Text

IR 05000334-12-005, 05000412-12-005; 10/01/2012 12/31/2012; Beaver Valley Power Station, Units 1 and 2; Refueling and Other Outage Activities
	ML13036A302
Person / Time
Site:	Beaver Valley
Issue date:	02/05/2013
From:	Hunegs G; NRC/RGN-I/DRP/PB6
To:	Harden P; FirstEnergy Nuclear Operating Co
	HUNEGS, GK
References
	IR-12-005
	Download: ML13036A302 (44)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION ary 5, 2013

SUBJECT:

BEAVER VALLEY POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000334/2012005 AND 05000412/2012005

Dear Mr. Harden:

On December 31, 2012, 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 January 15, 2012, with Paul Harden, Site Vice President, 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 two NRC-identified findings of very low safety significance (Green).

These findings were determined to involve violations of NRC requirements. 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 (NCVs), consistent with Section 2.3.2 of the NRC Enforcement Policy. If you contest any NCVs 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, United States 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 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 10 CFR 2.390 of the NRCs Rules of Practice, a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records (PARS) component of the NRCs document system (ADAMS). ADAMS is accessible from the NRC website at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Gordon K. Hunegs, Chief Reactor Projects Branch 6 Division of Reactor Projects Docket Nos.: 50-334, 50-412 License Nos.: DPR-66, NPF-73

Enclosure:

Inspection Report 05000334/2012005 and 05000412/2012005 w/Attachment: Supplementary Information

REGION I==

Docket Nos.: 50-334, 50-412 License Nos.: DPR-66, NPF-73 Report No.: 05000334/2012005 and 05000412/2012005 Licensee: FirstEnergy Nuclear Operating Company (FENOC)

Facility: Beaver Valley Power Station, Units 1 and 2 Location: Shippingport, PA 15077 Dates: October 1, 2012 to December 31, 2012 Inspectors: D. Spindler, Senior Resident Inspector E. Bonney, Resident Inspector E. Burkett, Reactor Inspector S. Galbreath, Reactor Engineer P. Kaufman, Senior Reactor Inspector T. Moslak, Health Physicist L. Scholl, Senior Reactor Inspector T. Ziev, Reactor Engineer Approved By: Gordon Hunegs, Chief Reactor Projects Branch 6 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

IR 05000334/2012005, 05000412/2012005; 10/01/2012 - 12/31/2012; Beaver Valley Power

Station, Units 1 and 2; Refueling and Other Outage Activities.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. Inspectors identified two (2) findings of very low safety significance (Green), which were non-cited violations (NCVs). The significance of most findings is indicated by their color (Green, White, Yellow, Red) using Inspection Manual Chapter (IMC) 0609, Significance Determination Process (SDP). The cross-cutting aspects for the findings were determined using IMC 0310, Components Within Cross-Cutting Areas. Findings for which the SDP does not apply may be Green, or be assigned a severity level after NRC management review. The NRCs program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 4, dated December 2006.

Cornerstone: Initiating Events

Green: A self revealing, Green NCV of Technical Specification 5.4.1 Procedures, was identified for FENOCs failure to use a procedure when operating chemical volume and control system (CVCS) valve 2CHS-FCV122 during troubleshooting, as required by the regulatory guide (RG) 1.33 Quality Assurance Program Requirements. Specifically, when an operator discovered that the valve positioner main feedback arm was sheared, the operator inadvertently manipulated the valve without guidance from a procedure or problem solving plan.

The inspectors determined that failing to use a procedure when operating 2CHS-FCV122 during troubleshooting was a performance deficiency within FENOCs ability to foresee and correct which contributed to over-pressurizing the reactor coolant system RCS during solid plant operations. This finding is more than minor because it is associated with the human perfor-mance 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. Specifically, the operators failure to use a procedure when operating 2CHS-FCV122 during troubleshooting led to over-pressurization of the reactor coolant system. The inspectors evaluated the finding using PWR Refueling Operation: RCS level > 23 or PWR Shutdown Operation with Time to Boil > 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and Inventory in the Pressurizer Checklist 4 of Attachment 1 to Appendix G of IMC 0609. Because no loss of control occurred and no checklist attributes were adversely impacted, a Phase 2 quantitative assessment was not required. Therefore, the inspectors determined the finding to be of very low safety significance.

This finding has a cross-cutting aspect in the area of Human Performance, Work Practices, because FENOC personnel failed to use human error prevention techniques during troubleshooting of 2CHS-FCV122, and proceeded in the face of uncertainty after identifying the broken positioned feedback arm H.4(a). (Section 1R20)

Green: A self revealing, Green NCV was indentified for FENOC violating 10 CFR 50, Appendix B, Criterion XVI Corrective Action, for failure to identify and correct a condition adverse to quality on the Controller Driver printed circuit board (NCD board) for the controller for 2CHS-FCV160. Specifically, FENOC failed to identify that an NCD board was installed on the controller for 2CHS-FCV160 that was potentially impacted by defects identified in Westinghouse Technical Bulletin TB-08-06 and take corrective actions.

The inspectors determined that failing to identify and correct a condition adverse to quality on the NCD board for the controller for 2CHS-FCV160 was a performance deficiency within FENOCs ability to foresee and correct which contributed to over-pressurization of the reactor coolant system (RCS) during solid plant operations. The 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. Specifically, the failure to ensure the availability and reliability of 2CHS-FCV160 led to over-pressurization of the reactor coolant system. The inspectors evaluated the finding using PWR Refueling Operation: RCS level > 23 or PWR Shutdown Operation with Time to Boil > 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and Inventory in the Pressurizer Checklist 4 of Attachment 1 to Appendix G of IMC 0609. Because no loss of control occurred and no checklist attributes were adversely impacted, a Phase 2 quantitative assessment was not required. Therefore, the inspectors determined the finding to be of very low safety significance.

There is no cross-cutting aspect associated with this finding because the performance deficiency is not reflective of FENOCs current performance. (Section 1R20)

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. The unit remained at or near 100 percent power throughout the inspection period.

