

a. Inspection Scope

The inspectors reviewed the performance of OST-1013, A EDG Operability Test Monthly Interval Modes 1-6, on March 27, 2014, to evaluate the effectiveness of the licensees American Society of Mechanical Engineers (ASME)Section XI testing program for determining equipment availability and reliability. This surveillance satisfies the IST requirements for the following components in the EDG system: A DFO Transfer Pump, 1DFO-168 DFO Transfer Pump discharge check valve, 1DFO-173 Fuel Oil Day Tank Inlet Valve. The inspectors evaluated selected portions of the following areas:

• Testing procedures and methods

• Acceptance criteria

• Compliance with the licensees IST program, TS, selected licensee commitments, and code requirements

• Range and accuracy of test instruments

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

• AR #678486, Broken Bolt on the Fuel Oil Supply Header for A EDG

b. Findings

No findings were identified.

1EP6 Emergency Planning Drill Evaluation

a. Inspection Scope

The inspectors observed an emergency preparedness drill conducted on March 19, 2014, to verify licensee self-assessment of classification, notification, and protective action recommendation development in accordance with 10 CFR Part 50, Appendix E.

b. Findings

No findings were identified.

4OA1 Performance Indicator (PI) Verification

a. Inspection Scope

To verify the accuracy of the PI data reported to the NRC, the inspectors compared the licensees basis in reporting each data element to the PI definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline.

Initiating Events Cornerstone

• Unplanned Scrams per 7000 Critical Hours

• Unplanned Power Changes per 7000 Critical Hours

• Unplanned Scrams with Complications The inspectors sampled licensee submittals for the performance indicators listed above for the period from the first quarter 2013 through the fourth quarter 2013. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports and NRC Inspection reports for the period to validate the accuracy of the submittals. Documents reviewed are listed in the Attachment.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

.1 Routine Reviews of items Entered Into the Corrective Action Program

a. Inspection Scope

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 licensees CAP. The review was accomplished by reviewing daily AR reports.

b. Findings

No findings were identified.

.2 Selected Issue Follow-up Inspection: Failure to Prevent Recurrence of a Significant

Condition Adverse to Quality

a. Inspection Scope

The inspectors selected AR #663324, Alert Declared due to Indications of Fire in the 1D2 Transformer 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.

b. Findings

Introduction:

A self-revealing Green finding was identified for the failure to implement an adequate corrective action to prevent recurrence (CAPR) for a Significant Condition Adverse to Quality (SCAQ) as required by licensee procedure CAP-NGGC-0205 resulting in the failure of the 1D2 transformer on January 18, 2014. Specifically, after the 1E2 transformer failed on August 8, 2013, the licensee determined the event to be a SCAQ, but failed to implement an adequate CAPR to prevent the failure of the 1D2 transformer.

Description:

On August 8, 2013, the 1E2 transformer unexpectedly failed while it was energized and providing power to nonsafety-related electrical loads. The licensee entered this issue into the CAP as AR #621738. A finding associated with this issue is documented in Inspection Report 05000400/2013005. As directed by procedure CAP-NGGC-0200, Condition Identification and Screening Process, the licensee determined that this issue was a SCAQ and performed a root cause evaluation.

Licensee procedure CAP-NGGC-0205 is used to perform root cause evaluations.

Procedure CAP-NGGC-0205, Section 9.2, Step 2, requires that at least one CAPR for each root cause be developed to prevent a similar issue from occurring again. During their root cause evaluation, the licensee created a CAPR to perform preventative and predictive maintenance techniques recommended by their Dry Type Transformer Working Group.

However, on January 18, 2014, the 1D2 transformer also failed while it was in service and supplying power to nonsafety-related electrical loads. This issue was entered into CAP as AR #663324. During the evaluation of this issue, the licensee determined that if the preventative and predictive maintenance techniques had been implemented, they may have detected an issue with the 1D2 transformer and prevented failure.

Additionally, a refueling outage that started November 9, 2013, gave the licensee the opportunity to perform this maintenance prior to the failure.

