Text

NRC Integrated Inspection Report 05000334/2013005 and 05000412/2013005 (Oct 1 - Dec 31, 2013)
	ML14041A003
Person / Time
Site:	Beaver Valley
Issue date:	02/10/2014
From:	Cook W; NRC/RGN-I/DRP/PB6
To:	Larson D; FirstEnergy Nuclear Operating Co
	COOK, WA
References
	IR-13-005
	Download: ML14041A003 (54)
	v • d • e

UNITED STATES NUCLEAR REGULATORY COMMISSION ary 10, 2014

SUBJECT:

BEAVER VALLEY POWER STATION - NRC INTEGRATED INSPECTION REPORT 05000334/2013005 AND 05000412/2013005

Dear Mr. Larson:

On December 31, 2013, 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 31, 2014 with E. Larson, 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 one NRC-identified finding and one self-revealing finding of very low safety significance (Green). These findings were determined to involve violations of NRC requirements. However, because of the very low safety significance, and because these findings were entered into your corrective action program, the NRC is treating these findings as 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.

As a result of the Safety Culture Common Language Initiative, the terminology and coding of cross-cutting aspects were revised beginning in calendar year (CY) 2014. New cross-cutting aspects identified in CY 2014 will be coded under the latest revision to IMC 0310. Cross-cutting aspects identified in the last six months of 2013 using the previous terminology will be converted to the latest revision in accordance with the cross-reference in IMC 0310. The revised cross-

(E. Larson) 2 cutting aspects will be evaluated for cross-cutting themes and potential substantive cross-cutting issues in accordance with IMC 0305 starting with the CY 2014 mid-cycle assessment review.

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 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 William A. Cook, 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 05000334/2013005 and 05000412/2013005 w/Attachment: Supplementary Information

REGION I==

Docket Nos.: 50-334, 50-412 License Nos.: DPR-66, NPF-73 Report No.: 05000334/2013005 and 05000412/2013005 Licensee: FirstEnergy Nuclear Operating Company (FENOC)

Facility: Beaver Valley Power Station, Units 1 and 2 Location: Shippingport, PA 15077 Dates: October 1, 2013 to December 31, 2013 Inspectors: D. Spindler, Senior Resident Inspector E. Carfang, Resident Inspector B. Bickett, Senior Project Engineer A. Dugandzic, Project Engineer P. Kaufman, Senior Reactor Inspector J. Laughlin, Emergency Preparedness Inspector T. Moslak, Senior Health Physicist Inspector M. Patel, Reactor Inspector D. Silk, Senior Licensed Operator Examiner Approved By: William A. Cook, Acting Chief Reactor Projects Branch 6 Division of Reactor Projects Enclosure

SUMMARY

IR 05000334/2013005, 05000412/2013005; 10/01/2013-12/31/2013; Beaver Valley Power

Station, Units 1 and 2; Refueling and Other Outage Activities and Radiological Hazard Assessment and Exposure Controls.

This report covered a three-month period of inspection by resident inspectors and announced inspections performed by regional inspectors. One NRC-identified non-cited violation and one self-revealing non-cited violation of very low safety significance (Green) were identified. 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, Components Within Cross-Cutting Areas, dated October 28, 2011. 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 4.

Cornerstone: Initiating Events

Green.

A self-revealing, Green NCV of TS 5.4.1 Procedures was identified when an operator did not correctly implement procedure 1OM-52.4.A, Raising Power from 5% to Full Load Operation, Revision 68, during the warm up the moisture separator reheaters. Specifically, a human performance error resulted in a main steam valve being mispositioned that subsequently caused a plant power transient. FENOC entered this issue into the corrective action program under CR 2013-17848 and reviewed the transient under the Reactivity Management Program.

The site performed a limited apparent cause evaluation and plans to update the procedure.

The finding is more than minor because it is associated with the Human Performance attribute of the Initiating Events cornerstone and affects 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, a human performance error resulted in a main steam valve being mispositioned that subsequently caused a plant power transient. The finding is also similar to the more than minor example 4.b in IMC 0612, Appendix E, Examples of Minor Issues. 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 mitigation equipment relied upon to transition the plant to a stable shutdown condition. This finding has a cross-cutting aspect in the area of Work Practices, Human Performance because FENOC did not ensure personnel work practices support human performance. Specifically, FENOC operators did not use an appropriate self-check and peer check during an activity with the potential to affect reactivity H.4(a). (Section 1R20)

Cornerstone: Occupational Radiation Safety

Green.

The inspectors identified a Green non-cited violation involving the failure to properly ensure that a device used to control access to a Very High Radiation Area was adequate to prevent an unauthorized entry into the area. Specifically, the licensee used a pliers-style locking device that did not provide a robust locking mechanism to prevent unauthorized access into a VHRA. In response to the concern, FENOC entered the issue into the corrective action program as CR 2013-18743 and changed the VHRA locking device at the Unit 2 reactor keyway.

The finding is more than minor because it is associated with the Program and Process attribute of the Occupational Radiation Safety Cornerstone and affects the cornerstone objective of ensuring the adequate protection of the worker health and safety from exposure to radiation from radioactive material during routine reactor refueling operations. The finding is also similar to the more-than-minor example 6.g in IMC 0612, Appendix E, Examples of Minor Issues issued August 11, 2009. In accordance with IMC 0609.04, Initial Characterization of Findings, issued June 19, 2012 and IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, issued August 19, 2008, the finding was determined to have very low safety significance (Green), because the finding was identified during a routine test and no unauthorized entry occurred, did not result in an ALARA Planning or work control issue, did not result in an overexposure nor was there a substantial potential for an overexposure, and the ability to assess dose was not compromised. The finding has a cross-cutting aspect in the area of Corrective Action Program, Problem Identification and Resolution, in that FENOC did not identify that the locking device was inadequate for the reactor keyway VHRA, and consequently, did not plan to replace the same type of device in place at Unit 2, even after replacing the failed reactor keyway VHRA locking device at Unit 1 P.1(c). (Section 2RS01)