Unit 2 began the inspection period shutdown in a refueling outage and returned to full power on November 6, 2012. The unit 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

.1 Readiness for Seasonal Extreme Weather Conditions

a. Inspection Scope

The inspectors performed a review of FENOCs readiness for the onset of seasonal cold temperatures. The review focused on the Unit 1 and Unit 2 refueling water storage tanks. The inspectors reviewed the Updated Final Safety Analysis Report (UFSAR),technical specifications, control room logs, and the corrective action program to determine what temperatures or other seasonal weather could challenge these systems, and to ensure FENOC personnel had adequately prepared for these challenges. The inspectors reviewed station procedures, including FENOC seasonal weather preparation procedures and applicable operating procedures. The inspectors performed walkdowns of the selected systems to ensure station personnel identified issues that could challenge the operability of the systems during cold weather conditions. Documents reviewed for each section of this inspection report are listed in the Attachment.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Partial System Walkdowns

Main article: IP 71111.04Q

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

Unit 1, A Emergency Diesel Generator (EDG) during A system service station transformer (SSST) out of service on October 18, 2012 Unit 1, A Quench Spray system during preventive maintenance and testing on B Quench Spray Pump (QS-P-1B) on December 17, 2012 Unit 2, Low head safety injection trains A and B while crediting A as the boration path Unit 2, 2-1 Diesel support systems fuel and starting air while the 2-1 EDG was inoperable for testing on November 28, 2012 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 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 FENOC 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, Auxiliary feedwater and quench spray pump room (Fire Area QP-1) on November 27, 2012 Unit 1, Charging Pump Cubicles (Fire Area PA-1G) on November 30, 2012 Unit 1, Switchgear room (Fire Area ES-1) on November 30, 2012 Unit 2, Reactor containment building (Fire Area RC-1) on October 17, 2012 Unit 2, Valve pit area (Fire Area VP-1) on October 26, 2012

b. Findings

No findings were identified.

.2 Fire Protection - Drill Observation

Main article: IP 71111.05A

a. Inspection Scope

The inspectors observed a fire brigade drill scenario conducted on November 28, 2012, that involved a simulated fire in the site office support building (SOSB) auxiliary boiler room. 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 Search for victims and propagation of the fire into other plant areas Smoke removal operations Utilization of pre-planned strategies Adherence to the pre-planned drill scenario Drill objectives met The inspectors also evaluated the fire brigades actions to determine whether these actions were in accordance with FENOCs fire-fighting strategies.

b. Findings

No findings were identified.

1R06 Flood Protection Measures

Main article: IP 71111.06

.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 in the Unit 1 Auxiliary Building (PAB).

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. The inspectors also focused on the component cooling water pump room areas to verify the adequacy of equipment seals located below the flood line, floor, and water penetration seals, watertight door seals, common drain lines and sumps, sump pumps, level alarms, control circuits, and temporary or removable flood barriers.

b. Findings

No findings were identified.

1R08 In-service Inspection - Beaver Valley Unit 2

a. Inspection Scope

(71111.08 - 1 sample)

From October 1-12, 2012, the inspector conducted a review of FENOCs implementation of in-service inspection (ISI) program activities for monitoring degradation of the reactor coolant system boundary, risk significant piping and components, and containment systems during the BVPS, Unit 2, refueling outage (2R16). The sample selection was based on the inspection procedure objectives and risk priority of those pressure retaining components in these systems where degradation would result in a significant increase in risk. The inspector observed in-process non-destructive examinations (NDE), reviewed documentation, and interviewed licensee personnel to verify that the non-destructive examination activities performed as part of the Interval 3, Period 2, of the BVPS ISI program were conducted in accordance with the requirements of American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI, 2001 Edition, 2003 Addenda.

Nondestructive Examination (NDE) and Welding Activities (IMC Section 02.01)

The inspector performed direct observations of NDE activities in process and reviewed records of nondestructive examinations listed below:

ASME Code Required Examinations Direct field observation of manual Ultrasonic Test (UT), volumetric inspection, 6-inch diameter safety injection system ASME Class 2, pipe/elbow butt weld 2SIS-270-F06 and 3-inch diameter reactor coolant system pipe/pipe butt weld 2RCS-151-F05 and record review of the associated UT examination reports.

Remote observation of bare metal visual examination of the reactor vessel upper closure head (RVUCH) and control rod drive mechanism (CRDM) nozzles penetrations.

Remote observation of the automatic volumetric UT inspection of the RVUCH CRDM penetration nozzles and vent nozzle.

Record review of UT examination data records for the ASME Class 2, 6-inch diameter pipe welds on the hot and cold leg safety injection system piping (UT-12-1133, UT-12-1134, UT-121135, UT-121136, and UT-121137). These welds were examined based on Materials Reliability Program (MRP)recommendations.

Remote observation of steam generator (S/G) eddy current testing (ECT)examinations, S/G tube sleeving, and S/G tube plugging.

Remote observation of the weld overlay repair on the RVUCH CRDM penetration

44 J-groove weld indications.

Record review of liquid penetrant (PT) examinations of the RVUCH penetration weld overlays on penetrations #16 and #57 that were installed during previous refueling outages.

Record review of the automated remote volumetric UT inspection of the reactor vessel hot leg outlet nozzle dissimilar metal and safe-end welds from the inside diameter, ASME Class 1 component welds (2RCS*REV21-N24, 2RCS*REV21-N26, and 2RCS*REV21-N28).

Independent general visual inspection of the containment liner coating.

The inspector reviewed certifications of the NDE technicians performing the examina-tions. The inspector also verified that the inspections were performed in accordance with approved procedures and that the results were reviewed and evaluated by certified Level III NDE personnel.

Other Augmented or Industry Initiative Examinations The inspector reviewed inspections conducted to implement an industry initiative in accordance with the MRP-146, Management of Thermal Fatigue in Normally Stagnant Non-Isolable Reactor Coolant System Branch Lines, to verify the inspections were conducted in conformance with the management guidelines. Specifically, the inspector reviewed UT examination data records of hot and cold leg safety injection system piping welds to verify that the activities were performed in accordance with applicable examination procedures and industry guidance.

Review of Originally Rejectable Indications Accepted by Evaluation There were no samples available for review during this inspection that involved examinations with recordable indications that had been accepted for continued service.

Repair/Replacement Consisting of Welding Activities The inspector reviewed weld overlay of the RVUCH CRDM penetration #44 J-groove weld to verify that the welding and applicable NDE activities were performed in accordance with ASME Code requirements.

PWR Vessel Upper Head Penetration (VUHP) Inspection Activities (IMC Section 02.02)

The inspector verified that the RVUCH penetration J-groove weld examinations were performed in accordance with requirements of 10 CFR 50.55a(g)(6)(ii)(D) and ASME Boiler and Pressure Vessel Code Case N-729-1, Alternative Examination Requirements for PWR Reactor Vessel Upper Heads, to ensure the structural integrity of the reactor vessel head pressure boundary. The inspector directly observed portions of the remote bare metal visual examination of the exterior surface of the RVUCH to confirm appropriate inspection coverage was achieved and to verify that no boric acid leakage or wastage had been observed. The inspector also directly observed a sample of RVUCH CRDM penetration nozzle weld UT examinations, supplementary ECT examinations and portions of the weld repair activities.