Analysis:

The inspectors determined that the failure to implement an adequate CAPR for a SCAQ was a performance deficiency. Specifically, after the 1E2 transformer failed on August 8, 2013, the licensee determined the event to be a SCAQ, but failed to implement an adequate CAPR to prevent the failure of the 1D2 transformer on January 18, 2014. This finding was more than minor because it was associated with the Initiating Events cornerstone attribute of Equipment Performance, and adversely affected the cornerstone objective of limiting the likelihood of those events that upset plant stability and challenge critical safety functions during power operation. Specifically, a manual reactor trip resulted from the 1D2 failure. Using IMC 0609, Significance Determination Process, Appendix A, Exhibit 1- Initiating Events Screening Questions, the inspectors determined this finding to be of very low safety significance (Green)because the finding did cause a reactor trip but did not result in the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition (e.g. loss of condenser, loss of feedwater). The finding had a cross-cutting aspect of Resolution, as described in the Problem Identification and Resolution cross-cutting area because the licensee did not implement effective corrective actions to address the issue in a timely manner commensurate with their safety significance.

Specifically, the licensees CAPR for the August 8, 2013, event did not resolve the cause for transformer failures. (P.3)

Enforcement:

This issue does not involve enforcement action because no violation of a regulatory requirement was identified for the testing performed on this nonsafety-related transformer. As corrective action, the licensee is replacing the 1D2 transformer and other similar transformers and implementing additional testing to aid in the identification of degradation prior to transformer failure. The licensee entered these issues into the CAP as AR #663324. Because this finding does not involve a violation of regulatory requirements and has very low safety significance, it is identified as finding:

FIN 05000400/2014002-02, Failure to Prevent Recurrence of a Significant Condition Adverse to Quality.

.3 (Closed) Unresolved Item (URI) 05000400/2013005-02: Operations of the Waste Gas

System with Oxygen Concentrations Greater than the Technical Specification Limits

a. Inspection Scope

In Inspection Report 05000400/2013005, the inspectors identified an URI regarding operations of the waste gas system with oxygen concentrations greater than the technical specification limits. The inspectors reviewed the licensees root cause evaluation performed under AR #647917 to determine if there was a performance deficiency and the adequacy of corrective actions. The inspectors evaluated the report against the requirements of the licensees CAP as delineated in CAP-NGGC-0200, Condition Identification and Screening Process, and 10 CFR Part 50, Appendix B. This URI is closed.

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

• AR #647120, OP-120, Precaution and Limitation not Referenced by OST-2044 (Radwaste Daily Operations Surveillance Test Modes at all times)

• AR #647129, Waste Gas Decay Tank (WGDT) Sample Results not in Chemistry Data Management System

• AR #651188, Waste Gas Issues

• AR #650407, OARC-1119B (Oxygen Analyzer) not Indicating Properly, Repels High

b. Findings

Introduction:

The inspectors identified a Green NCV of TS 3.11.2.5, Explosive Gas Mixture, for the failure to implement the actions of the LCO. Specifically, during shutdown plant operations in November 2013, the licensee identified oxygen concentrations in the gaseous radwaste treatment system (GRTS) of greater than two percent oxygen, with hydrogen concentration greater than four percent and did not take the actions of TS LCO 3.11.2.5.

Description:

On November 8, 2013, following a plant shutdown for a refueling outage, the GRTS was placed in service to purge hydrogen gas and fission products from multiple tanks. Due to equipment issues, the GRTS hydrogen recombiner and the oxygen and hydrogen analyzers were inoperable and non-functional. SR 4.11.2.5 states, The concentration of hydrogen and oxygen concentrations in the GRTS shall be determined to be within the above limits by monitoring, at least once per 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />, the waste gases in the GRTS. TS 3.11.2.5 states, The concentrations of oxygen in the GRTS downstream of the hydrogen recombiners shall be limited to less than or equal to two percent by volume whenever hydrogen concentration exceeds four percent by volume.