Other Findings

No other findings are identified in this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 began the inspection period in a refueling outage (1R22) and commenced a reactor start up on November 2, 2013. The unit reached and maintained 48 percent power on November 5, 2013 for repairs to the A condensate pump. On November 5, 2013, Unit 1 was manually tripped from 48 percent power due to a divergence between average coolant temperature and reference temperature when steam dumps opened from a turbine trip. The turbine trip was the result of an arc flash and fire in a non-safety related 4 kilovolts (kV) system. Unit 1 commenced a startup on November 8, 2013 and reached full power on November 11, 2013. The unit remained at 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 full power throughout 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, intake structure, and emergency diesel generators. 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 71111.04

a. Inspection Scope

The inspectors performed partial walkdowns of the following systems:

River water system restoration from reverse flow alignment on October 18, 2013 1B low head safety injection boration flow path after the protected train swap on October 21, 2013 22A diesel air start compressor after restoration from corrective maintenance on December 11, 2013 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 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.

.2 Full System Walkdown

Main article: IP 71111.04S

a. Inspection Scope

On October 28 through October 30, 2013, the inspectors performed a complete system walkdown of accessible portions of the Unit 1 recirculation spray system to verify the existing equipment lineup was correct. The inspectors reviewed operating procedures, surveillance tests, drawings, equipment line-up check-off lists, and the UFSAR to verify the system was aligned to perform its required safety functions. The inspectors also reviewed electrical power availability, component lubrication and equipment cooling, hangar and support functionality, and operability of support systems. The inspectors performed field walkdowns of accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no deficiencies. Additionally, the inspectors reviewed a sample of related condition reports and work orders to ensure FENOC appropriately evaluated and resolved any deficiencies.

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 Reactor containment building (Fire Area RC-1) on October 29, 2013 Unit 2 DF switchgear room (Fire Area SB-2) on November 20, 2013 Unit 2 Normal switchgear room (Fire Area SB-4) on November 20, 2013 Unit 2 Transformers TR-MT-2, TR-2C, TR-2D (Fire Area TR-1,2, 3) on November 21, 2013 Unit 2 AE switchgear room (Fire Area SB-1) on November 21, 2013

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 15, 2013, that involved a fire in 2-3 battery 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 post-drill 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.

1R07 Heat Sink Performance (711111.07A - 1 sample)

a. Inspection Scope

The inspectors reviewed the 1-1 emergency diesel generator jacket water heat exchanger (1EE-E-1A) to determine its readiness and availability to perform its safety functions. The inspectors reviewed the design basis for the component and verified FENOCs commitments to NRC Generic Letter 89-13. The inspectors reviewed the results of previous inspections of the 1EE-E-1A and similar heat exchangers. The inspectors discussed the results of the most recent inspection with engineering staff and reviewed pictures of the as-found and as-left conditions. The inspectors verified that FENOC initiated appropriate corrective actions for identified deficiencies. The inspectors also verified that the number of tubes plugged within the heat exchanger did not exceed the maximum amount allowed.

b. Findings

No findings were identified.

1R08 In-service Inspection Beaver Valley Unit 1

Main article: IP 71111.08

a. Inspection Scope

A specialist inspector from the NRC Region I office 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 Unit 1, refueling outage 1R22. 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 conducted a short onsite inspection which was interrupted due to the temporary furlough of some U.S. government workers, including NRC Region I specialist inspectors. As a result, the inspector subsequently completed an in-office review of non-destructive examination (NDE) procedures and completed NDE records to verify that the non-destructive examination activities performed 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 reviewed the following NDE activities and completed data records:

ASME Code Required Examinations Manual Ultrasonic Test (UT), volumetric inspection record, 31-inch diameter reactor coolant system ASME, Class 1, B steam generator to pump crossover pipe to elbow butt weld DLW LOOP2-5-S-01 Bare Metal Visual Examination record of the reactor vessel lower head and instrument nozzle penetrations Manual UT Examination data record, Class 1, pressurizer bottom head to shell circumferential weld, tank RC-TK-1-C-4 Radiograph Examination report BOP-VE-13-001, Class 2, 3-inch diameter low head to high head safety injection system, pipe to flange weld Radiograph Examination report BOP-VE-13-002, Class 2, 3-inch diameter low head to high head safety injection system, tee to pipe weld Radiograph Examination report BOP-VE-13-003, Class 2, 6-inch diameter low head to high head safety injection system, tee to pipe weld Radiograph Examination report BOP-VE-13-004, Class 2, 6-inch diameter low head to high head safety injection system, pipe to tee weld Unit 1 containment liner plate repair, magnetic particle records, ultrasonic testing records, and leak rate pressure testing records Visual Exam of Equipment and Components (General) record BOP-VT-13-080 of Unit 1 Containment liner defect (1R22)

BOP-UT-13-302, 304, 309, 310, 312 and 325, Manual UT Erosion/Corrosion Examination data records of Unit 1 Containment liner plate The inspector reviewed certifications of the NDE technicians performing the examinations and verified that the inspections were performed in accordance with approved NDE procedures and that the results were reviewed and evaluated by certified Level III NDE personnel.

Re-examination of an Indication Previously Accepted For Service After Analysis There were no samples available for review during this inspection that involved examinations with recordable indications that had been accepted for continued service following the previous Unit 1 1R21 outage.