During ultrasonic testing of the RVUCH penetration welds, FENOC identified indications in penetration #44 J-groove weld on October 6, 2012 (NRC event notification 48387).

The inspector reviewed the UT examination records and evaluated the automated UT data scans and PT examination data records/photos of the three indications (one linear 0.50-inch long, one rounded 0.152-inch and one rounded 0.06-inch) that were identified on the outside diameter (OD) of the CRDM penetration #44 J-groove weld. The inspector reviewed the weld overlay repair activity to penetration #44 to ensure that it was conducted in accordance with Beaver Valley Power Station Unit 2, Relief Request No. 2-TYP-3-RV-01, and that the indication in the J-groove weld was properly mitigated by the repair. The inspector reviewed the certifications of the welders performing the weld overlay and the NDE technicians performing the PT examinations. The inspector verified that all repair activities were satisfactorily completed prior to returning the RVUCH to service.

FENOC also identified that the results of PT examinations performed on two previously installed weld overlay repairs on the RVUCH penetrations #16 and #57 J-groove welds did not meet applicable acceptance criteria. The indication in the weld overlay on penetration #16 required grinding to remove the indication and a manual weld repair was performed to restore the weld overlay. The indication in the weld overlay on penetration

57 only required minor buffing to remove the indication and no weld repair was required. The inspector reviewed the PT data records/photographs of the indication identified on previously installed weld overlay to the J-groove weld on CRDM penetration

16 and verified the weld repair activity and PT activity was in accordance with the approved procedure.

Boric Acid Corrosion Control (BACC) Inspection Activities (IMC Section 02.03)

The inspector reviewed the BACC program, which is performed in accordance with BVPS procedures, discussed the program with the boric acid program owner, and sampled photographic inspection records of boric acid found on safety significant piping and components inside the containment structure during walkdowns conducted by licensee personnel and directly observed by the NRC Resident Inspectors on September 24, 2012. The inspector observed the identification and documentation of non-conforming conditions of boric acid leaks in the corrective action program with a focus on areas that could cause degradation of safety significant components.

The inspector verified that potential deficiencies identified during the walkdowns were entered into the licensees corrective action program and reviewed evaluations of the more significant deficiencies documented in condition reports (CR 2012-14682, 2RHS-E21B B residual heat removal heat exchanger tubesheet flange area leakage, CR 2012-14687, pressurizer targets from 2RCS-269 valve leak, and CR 2012-14668, primary coolant cold leg sample isolation valve packing leak) to verify that the corrective actions were consistent with the requirements of the ASME Code and 10 CFR 50, Appendix B, Criterion XVI. The inspector also reviewed the associated engineering evaluations for the above condition reports to verify that equipment or components that were wetted or impinged upon by boric acid solutions were properly analyzed for degradation that might impact their function.

Steam Generator (S/G) Tube Inspection Activities (IMC Section 02.04)

The inspector directly observed a sample of the BVPS S/G eddy current tube examinations, which consisted of full length bobbin inspection of 100% of the in-service tubes in each of the three S/Gs (except rows 1 and 2, U-bends), plus-point inspection of 100% of row 1 and 2, U-bends, plus-point inspection of 100% of the bobbin special interest I-codes. The inspector reviewed a sample of the indications identified in the S/Gs during the eddy current inspections to verify that they were consistent with the potential degradation mechanisms as documented in the Steam Generator Degradation Assessment Report.

The inspector verified that the S/G eddy current tube examinations were performed in accordance with Unit 2 Technical Specification 5.5.5.2 and the Steam Generator Program. The inspector reviewed the S/G tube eddy current test results to verify that no in-situ pressure testing was required, no tubes required stabilization, no primary-to-secondary leakage occurred over the operating cycle, and that tubes which exhibited degradation and did not meet acceptance criteria were plugged (10 tubes) or sleeved (97 tubes) using the alternate repair criteria per Generic Letter 95-05, Voltage-Based Repair Criteria for Westinghouse Steam Generator Tubes Affected by Outside Diameter Stress Corrosion Cracking. The inspector verified that the S/G tube examination screening criteria was in accordance with the Electric Power Research Institute (EPRI)

Steam Generator Guidelines and flaw sizing was in accordance with the EPRI examination technique specification sheet.

In addition, the inspector reviewed the foreign object search and retrieval (FOSAR)results on the secondary side of the S/Gs and reviewed corrective actions to remove the foreign objects, when possible. The inspector verified a sample of the following FOSAR results: S/G A, one item was retrieved (small, 2-inch long piece of gasket backing) and S/G C, a small, thin diameter wire approximately 1-inch long in the tube lane region which was embedded in hardened deposits in the tube lane near Row 1, C45 remained in S/G C.

Identification and Resolution of Problems (IMC Section 02.05)

The inspector reviewed a sample of condition reports, which identified NDE indications, deficiencies and other nonconforming conditions since the previous refueling outage.

The inspector verified that nonconforming conditions were properly identified, characterized, evaluated, corrective actions identified and dispositioned, and appropriately entered into the corrective action program.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

Main article: IP 71111.11

.1 Quarterly Review of Licensed Operator Requalification Testing and Training

a. Inspection Scope

The inspectors observed licensed operator simulator training on November 15, 2012, which included a loss of all alternating current. 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, implement-tation 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 shift technical advisor.

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 Review of Licensed Operator Performance in the Main Control Room

a. Inspection Scope

The inspectors observed and reviewed Unit 2 refueling cavity drain-down to the reactor flange on October 19 and 20, 2012. The inspectors observed evolution briefings and reactivity control briefings to verify that the briefings met the criteria specified in NOP-OP-1002, Conduct of Operations, Revision 7. Additionally, the inspectors observed operator performance to verify that procedure use, crew communications, and coordination of activities between work groups similarly met established expectations and standards.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

Main article: IP 71111.12

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.

