Text

NRC Integrated Inspection Report 05000334/2014002 and 05000412/2014002 (Jan 1 - Mar 31, 2014)
	ML14135A317
Person / Time
Site:	Beaver Valley
Issue date:	05/15/2014
From:	Kevin Mangan; Reactor Projects Region 1 Branch 4
To:	Emily Larson; FirstEnergy Nuclear Generation
	Mangan, KA
References
	IR-14-002
	Download: ML14135A317 (40)
	v • d • e

May 15, 2014

SUBJECT:

BEAVER VALLEY POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000334/2014002 AND 05000412/2014002

Dear Mr. Larson:

On March 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Beaver Valley Power Station, Units 1 and 2. The enclosed inspection report documents the inspection results, which were discussed on April 3, 2014, with Mr. R. Bologna, Director of Site Operations, 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.

This report documents one violation of an NRC requirement and one finding, both of which were of very low safety significance (Green). Additionally, a licensee-identified violation, which was determined to be of very low safety significance, is listed in this report. However, because of the very low safety significance, and because they are entered into your corrective action program, the NRC is treating these findings as non-cited violations, consistent with Section 2.3.2.a of the NRC Enforcement Policy. If you contest the non-cited violations in this report, 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 I; the Director, Office of Enforcement, U. S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at Beaver Valley Power Station. In addition, if you disagree with the cross-cutting aspect assigned to any finding, or a finding not associated with a regulatory requirement in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region I, and the NRC Resident Inspector at Beaver Valley Power Station. In accordance with Title 10 of the Code of Federal Regulations (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 NRCs Public Document Room or from the Publicly Available Records component of the NRCs Agencywide Documents Access Management System (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Kevin A. Mangan, Acting Chief Reactor Projects Branch 6 Division of Reactor Projects Docket Nos.: 50-334, 50-412 License Nos.: DPR-66, NPF-73

Enclosure:

Inspection Report 05000334/2014002 and 05000412/2014002 w/Attachment: Supplementary Information

REGION I==

Docket Nos.: 50-334, 50-412 License Nos.: DPR-66, NPF-73 Report No.: 05000334/2014002 and 05000412/2014002 Licensee: FirstEnergy Nuclear Operating Company (FENOC)

Facility: Beaver Valley Power Station, Units 1 and 2 Location: Shippingport, PA 15077 Dates: January 1 to March 31, 2014 Inspectors: J. Nadel, Acting Senior Resident Inspector E. Carfang, Resident Inspector E. Burket, Emergency Preparedness Inspector N. Floyd, Reactor Inspector D. Orr, Senior Reactor Inspector S. Pindale, Senior Reactor Inspector R. Rolph, Health Physicist Inspector Approved By: Kevin Mangan, Chief (Acting)

Reactor Projects Branch 6 Division of Reactor Projects Enclosure

SUMMARY

IR 05000334/2014002, 05000412/2014002; 01/01/2014 - 03/31/2014; Beaver Valley Power

Station, Units 1 and 2; Post Maintenance Testing; Plant Events.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified two findings of very low safety significance (Green), of which one was a non-cited violation (NCV). The significance of most findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red)and determined using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP), dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310,

Aspects Within the Cross-Cutting Areas, dated December 19, 2013. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated January 28, 2013. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5.

Cornerstone: Initiating Events

Green.

A self-revealing, Green finding was identified because FirstEnergy Nuclear Operating Company (FENOC) did not evaluate technical information provided in a vendor report as required by FENOC procedures: 1/2-ADM-2017, Control of Vendor Technical Information and NOP-CC-1003, Vendor Manuals and Vendor Technical Information.

Specifically, FENOC did not take action to address the recommendation in the ABB Inc.

Life Assessment Report, dated September 2, 2008, to prevent the running of all the main transformer oil pumps when the oil temperature is below 50°C. As a result on January 6, 2014 the Beaver Valley main transformer failed resulting in a reactor trip. Following the trip FENOC conducted an apparent cause evaluation and determined the transformer failure resulted from static electrification caused by improper cooling system operation. FENOC subsequently performed corrective actions included a review of engineering training and updating the operating procedures for the main transformer at both units. The inspectors determined the actions to be reasonable.

The inspectors determined the performance deficiency is more than minor because it is associated with the equipment performance attribute of the Initiating Events cornerstone, and adversely impacted the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the main transformer faulted due to improper guidance on transformer cooling bank operation which resulted in a plant trip. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, the inspectors determined that this finding is of very low safety significance (Green) because the performance deficiency did not cause both a reactor trip and the loss of mitigating equipment. This finding has a cross-cutting aspect in the area of Human Performance, Design Margin, in that FENOC did not ensure that equipment margin was carefully guarded and changed through a systematic and rigorous process. Specifically, FENOC did not ensure that the vendor technical review process implemented main transformer operating margin guidance that resulted in the failure of the transformer (H.6). (Section 4OA3)

Cornerstone: Mitigating Systems

Green.

A self-revealing, Green NCV of 10 CFR 50, Appendix B, Criterion V, Instructions,

Procedures, and Drawings, was identified because FENOC did not establish appropriate post maintenance test procedures for the Turbine Driven Auxiliary Feedwater (TDAFW)pump following trip/throttle valve maintenance that required the removal and reinstallation of the governor. Specifically, FENOC identified in their apparent cause evaluation that vendor technical information regarding the verification of stable governor operating temperature following governor compensating needle valve adjustment was not incorporated into surveillance and post maintenance testing procedures. Because of this omission FENOC did not identify an incorrect governor compensating needle valve adjustment during post maintenance testing on November 1, 2103 and declared the TDAFW pump operable when it was not able to perform its safety function. As a result, the TDAFW pump tripped on overspeed following a reactor trip on January 6, 2014. Following the event, FENOC entered the issue into the corrective action program (CR-2014-0177), performed an apparent cause evaluation, and took corrective actions to update TDAFW pump surveillance and maintenance procedures to ensure the establishment of a stable governor temperature during post maintenance testing runs. The inspectors determined the actions to be reasonable.

The inspectors determined the performance deficiency is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely impacted the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the inadequate post maintenance testing procedure resulted in the inoperability of the TDAFW pump. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, the inspectors determined that a detailed risk evaluation was required because the finding represented an actual loss of function of a single train of auxiliary feedwater (AFW) for greater than its Technical Specification allowed outage time. The detailed risk evaluation determined that the finding was of very low safety significance (Green). This finding did not have a cross-cutting aspect because the most recent opportunity for FENOC to include the appropriate vendor information in the post maintenance testing procedure was in 2009 and is not indicative of current performance.