Modification/Repair/Replacements Consisting of Welding on Pressure Boundary Risk Significant Systems Beaver Valley staff completed inspections and assessments of the Unit 1 containment coatings during 1R22 outage and identified a paint blister on October 4, 2013. The blister was removed and a through-wall hole was identified in the 3/8 inch thick steel containment liner plate. The steel liner acts as an impervious membrane. Beaver Valley staff performed a visual examination and UT to characterize the extent of liner plate degradation. The size of the through-wall flaw was determined to be 0.42 inches by 0.29 inches, approximately 0.122 square inches. The hole was located about 7 inches above the containment basement floor between columns 9 and 9.5 near instrument rack 108. Laboratory analysis indicated that the corrosion was initiated from foreign material containing significant moisture which enabled an electrolytic corrosion cell to manifest where material was touching the outside of the containment steel liner when the concrete was poured during initial plant construction. From that interaction a slow acting corrosion cell was established and with time corroded a through-wall hole in the steel liner.

Since a visual examination of 100% of accessible areas of the containment liner had already been performed by a coating inspection contractor during the 1R22 outage the inspector concluded there was no required expansion of scope by the ASME code.

However, Beaver Valley staff responsible for the containment liner inspection program independently performed a 100% visual examination of the containment liner and did not identify additional deficiencies. In addition, Beaver Valley personnel performed UT thickness measurements on eight supplemental examination locations in the lower elevation of the Unit 1 containment building corresponding to the through-wall hole spaced approximately equidistant around the containment. The UT results did not identify evidence of wall loss.

The resident inspectors observed portions of the in-progress Unit 1 containment liner plate repair/replacement activities, including removal of the degraded portion of the containment liner plate, fit-up of replacement 9 inch by 13 inch liner plate, and local pressure testing following the liner repair. The inspector performed an in-office review of engineering change package (ECP) 13-0700-01, material specification BVS-136, welding specifications, welding procedures, welder qualification records, completed magnetic particle and volumetric ultrasonic testing records, and local leak rate pressure testing results to verify that the welding and applicable NDE activities were performed in accordance with FENOC procedure 1/2-NOP-CC-5703, ASME Code Boiler and Pressure Vessel Code,Section III for Class A vessels,Section VIII, 1968, original Codes of construction and Section XI, 2001 Edition, 2003 Addenda.

Pressurized Water Reactor Vessel Upper Head Penetration (RVUHP) Inspection Activities (IMC Section 02.02)

The inspector verified that no inspections were required to be performed of the RVUHP during 1R22.

Reactor Vessel Lower Head Penetration Nozzle Inspection Activities The inspector reviewed the bare metal visual examination data record VT-13-1032 of the 50 reactor vessel lower head in-core instrument nozzle penetration welds. The inspector assessed the acceptability of the as-found conditions to ensure the integrity of the reactor coolant pressure boundary. No indication of boric acid leakage was observed.

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 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 which was directly observed by the resident inspectors. 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 corrective action program of the more significant deficiencies documented in the following condition reports (CR 2013-15309, residual heat removal flange 1RH-E1A area leakage, CR 2013-15406, residual heat removal pump 1RH-P-1A mechanical seal leakage, and CR 2013-15303, thermal relief valve RV-1CH-391 for penetration #46 leakage on tailpipe) 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 reviewed the BVPS Unit 1 1R21 steam generator degradation assessment SG-SGMMP-12-01. No inspections were performed of the BVPS Unit 1 steam generator tubes during the 1R22 refueling outage. The inspector reviewed 10 Code of Federal Regulations (CFR) Part 50 and the ASME Boiler and Pressure Vessel Code Section XI to verify that no S/G tube examinations were required during the 1R22 refueling outage.

Identification and Resolution of Problems (IMC Section 02.05)

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

The inspector verified that non-conforming 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 26, 2013, which included loss of main generator isophase bus cooling, failure of steam generator feedwater level control, and a small break loss of coolant accident. 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 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 1 reactor draining to the vessel flange on October 4, 2013. 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 8. Additionally, the inspectors observed operator performance 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.

.3 Licensed Operator Requalification Program

a. Inspection Scope

On December 6, 2013, one NRC region-based inspector conducted an in-office review of results of licensee-administered annual operating tests for 2013, for Unit 1 operators.

(There was no Unit 1 written exam this year.) The inspection assessed whether pass rates were consistent with the guidance of NRC Manual Chapter 0609, Appendix I, and Operator Requalification Human Performance Significance Determination Process (SDP). The review verified that the failure rate (individual or crew) did not exceed 20%.

1 out of 37 operators failed at least one section of the Annual Exam. The overall individual failure rate was 2.7%.

0 out of 9 crews failed the simulator test. The crew failure rate was 0.0%.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

Main article: IP 71111.12Q

a. Inspection Scope

The inspectors reviewed the Unit 2 emergency switchgear ventilation system (a)(1)evaluation on December 13, 2013 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. The inspectors verified that the SSC was properly scoped into the maintenance rule in accordance with 10 CFR 50.65 and 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.

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 elevated (yellow) planned risk for decay heat removal (DHR) with reactor vessel level drained to the flange on October 4 through 6, 2013 Unit 1 elevated (orange) planned risk for electrical redundancy due to the 4kV DF emergency switchgear electrical bus outage on October 15, 2013 Unit 1 elevated (yellow) planned risk entry during reactor coolant system depressurization on October 4, 2013 Unit 1 extended elevated (yellow) risk for spent fuel pool (SFP) cooling due to B SFP cooling pump breaker failure to close on October 18, 2013

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 1 pressurizer upper manhole bolts exceeded vendor recommended torque value during removal on October 14, 2013 2-1 and 2-2 Emergency diesel generator (EDG) fuel roll pins not classified as safety related, inventoried as non-safety related, and installed in EDG discovered on October 22, 2013 Grid operator post-trip contingency evaluation for degraded voltage on October 4, 2013 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 Permanent Modifications

a. Inspection Scope

The following inspection sample examined a modification associated with a new piping connection installation into the low head safety injection system. The inspection scope for the modification was restricted to those elements necessary to satisfy the stated objectives of IP 71111.18, specifically:

To verify that modifications have not affected the safety functions of important safety systems; To verify that the design bases, licensing bases, and performance capability of risk significant SSCs have not been degraded through modifications; and Verify that modifications performed during increased risk-significant configurations did not place the plant in an unsafe condition.