Unit 1, Fuel transfer/handling system

(66) Unit 2, Fuel transfer/handling system

(66) Unit 2, Auxiliary steam solenoid operated seam supply valves (2MSS-SOV-105A-F)

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, Yellow risk for opening OCB-92 to support U2 OCB-94 return to service on October 2, 2012 Unit 1, Probabilistic risk assessment (PRA) yellow risk entry during A SSST unavailability on October 2, 2012 Unit 2, Shutdown defense in-depth yellow risk for decay heat removal drain down to the reactor vessel flange on September 30, 2012 Unit 2, Operational Decision Making Issue (ODMI) on un-sat Doble testing of B SSST, on October 18, 2012 Unit 2, Mode 4 Risk Assessment required by Technical specification limiting condition for operation (LCO) 3.0.46 for North Safeguards Area air conditioning unit on October 30, 2012

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:

Unit 2, Low individual cell voltages on [BAT*2-4] station battery on October 2, 2012 Unit 2, Additional tube plugging following Eddy current testing on 2EDS-E21B (Diesel Generator Intercooler Heat Exchanger) on October 5, 2012 Unit 2, Foreign material found in the right side bank of the turbocharger intercooler on the 2-2 emergency diesel generator (EDG) on October 6, 2012 Unit 2, Initial reactor vessel head bolting elongation exceeded acceptance criteria on October 24, 2012 (2R16)

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 Engineering Change Package 12-0696, 2R16 T-Mod Fuel Transfer Cart Addition of Safety Switch Modification, to deter-mine whether the modification affected the safety functions of a system important to safety. The inspectors reviewed 10 CFR 50.59 documentation and post-modification testing results, and conducted field walkdowns of the modifications 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 to the component cooling water (CCP) system.

Engineering change package 12-0242-00 Replacement of Primary Component Cooling Water Heat Exchanger 2CCCP-E21A installed a new A CCP heat exchanger on November 4, 2012. 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 heat exchanger replacement, including alteration of the heat exchanger tubing material. The inspectors interviewed engineering personnel to ensure the modification could be reasonably performed.

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 that 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.

Unit 1, A motor-driven auxiliary feedwater (AFW) pump packing adjustment on October 17, 2012 Unit 1, B Quench Spray pump (QS-P-1B) preventive maintenance on December 17, 2012 Unit 2, Station Battery [BAT*2-4] replacement on October 7, 2012 Unit 2, 2-2 EDG repairs to low rocker arm oil pressure switch and exhaust manifold inspection on October 20, 2012 Unit 2, B AFW impeller and mechanical seal replacement and motor refurbishment on October 22, 2012 Unit 2, 2-1 EDG maintenance during refuel outage 2R16

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

Main article: IP 71111.20

a. Inspection Scope

The inspectors reviewed the stations work schedule and outage risk plan for the Unit 2 maintenance and refueling outage (2R16), which was conducted September 24 through November 1. 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. During the outage, the inspectors observed portions of the shutdown and cooldown processes and monitored controls associated with the following outage activities:

Configuration management, including maintenance of defense-in-depth, commensurate with the outage plan for the key safety functions and compliance with the applicable technical specifications when taking equipment out of service Implementation of clearance activities and confirmation that tags were properly hung and that equipment was appropriately configured to safely support the associated work or testing Installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication and instrument error accounting Status and configuration of electrical systems and switchyard activities to ensure that technical specifications were met Monitoring of decay heat removal operations Impact of outage work on the ability of the operators to operate the spent fuel pool cooling system Reactor water inventory controls, including flow paths, configurations, alternative means for inventory additions, and controls to prevent inventory loss Activities that could affect reactivity Maintenance of secondary containment as required by technical specifications Refueling activities, including fuel handling and fuel receipt inspections Fatigue management Identification and resolution of problems related to refueling outage activities

b. Findings

1. Failure to Use a Procedure to Operate a CVCS Valve

Introduction:

A self revealing, Green NCV of Technical Specification 5.4.1 Procedures, was identified for FENOCs failure to use a procedure when operating chemical volume and control system (CVCS) valve 2CHS-FCV122 during troubleshooting, as required by the RG 1.33 Quality Assurance Program Requirements. Specifically, when an operator discovered that the valve positioner main feedback arm was sheared, the operator inadvertently manipulated the valve without guidance from a procedure or problem solving plan.

Description:

On September 24, 2012, during Unit 2 Mode 5 solid plant operations, charging discharge flow control valve 2CHS-FCV122 failed closed. In response to the resulting drop in reactor coolant system pressure, operators secured the C reactor coolant pump per procedure. After operators stabilized the plant, an operator was dispatched to the valve to investigate the valve failure. The operator discovered that the feedback arm for the valves positioner was sheared. The operator lifted the broken feedback arm to determine where it connected to the valve. This manipulation of the feedback arm caused the valve to the open. When the valve reopened, the reactor coolant system pressure spiked to a maximum of 429 psig, exceeding the over pressure protection system power operated relief valve set point of 425 psig. The power operated relief valve lifted twice to relieve reactor coolant system pressure. In response to the pressure spike, operators secured the B charging pump and isolated 2CHS-FCV122.

After verifying isolation of 2CHS-FCV122, operators restarted the B charging pump and stabilized reactor coolant system pressure within the recommended band of 275 to 325 psig.

FENOC procedure NOP-OP-1002, Conduct of Operations, Revision 7, states that operators are to operate plant equipment with procedures, clearances, or other documents as appropriate. This procedure also states that when faced with uncertainty to stop, place the equipment in a safe condition, and obtain the appropriate guidance before proceeding. In this instance, the operator manipulated the feedback arm without fully understanding the consequences nor was the valve placed in a condition where troubleshooting could be safely performed per NOP-ER-3001, Problem Solving and Decision Making, Revision 5.

Analysis:

The inspectors determined that failing to use a procedure when operating 2CHS-FCV122 during troubleshooting was a performance deficiency within FENOCs ability to foresee and correct which contributed to over-pressurizing the RCS during solid plant operations. This finding is more than minor because it is associated with the human 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. Specifically, the operators failure to use a procedure when operating 2CHS-FCV122 during troubleshooting lead to over-pressurization of the reactor coolant system. The inspectors evaluated the finding using PWR Refueling Operation: RCS level > 23 or PWR Shutdown Operation with Time to Boil > 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and Inventory in the Pressurizer Checklist 4 of Attachment 1 to Appendix G of IMC 0609. Because no loss of control occurred and no checklist attributes were adversely impacted, a Phase 2 quantitative assessment was not required. Therefore, the inspectors determined the finding to be of very low safety significance (Green).

This finding has a cross-cutting aspect in the area of Human Performance, Work Practices, because FENOC personnel failed to use human error prevention techniques during troubleshooting of 2CHS-FCV122, and proceeded in the face of uncertainty after identifying the broken positioned feedback arm H.4(a).