(Section 1R19)

Other Findings

A violation of very low safety significance that was identified by FENOC was reviewed by the inspectors. Corrective actions taken or planned by FENOC have been entered into FENOCs corrective action program. This violation and corrective action tracking number are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period at 100 percent power. On January 6, 2014, the unit tripped due to a main transformer fault. Following the replacement of the main transformer, operators returned the unit to 100 percent power on January 30, 2014. On January 31, 2014, operators down powered the unit to approximately 15 percent power to remove the main transformer from service due to an open current transformer. The unit returned to 100 percent power on February 1, 2014. The unit remained at or near 100 percent power for the remainder of the inspection period.

Unit 2 began the inspection period at 100 percent power and remained at or near 100 percent power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Main article: IP 71111.01

Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

The inspectors reviewed FENOCs preparations for the onset of cold weather the week of January 6, 2014. The inspectors reviewed the implementation of adverse weather preparation procedures before the onset of and during this adverse weather condition to determine if the impending adverse weather could challenge safety systems and to ensure that FENOC personnel had adequately prepared for potential challenges. The inspectors walked down the emergency diesel generators and auxiliary feedwater system to ensure system availability. The inspectors verified that operator actions defined in FENOCs adverse weather procedure maintained the readiness of essential systems. The inspectors discussed readiness and FENOC personnel availability for adverse weather response with the operations and work control departments to ensure that they were available and capable of responding to potential adverse weather challenges.

b. Findings

No findings were identified.

1R04 Equipment Alignment

Partial System Walkdowns (71111.04 - 4 samples)

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

47 service water strainer during 48 service water strainer outage for corrective maintenance on February 13, 2014 2A recirculation spray pump while 2B recirculation spray pump was out of service for preventative maintenance on MOV-1RS-156B and 1RS-159 on February 14, 2014 1A quench spray pump during planned maintenance on the 1B quench spray pump on March 10, 2014 2-1 Emergency diesel generator (EDG) during corrective maintenance on the 2-2 EDG cooler on March 17, 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 reviewed applicable operating procedures, system diagrams, the Updated Final Safety Analysis Report (UFSAR), technical specifications, work orders, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have impacted system performance of their intended safety functions. The inspectors also performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and were operable.

The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. The inspectors also reviewed whether FENOCs staff had properly identified equipment issues and entered them into the corrective action program for resolution with the appropriate significance characterization.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Resident Inspector Quarterly Walkdowns

Main article: IP 71111.05Q

a. Inspection Scope

The inspectors conducted tours of the areas listed below to assess the material condition and operational status of fire protection features. The inspectors verified that FENOC controlled combustible materials and ignition sources in accordance with administrative procedures. The inspectors verified that fire protection and suppression equipment was available for use as specified in the area pre-fire plan, and passive fire barriers were maintained in good material condition. The inspectors also verified that station personnel implemented compensatory measures for out of service, degraded, or inoperable fire protection equipment, as applicable, in accordance with procedures.

Unit 1 1-1 EDG room (Fire Area DG-1) on January 10, 2014 Unit 1 1-2 EDG room (Fire Area DG-2) on January 10, 2014 Unit 2 alternate shutdown panel (Fire Area ASP) on February 4, 2014 Unit 2 west communications room (Fire Area CB-6) on February 5, 2014 Unit 2 fan room (Fire Area CB-5) on February 5, 2014 Unit 1 cable tray mezzanine (Fire Area CS-1) on March 10, 2014

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation

Main article: IP 71111.05A

a. Inspection Scope

The inspectors observed a re-test fire brigade drill scenario conducted on March 31, 2014, that involved a fire in Unit 1 AE emergency switchgear. The inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that FENOC personnel identified deficiencies, openly discussed them in a self-critical manner at the debrief, and took appropriate corrective actions as required. The inspectors evaluated specific attributes as follows:

Proper wearing of turnout gear and self-contained breathing apparatus Proper use and layout of fire hoses Employment of appropriate fire-fighting techniques Sufficient fire-fighting equipment brought to the scene Effectiveness of command and control Utilization of pre-planned strategies Adherence to the pre-planned drill scenario Drill objectives met The inspectors evaluated the fire brigades actions to determine whether these attributes were in accordance with FENOCs fire-fighting strategies.

b. Findings

No findings were identified.

1R06 Flood Protection Measures (71111.06 - 1 sample, 1 partial sample)

.1 Internal Flooding Review

a. Inspection Scope

The inspectors reviewed the UFSAR, the site flooding analysis, and plant procedures to assess susceptibilities involving internal flooding. The inspectors also reviewed the corrective action program to determine if FENOC identified and corrected flooding problems and whether operator actions for coping with flooding were adequate.

Specifically, the inspectors determined if plant design features including equipment seals located below the flood line, floor and water penetration seals, common drain lines and sumps, sump pumps, level alarms, control circuits, and temporary or removable flood barriers would mitigate an internal flood in the unit 1 control room air conditioning equipment room.

b. Findings

No findings were identified.

.2 Annual Review of Cables Located in Underground Bunkers/Manholes

a. Inspection Scope

The inspectors conducted an inspection of underground bunkers/manholes subject to flooding that contain cables whose failure could affect risk-significant equipment. The inspectors performed walkdowns of risk-significant areas, including manhole 1EMH8B containing river water and service water cables, to verify that the cables were not submerged in water, that cables and splices appeared intact, and to observe the condition of cable support structures. When applicable, the inspectors verified proper sump pump operation and verified level alarm circuits were set in accordance with station procedures and calculations to ensure that the cables will not be submerged during normal plant operations.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

Main article: IP 71111.11Q

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training scenario 1DRLS-FR-H-1.006 on March 18, 2014, which included a loss of all main feedwater, a faulted steam generator, and the failure of select components to automatically start as required. The inspectors evaluated operator performance during the simulated event and verified completion of risk significant operator actions, including the use of abnormal and emergency operating procedures. The inspectors assessed the clarity and effectiveness of communications, implementation of actions in response to alarms and degrading plant conditions, and the oversight and direction provided by the control room supervisor. The inspectors verified the accuracy and timeliness of the emergency classification made by the shift manager and the technical specification action statements entered by the crew.

Additionally, the inspectors assessed the ability of the crew and training staff to identify and document crew performance problems.

b. Findings

No findings were identified.

.2 Quarterly Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

The inspectors observed Unit 1 criticality, start-up, and synchronization to the grid activities on January 29, 2014. Inspectors also observed a rapid Unit 1 down-power and taking the unit offline after the discovery of an open current transformer in the main unit transformer on January 31, 2014. The inspectors observed evolution briefings and reactivity control briefings prior to these operations to verify the briefings met the criteria specified in NOP-OP-1002, Conduct of Operations, Revision 8. Additionally, the inspectors observed operator performance during the power maneuvers to verify that procedure use, crew communications, reactivity management, and coordination of activities between work groups met established expectations and standards.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

Main article: IP 71111.12Q

a. Inspection Scope

The inspectors reviewed the samples listed below to assess the effectiveness of maintenance activities on structure, system, or component (SSC) performance and reliability. The inspectors reviewed system health reports, corrective action program documents, maintenance work orders, and maintenance rule basis documents to ensure that FENOC was identifying and properly evaluating performance problems within the scope of the maintenance rule. For each sample selected, the inspectors verified that the SSC was properly scoped into the maintenance rule in accordance with 10 CFR 50.65 and verified that the (a)(2) performance criteria established by FENOC staff was reasonable. As applicable, for SSCs classified as (a)(1), the inspectors assessed the adequacy of goals and corrective actions to return these SSCs to (a)(2). Additionally, the inspectors ensured that FENOC staff was identifying and addressing common cause failures that occurred within and across maintenance rule system boundaries.