The inspection did not address whether the associated modification(s) satisfactorily addressed the objectives of Japan Lessons Learned Order EA-12-049. The inspectors evaluated a modification of the low head safety injection system implemented by engineering change package 13-0418-005, Install 6x6x3 Blind Pipe Tee Upstream of CVCS Supply Valve MOV-1SI-863B. 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. Inspectors reviewed the weld data sheets and discussed radiography results with engineering. The inspection sample examined was associated with FirstEnergys modifications in response to Japan Lessons Learned Order EA-12-049, concerning mitigating strategies for beyond-design-basis external events (ML12054A735).

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.

2-1 EDG digital reference unit replacement and EDG lockout relay 86-EGSADX1 testing on September 19-20, 2013 Vital bus battery 1-4 replacement on October 9, 2013 Unit 1 manipulator crane gripper replacement on October 15, 2013 1-2 EDG governor replacement on October 18, 2013 Unit 1 containment liner repair and local leak rate testing from October 27 through October 29, 2013 3A auxiliary feedwater pump packing repair on November 6, 2013

b. Findings

No findings were identified.

1R20 Refueling and Other Outage Activities

Main article: IP 71111.20

.1 Refueling Outage 1R22

a. Inspection Scope

The inspectors reviewed the stations work schedule and outage risk plan for the Unit 1 maintenance and refueling outage 1R22, which was conducted September 29 through November 2, 2013. The inspectors reviewed FENOCs development and implemen-tation 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 Tracking of startup prerequisites, walkdown of the primary containment to verify that debris had not been left which could block the emergency core cooling system suction strainers, and startup and ascension to 48 percent power operation Identification and resolution of problems related to refueling outage activities

b. Findings

Introduction.

A self-revealing, Green NCV of Technical Specification (TS) 5.4.1 Procedures was identified when an operator did not correctly implement procedure 1OM-52.4.A, Raising Power from 5% to Full Load Operation, Revision 68, during the warm-up the moisture separator reheaters.

Description.

Moisture separator reheaters (MSRs) are part of the main steam system.

Steam exits the high pressure turbine into the MSRs and is directed into the low pressure turbines. High pressure steam from the main steam header provides the heating steam to the MSRs. On November 5, 2013, the MSR heat-up was started in accordance with 1OM-52.4.A. The procedure requires that the dial potentiometer associated with the 1A and 1C reheater steam supply valves FCV-1MS-100A and FCV-1MS-100C be taken to the full open position to ensure the valves remain open when the controller is placed in manual. The operator placed the potentiometer in the full closed position instead of full open, and when the controller was taken to manual, the valves closed. Reactor coolant system (RCS) pressure first dropped from 2236 PSIG to 2210PSIG, then increased to 2264 PSIG. Pressurizer level increased from 37% to 46%.

Average coolant temperature increased from 560F to 566F and reactor power lowered from 46% to 41%. The valves were reopened, and parameters returned to expected values, concluding the transient.

FENOC entered this issue into the corrective action program under CR 2013-17848 and reviewed the transient under the Reactivity Management Program. The site performed a limited apparent cause evaluation and determined that the operator believed he was operating the potentiometer correctly but did not perform an adequate self-check.

FENOC also determined the individual providing the peer check, a trainee, had insufficient knowledge of the system to adequately provide a verification check.

Analysis.

The inspectors determined that the operators failure to correctly operate the moisture separator reheater system in accordance with 1OM-52.4.A was a performance deficiency that was reasonably within FENOCs ability to foresee and correct and should have been prevented.

The finding is more than minor because it is associated with the Human Performance attribute of the Initiating Events cornerstone and affects the cornerstone objective to limit the likelihood of events that upset plant stability and challenge critical safety functions during power operations. Specifically, a human performance error resulted in a main steam valve being mispositioned that subsequently caused a plant transient. The finding is also similar to the more than minor example 4.b in IMC 0612, Appendix E, Examples of Minor Issues. 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, dated 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 mitigation equipment relied upon to transition the plant to a stable shutdown condition.

This finding has a cross-cutting aspect in the area of Work Practices, Human Performance because FENOC did not ensure personnel work practices support human performance. Specifically, FENOC operators did not use an appropriate self-check and peer check during an activity with the potential to affect reactivity H.4(a).

Enforcement.

TS 5.4.1, Procedures, states, in part, that written procedures shall be established, implemented and maintained in accordance with Regulatory Guide (RG)1.33. RG 1.33 identified that procedures should be written to provide directions for changing reactor power level per Section 2.f, Changing Load. Contrary to the above, on November 5, 2013, FENOC failed to adequately implement 1OM-52.4.A.

Specifically, the procedure provides guidance on MSR warm-up, which was incorrectly followed and resulted in a plant transient. FENOCs immediate corrective actions included entering the misposition event into the corrective action program as condition report 2013-17848, performing a crew stand down, and conducting a limited apparent cause evaluation. Because this issue was of very low safety significance (Green),and FENOC entered this issue into their corrective action program (2013-17848), this violation is being treated as a non-cited violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000334/2013005-01, Moisture Separator Reheater Valve Misposition Results in Plant Transient)

.2 Forced Outage 1FOAC2

a. Inspection Scope

The inspectors reviewed the stations work schedule and risk plan for the Unit 1 forced outage 1FOAC2, which was conducted November 5 through November 8, 2013. The outage was performed following a manual trip of the plant due to a deviation between average coolant temperature and reference temperature when steam dumps opened during a turbine trip. The turbine tripped due to an arc flash and fire in a 4kV cable tray in the turbine building. During the outage, the inspectors observed portions of the startup and power ascension processes and monitored controls associated with the following outage activities:

Hot shutdown temperature control Portions of offsite power transformer cable inspection Restart readiness meeting Reactor start up and ascension to full power Licensee identification and resolution of problems

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, 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:

1BVT-1.21.2, Trevi Test Method for Main Steam Safety Valve Setpoint Check, on September 29, 2013 1OST-47.3F, Containment System Operating Surveillance Test - Containment Isolation and ASME test Work Week 2, on October 9, 2013 (containment isolation valve)1OST-11.14B, High Head Safety Injection Full Flow Test, on October 22, 2013 (in-service test)2OST-24.4, Steam Driven Auxiliary Feed Pump [2FWE*P22] Quarterly Test, on December 3, 2013

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes

Main article: IP 71114.04

a. Inspection Scope

The NSIR headquarters staff performed an in-office review of the latest revisions of various Emergency Plan Implementing Procedures (EPIPs) and the Emergency Plan located under ADAMS accession number ML13268A074 and ML13151A048 as listed in the Attachment.

The licensee determined that in accordance with 10 CFR 50.54(q), the changes made in the revisions resulted in no reduction in the effectiveness of the Plan, and that the revised Plan continued to meet the requirements of 10 CFR 50.47(b) and Appendix E to 10 CFR Part 50. The NRC review was not documented in a safety evaluation report and did not constitute approval of licensee-generated changes; therefore, this revision is subject to future inspection. The specific documents reviewed during this inspection are listed in the Attachment.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstone: Occupational Radiation Safety

2RS0 1 Radiological Hazard Assessment and Exposure Controls

Main article: IP 71124.01

During the period November 18 - 21, 2013, the inspector evaluated FENOCs performance in assessing the radiological hazards and the effectiveness of radiological controls implemented during the fall 1R22 refueling outage and during power operations.

The inspector used the requirements in 10 CFR 20 and guidance in Regulatory Guide (RG) 8.38 Control of Access to High and Very High Radiation Areas (VHRAs) for Nuclear Plants, Technical Specifications, and the FENOC procedures as criteria for determining compliance.

a. Inspection Scope

The inspector reviewed the 2013 Beaver Valley performance indicators for the occupational exposure cornerstone, and relevant condition reports related to occupational radiation safety initiated since the last inspection, to identify performance trends and repetitive problem areas.

Radiological Hazards Control and Work Coverage The inspector identified work performed in radiological controlled areas in Unit 1 and in Unit 2 and evaluated the licensees assessment of the radiological hazards. The inspector evaluated the survey maps, exposure control evaluations, electronic dosimeter dose/dose rate alarm set points, air sampling records, and radiation work permits (RWP), associated with these areas, to determine if the exposure controls were acceptable. Specific work activities evaluated included entry into the Unit 2 reactor building, at power, to lubricate the containment air recirculation fans (RWP 213-2019),and characterizing radwaste containers in the waste handling building (RWP 113-1013).

For these tasks, the inspector evaluated the barrier controls and contamination controls applied to the job site, and discussed the radiological controls with the licensee staff.

The inspector reviewed the air sample records for samples taken in various plant areas, to determine if the samples collected were representative of the breathing air zone and analyzed/recorded in accordance with established procedures. During tours of the radiological controlled areas, the inspector evaluated whether the continuous air monitors were strategically located to assure that potential airborne contamination could be promptly identified and that the monitors were located in low background areas.

During walk downs of the Unit 1 and Unit 2 auxiliary buildings, waste handling buildings and spent fuel pool buildings, the inspector evaluated dose rates in selected areas to confirm the accuracy of survey maps, and to verify that Locked High Radiation Areas (LHRA)/VHRAs were properly posted and secured and access properly controlled.

Additionally the inspector reviewed the RWPs developed for work performed during the fall 1R22 refueling outage, including temporary shielding installation, scaffolding construction, and various steam generator tasks to determine if the potential hazards were assessed. In particular, the inspector reviewed the electronic dosimeter (ED)dose/dose rate alarm set points, stated on the RWP, and the condition reports associated with ED actual alarms, to determine if the set points were consistent with the survey indications and plant policy.

Instructions to Workers The inspector reviewed RWP briefing materials and observed various briefings at the control point to determine if workers, performing radiological significant tasks, were properly informed of electronic dosimeter alarm set points, low dose waiting areas, and work site radiological conditions. Briefing materials reviewed included lubrication of the Unit 2 CAR fans, during power operations (RWP 213-2019).

During tours of Unit 1 and 2 radiological controlled areas (RCA), the inspector determined if LHRAs had the appropriate warning signs and were secured. Additionally, the inspector identified that low dose waiting areas were appropriately surveyed, identified, and used by personnel.

The inspector discussed with radiation protection supervision the procedural controls for accessing LHRAs and VHRAs and determined that no changes have been made to reduce the effectiveness and level of worker protection.

The inspector verified that keys to LHRAs and VHRAs were properly accounted for at the control point, in the control room, and in the radiation protection managers office.

Contamination and Radioactive Material Control During tours of the Unit 1 and 2 auxiliary buildings, waste handling building, safeguards building, and spent fuel pool areas, the inspector confirmed that contaminated materials were properly bagged, surveyed/ labeled, and segregated from work areas. The inspector observed workers using contamination monitors to determine if various tools/equipment were potentially contaminated and the material met criteria for releasing the materials from the RCA.

Radiation Worker Performance During job performance observations, the inspector evaluated if workers complied with RWP requirements and were aware of radiological conditions at the work site.

Additionally, the inspector determined if radiation protection technicians were aware of RWP controls/limits applied to various tasks and provided positive control of workers to reduce the potential of unplanned exposure and personnel contaminations.

Problem Identification and Resolution A review of Nuclear Oversight field observation reports, dose/dose rate alarm reports, personnel contamination event reports, and associated condition reports, was conducted to determine if identified problems and negative performance trends were entered into the corrective action program and evaluated for resolution and to determine if an observable pattern traceable to a similar cause was evident.