Enforcement:

TS 5.4.1 requires, in part, that written procedures be established, implemented, and maintained covering applicable procedures recommended in Regulatory Guide (RG) 1.33, Revision 2, Appendix A, February 1978. RG 1.33 requires, in part, that procedures be established for operation of the CVCS. Contrary to the above, on September 24, 2012, FENOC failed follow the guidance of NOP-OP-1002 when faced with uncertainty and operated CVCS valve 2CHS-FCV122 during troubleshooting of the broken feedback positioner arm without placing 2CHS-FCV-122 in a safe condition prior to troubleshooting. As a result, 2CHS-FCV122 failed open during solid plant operations, causing an over-pressurization of the RCS. Because this issue is of very low safety significance (Green) and FENOC entered this issue into the corrective action program as CR-2012-16903, this finding is being treated as an NCV consistent with the NRC enforcement policy. (NCV 05000412/2012005*01, Failure to Use a Procedure to Operate a CVCS Valve)

2. Failure to Identify and Correct a Condition Adverse to Quality

Introduction:

A self revealing, Green NCV was indentified for FENOC violating 10 CFR 50 Appendix B, Criterion XVI Corrective Action, for failure to identify and correct a condition adverse to quality on the Controller Driver printed circuit board (NCD board) for 2CHS-FCV160. Specifically, FENOC failed to identify that a NCD board was installed on the controller for 2CHS-FCV160 that was potentially impacted by defects identified in Westinghouse Technical Bulletin TB-08-06 and take corrective actions.

Description:

On September 24, 2012, during Unit 2 Mode 5 solid plant operations with normal charging discharge valve 2CHS-FCV122 out of service, operators attempted to open 2CHS-FCV160 to use RCS Loop Fill as an alternate charging flow path. Upon pressing the manual open button, 2CHS-FCV160 fully opened instead of opening partially as expected. When the valve opened, the reactor coolant system pressure spiked to a maximum of 427 psig, exceeding the over pressure protection system power operated relief valve set point of 425 psig. The power operated relief valve lifted once to relieve reactor coolant system pressure. Operators adjusted the valve controller and letdown flow to stabilize reactor coolant system pressure at 294 psig. Investigation of the failure of 2CHS-FCV160 identified the NCD board for the valve controller as the cause of the valve fully opening. Further review revealed that the part number for the controller NCD board was identified in 2008 by Westinghouse Technical Bulletin TB-08-06 as being deficient. TB-08-06 stated that there could be an unexpected step change instead of the expected linear ramp with manual raise or lower inputs. During the review of TB-08-06, FENOC failed to identify that the part number for the NCD board installed in the controller for 2CHS-FCV160 was the same as the one identified in TB-08-06 and take corrective actions. During the extent of condition search, FENOC identified one additional NCD board installed in a non-safety related component. Actions to replace the additional board have been taken.

Analysis:

The inspectors determined that failing to identify and correct a condition adverse to quality on the NCD board for the controller for 2CHS-FCV160 was a performance deficiency within FENOCs ability to foresee and correct which contributed to over-pressurization of the RCS during solid plant operations. The 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. Specifically, the failure to ensure the availability and reliability of 2CHS-FCV160 lead to over-pressurization of the reactor coolant system. The inspectors evaluated the finding using PWR Refueling Operation: RCS level > 23 or PWR Shutdown Operation with Time to Boil > 2 hours2.314815e-5 days 5.555556e-4 hours 3.306878e-6 weeks 7.61e-7 months and Inventory in the Pressurizer Checklist 4 of Attachment 1 to Appendix G of IMC 0609. Because no loss of control occurred and no checklist attributes were adversely impacted, a Phase 2 quantitative assessment was not required. Therefore, the inspectors determined the finding to be of very low safety significance (Green).

There is no cross-cutting aspect associated with this finding because the performance deficiency is not reflective of FENOCs current performance.

Enforcement:

10 CFR Part 50, Appendix B, Criterion XVI requires, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and non-conformances are promptly identified and corrected. Contrary to the above, on September 08, 2008, FENOC failed to identify that the NCD board installed on the controller for 2CHS-FCV160 had the part number identified in TB-08-06 and take corrective actions. As a result, the controller for 2CHS-FCV160 failed full open during solid plant operations, causing an over-pressurization of the RCS. Because this issue is of very low safety significance (Green) and FENOC entered this issue into the corrective action program as CR-2012-14860, this finding is being treated as an NCV consistent with the NRC enforcement policy. (NCV 05000412/2012005*02, Failure to Identify and Correct a Condition Adverse to Quality)

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, test instrumentation had current calibrations and the range 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 supported that equipment was capable of performing the required safety functions. The inspectors reviewed the following surveillance tests:

Unit 1, 1OST-15.02 Primary Component Cooling Water Pump 1CC-P-1B Test on November 30, 2012 (in service test)

Unit 2, 2BVT1.47.11, Safety Injection & Charging System Containment Penetration Valve Integrity Test (containment isolation valve)

Unit 2, 2OST-36.4, Emergency Diesel Generator [2EGS*EG2-2] Automatic Test Unit 2, 2OST-10.3, Residual Heat Removal System Train A Valve Exercise on October 13, 2012 (containment isolation valve)

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

RS01 Radiological Hazard Assessment and Exposure Controls

a. Inspection Scope

(71124.01 - 1 sample)

During the period December 3 - 6, 2012, the inspector conducted the following activities to verify that the licensee was properly implementing physical, administrative, and engineering controls for access to locked high radiation areas, and other radiological controlled areas (RCAs). Implementation of these controls was reviewed against the criteria contained in 10 CFR 20, relevant Technical Specifications, and the licensee=s procedures.

Plant Walkdown and Radiation Work Permits (RWP) Reviews The inspector toured accessible radiological controlled areas in the Unit 1 and Unit 2 primary auxiliary buildings. Radiation survey maps were reviewed of selected areas to identify radiological conditions, and the adequacy of postings.

The inspector identified tasks performed in the RCAs. The inspector reviewed the applicable RWPs, and the electronic dosimeter dose/dose rate alarm set points, for the associated tasks, to determine if the radiological controls were acceptable and if the set points were consistent with plant policy. Jobs reviewed included performing a walkdown of effluent monitoring instrumentation and the Supplemental Leak Collection and Release Systems (SLCRS) in Units 1 and 2 RCAs.

The inspector evaluated the effectiveness of contamination controls by reviewing personnel contamination event reports (and related condition reports), and observing practices at various locations.

Problem Identification and Resolution The inspector evaluated the licensee=s program for assuring that access controls to radiological significant areas were effective and properly implemented by reviewing electronic dosimeter alarm reports, personnel contamination event reports, and relevant condition reports. The inspector determined that problems were identified in a timely manner, that extent of condition and cause evaluations were performed when appropriate, and corrective actions were appropriate to preclude repetitive problems.

b. Findings

No findings were identified.

Cornerstone: Public Radiation Safety

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

Main article: IP 71124.06

During the period December 3 - 6, 2012, the inspector conducted the following activities to ensure the gaseous and liquid effluent processing systems are maintained so radiological discharges are properly reduced, monitored, and evaluated, and to verify the accuracy of effluent releases and public dose calculations resulting from radioactive effluent discharges.