Condensate recirculation flow valve failure maintenance rule evaluation on November 29, 2013 1A main feedwater pump oil leak on February 1, 2014

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

Main article: IP 71111.13

a. Inspection Scope

The inspectors reviewed station evaluation and management of plant risk for the maintenance and emergent work activities listed below to verify that FENOC performed the appropriate risk assessments prior to removing equipment for work. The inspectors selected these activities based on potential risk significance relative to the reactor safety cornerstones. As applicable for each activity, the inspectors verified that FENOC personnel performed risk assessments as required by 10 CFR 50.65(a)(4) and that the assessments were accurate and complete. When FENOC performed emergent work, the inspectors verified that operations personnel promptly assessed and managed plant risk. The inspectors reviewed the scope of maintenance work and discussed the results of the assessment with the stations probabilistic risk analyst to verify plant conditions were consistent with the risk assessment. The inspectors also reviewed the technical specification requirements and inspected portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met.

Unit 1 planned and emergent maintenance for the work week of January 6, 2014 Unit 2 planned maintenance risk during the work week of February 3, 2014 Unit 1 and Unit 2 Regional transmission organization grid emergency declaration impact on planned maintenance on March 4, 2014 Unit 1 emergent maintenance on 1C river water pump cell switch failure on March 6, 2014 Unit 1 planned and emergent maintenance for the work week of March 17, 2014

b. Findings

No findings were identified.

1R15 Operability Determinations and Functionality Assessments

Main article: IP 71111.15

a. Inspection Scope

The inspectors reviewed operability determinations for the following degraded or non-conforming conditions:

3B motor-driven AFW flow control valve remote position indication on February 20, 2014 Appendix R temporary light functionality assessment on February 28, 2014 Fire protection piping minimum thickness calculations on March 4, 2014 Potential thermal fatigue from leak by into the Unit 1 residual heat removal system on February 24, 2014 21B Safety injection accumulator level indication accuracy on March 18, 2014 The inspectors selected these issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the operability determinations to assess whether technical specification 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 technical specifications and UFSAR to FENOCs 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 by FENOC. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations.

b. Findings

No findings were identified.

1R18 Plant Modifications

Main article: IP 71111.18

.1 Temporary Modifications

a. Inspection Scope

The inspectors reviewed the temporary modification implemented by engineering change package 14-0099 Lower loop 3 pressurizer spray alarm setpoint to determine whether the modification affected the safety functions of systems that are important to safety. The inspectors reviewed 10 CFR 50.59 documentation and post-modification testing results, and conducted a control room walkdown of the modification to verify that the temporary modification did not degrade the design bases, licensing bases, and performance capability of the affected system.

b. Findings

No findings were identified.

.2 Permanent Modifications

a. Inspection Scope

The inspectors evaluated a modification implemented by engineering change package 10-0440-003, Replacement Speed Sensing Relay EG-SSP1-2. The inspectors verified that the design bases, licensing bases, and performance capability of the affected systems were not degraded by the modification. In addition, the inspectors reviewed modification documents associated with the upgrade and design change, including the equivalent change evaluation for the speed sensing relay. Inspectors also observed the post-maintenance testing performed after the modification was installed.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

Main article: IP 71111.19

a. Inspection Scope

The inspectors reviewed the post-maintenance tests for the maintenance activities listed below to verify that procedures and test activities ensured system operability and functional capability. The inspectors reviewed the test procedure to verify that the procedure adequately tested the safety functions that may have been affected by the maintenance activity; that the acceptance criteria in the procedure was consistent with the information in the applicable licensing basis and/or design basis documents; and the procedure had been properly reviewed and approved. The inspectors also witnessed the test or reviewed test data to verify that the test results adequately demonstrated restoration of the affected safety functions.

1FW-P-2 turbine driven auxiliary feedwater pump governor compensating needle valve adjustment on January 8, 2014 21C charging pump auxiliary lube oil pump oil leak repair on January 29, 2014 1C river water pump seal planned replacement on February 10, 2014 48 service water strainer corrective maintenance on February 13, 2014 Diesel driven fire pump inspection and overhaul on February 20, 2014 Dedicated auxiliary feedwater pump motor refurbishment on March 4, 2014 8B manhole sump pump flow switch malfunction repair on March 7, 2014 1B quench spray pump discharge valve breaker maintenance on March 12, 2014

b. Findings

Introduction:

A self-revealing, Green NCV of 10 CFR 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified because FENOC did not establish appropriate post maintenance test procedures for the turbine driven auxiliary feedwater (TDAFW) pump. Specifically, vendor technical information regarding the verification of stable governor operating temperature was not incorporated into surveillance and post maintenance testing procedures resulting in a period of inoperability for the TDAFW pump from November 1, 2013, to January 8, 2014.

Description.

The inspectors reviewed a unit 1 tripped from full power as a result of a main unit transformer failure that occurred on January 6. 2014. The inspectors noted that all three auxiliary feedwater (AFW) pumps automatically started, as expected, due to lowering steam generator levels. The TDAFW pump ran for 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and 49 minutes at which time the pump tripped. FENOC declared the TDAFW pump inoperable and began troubleshooting in order to determine the cause of the pump trip.

FENOCs investigation determined that after 1 hour1.157407e-5 days 2.777778e-4 hours 1.653439e-6 weeks 3.805e-7 months and 21 minutes of operation the governor began to oscillate and tripped on overspeed. They determined that the speed oscillations were due to a misadjusted governor compensating needle valve. FENOC identified that the compensating needle valve adjustment was last made during the refueling outage in the Fall of 2013 in accordance with 1/2CMP-24-GOVERNOR-1M, Turbine Aux Feed Pump Governor Maintenance, Revision 9. This procedure is performed at a time in the outage in which steam is not available so the turbine is run using pressurized air as the motive force. This resulted in the turbine governor oil running at a lower than normal operating temperature which allowed the compensating needle valve to be set at the wrong point. Additionally, when the pump was run with steam as the motive force in Mode 3 on November 1, 2013, FENOC did not run the test run long enough to allow the oil in the governor to heat up, so the oil viscosity did not change enough to allow them to identify that the governor control would become unstable and oscillate. FENOC concluded that following the reactor trip the TDAFW pump ran long enough to heat up the oil to a viscocity that allowed the oscillations to cause the TDAFW pump to overspeed, and that the improper compensating needle valve setting had rendered the TDAFW pump inoperable.