Relevant condition reports, associated with radiation protection control access, initiated between July - November 2013, were reviewed and discussed with the licensee staff to determine if the follow up activities were being conducted in an effective and timely manner, commensurate with their safety significance.

b. Findings

Introduction:

The inspectors identified a Green non-cited violation involving the failure to properly ensure that a device used to control access to a Very High Radiation Area was adequate to prevent an unauthorized entry into the area.

Description:

A very high radiation area (VHRA) is defined as an area in which radiation levels meet or exceed 500 rads per hour (5 grays), as measured at one meter from a radiation source or any surface through which the radiation penetrates. A VHRA requires installation of a physical device to prevent inadvertent access to the area.

Physical devices include locks, keys, heavy gauge chain, gates and doors.

During the period October 5, 2013 through October 11, 2013, while Unit 1 was shut down, the in-core flux thimbles were retracted from the reactor core and stored in the reactor keyway, creating a VHRA in that location. In anticipation of these conditions, FENOC implemented procedures to control access to this area and installed an encumbering device that was intended to ensure that an individual could not gain unauthorized or inadvertent access to the keyway area. On October 11, 2013, during a routine daily physical challenge of the pliers-style locking device, the device failed when twisted by a technician. The jaws of the device separated and no longer prevented personnel access to the VHRA. When this failure occurred, the area was continuously guarded until a more robust locking device was installed and independently verified.

The licensee confirmed that, during the period in which the inadequate device was installed, no entry was made into the VHRA. This issue was entered into FENOCs corrective action program under condition report (CR) 2013-16303.

The inspector determined that the pliers-style locking device was not adequate to control access to a VHRA. The inspector reviewed FENOCs disposition of CR 2013-16303.

Based on a review of the CR disposition the inspector determined that FENOCs review of the issue did not identify that the pliers-style locking device did not meet the requirements for a VHRA locking device and should not have been used to secure a VRHA access. Secondly, FENOC did not conduct an extent of condition review and failed to identify the application of a similar device on the access to the VHRA in the Unit 2 reactor keyway area. In response to this NRC identified concern, FENOC entered the issue into the corrective action program as CR 2013-18743 and placed administrative controls on access to the Unit 2 reactor keyway until the corrective action to change the VHRA locking device at the Unit 2 reactor keyway was completed. FENOC also looked for improper use of the pliers-style locking device on other VHRAs, but found none.

Analysis:

The inspector determined that the use of a pliers-style locking device that did not provide a positive locking mechanism to prevent unauthorized access into a VHRA was a performance deficiency that was reasonably within FENOCs ability to foresee and correct and should have been prevented.

The finding is more than minor because it is associated with the Program and Process attribute of the Occupational Radiation Safety Cornerstone and affects the cornerstone objective of ensuring the adequate protection of the worker health and safety from exposure to radiation from radioactive material during routine plant operations. The finding is also similar to the more-than-minor example 6.g in IMC 0612, Appendix E, Examples of Minor Issues, issued August 11, 2009.

In accordance with IMC 0609.04, Initial Characterization of Findings, issued June 19, 2012 and IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, issued August 19, 2008, the finding was determined to have very low safety significance (Green), because the finding was identified during a routine test and no unauthorized entry occurred, did not result in an ALARA Planning or work control issue, did not result in an overexposure nor was there a substantial potential for an overexposure, and the ability to assess dose was not compromised.

The finding has a cross-cutting aspect in the area of Corrective Action Program, Problem Identification and Resolution, in that FENOC did not fully identify an issue potentially impacting nuclear safety. Specifically, FENOC did not identify that the locking device was inadequate for the reactor keyway VHRA, and consequently, did not identify a similar misapplication of this device at Unit 2. P.1(c).

Enforcement:

10 CFR 20.1602, Control of access to very high radiation areas, states that In addition to the requirements of 10 CFR 20.1601, the licensee shall institute additional measures to ensure that an individual is not able to gain unauthorized or inadvertent access to areas in which radiation levels could be encountered at 500 rads (5 grays) or more in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> at 1 meter from a radiation source or any surface through which the radiation penetrates. Contrary to the above, on October 5 to October 11, 2013, FENOC did not institute adequate measures to ensure that an individual was not able to gain unauthorized or inadvertent access to the Unit 1 reactor keyway with incore detectors retracted (a VHRA). Specifically, the locking device used to prevent unauthorized access to the VHRA was insufficient and opened when challenged.

Because this violation was of very low significance (Green) and FENOC entered this issue into their corrective action program (2013-18743), this violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy. (NCV 05000334/2013005-02, Insufficient VHRA Control Under Vessel)

2RS0 2 Occupational ALARA Planning and Controls

Main article: IP 71124.02

During the period November 18 - 21, 2013, the inspector assessed performance with respect to maintaining occupational individual and collective radiation exposures as low as is reasonably achievable (ALARA) during the fall 1R22 refueling outage. The inspector 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 as criteria for determining compliance.

a. Inspection Scope

The inspector reviewed pertinent information regarding the Beaver Valley collective dose history, current exposure trends, and ongoing or planned activities in order to assess current performance and exposure accrued for the 1R22 refueling outage. The inspector reviewed the plants three year rolling average collective exposure, various

1R22 outage ALARA Plans, and the 5-Year Exposure Reduction Plan.

The inspector 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.

Radiological Work Planning The inspector selected the following work activities that were radiologically significant for the 1R22 refueling outage. The effectiveness of the exposure controls for these maintenance and repair activities were evaluated by reviewing the associated post-job ALARA reviews.

RWP 113-4015 Secondary Side Steam Generator Sludge Lance/FOSAR RWP 113-4018 Reactor Disassembly/Reassembly RWP 113-4019 Remove and Install Core Exit Thermocouple Assemblies RWP 113-4021 Move Reactor Head & Upper Internals RWP 113-4022 Reactor Core Offload/Re-load RWP 113-4028 Scaffolding Construction RWP 113-4030 Install/Remove Temporary Shielding As part of this review, the inspector evaluated whether FENOC had identified appropriate dose reduction techniques; considered alternate dose reduction features; and estimated reasonable dose goals. The inspector determined if FENOCs ALARA assessment had taken into account decreased worker efficiency when using respiratory protection.

The inspector compared the results achieved in reducing dose rates and controlling actual dose with the forecasted dose, established in ALARA planning for these work activities. The inspector compared the person-hour estimates provided by maintenance planning and other groups to the radiation protection (RP) group actual person-hours for the work activity, and evaluated the accuracy of these time estimates. The inspector assessed the reasons for any inconsistencies between estimated and actual work activity doses.

The inspector determined if lessons learned from past outages were applied during the

1R22 outage to effectively control the source term and reduce dose rates in various

plant areas.

Verification of Dose Estimates and Exposure Tracking Systems The inspector reviewed the assumptions and basis for the current operational and outage collective dose estimates and compared these estimates with the actual exposure accrued. The inspector reviewed applicable procedures to determine the methodology for estimating exposures from specific work activities and for department and station collective dose goals.

The inspector evaluated whether the licensee had established measures to track, trend, and if necessary, to reduce occupational doses for ongoing work activities. The inspector evaluated the dose threshold criteria established to prompt additional reviews and implement additional ALARA planning and controls, by performing Work-In-Progress reviews when actual dose approached dose estimates.

The inspector evaluated the licensees method of adjusting exposure estimates, by reviewing the Station ALARA Committee evaluations if unexpected changes in dose rate, job scope or emergent work were encountered. The inspector assessed whether adjustments to exposure estimates were based on sound radiation protection and ALARA principles. The inspector reviewed the minutes from recent Station ALARA Committee meetings to perform this assessment and discussed the actions taken by the Station ALARA Committee with the radiation protection manager.

Source Term Reduction and Control The inspector reviewed the status and historical trends for the Unit 1 source term.

Through review of survey maps and interviews with the Radiation Protection manager, the inspector evaluated recent source term measurements and control strategies.

Specific strategies being employed by the licensee included operational controls to increase reactor coolant cleanup during shutdown, chemistry controls, use of macro-porous resin, system flushes, and temporary shielding.

Radiation Worker Performance The inspector observed radiation worker and RP technician performance during work activities being performed in radiation areas and HRAs. The inspector determined if workers demonstrated the ALARA philosophy in practice, by using low dose waiting areas and temporary shielding for their tasks.

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

b. Findings

No findings were identified.

2RS0 3 In-Plant Airborne Radioactivity Control and Mitigation

Main article: IP 71124.03

a. Inspection Scope

During the period November 18 - 21, 2013, the inspector evaluated whether in-plant airborne concentrations were being controlled consistent with ALARA principles. The inspector used the requirements in 10 CFR Part 20, Regulatory Guide 8.25, Air Sampling in the Workplace, and the licensees procedures as criteria for determining compliance.

Airborne Controls For work performed during 1R22, the inspector determined if the use of respiratory protection was evaluated by conducting Total Effective Dose Equivalent (TEDE) ALARA evaluations for tasks involving potential airborne contamination. The inspector assessed whether the evaluation compared the benefits of wearing respiratory protection with the possible decreases in worker efficiency and subsequent increased worker dose. The inspector confirmed that engineering controls; e.g. portable High Efficiency Particulate Air (HEPA) ventilation units were used at specific job sites to remove airborne contamination away from the work area.

During plant tours, the inspector verified the operability and location of various continuous airborne monitors to assure that areas that were susceptible to airborne contamination were properly monitored.

Problem Identification and Resolution The inspector evaluated whether problems associated with the control and mitigation of in-plant airborne radioactivity were being identified by the licensee at an appropriate threshold and were properly addressed for resolution in the licensee corrective action program. The inspector assessed whether the corrective actions were appropriate for a selected sample of problems involving airborne radioactivity and were appropriately documented by the licensee.

b. Findings

No findings were identified.

2RS0 4 Occupational Dose Assessment

Main article: IP 71124.04

a. Inspection Scope

During the period November 18 - 21, 2013, the inspector evaluated the processes and procedures implemented by the licensee to determine occupational dose. This was performed to determine if the TEDE evaluation, resulting from external and internal exposure, was appropriately monitored and assessed. The inspector used the requirements in 10 CFR Part 20, and the licensees procedures as criteria for determining compliance.

External Dose During plant tours, the inspector confirmed that detailed procedures were implemented associated with dosimeter use. The inspector confirmed that dosimeters were appropriately worn by workers, on their body location receiving the highest dose rate.

The inspector reviewed condition reports related to dose and dose rate alarms received on electronic dosimetry to determine if the cause of the alarm was properly determined and that no performance indicator criteria was exceeded The inspector reviewed exposure records for the ten highest exposed workers occurring in 2013 (through November 17, 2013) and electronic dosimeter alarm reports to verify that no regulatory criteria were exceeded and no performance indicator threshold was met.

Internal Dose The inspector reviewed internal dose assessments for workers who had the potential to receive a recordable committed effective dose equivalent dose greater than 10 millirem, from inhaling or ingesting radioactive contamination, to evaluate the processes implemented to determine the workers exposure. Included in this review were the initial and follow up whole body counts for the workers, a determination that the radionuclide library used for the counting system included the gamma-emitting radionuclides that exist at the site, and a review of the calculations used to make the dose assessment.

Declared Pregnant Workers The inspector assessed the program for controlling and restricting the dose to declared pregnant workers, who had access to performing outage related activities. The inspector reviewed the documentation for three declared pregnant workers to determine if the workers exposure was properly monitored and controlled.

Problem Identification and Resolution The inspector assessed whether problems associated with occupational dose assessment were being identified by the licensee at an appropriate threshold and are properly addressed for resolution in the licensee corrective action program. The inspector assessed the appropriateness of the corrective actions for a selected sample of problems documented by the licensee involving occupational dose assessment.

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, 2012 through September 30, 2013:

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 condition reports, and associated documents, for incidents involving locked high radiation areas, very high radiation areas, and unplanned exposures, occurring from October 1, 2012 through October 31, 2013, against the criteria specified NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, to verify that all occurrences that met the NEI criteria were identified and reported as performance indicators. This inspection activity represents the completion of one sample relative to this inspection area; completing the annual inspection requirement.

b. Findings

No findings were identified.

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

a. Inspection Scope

The inspector reviewed relevant effluent release reports for the period October 1, 2012 through October 31, 2013, for issues related to the public radiation safety performance indicator, which measures radiological effluent release occurrences that exceed 1.5 mrem/quarter whole body or 5.0 mrem/quarter organ dose for liquid effluents; or 5 mrad/quarter gamma air dose, 10 mrad/quarter beta air dose, and 7.5 mrad/quarter for organ dose for gaseous effluents. This inspection activity represents the completion of one sample relative to this inspection area; completing the annual inspection requirement.

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 (CAP) 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: TR-2B System Station Service Transformer Doble testing review

a. Inspection Scope

The inspectors performed an in-depth review of FENOCs operational decision making issue analysis and corrective actions associated with CR 2012-15978 concerning elevated Doble test results for the system station service transformer (SSST) TR-2B.

Specifically, during the performance of Doble test, the power factor acceptance criteria for CLT (Low to Tertiary) and CT (Tertiary to Ground) winding insulations were not met for the TR-2B transformer.

The inspectors assessed FENOCs operational decision making analysis, cause analyses, extent-of-condition reviews, compensatory actions, and the prioritization and timeliness of FENOCs corrective actions to determine whether FENOC was appropriately, identifying, characterizing, and correcting problems associated with the TR-2B SSST and whether the planned or completed corrective actions were appropriate.

The inspectors compared the actions taken to the requirements of FENOCs CAP.

b. Findings and Observations

No findings were identified.

The inspectors determined that FENOC appropriately identified, characterized, and implemented corrective actions associated with elevated Doble test results for the TR 2B SSST. FENOC installed a gas monitoring system with an alarm function to monitor 2B SSST gas conditions and track transformer health. However, inspectors noted that the implementation of the engineering change package, which installed the gas monitoring system, was not communicated effectively through operations. The inspectors interviewed two different shift crews to determine the understanding of the alarm function of the gas monitoring system. Both of the crew members were not able to recall from memory that the gas monitoring system installed for 2B SSST would alarm in the control room. The inspectors reviewed the alarm response procedure and determined that the alarm function of the 2B SSST was appropriately updated; however, inspectors determined that procedural guidance for the Electrical Maintenance department to access data from the TM view software, to analyze and determine which gases are in high alarm conditions, needed to be developed. FENOC entered the inspectors observations into their corrective action program (CRs 2013-18575, and 18578).

The inspectors determined FENOCs overall response to the issue was commensurate with the safety significance, was timely, and the actions taken and planned were reasonable to resolve the elevated Doble test results for TR-2B.

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

Main article: IP 71153

.1 Plant Events

a. Inspection Scope

For the plant event 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, issued October 28, 2011, 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 Notice of Unusual Event declaration due to an explosion in the protected area with subsequent turbine building cable fire and plant trip on November 5, 2013

b. Findings

No findings were identified.

.2 (Closed) Licensee Event Report (LER) 05000334/2013-002-00: Containment Liner

Through Wall Defect Discovered During Planned Visual Inspection On October 4, 2013, during a planned visual coatings inspection of the Unit 1 interior Reactor Containment Building (RCB) steel liner, a paint blister located at 692 foot elevation was observed. After cleaning the area and removal of the corrosion products a through wall defect was discovered that penetrated the RCB steel liner. Thickness measurements using UT were obtained around the area of the through wall liner corrosion. The affected section of the steel liner plate was removed and sent to a laboratory for examination. The laboratory analysis determined that there were a total of two through wall defects with a possible third through wall penetration. The total area of the three through wall penetrations was calculated to be 0.395 square inches. A new total calculated leakage, which included flow from the discovered defects, did not exceed the maximum leakage rate set by Technical Specification 5.5.12.c, Containment Leakage Rate Testing Program. The inspectors did not identify any new issues during the review of the LER. This LER is closed.

4OA5 Other Activities

.1 Buried Piping and Tanks, TI-2515/182, Phase 2 (1 sample)

a. Inspection Scope

The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraphs 03.02.a of the Temporary Instruction (TI) 2515/182, and it was confirmed that activities which correspond to the completion dates, specified in the program, which have passed since the Phase 1 inspection was conducted, have been completed.

The licensees buried piping and underground piping and tanks program was inspected in accordance with paragraph 03.02.b of the TI and responses to specific questions found in www.nrc.gov/reactors/operating/ops-experience/buried-pipe-ti-phase-2-insp-req-2011-11-16.pdf were submitted to NRC headquarters staff.

b. Findings

No findings were identified.

.2 Institute of Nuclear Power Operations (INPO) Report Review

a. Inspection Scope

The inspectors reviewed the final report for the INPO plant assessment of Beaver Valley conducted in March 2013. The inspectors evaluated the report to ensure that NRC perspectives of FENOC performance were consistent with any issues identified during the assessments. The inspectors also reviewed the report to determine whether INPO identified any significant safety issues that required further NRC follow-up.

b. Findings

No findings were identified.

4OA6 Meetings, Including Exit

On January 31, 2014, the inspectors presented the inspection results to E. Larson, Site Vice President 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.

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