The inspector used the requirements in 10 CFR Part 20, 10 CFR 50 Appendix I 10 CFR 50.75(g), applicable Industry standards, and licensee procedures, required by the site Offsite Dose Calculation Manual (ODCM), as criteria for determining compliance.

a. Inspection Scope

Event Report and Effluent Report Reviews The inspector reviewed the Beaver Valley Annual Radiological Effluent Release Reports for 2010 and 2011 to determine if the reports were submitted as required by the ODCM.

The inspector reviewed sampling results, and trends identified by the licensee. The inspector determined if these releases were evaluated, and any off-normal releases were entered in the corrective action program, and adequately resolved.

The inspector reviewed radioactive effluent monitor operability issues reported by the licensee as provided in the Beaver Valley Annual Radioactive Effluent Release Reports, and reviewed these issues. The inspector determined if the issues were entered into the corrective action program and that compensatory measures were implemented to assure that effluents were properly monitored and evaluated.

ODCM and Updated Final Safety Analysis Report Review The inspector reviewed the Beaver Valley Updated Final Safety Analysis Report (UFSAR) descriptions of the radioactive effluent monitoring systems, treatment systems, and effluent flow paths to identify system design features and required functions.

The inspector reviewed changes to the Beaver Valley ODCM made by the licensee since the last inspection. The inspector reviewed the evaluations of the changes and determined that they were technically justified and maintained effluent releases as low as is reasonably achievable (ALARA).

The inspector reviewed licensee documents to determine if the licensee has identified any non-radioactive systems; e.g., the Unit 2 nitrogen system, that have become contaminated as documented in a condition report (CR 2012-15547). The inspector reviewed selected evaluations and determined that no contaminated systems were identified that had an unmonitored effluent discharge path to the environment.

Groundwater Protection Initiative (GPI) Program The inspector reviewed reported groundwater monitoring sample results and changes to the licensees written program for identifying, controlling, and remediating contaminated spills/leaks to groundwater.

Procedures, Special Reports, and Other Documents The inspector reviewed condition reports related to the effluent program issued since the previous inspection to identify any additional focus areas for the inspection based on the scope of problems described in these reports.

The inspector reviewed effluent program implementing procedures, including those associated with effluent sampling, effluent monitor set-point determinations, and dose calculations.

The inspector reviewed copies of licensee assessment reports of the effluent monitoring program since the last inspection to gather insights into the effectiveness of the licensees program.

Walkdowns and Observations The inspector walked down selected components of the gaseous and liquid discharge systems to verify that equipment configuration and flow paths align with the descriptions in the Beaver Valley UFSAR and to assess equipment material condition. Special attention was made to identify potential unmonitored release points, building alterations which could impact airborne, or liquid effluent controls, and ventilation system leakage that communicate directly with the environment.

Monitoring equipment inspected included:

Liquid Discharge Monitors:

1RW-100 Component Cooling Heat Exchanger monitor 1RW-100 A/B/C/D, Recirculation Spray Heat Exchanger monitor 1LW-104, Unit 1 Liquid Waste Effluent monitor 1LW-116, Unit 1 Contaminated Drains monitor 2SGC-RQ100, Unit 2 Liquid Radwaste Discharge monitor Gaseous Discharge Monitors:

1GW-109, Process Vent monitor 2HVS-1RQ-109 B/C/D, Particulate, Iodine, Noble Gas Low, Medium and Wide range monitors 2RMQ-RQ301, Decon Building monitor 2HVS-RQ101, Ventilation Vent monitor 2HVL-RQ112, Condensate Polishing Vent monitor The inspector reviewed the licensee's surveillance test records for air cleaning equipment (i.e., fans, charcoal filters, and high efficiency particulate air (HEPA) filters for the Units 1 and 2 Supplemental Leak Collection and Release System (SLCRS)), to assure that the equipment met the Technical Specification operability criteria.

The inspector walked down filtered ventilation systems (SLCRS), to verify there were no degraded conditions associated with high-efficiency particulate air/charcoal banks, improper alignment, or system installation issues that would impact the performance, or the effluent monitoring capability of the effluent system.

The inspector determined that the licensee had not made any changes to their effluent release paths.

The inspector reviewed liquid and gaseous discharge permits for routine processing and discharging waste streams. The inspector verified that appropriate effluent treatment equipment was being used and that radioactive liquid and gaseous waste is being processed and discharged in accordance with licensee procedures.

Sampling and Analyses The inspector selected the condensate polishing building gaseous monitor (2HVL-RQ112), to verify that normal discharges were monitored using compensatory measures to ensure that sampling was performed consistent with the ODCM and that those controls were adequate to prevent the release of unmonitored gaseous effluents.

The inspector reviewed the results of the inter-laboratory and intra-laboratory comparison (cross check) programs to verify the quality of the radioactive effluent sample analyses. The inspector also assessed whether the intra and inter-laboratory comparison program includes hard-to-detect isotopes.

Instrumentation and Equipment Effluent Flow Measuring Instruments The inspector reviewed the methodology that the licensee uses to determine the effluent stack and vent flow rates to verify that the flow rates are consistent with TSs/ODCM and FSAR values.

Air Cleaning Systems The inspector determined that surveillance test results for the HEPA and charcoal filters in the Unit 1 and Unit 2 SLCRS discharge systems met TS/ODCM acceptance criteria.

Dose Calculations The inspector reviewed changes in reported dose values compared to the previous radioactive effluent release report to evaluate the factors which may have resulted in the change.

The inspector reviewed four radioactive liquid and two gaseous waste discharge permits to verify that the projected doses to members of the public were accurate and based on representative samples of the discharge path.

The inspector evaluated the methods used to determine the isotopes that are included in the source term to ensure all applicable radionuclides are included, within detectability standards. The review included the licensees current waste stream analyses to ensure hard-to-detect radionuclides are included in the effluent releases.

The inspector reviewed the licensees methodology for offsite dose calculations to verify compliance with the ODCM and RG 1.109. The inspector reviewed meteorological dispersion and deposition factors used in the ODCM and effluent dose calculations to ensure appropriate dispersion/deposition factors are being used for public dose calculations.

The inspector reviewed the latest Land Use Census to verify that changes in the local land use have been factored into the dose calculations and environmental sampling/analysis program.

The inspector determined that the calculated doses are within the 10 CFR 50, Appendix I and ODCM dose criteria. The inspector determined that the licensee was tracking cumulative doses on a monthly, quarterly, and annual basis, and comparing dose to the regulatory criteria.