The inspectors found that the TDAFW pump vendor technical manual had specific guidance regarding the adjustment of the needle valve. The vendor technical manual includes the following requirements; from the Initial Operation section, step 4, Start the engine as instructed by the prime mover manufacturer, and allow the governor to reach its normal operating temperature, and from the Compensation Needle Valve Adjustment section, step 3, Once the needle valve adjustment is correct, it is not necessary to change the setting except for large permanent changes in temperature which affect governor oil viscosity. However the inspectors noted that these requirements were never added to plant surveillance and post maintenance testing procedures. The inspectors identified that FENOC Procedure NOP-CC-1003, Vendor Manuals and Vendor Technical Information, contains specific requirements to review vendor technical information after each technical manual update to ensure it is included in plant procedures. Additionally, the inspectors found that the procedure requires that FENOC review changes to the vendor documents and determined that 2009 was the last time the statements regarding compensating needle valve adjustments would have been required to be reviewed. Following identification of the issue, FENOC entered the issue into the corrective action program and completed immediate corrective actions to perform governor compensating needle valve adjustments in accordance with vendor guidance. Additionally, FENOC performed an extended return to service post maintenance test run where stable operating temperatures were verified prior to declaring the pump operable. The inspectors reviewed these actions and determined them to be reasonable.

Analysis:

The inspectors determined that the failure to establish appropriate TDAFW pump surveillance and post maintenance testing procedures, as required by 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was a performance deficiency that was within FENOCs ability to foresee and correct and should have been prevented. Specifically, vendor technical information regarding the verification of stable governor operating temperature following needle valve adjustments was not incorporated into surveillance and post maintenance testing procedures. The performance deficiency is more than minor because it is associated with the equipment performance attribute of the Mitigating Systems cornerstone and adversely impacted the cornerstone objective to ensure the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the inadequate post maintenance testing procedure resulted in the inoperability of the TDAFW from November 1, 2013, to January 8, 2014.

Using Manual Chapter 0609.04, Initial Characterization of Findings, Table 2, dated June 19, 2012, and Manual Chapter 0609 Appendix A, Significance Determination Process (SDP) for Findings at-Power, dated June 19, 2012, the inspectors determined that a detailed risk evaluation was required because the finding represented an actual loss of function of a single train of AFW for greater than its Technical Specification allowed outage time. A Detailed Risk Evaluation was performed by the Senior Reactor Analysts (SRAs) utilizing the Beaver Valley Unit 1 SPAR model version 8.22. Given a 68 day exposure period with the TDAFW pump assumed to fail-to-run, the change in the internal events core damage frequency (CDF) was calculated to be in the low 10-7range. The dominant sequences included losses of offsite power progressing to a station blackout with the failure of dedicated AFW and the failure to recover offsite power. Since the internal events CDF exceeded 1x10-7, an evaluation of external risk contributors was conducted. For the performance deficiency, seismic events contributed the most risk with the dominant sequence being a seismic event resulting in a station blackout with a failure of the Emergency Response Facility diesel. The total risk from internal and external sources was calculated to be in the mid to high 10-7range. Contributions from a large early release did not need to be considered since none of the dominant accident sequences included steam generator tube ruptures or other containment bypass events and that Beaver Valley Unit 1 has a large dry containment. Based on the Detailed Risk Evaluation, the SRAs determined that the finding was of very low safety significance (Green).

This finding did not have a cross-cutting aspect because the most recent opportunity for FENOC to include the appropriate vendor information in the post maintenance testing procedure was in 2009 and is not indicative of current performance.

Enforcement.

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality shall be prescribed by documented instructions or procedures of a type appropriate to the circumstances and shall include qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Contrary to the above, since at least September 29, 2009, and until January 6, 2014, FENOCs procedure 1OST-24.9, did not include qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished. Specifically, FENOC procedure 1OST-24.9 did not include vendor technical requirements to ensure that the governor had reached a stable operating temperature during testing in instances where adjustments had been performed on the governor compensating needle valve. FENOCs corrective actions included updating TDAFW pump surveillance and maintenance procedures to ensure the establishment of a stable governor temperature and then performing the TDAFW surveillance to ensure the governor compensating needle valve was properly adjusted prior to declaring it operable. Because this deficiency is considered to be of very low safety significance (Green) and FENOC entered this issue into the corrective action program (CR 2014-00177), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000334/2014002-01, Inadequate Post Maintenance Testing Procedures Resulted in TDAFW Pump Inoperability)

1R20 1FOAC3 Outage Activities

Main article: IP 71111.20

a. Inspection Scope

The inspectors reviewed the stations unit 1 activities for the main transformer replacement and forced outage (1FOAC3), which was conducted from January 6, 2014 to January 30, 2014. The inspectors reviewed FENOCs development and implementation of outage plans and schedules to verify that risk, industry experience, previous site-specific problems, and defense-in-depth were considered. The unit remained in Mode 3 (Hot Standby) throughout the forced outage. During the outage, the inspectors observed portions of the shutdown process and monitored controls associated with the following outage activities:

Configuration management and compliance with the applicable technical specifications when taking equipment out of service Status and configuration of electrical systems and switchyard activities to ensure that technical specifications were met Monitoring of decay heat removal operations Activities that could affect reactivity Observed startup/grid synchronization activities on January 29, 2014

b. Findings

No findings were identified.

1R22 Surveillance Testing

Main article: IP 71111.22

a. Inspection Scope

The inspectors observed performance of surveillance tests and/or reviewed test data of selected risk-significant SSCs to assess whether test results satisfied technical specifications, the UFSAR, and FENOC procedure requirements. The inspectors verified that test acceptance criteria were clear, tests demonstrated operational readiness and were consistent with design documentation. Additionally, inspectors determined whether test instrumentation had current calibrations, adequate ranges and accuracy for the application; tests were performed as written; and applicable test prerequisites were satisfied. Upon test completion, the inspectors considered whether the test results validated that the equipment was capable of performing the required safety functions. The inspectors reviewed the following surveillance tests:

1OST-6.7A, Computer Generated Reactor Coolant System Water Inventory Balance on January 2 and 5, 2014 (leak rate)2OST-36.2, Emergency Diesel Generator [2EGS*EG2-2] Monthly Test on January 22, 2013 1OST-49.2, Shutdown Margin Calculation (Plant Shutdown) on January 29, 2014 1OST-24.3, B Motor Driven Auxiliary Feedwater Pump Test on February 19, 2014 (in-service test)2OST-30.13B, Train B Service Water Full Flow Test, on March 13, 2014

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP4 Emergency Action Level and Emergency Plan Changes

Main article: IP 71114.04

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

FENOC implemented various changes to the Beaver Valley Emergency Action Levels (EALs), Emergency Plan, and Implementing Procedures. The inspectors noted FENOC had determined that, in accordance with 10 CFR 50.54(q)(3), any change made to the EALs, Emergency Plan, and its lower-tier implementing procedures, had not resulted in any reduction in effectiveness of the Plan, and that the revised Plan continued to meet the standards in 50.47(b) and the requirements of 10 CFR 50 Appendix E.