The licensee began degassing the volume control tank at approximately 1000 on November 9, 2014, with the hydrogen and oxygen analyzers unavailable to perform the SR. The licensee used periodic manual samples, in place of the analyzers, to evaluate the gas concentrations via procedure RST-202, Hydrogen and Oxygen Surveillance of the GRTS, typically every three hours during degassing operations. Procedure RST-202 had a step that specifically evaluated the status of the hydrogen analyzer, as either operable or inoperable. The hydrogen analyzer was deemed to be inoperable, therefore, the procedure required the licensee to assume greater than four percent hydrogen concentration, declare an unsatisfactory surveillance test for RST-202, and to notify Operations. On November 9, 2013, at approximately 1225 the C WGDT was sampled with concentrations of hydrogen of 12.4 percent and oxygen of less than 0.5 percent, via procedure RST-202. On November 11, 2013, at approximately 2100, the C WGDT sample results were hydrogen concentration at 0.88 percent and oxygen at 4.03 percent. These samples continued every three to nine hours through November 14, 2013, with a final gas concentration sample of the C WGDT hydrogen concentration at 0.9 percent and oxygen at 5.3 percent. The waste gas system has 10 WGDTs and during the period of November 8 - 11, 2013, three of the WGDTs had hydrogen gas concentrations of greater than four percent, in conjunction with the C WGDT having oxygen concentrations greater than two percent. The system was shutdown on November 14, 2013, at approximately 1500. The licensee entered the issue into their CAP as AR #651188 and reduced the oxygen concentration to less than two percent on December 11, 2013.

Analysis:

The licensees failure to enter and implement the actions of TS LCO 3.11.2.5, once oxygen concentrations exceeded two percent with hydrogen concentrations greater than four percent within the GRTS was a performance deficiency. Specifically, after the C WGDT sample results identified on November 11, 2013, an oxygen concentration of 4.03 percent, with three of the WGDTs already having greater than four percent hydrogen, LCO 3.11.2.5 should have been entered and the actions implemented. The performance deficiency was determined to be more than minor in accordance with IMC 0612, Appendix B, because if left uncorrected, it would have the potential to lead to a more significant safety concern such as an explosive gas mixture. Specifically, on November 11, 2013, SR 4.11.2.5 was performed unsatisfactorily; Operations was unaware of the results and did not implement the actions of TS LCO 3.11.2.5. Using IMC 0609, SDP, Appendix A, Exhibit 2-External Event Mitigation Systems Screening Questions, the inspectors determined this finding to be of very low safety significance (Green) because it was a deficiency that did not result in a degradation or loss of system function. The finding had a cross-cutting aspect of Procedure Adherence, as described in the Human Performance cross-cutting area because individuals did not follow processes, procedures, and work instructions. Specifically, the licensee failed to comply with RST-202 and notify Operations of the unsatisfactory test result. (H.8)

Enforcement:

TS 3.11.2.5, Explosive Gas Mixtures, requires that the concentration of oxygen in the GRTS downstream of the hydrogen recombiners shall be limited to less than or equal to two percent by volume whenever the hydrogen concentration exceeds four percent by volume. Contrary to the above, the licensee allowed concentrations of greater than two percent oxygen to accumulate in the C WGDT, while three of the remaining decay tanks had hydrogen concentration greater than four percent, in the GRTS in November 2013. The licensee reduced the oxygen concentration to less than two percent on December 11, 2013. This violation is being treated as an NCV, consistent with Section 2.3.2.a of the Enforcement Policy. This violation was entered into the licensees CAP as AR #651188 and is designated as NCV 05000400/2014-002-03, Failure to Comply with Technical Specification 3.11.5.2.

4OA3 Follow-up of Events

.1 Event Notification #49742: Alert Declared due to Fire in a 480V Bus

a. Inspection Scope

The inspectors reviewed the plants response to an alert declared due to a fire in a 480V bus that supplies safe shutdown equipment on January 18, 2014. At 0933, the licensee commenced a rapid shutdown from RTP due to a hard ground indication on the 1D2 nonsafety-related bus. At 1011, the control room initiated a manual reactor trip from 74 percent due to indications of fire in the 1D2 transformer (6.9kV to 480V) which is part of the licensees safe shutdown equipment list. At time 1016, the licensee declared an Alert (HA 2.1) due to a fire affecting plant systems required for safe shutdown. There was no ongoing fire after the bus was deenergized. No personnel were injured and no damage to other equipment was identified. This event is discussed in more detail with an associated finding in section 4OA2.2 of this report.

b. Findings

No findings were identified.

.2 (Closed) LER 05000400/2014-001-00, Manual Reactor Trip due to Indications of Fire

Event Notification #49742, discussed in section 4OA3.1 of this report, resulted in LER 05000400/2014-001-00 because it resulted in a manual reactor trip due to indications of fire as well as the automatic start of the A EDG. After the reactor trip, the 1D2 nonsafety-related bus was deenergized by deenergizing bus 1D. Bus 1D is the normal power supply to the 6.9 kV A safety bus, which was deenergized as a result. The A EDG automatically started and provided electrical power to the A safety bus and loads as required by design. This issue and associated finding is discussed in more detail in section 4OA2.2 of this report. This LER is closed.

.3 (Closed) LER 05000400/2013-003-00, Reactor Pressure Vessel Head Penetration

Nozzle 37 Indication Attributed to Primary Water Stress Corrosion Cracking On November 18, 2013, the reactor vessel head penetrations were being examined while the unit was shut down for a scheduled refueling outage. Ultrasonic examinations identified an indication in head penetration Nozzle 37. Nozzle 37 was repaired utilizing the inside diameter temper bead welding process, which was completed December 2, 2013. The repair restored compliance with the ASME code requirements.

The LER was reviewed and no findings or violations of NRC requirements were identified. This LER is closed.

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

• AR #645884, Unacceptable Indication Found on Nozzle 37

4OA5 Other Activities

.1 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 NCV 05000400/2013004-01 H.3(a) H.5 NCV 05000400/2013005-01 P.3(a) P.6 NCV 05000400/2013005-03 H.2(a) H.6

4OA6 Management Meetings

.1 Exit Meeting Summary

On April 23, 2014, the inspectors presented the inspection results to Mr. Kapopoulos, and other members of the licensee staff. The inspectors confirmed that proprietary information was not provided or examined during the inspection period.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee personnel

D. Corlett, Manager, Nuclear Regulatory Affairs

J. Dufner, Plant Manager

D. Griffith, Manager, Nuclear Training

L. Hughes, Manager, Nuclear Chemistry

E. Kapopoulos, Site Vice President Harris Plant

S. OConnor, General Manager, Nuclear Engineering

M. Parker, Manager, Nuclear Radiation Protection

T. Slake, Director, Nuclear Plant Security

J. Warner, Manager, Nuclear Work Management

F. Womack, Manager, Nuclear Oversight

NRC personnel

G. Hopper, Chief, Reactor Projects Branch 4, Division of Reactor Projects, Region II

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

05000400/2014-002-01 NCV Failure to Adequately Perform the New Fuel Oil Surveillance Requirement (Section 1R22)

05000400/2014-002-02 FIN Failure to Prevent Recurrence of a Signifiant Condition Adverse to Quality (Section 4OA2.2)

05000400/2014-002-03 NCV Failure to Comply With Technical Specification 3.11.5.2 (Section 4OA2.3)

Closed

05000400/2013005-002 URI Operations of the Waste Gas System With Oxygen Concentrations Greater Than the Technical Specification Limits (Section 4OA2.3)

05000400/2014-001-00 LER Manual Reactor Trip Due to Indications of Fire (Section 4OA3.2)

05000400/2013-003-00 LER Reactor Pressure Vessel Head Penetration Nozzle 37 Indication Attributed to Primary Water Stress Corrosion Cracking (Sectin 4OA3.3)