Problem Identification and Resolution Inspector assessed whether problems associated with the effluent monitoring and control program are being identified by the licensee at an appropriate threshold and are properly addressed for resolution in the licensees corrective action program. In addition, the inspector evaluated the effectiveness of the corrective actions for a selected sample of problems documented by the licensee.

b. Findings

No findings were identified.

Groundwater Protection Initiative (GPI) Implementation (TI-2515/185 - 1 sample)

a. Inspection Scope

The inspector reviewed monitoring results of the GPI to determine if the licensee has implemented its program as intended, and to identify any anomalous results. For anomalous results, the inspector assessed that the licensee has identified and addressed deficiencies through its corrective action program.

The inspector reviewed identified leakage or spill events and entries made into licensees 50.75

(g) decommissioning files. The inspector reviewed evaluations of leaks or spills, and reviewed the effectiveness of any remediation actions. The inspector reviewed onsite contamination events involving contamination of groundwater and assessed whether the source of the leak or spill was identified and terminated.

For past spills, leaks, or unexpected liquid or gaseous discharges, the inspector assessed that an evaluation was performed to determine the type and amount of radioactive material that was discharged, by determining that sufficient radiological surveys were performed to evaluate the extent of the contamination; assessing whether an evaluation had been performed to include consideration of hard-to-detect radionuclides; and determining whether the licensee completed offsite notifications, as provided in its GPI implementing procedures.

The inspector reviewed the evaluation of discharges from onsite surface water bodies that contain or potentially contain radioactivity, and the potential for groundwater leakage from these onsite surface water bodies. The inspector assessed whether the licensee is properly accounting for discharges from these surface water bodies as part of their effluent release reports.

The inspector assessed whether on-site groundwater sample results and a description of any significant on-site leaks/spills into groundwater are documented in the Annual Radioactive Effluent Release Report.

The inspector performed walkdowns of selected on-site groundwater monitoring wells to confirm their locations and assess their material condition.

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

Main article: IP 71114.06

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine FENOC emergency drill on November 15, 2012, to identify any weaknesses and deficiencies in the classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator, technical support center, and operation support center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the station drill critique to compare inspector observations with those identified by FENOC staff in order to evaluate FENOCs critique and to verify whether the FENOC staff was properly identifying weaknesses and entering them into the corrective action program.

b. Findings

No findings were identified.

OTHER ACTIVITIES

4OA1 Performance Indicator Verification

Main article: IP 71151

.1 Mitigating Systems Performance Index (4 samples)

a. Inspection Scope

The inspectors reviewed FENOCs submittal of the Mitigating Systems Performance Index for the following systems for the period of October 1, 2011 through September 30, 2012:

Unit 1, Emergency AC Power System Unit 2, Emergency AC Power System Unit 1, High Pressure Injection System Unit 2, High Pressure Injection System To determine the accuracy of the performance indicator data reported during those periods, the inspectors used definitions and guidance contained in Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6. The inspectors also reviewed operator narrative logs, condition reports, mitigating systems performance index derivation reports, event reports, and NRC integrated inspection reports to validate the accuracy of the submittals.

b. Findings

No findings were identified.

.2 Occupational Exposure Control Effectiveness (1 sample)

a. Inspection Scope

The inspector reviewed implementation of the licensees Occupational Exposure Control Effectiveness Performance Indicator Program. Specifically, the inspector reviewed electronic dosimeter dose and dose rate alarm reports, condition reports, and associated documents, for occurrences involving locked high radiation areas, very high radiation areas, and unplanned exposures occurring during the past four

(4) calendar quarters.

Data contained in these records was reviewed against the criteria specified in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, to verify that all occurrences that met the NEI criteria were identified and reported as performance indicators.

b. Findings

No findings were identified.

.3 RETS/ODCM Radiological Effluent Occurrences (1 sample)

a. Inspection Scope

The inspector reviewed relevant effluent release reports and associated dose assessments for the period October, 2011 through October, 2012, for issues related to the public radiation safety performance indicator, which measures radiological effluent release occurrences that exceed 1.5 mrem/qtr whole body or 5.0 mrem/qtr organ dose for liquid effluents; and 5 mrads/qtr gamma air dose, 10 mrad/qtr beta air dose, and 7.5 mrads/qtr for organ dose for gaseous effluents.

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 Annual Sample: Degraded Voltage Relay Time Delay

a. Inspection Scope

The inspector performed an in-depth review of FENOCs evaluations and corrective actions associated with condition reports (CRs) 2011-95145 and 2011-96495 that documented issues associated with the design and operation of the Beaver Valley Units 1 and 2 electrical systems. During a component design basis inspection (CDBI) an unresolved item (URI) was identified regarding the adequacy of the degraded voltage protection schemes for Units 1 and 2. Specifically, the acceptability of having a 90 +/-

5 second time delay before the safety related electrical buses are transferred to the emergency diesel generators during a degraded electrical grid event was questioned.

The inspector assessed FENOCs problem identification threshold, causal analyses, extent of condition reviews, compensatory actions, and the prioritization and timeliness of Entergys corrective actions to determine whether FENOC was appropriately identifying, characterizing, and correcting problems associated with this issue. The inspector compared the actions taken to the requirements of Entergys corrective action program and Title 10 of the Code of Federal Regulations (10 CFR) Part 50, Appendix B, Criterion XVI, Corrective Action. In addition, the inspector reviewed documentation associated with this issue, including condition reports, engineering analyses and interviewed engineering personnel to assess the effectiveness of the implemented corrective actions and the actions planned to complete full resolution of the issue.

b. Findings and Observations

No findings were identified.

The inspectors found that FENOC was appropriately entering issues associated with the electrical system design bases into the corrective action program. Issues were being reviewed for the impact on current and past operability and potential reportability.

Causal evaluations and extent of condition assessments were also found to be appropriate. A broad scope electrical calculation reconstitution plan was developed and calculation updates were currently ongoing. The inspector found that appropriate resources were allocated to support implementation of the reconstitution plan.

Following the completion of supporting calculation updates, plant modifications will be developed and implemented to modify the degraded voltage protection scheme to ensure all necessary plant equipment will remain available and operable during and following a degraded electrical grid event. The changes will take into account the timing of the degraded grid event relative to possible coincident plant transients and design basis accidents. The potential elimination of the degraded grid protection at the 480 volts alternating current (VAC) level buses will also be assessed. The changes are also intended to eliminate any apparent inconsistencies in associated correspondence and other documentation including NRC letters, technical specifications, safety evaluation reports and the Final Safety Analysis Report. Actions to implement the electrical calculation reconstitution plan are being tracked within the corrective action program.

Based on the actions taken by the licensee action to date, and on the planned actions described above, URI 05000334;05000412/2011007-03, Degraded Voltage Relay Time Delay, is closed.