The inspectors performed an in-office review of all EAL and Emergency Plan changes submitted by FENOC as required by 10 CFR 50.54(q)(5), including the changes to lower-tier emergency plan implementing procedures, to evaluate if any reductions in effectiveness of the Emergency Plan had occurred as a result of the changes. The review by the inspectors was not documented in an NRC 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 requirements in 10 CFR 50.54(q) were used as reference criteria. The specific documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstone: Occupational/Public Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls (71124.01 - 0 Samples)

a. Inspection Scope

During March 3 - 6, 2014, the inspectors reviewed FirstEnergy Nuclear Operating Company (FENOC) performance in assessing the radiological hazards and exposure control in the workplace. The inspector used the requirements in 10 CFR Part 20 and guidance in Regulatory Guide (RG) 8.38 Control of Access to High and Very High Radiation Areas for Nuclear Plants, Technical Specifications (TS), and the FENOC procedures required by TSs as criteria for determining compliance.

Radiological Hazard Assessment The inspectors determined if there have been changes to plant operations since the last inspection that may result in a significant new radiological hazard for onsite workers or members of the public. The inspectors evaluated whether FENOC assessed the potential impact of these changes.

The inspectors reviewed the last two radiological surveys from the Unit 1: Safeguards room, Auxiliary Building, Charging Pump Pit A, Charging Pump Pit B, and Charging Pump Pit C and Unit 2: Charging Pump A, Charging Pump B, and Charging Pump C.

The inspectors evaluated whether the thoroughness and frequency of the surveys were appropriate.

The inspectors conducted walk-downs and independent radiation measurements in the facility, including the Units 1 and 2 auxiliary buildings, radioactive waste processing, storage, and handling areas to evaluate postings, material and radiological conditions.

Instructions to Workers The inspectors selected five containers of non-exempt licensed radioactive materials.

The inspectors assessed whether the containers were labeled and controlled in accordance with 10 CFR Part 20 requirements.

The inspectors reviewed radiation work permits (RWP), listed in the Attachment, used to access high radiation areas (HRA) and evaluated if the specified work control instructions and control barriers were consistent with TS requirements for HRA. For these RWPs, the inspectors assessed whether permissible dose for radiologically significant work under each RWP was clearly identified. The inspectors evaluated whether electronic personal dosimeter (EPD) alarm set-points were in conformance with survey indications and plant procedural requirements.

The inspectors reviewed two occurrences where a workers EPD malfunctioned or alarmed. The inspectors evaluated whether workers responded appropriately. The inspectors assessed whether the issue was included in the corrective action program and whether compensatory dose evaluations were conducted, if appropriate.

For work activities that could suddenly increase radiological conditions, the inspectors assessed the FENOCs means to inform workers of these changes.

Contamination and Radioactive Material Control The inspectors reviewed FENOCs criteria for the survey and release of potentially contaminated material. The inspectors evaluated whether there was sufficient alarm response guidance.

Radiological Hazards Control and Work Coverage The inspectors evaluated ambient radiological conditions and performed independent radiation measurements during walk-downs of the facility. The inspectors assessed whether the conditions were consistent with applicable posted surveys, RWPs, and associated worker briefings.

The inspectors evaluated the adequacy of radiological controls, such as required surveys, radiation protection job coverage and contamination controls. The inspectors evaluated FENOCs use of EPDs in high noise areas in HRAs.

The inspectors examined FENOCs physical and programmatic controls for highly activated or contaminated materials stored within spent fuel and other storage pools.

The inspectors assessed whether appropriate controls were in place to preclude inadvertent removal of these materials from the pool.

The inspectors examined the posting and physical controls for selected HRAs, LHRAs and very high radiation areas (VHRA) to verify conformance with the occupational performance indicator.

Risk-Significant HRA and VHRA Controls The inspectors discussed with the Radiation Protection Manager (RPM) the controls and procedures for high-risk HRAs and VHRAs. The inspectors assessed whether any changes to FENOCs relevant procedures substantially reduce the effectiveness and level of worker protection.

The inspectors discussed with first-line health physics supervisors the controls in place for special areas that have the potential to become VHRAs during certain plant operations. The inspectors assessed whether these plant operations require communication beforehand with the health physics group, so as to allow corresponding timely actions to properly post, control, and monitor the radiation hazards including reaccess authorization.

The inspectors evaluated FENOCs controls for VHRAs to ensure that an individual was not able to gain unauthorized access.

Problem Identification and Resolution The inspectors reviewed the results of radiation program (RP) program audits. The inspectors reviewed all reports of operational occurrences related to occupational radiation safety since the last inspection.

The inspectors evaluated whether problems associated with radiation monitoring and exposure control were being identified by FENOC at an appropriate threshold and were properly addressed for resolution in the licensees corrective action program. The inspectors assessed the appropriateness of the corrective actions for problems documented by FENOC that involve radiation monitoring and exposure controls.

b. Findings

No findings were identified.

2RS2 Occupational ALARA Planning and Controls (71124.02 - 0 Samples)

a. Inspection Scope

During March 3 - 6, 2014, the inspectors assessed performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA). The inspectors used the requirements in 10 CFR Part 20, RG 8.8, - Information Relevant to Ensuring that Occupational Radiation Exposures at Nuclear Power Plants will be As Low As Is Reasonably Achievable, RG 8.10 - Operating Philosophy for Maintaining Occupational Radiation Exposure As Low as Is Reasonably Achievable, TSs, and FENOC procedures required by TSs as criteria for determining compliance.

The inspectors reviewed information regarding Beaver Valley collective dose history, current exposure trends, and ongoing or planned activities in order to assess current performance and exposure challenges. The inspectors reviewed the plants three year rolling average collective exposure.

The inspectors compared the site-specific trends in collective exposures against the industry average values and those values from similar nuclear power plants. In addition, the inspectors reviewed any changes in the radioactive source term by reviewing the trend in average contact dose rate with reactor coolant piping.

Finally, the inspectors reviewed site-specific procedures associated with maintaining occupational exposures ALARA, which included a review of processes used to estimate and track exposures from specific work activities.

Verification of Dose Estimates and Exposure Tracking Systems The inspectors reviewed the assumptions and basis for the current annual collective dose estimate for accuracy. The inspectors reviewed applicable procedures to determine the methodology for estimating exposures from specific work activities and for department and station collective dose goals.

Source Term Reduction and Control The inspectors used licensee records to determine the historical trends and current status of plant source term that contribute to elevated facility collective dose. The inspectors assessed whether the licensee had developed contingency plans for expected changes in the source term as the result of changes in plant fuel performance issues or changes in plant primary chemistry.

Problem Identification and Resolution The inspectors evaluated whether problems associated with ALARA planning and controls are being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensees corrective action program. The inspectors assessed FENOCs process for applying operating experience to their plant.

b. Findings

No findings were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification

Main article: IP 71151

.1 Unplanned Scrams, Unplanned Power Changes, and Unplanned Scrams with

Complications (6 samples)

a. Inspection Scope

The inspectors reviewed FENOCs submittals for the following Initiating Events Cornerstone performance indicators for the period of January 1, 2013, through December 31, 2013.

Unit 1 Unplanned Scrams Unit 2 Unplanned Scrams Unit 1 Unplanned Power Changes Unit 2 Unplanned Power Changes Unit 1 Unplanned Scrams with Complications Unit 2 Unplanned Scrams with Complications To determine the accuracy of the performance indicator data reported during those periods, inspectors used definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors reviewed FENOCs operator narrative logs, maintenance planning schedules, condition reports, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution

Main article: IP 71152

.1 Routine Review of Problem Identification and Resolution Activities

a. Inspection Scope

As required by Inspection Procedure 71152, Problem Identification and Resolution, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify that FENOC entered issues into the corrective action program at an appropriate threshold, gave adequate attention to timely corrective actions, and identified and addressed adverse trends. In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a daily screening of items entered into the corrective action program and periodically attended condition report screening meetings.

b. Findings

No findings were identified.

.2 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a semi-annual review of site issues, as required by Inspection Procedure 71152, Problem Identification and Resolution, to identify trends that might indicate the existence of more significant safety issues. In this review, the inspectors included repetitive or closely-related issues that may have been documented by FENOC outside of the corrective action program, such as trend reports, performance indicators, major equipment problem lists, system health reports, maintenance rule assessments, and maintenance or corrective action program backlogs. The inspectors also reviewed FENOCs corrective action program database for the third and fourth quarters of 2013 to assess condition reports written in various subject areas (equipment problems, human performance issues, security, etc.), individual issues identified during the resident inspectors daily condition report review (Section 4OA2.1), and all calendar year 2013 oversight reports. The inspectors reviewed FENOCs two semi-annual trend reports for the 2013 calendar year, conducted under procedure NOBP-LP-2018, Integrated Performance Assessment and Trending, Revision 10, to verify that FENOC personnel were appropriately evaluating and trending adverse conditions in accordance with applicable procedures.

b. Findings and Observations

No findings were identified.

The inspectors evaluated a sample of FENOC departments (including maintenance, operations, engineering, and security) required to provide input into the semi-annual trend reports. This review included a sample of issues and events that occurred over the course of the past two quarters to objectively determine whether issues identified were appropriately evaluated in order to determine if it was an emerging or adverse trend, and in some cases, inspectors verified the appropriate disposition of the identified trends. The inspectors verified that these issues were addressed within the scope of the corrective action program or through department review and documentation in the quarterly trend report for overall assessment. For example, the inspectors noted that the issue of housekeeping was identified as a weakness by outside auditing organizations and plant oversight. Negative trends in housekeeping and cleanliness were identified in the operations and maintenance departments multiple times since 2010. In calendar year 2013, new adverse trends were identified by FENOC in housekeeping for both the operations and maintenance departments with pending corrective actions at the time of the inspectors review. Inspectors noted that, while some improvement had been seen in the number of new issues being identified, additional attention and corrective actions had been identified in order to close the open trends by the set closure dates in 2014.

This issue has been entered into the licensees corrective action program as condition report (CR) 2014-06233. Inspectors also noted an open trend in the related area of foreign material exclusion (FME) control and several low consequence examples of FME events over the last year. Inspectors reviewed a status roll-up of over 50 corrective actions related to FME issues over the 2013 calendar year. Some of these corrective actions related to procedure changes were still open, but are expected to be complete prior to the upcoming Unit 2 refueling outage. Through discussions with station management and FME program owners, inspectors determined that special management attention, programs, and training was planned both prior to and during upcoming refueling outages, which is the time that the most significant issues have occurred historically. No new adverse trends were identified by the inspectors this period that had not already been identified by the licensee.

.3 Annual Sample: Valve Failure due to Inadequate Vendor Document Review (1 Sample)

a. Inspection Scope

The inspectors performed an in-depth review of FENOCs evaluation and corrective actions associated with a deficient evaluation of a vendor technical bulletin, which resulted in a charging system flow control valve failure. Specifically, FENOC did not identify that a circuit board that was the subject of a vendor technical bulletin was installed in the flow control valves controller circuit. The valve subsequently failed to operate when called upon by operators.

The inspectors assessed FENOCs cause evaluation, associated extent-of-condition review, and the prioritization and timeliness of actions to evaluate whether the licensee was appropriately identifying, characterizing, and correcting problems; and whether the associated corrective actions were appropriate and met the requirements of FENOCs corrective action program. The inspectors reviewed documents and interviewed engineering personnel to assess the acceptability and effectiveness of FENOCs actions and the effectiveness of their program to maintain and evaluate vendor technical information. The inspectors reviewed the applicable CR (2013-01974) and related documents and procedures to determine if corrective actions, both planned and completed, adequately address the identified deficiencies. In addition, the inspectors independently reviewed FENOCs responses to selected operating experience and vendor correspondence to evaluate the effectiveness of their corrective actions.

b. Findings and Observations

No findings were identified.

The inspectors determined that FENOCs overall response to the issue was commensurate with the safety significance, was timely, and included appropriate corrective actions. The inspectors determined that FENOC appropriately identified the apparent cause of the valve failure as an inadequate investigation of the related vendor technical bulletin. The inspectors reviewed FENOCs specific corrective actions, which included completing a thorough review of the technical bulletin, and identifying all suspect components and assigning the appropriate work activity for hardware replacement. The need for additional training related to conducting vendor document reviews was also considered; and an extent-of-condition review was completed, which included a sampling of previously completed vendor technical bulletins and 10 CFR Part 21 notifications to ensure they were technically correct and thorough.

Notwithstanding the overall acceptable response to this issue, the inspectors identified a weakness during an independent review of previously completed vendor correspondence. In particular, FENOCs review of a 10 CFR Part 21 notification related to wedge pin failures of certain motor-operated double disc gate valves did not identify that four additional valves had been installed at Unit 1 beyond the initial number of valves (seven) identified by the vendor. While FENOC subsequently self-identified the additional four installed valves, the associated CR (2013-18679) was narrowly focused in that it did not evaluate the failure to identify those valves during the initial review.

Rather, the CR focused on implementing only the hardware inspections and corrective actions. In response, FENOC initiated CR 2014-01651 to identify and correct the evaluation weakness associated with the 10 CFR Part 21 review. The subsequent evaluation found no additional deficiencies.

.4 Annual Sample: Unit 1 4kV Cable Failure

a. Inspection Scope

The inspectors performed an in-depth review of FENOCs root cause analysis and corrective actions associated with CR 2013-17888. On November 5, 2013, a cable failure occurred within the Unit 1 Husky (Husky is a trade name) bus from unit station service transformer (USST), TR-1C, to the 1B normal switchgear bus. FENOC identified that a failure of cable jacketing, shielding and insulation resulted in a flow of electrical current to ground causing an arc flash. The arc flash subsequently damaged additional cables from TR-1C to normal switchgear 4kV bus 1B and from both USSTs, TR-1C and TR-1D, to normal 4kV buses 1A, 1C, and 1D. As a result of the fault condition, Unit 1 experienced an automatic turbine trip due to differential protection relay actuation associated with TR-1C. Subsequently, the reactor operator manually tripped the reactor due to multiple unexpected alarms. On February 20, 2014, FENOC completed the root cause analysis report for the cable failure that occurred on November 5, 2013.

The inspectors assessed FENOCs problem identification threshold, causal analyses, technical analyses, extent of condition reviews, operational decision making, and the prioritization and timeliness of corrective actions to determine whether FENOC was appropriately identifying, characterizing, and correcting problems associated with this issue. The inspectors focused on opportunities for FENOC to have identified any earlier degradation of cable insulation or jacketing. The inspectors also assessed FENOCs corrective actions to establish a cable condition monitoring program. In addition, the inspectors reviewed documentation associated with this issue, including condition and failure analysis reports, and interviewed engineering personnel to assess the effectiveness of the implemented and planned corrective actions. Resident inspectors previously reviewed the adequacy of the FENOC staff response and evaluation of the event during and promptly after the event. The review was documented in the event follow-up inspection activities in NRC Integrated Inspection Report 05000334/2013004 and 05000412/2013004 (ADAMS ML14041A003) Section 4OA3.1.

b. Findings and Observations

No findings were identified.

The inspectors found that FENOC promptly initiated an investigation and chartered a team to determine the root cause of the TR-1C Husky bus cable failure and subsequent arc flash. FENOC additionally assessed all potential collateral damage in the vicinity of the arc flash as well as potential adverse interactions to equipment electrically connected at the time of the fault. FENOC established corrective actions to replace all the cabling from both USSTs to all normal switchgear 4kV buses by May 4, 2014.

FENOC additionally completed an engineering assessment on November 8, 2013, to assess the condition of the similar designed Husky bus cables from TR-1A and TR-1B SSSTs prior to plant restart.

The inspectors review of the root cause analysis found that, due to the extent of the damage caused by the event, the exact triggering mechanism or root cause of the cable failure could not be identified. However, FENOC determined five conditions that may have caused the cable jacket and insulation failure with subsequent arc flash, to occur:

Diminished cable service life due to chronic exposure to ohmic heating within the Husky bus enclosure

A latent manufacturing defect

Physical damage to the cable during installation

Cables not covered at the wall penetration by a cable tray cover resulting in fluids or foreign material falling on the cable and subsequently damaging or degrading the cables

Moisture or humidity intrusion through degraded cable jacketing and shielding For each contributing cause, the inspectors determined that FENOC had planned corrective actions to ensure the replacement cables would not be subject to the same conditions.

For the Beaver Valley Power Station (BVPS) Husky bus configuration and environmental conditions, the inspectors did not identify an industry standard that required condition monitoring of the USST cables prior to their failure. However, the inspectors noted that FENOC had previously established a cable condition monitoring program that augmented its scope when operational history indicates failure of cables. As such, FENOC initiated a corrective action to include the Unit 1 and Unit 2 Husky bus cables in its license renewal commitment for cable aging management. FENOC additionally sent cable samples from locations near but not damaged by the arc flash to a laboratory for testing and analysis. The results of the laboratory analysis were expected by May 1, 2014. The inspectors determined that FENOCs overall response to the issue was commensurate with the safety significance, was timely, and the actions taken and planned were reasonable to restore the USSTs to service and to ensure degradation did not exist on similar designed Husky bus cables from the Unit 1 SSSTs and the Unit 2 USSTs and SSSTs.

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

Main article: IP 71153

.1 Plant Events

a. Inspection Scope

For the plant events listed below, the inspectors reviewed and/or observed plant parameters, reviewed personnel performance, and evaluated performance of mitigating systems. The inspectors communicated the plant events to appropriate regional personnel, and compared the event details with criteria contained in IMC 0309, Reactive Inspection Decision Basis for Reactors, for consideration of potential reactive inspection activities. As applicable, the inspectors verified that FENOC made appropriate emergency classification assessments and properly reported the event in accordance with 10 CFR Parts 50.72 and 50.73. The inspectors reviewed FENOCs follow-up actions related to the events to assure that FENOC implemented appropriate corrective actions commensurate with their safety significance.

Unit 1 plant trip due to a main transformer fault on January 6, 2014 Unit 1 unplanned down-power to 15 percent on January 31, 2014, due to an open current transformer on the main transformer Unit 1 declaration of a Notice of Unusual Event on March 2, 2014, due to a fire alarm in containment that could not be visually verified within 15 minutes

b. Findings

Introduction:

A self-revealing, Green finding was identified because FENOC did not evaluate technical information provided in a vendor report as required by 1/2-ADM-2017, Control of Vendor Technical Information, and NOP-CC-1003, Vendor Manuals and Vendor Technical Information. Specifically, FENOC did not evaluate and incorporate a recommendation in the ABB Inc. Life Assessment Report, that FENOC should have operating procedures that prevent the running of all the main transformer oil pumps when the oil temperature is below 50°C. Subsequently, the transformer failed resulting in a reactor trip.

Description:

On January 6, 2014, the unit 1 main transformer experienced an internal electrical fault that resulted in a turbine and reactor trip. Operators were securing transformer cooling fans due to oil temperature dropping below 40°C, to comply with precautions listed in 1OM-35.2.A, Main Generator and Transformer Precautions, Limitations, and Setpoints, Revision 9, when the transformer fault occurred. Following the main transformer failure, FENOC performed a root cause evaluation (CR 2014-00175) and determined that static electrification, caused by inadequate operating procedures for the transformer, was the most likely cause of the transformer fault. A new transformer was installed and placed in service on January 28, 2014.

In the root cause evaluation FENOC noted that, in 1990, the licensee staff at Beaver Valley had reviewed industry operating experience (OE) regarding large transformer faults that were attributed to static electrification - the buildup of a static charge within a transformer as a result of ionization of the circulating oil as it passes through pumps, heat exchangers and over the insulating materials of the transformer windings. Beaver Valleys initial review of the OE found that static electrification is caused by a combination of low oil temperature, high oil flow, moisture content of the oil, and contaminates in the oil. If a sufficiently large potential difference builds up, a large direct current discharge can occur which can result in the failure of the transformer. The Beaver Valleys original evaluation determined that the potential for static electrification was greatest with oil temperatures between 10-40°C and during initial energization. As a result, the precaution was added to the operating procedures to limit the cooling fan operation for the transformers in service when oil temperature is less than 40°C.

FENOC identified in their root cause evaluation that no operating margin was added to this limit. Specifically, the operating procedure did not direct the action to reduce the potential for static electrification by reducing cooling fans until the 40°C limit was reached; additionally, the procedure did not include any guidance on securing transformer oil cooling pumps.

FENOC also identified that, on September 2, 2008, they received the ABB Inc. Life Assessment Report in which ABB evaluated the Unit 1 main transformer operational performance. In the design considerations section, ABB recommended establishing operating procedures to prevent the running of all the oil pumps when oil temperature was below 50°C to reduce the risk of static electrification. FENOC had determined the report was a vendor technical document in accordance with Beaver Valley procedure, 1/21/2-ADM-2017, Control of Vendor Technical Information and was therefore required, per the procedure, to review the report to identify impacts on plant operations. However the report was not processed as a technical document and, as a result, FENOC did not complete an evaluation of the vendor recommendations related to oil pump operation or revise the unit 1 procedural guidance.

Additionally, FENOC identified that, on September 4, 2013, the transformer Vendor Manual 01.014-0178 was updated to incorporate the 2008 ABB Inc. Life Assessment Report. FENOC determined that NOP-CC-1003, Vendor Manuals and Vendor Technical Information, Revision 1, required that vendor technical information be screened for potential changes to procedures and equipment, and if potential changes were identified during that screen, the document was then required to be reviewed through an engineering change process. However, FENOC staff considered the change administrative in nature and the recommendations were not evaluated; therefore, no changes were made to the transformer operating procedures. FENOC determined in the root cause evaluation that the recommendations regarding oil pump operation in the vendor report were recommendations for potential changes to procedures as defined in FENOC procedure NOP-CC-1003 and should have been reviewed through an engineering change process.

The inspectors reviewed the root cause evaluation and associated corrective actions.

The inspectors found that FENOC adequately evaluated the event and instituted specific procedural guidance for the monitoring and operation of all main transformers during cold weather as described in the ABB report as a corrective action for the event. The inspectors determined these actions to be reasonable.

Analysis:

The inspectors determined that FENOCs failure to appropriately evaluate technical information from a vendor that affected the operation of plant equipment, as required by both 1/2-ADM-2017 and NOP-CC-1003, was a performance deficiency that was within FENOCs ability to foresee and correct and should have been prevented.

Specifically, FENOC did not evaluate a recommendation in the ABB Inc. Life Assessment Report to prevent the running of all the main transformer oil pumps when the oil temperature is below 50°C, which led to a main transformer fault and a plant trip.

This finding is more than minor because it is associated with the equipment performance attribute of the Initiating Events cornerstone, and adversely impacted the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. In accordance with IMC 0609.04, Initial Characterization of Findings, and Exhibit 1 of IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, issued June 19, 2012, the inspectors determined that this finding is of very low safety significance (Green)because the performance deficiency did not cause both a reactor trip and the loss of mitigating equipment.

This finding has a cross-cutting aspect in the area of Human Performance, Design Margin, in that FENOC did not ensure that equipment margin was carefully guarded and changed through a systematic and rigorous process. Specifically, FENOC did not ensure that the vendor technical review process implemented main transformer operating margin guidance that resulted in the failure of the transformer. (H.6)

Enforcement:

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. Because this finding does not involve a violation and is of very low safety significance, it is identified as a finding. (FIN 05000334/

2014002-02, Main Transformer Failure Due to Static Electrification)

.2 (Closed) Licensee Event Report (LER) 05000334/2013-001-00: Manual Start of a Motor

Driven Auxiliary Feedwater Pump On September 30, 2013, FENOC operators manually started the Unit 1 B motor driven AFW pump based on lowering steam generator water levels. The failure of the condensate pump recirculation flow control valve to operate as expected resulted in a diversion of water from the normal steam generator flow path through the bypass feedwater regulating valves. Following the start of the B AFW pump, steam generator water levels returned to the normal operating control band. The LER was reviewed and no findings or violations of NRC requirements were identified. This LER is closed.

.3 (Closed) Licensee Event Report (LER) 05000334/2013-003-00: Beaver Valley Unit 1

Turbine Trip and Subsequent Manual Reactor Trip due to 4KV Cable Fault On November 5, 2013, at 1747, BVPS Unit 1 experienced a turbine trip and subsequent manual reactor trip due to a 4KV cable fault. Details of the 4kV cable fault are described in Section 4OA2.1 of this report. The LER and associated root cause analysis were reviewed for accuracy, the appropriateness of corrective actions, violations of require-ments, and generic issues. No findings or violations of NRC requirements were identified. This LER is closed.

4OA6 Meetings, Including Exit

On April 3, 2014, the inspectors presented the inspection results to Mr. R. Bologna, Director of Site Operations, and other members of the Beaver Valley Power Station staff.

The inspectors verified that no proprietary information was retained by the inspectors or documented in this report.

4OA7 Licensee-Identified Violations

The following violation of very low safety significance (Green) was identified by FENOC and is a violation of NRC requirements which meets the criteria of the NRC Enforcement Policy for being dispositioned as an NCV.

10 CFR 50.54(q)(2) Conditions of Licenses requires, in part, that licensees maintain an emergency plan that meets the requirements of 10 CFR 50, Appendix E and the planning standards in 10 CFR 50.47(b). 10 CFR 50.47(b)(4) requires use of a standard emergency classification and action level (EAL) scheme. Additionally, 10 CFR 50, Appendix E, Section IV.C.2 states that the licensee maintain the capability to assess, classify, and declare an emergency condition within 15 minutes after the availability of indications that an EAL has been exceeded. Contrary to the above, on March 2, 2014, FENOC failed to declare a Notification of Unusual Event (NOUE) in a timely manner. Specifically, while performing an evolution to fill the safety injection accumulator, a containment residual heat removal system smoke alarm was received at 9:20 pm on March 1, 2014. The Shift Manager determined the alarm was invalid and was likely due to a relief valve that lifted during the fill evolution causing the smoke alarm. However, the EAL basis for HU4, Fire within the Protected Area not extinguished within 15 minutes, specifies that the alarm must be assumed to be an indication of a fire unless a person on scene can disprove the alarm within 15 minutes. After further review, FENOC determined that conditions did exist for an NOUE, in accordance with EAL HU4, and declared a NOUE at 12:13 am on March 2, 2014. The finding was determined to be of very low safety significance (Green) in accordance with Section 4.3 and Attachment 1 of IMC 0609 Appendix B, Emergency Preparedness SDP, for failing to adequately implement the emergency plan by not making an emergency declaration (NOUE) during an actual event in a timely manner. This event was documented in FENOCs corrective action program as CR 2014-04517.