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

Main article: IP 71153

.1 (Closed) Licensee Event Report (LER) 05000412/2012-001-00: Automatic Actuation of

Standby Service Water Pump During Emergency Diesel Generator Test On September 24, 2012, while performing Unit 2 A Emergency Diesel Generator (EDG) Automatic Test, the B Standby Service Water Pump (2SWE-P21B)automatically started. During this test, the A Service Water Pump (2SWS-P21A)was intentially tripped to simulate a loss of offsite power. Immediately after the Service Water pump was tripped a low pressure condition occurred which initiated the automatic start of 2SWE-P21B. The inspectors determined that no new findings were identified.

This LER is closed.

.2 (Closed) Licensee Event Report (LER) 05000412/2012-002-00: Unacceptable Indication

Identified During Reactor Vessel Head Inspection On October 6, 2012, during Unit 2 refueling outage (2R16), reactor vessel head penetration 44 did not meet ultrasonic testing acceptance criteria. The indication was not through wall and was repaired according to acceptable flaw repair methodology.

The inspectors determined that no new findings were identified. This LER is closed.

.3 (Closed) Licensee Event Report (LER) 05000412/2012-003-00: Inoperable Reactor

Cooling Water Radiation Monitor On October 20, 2012, FENOC discovered that Beaver Valley Unit 2 had entered Mode 3 without meeting the requirements of technical specifications with two

(2) trains of main turbine trip actuation relays inoperable. As a result, the licensee failed to meet the requirements of Technical Specification 3.0.4.a when transitioning from Mode 4 to Mode 3. The enforcement aspects of this issue are discussed in Section 4OA7. The inspectors did not identify any new issues during the review of the LER. This LER is closed.

4OA5 Other Activities

.1 Temporary Instruction 2515/187 - Inspection of Near-Term Task Force

Recommendation 2.3 Flooding Walkdowns The inspectors verified that FENOCs walkdown packages for the Unit 1 and Unit 2 intake structure and the Unit 1 charging pump cubicles contained the elements as specified in NEI 12-07 Walkdown Guidance document:

The inspector accompanied FENOC on their walkdown of the Unit 1 and Unit 2 intake structure and verified that the licensee confirmed the following flood protection features:

Visual inspection of the intake cubicle walls, including penetrations and doors with inflatable seals.

External visual inspection for indications of degradation that would prevent its credited function from being performed was performed for the exterior of the intake structure.

Open penetrations into the cubicle were verified above the PMF.

Available physical margin was determined.

Flood protection feature functionality was determined using visual observation.

The inspectors independently performed their walkdown and verified that the following flood protection features were in place:

Charging pump cubicles walls were verified to be above calculated external flood height.

Available physical margin documented corresponded with inspected conditions.

Interior and exterior wall conditions were acceptable.

All required penetrations were sealed.

The inspectors verified that non-compliances with current licensing requirements, and issues identified in accordance with the 10 CFR 50.54(f) letter, Item 2.g, of Enclosure 4, were entered into the licensee's corrective action program. In addition, issues identified in response to Item 2.g that could challenge risk significant equipment and the licensees ability to mitigate the consequences, will be subject to additional NRC evaluation.

No NRC-identified or self-revealing findings were identified.

.2 Temporary Instruction 2515/188 - Inspection of Near-Term Task Force

Recommendation 2.3 Seismic Walkdowns The inspectors accompanied the licensee on their seismic walkdowns of the Unit 2 Turbine Driven Feed Pump - 2FWE-P22, September 17, 2012, Unit 2 Safeguards Building; Unit 2 A Quench Spray Pump Suction Valve - 2QSS-MOV-100A, September 17, 2012, Unit 2 Safeguards Building, Unit 2 A Low Head Safety Injection Pump Suction Isolation Valve 2SIS-1, Unit 2 Safeguards Building and verified that the licensee confirmed that the following seismic features associated with 2FWE-P22, 2QSS-MOV-100A, and 2SIS-1 were free of potential adverse seismic conditions:

Anchorage was free of bent, broken, missing or loose hardware Anchorage was free of corrosion that is more than mild surface oxidation Anchorage was free of visible cracks in the concrete near the anchors Anchorage configuration was consistent with plant documentation SSCs will not be damaged from impact by nearby equipment or structures Overhead equipment, distribution systems, ceiling tiles and lighting, and masonry block walls are secure and not likely to collapse onto the equipment Attached lines have adequate flexibility to avoid damage The area appears to be free of potentially adverse seismic interactions that could cause flooding or spray in the area The area appears to be free of potentially adverse seismic interactions that could cause a fire in the area The area appears to be free of potentially adverse seismic interactions associated with housekeeping practices, storage of portable equipment, and temporary installations (e.g., scaffolding, lead shielding).

The inspectors independently performed their walkdown and verified that the following were free of potential adverse seismic conditions:

Unit 1 #1 Emergency Diesel Generator - 1EG-1, December 19, 2012, Unit 1 Diesel Generator Building Unit 2 B Safety Injection Accumulator- 2SIS-21B, October 15, 2012, Unit 2 Primary Containment Elevation 692 Observations made during the walkdown that could not be determined to be acceptable were entered into the licensees corrective action program for evaluation.

Additionally, inspectors verified that items that could allow the spent fuel pool to drain down rapidly were added to the seismic walkdown equipment list (SWEL) and these items were walked down by the licensee.

No NRC-identified or self-revealing findings were identified.

4OA6 Meetings, Including Exit

On January 15, 2012, the inspectors presented the inspection results to Paul Harden, Site Vice President, and other members of the BVPS 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.

A licensee identified, Green NCV of Technical Specifications (TS) 3.0.4.a was identified for FENOCs meet all Technical Specification Table 3.3.2-1 requirements to enter mode 3 during reactor startup following a refueling outage on Unit 2. Specifically, while testing turbine trip relays during, two trains of turbine trip relays were inoperable which requires all feedwater lines to be isolated and deactivated. The licensee failed to ensure that the feedwater lines were appropriately isolated and deactivated prior to entering mode 3.

This finding is more than minor because it is associated with the transient initiator contributor 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 plant startup. The inspectors evaluated the finding using Exhibit 2, "Initiating Events Screening Questions" worksheet in Appendix A of IMC 0609, "Significance Determination Process." The inspectors determined this finding was not a design qualification deficiency resulting in a loss of functionality or operability, did not represent an actual loss of safety function of a system or train of equipment, was not potentially risk-significant due to a seismic, fire, flooding, or severe weather initiating event, did not affect reactivity control systems, and did not involve the fire brigade. Therefore, inspectors determined the finding to be of very low safety significance (Green).

ATTACHMENT: