Text

IR 05000266/2014005, 05000301/2014005; on 10/01/2014-12/31/2014; Point Beach Nuclear Plant, Units 1 & 2; Adverse Weather Protection
	ML15029A579
Person / Time
Site:	Point Beach
Issue date:	01/29/2015
From:	Jamnes Cameron; Reactor Projects Region 3 Branch 4
To:	Mccartney E; Point Beach
References
	IR 2014005
	Download: ML15029A579 (60)
	v • d • e

UNITED STATES ary 29, 2015

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000266/2014005; 05000301/2014005

Dear Mr. McCartney:

On December 31, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Point Beach Nuclear Plant, Units 1 and 2. The enclosed report documents the results of this inspection, which were discussed on January 15, 2015, with you and other members of your staff.

Based on the results of this inspection, one NRC-identified finding of very low safety significance was identified. The finding involved a violation of NRC requirements. Additionally, three licensee-identified violations are listed in Section 4OA7 of this report. However, because of the very low safety significance and because the issues were entered into your corrective action program (CAP), the NRC is treating the issues as non-cited violations (NCVs) in accordance with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the subject or severity of these NCVs, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with a copy to the Regional Administrator, U.S. Nuclear Regulatory Commission-Region III, 2443 Warrenville Road, Suite 210, Lisle, IL 60532-4352; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the Resident Inspector Office at the Point Beach Nuclear Plant. 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 III, and the NRC Resident Inspector at the Point Beach Nuclear Plant. In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records (PARS)

component of the NRC's Agencywide Documents Access and Management System (ADAMS).

ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Jamnes Cameron, Chief Branch 4 Division of Reactor Projects Docket Nos. 50-266; 50-301 License Nos. DPR-24; DPR-27

Enclosure:

IR 05000266/2014005; 05000301/2014005 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 05000266; 05000301 License Nos: DPR-24; DPR-27 Report No: 05000266/2014005; 05000301/2014005 Licensee: NextEra Energy Point Beach, LLC Facility: Point Beach Nuclear Plant, Units 1 and 2 Location: Two Rivers, WI Dates: October 1, 2014 through December 31, 2014 Inspectors: D. Oliver, Senior Resident Inspector K. Barclay, Resident Inspector B. Bartlett, Project Engineer J. Beavers, Emergency Preparedness Inspector V. Myers, Health Physicist J. Rutkowski, Project Engineer A. Shaikh, Reactor Inspector Approved by: J. Cameron, Chief Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000266/2014005, 05000301/2014005; 10/01/2014-12/31/2014; Point

Beach Nuclear Plant, Units 1 & 2; Adverse Weather Protection.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. One Green finding was identified by the inspectors.

The finding was considered an NCV of NRC regulation. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using IMC 0609, Significance Determination Process dated June 2, 2011.

cross-cutting aspects are determined using IMC 0310, Aspects Within the Cross-Cutting Areas effective date January 1, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy dated July 9, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process Revision 5, dated February 201

NRC-Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance and associated NCV of 10 CFR Part 50,

Appendix B, Criterion XVI, Corrective Action, was identified by the inspectors for the failure to promptly repair the non-functional HX-272A, a safety-related room heater for the G-04 Emergency Diesel Generator (EDG) day tank room. Specifically, HX-272A was identified failed in June 2012 and was not corrected until November 2014 but not before inspectors identified that the redundant room heater, HX-272B, had also failed and the room temperature had dropped below the design basis temperature of 50 degrees Fahrenheit. The licensee repaired HX-272A on November 25, 2014 and also installed a thermometer in the fuel oil day tank room for operators to monitor room temperature. The licensee entered the issue into their CAP as action request (AR)02018260 and AR 02008296.

The inspectors determined that failing to promptly repair safety-related room heater,

HX-272A, G-04 EDG day tank room heater was contrary to 10 CFR 50 Appendix B,

Criterion XVI and was a performance deficiency. The inspectors determined that the finding was more than minor, because, if left uncorrected, it could have the potential to become a more significant safety concern. Specifically, the inspectors found both safety-related heaters non-functional in the fuel oil day tank room with outside air blowing into the room through a ventilation damper. The outside temperature was approximately 17 degrees Fahrenheit, and while the licensee determined that at the time their fuel oil cloud point was approximately zero degrees Fahrenheit, the licensees specification for fuel oil cloud point allowed for a fuel oil cloud point of up to 25 degrees Fahrenheit. Additionally, if the fuel oil day tank room temperatures dropped below freezing, the fire sprinkler piping within the room could have actuated and/or ruptured and adversely affected the safety-related fuel oil transfer pumps within the room. The inspectors determined the finding could be evaluated using the SDP in accordance with Inspection Manual Chapter (IMC) 0609, Significance Determination Process,

Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process for Findings At Power, Exhibit 2,

Mitigating Systems Screening Questions, dated June 19, 2012.

The inspectors concluded that the finding was of very low safety significance because the inspectors answered "No" to the Mitigating Systems screening questions. This finding has a cross-cutting aspect of Work Management (H.5), in the area of Human Performance, for failing to implement a process of planning, controlling, and executing work activities such that nuclear safety is an overriding priority. (Section 1R01.1)

Licensee-Identified Findings Violations of very low safety or security significance or Severity Level IV that were identified by the licensee have been reviewed by the NRC. Corrective actions taken or planned by the licensee have been entered into the licensees CAP. These violations and CAP tracking numbers are listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

Unit 1 The unit operated at or near full power until October 3. On October 3, the operators reduced power in preparation for the October 4 shutdown and refueling outage 35. The unit remained shutdown until October 30, when the unit was started-up. The unit reached full power on November 4 and operated at or near full power until it was manually tripped on December 2 for condensate pump malfunction. The unit was returned to full power on December 8 and remained at full power for the remainder of the inspection period.

Unit 2 The unit operated at or near full power for the inspection period, except for brief power reductions to conduct planned maintenance and surveillance activities.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

1R01 Adverse Weather Protection

Main article: IP 71111.01

.1 Winter Seasonal Readiness Preparations

a. Inspection Scope

The inspectors conducted a review of the licensees preparations for winter conditions to verify that the plants design features and implementation of procedures were sufficient to protect mitigating systems from the effects of adverse weather. Documentation for selected risk-significant systems was reviewed to ensure that these systems would remain functional when challenged by inclement weather. During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions. Additionally, the inspectors reviewed the Final Safety Analysis Report (FSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. Cold weather protection, such as heat tracing and area heaters, was verified to be in operation where applicable. The inspectors also reviewed CAP items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures. Documents reviewed are listed in the Attachment to this report. The inspectors reviews focused specifically on the following plant systems due to their risk significance or susceptibility to cold weather issues:

service water (SW); and

EDGs.

This inspection constituted one winter seasonal readiness preparations sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

(1) Failure to Promptly Correct a Failed Emergency Diesel Generator Day Tank Room Heater

Introduction:

A finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, was identified by the inspectors for the failure to promptly repair the non-functional HX-272A, a safety-related room heater for the G-04 EDG day tank room. Specifically, HX-272A was identified failed in June 2012 and was not corrected until November 2014 but not before inspectors identified that the redundant room heater, HX-272B, had also failed and the room temperature had dropped below the design basis temperature of 50 degrees Fahrenheit.

Description:

On November 20, 2014, while performing cold weather walkdowns of the G-03 and G-04 EDGs, the inspectors noted that the G-04 fuel oil day tank room was abnormally cold. The inspectors observed that neither room heater was operating and notified the control room. The inspectors used an infrared thermometer and found that temperature readings at some locations within the room were in the mid-forties.

Additionally, some readings below ventilation grating, and near fuel oil and fire protection piping, were in the thirties. The licensee manually cycled a disconnect for heater HX-272B, which was successful in restoring the heater. The licensee continued to monitor HX-272B to ensure that it functioned properly and raised the room temperature to above 50 degrees Fahrenheit, the design basis temperature of the room. The inspectors review of the second heater, HX-272A, found that the licensee had written AR 01774095, for the failed heater in June of 2012, and subsequently closed the AR to a work request (WR). The inspectors found that the work management process did not progress the WR to a work order (WO) in a timely manner that would have ensured prompt correction of the failed heater. Further inspection of the cold weather protection for the fuel oil day tank room found that the room didnt have any temperature alarms to notify the control room of below design basis temperatures, nor did the daily operator rounds have any requirements for monitoring room temperature. The licensee repaired HX-272A on November 25, 2014, and also installed a thermometer in the fuel oil day tank room for operators to monitor room temperature.

Analysis:

The inspectors determined that failing to promptly repair safety-related room heater, HX-272A, G-04 EDG day tank room heater was contrary to 10 CFR 50 Appendix B, Criterion XVI and was a performance deficiency. The inspectors determined that the finding was more than minor, because, if left uncorrected, it could have the potential to become a more significant safety concern. Specifically, the inspectors found both safety-related heaters non-functional in the fuel oil day tank room with outside air blowing into the room through a ventilation damper. The outside temperature was approximately 17 degrees Fahrenheit, and while the licensee determined that at the time their fuel oil cloud point was approximately zero degrees Fahrenheit, the licensees specification for fuel oil cloud point allowed for a fuel oil cloud point of up to 25 degrees Fahrenheit. Additionally, if the fuel oil day tank room temperatures dropped below freezing, the fire sprinkler piping within the room could have actuated and/or ruptured and adversely affected the safety-related fuel oil transfer pumps within the room.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012. The inspectors concluded that the finding was of very low safety significance (Green), because the inspectors answered "No" to the Mitigating Systems screening questions.

This finding has a cross-cutting aspect of Work Management (H.5), in the area of Human Performance, for failing to implement a process of planning, controlling, and executing work activities such that nuclear safety is an overriding priority. Specifically, the licensee closed the AR for the failed safety-related heater to a WR in June of 2012 and the heater was not repaired until November of 2014.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, states, in part, that measures shall be established to assure that conditions adverse to quality, such as failures, malfunctions, deficiencies, deviations, defective material and equipment, and nonconformances, are promptly identified and corrected.

Contrary to this, from June 6, 2012 to November 25, 2014, a condition adverse to quality was not promptly corrected. Specifically, the licensee did not correct a failed safety-related EDG fuel oil day tank room heater for over two years and five months.

This time frame included two complete cold weather seasons and below freezing temperatures of the third season.

Because this violation was of very low safety significance and the licensee entered it into the CAP as AR02018260 and AR02008296, it is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. The licensees corrective actions included repair of the HX-272A room heater and installation of a thermometer in the fuel oil day tank room for operators to monitor room temperature. (NCV 05000301/2014005-01; Failure to Promptly Correct a Failed Emergency Diesel Generator Day Tank Room Heater).

1R04 Equipment Alignment

Main article: IP 71111.04

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

G-02, EDG following maintenance;

motor driven auxiliary feedwater pump 1P-53 following maintenance on 1P-29 turbine-driven auxiliary feedwater pump (TDAFWP); and

diesel driven fire pump while the motor driven fire pump was out of service.

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, FSAR, Specification (TS) requirements, outstanding WOs, condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the to this report.

These activities constituted three partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

Main article: IP 71111.05

.1 Routine Resident Inspector Tours

Main article: IP 71111.05Q

a. Inspection Scope

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

Fire Zone 224: alternate shutdown panel zone;

Fire Zone 225: battery room D-106;

Fire Zone 226: 125 VDC electrical equipment room-D-04;

Fire Zone 227: 125 VDC electrical equipment room-D-03;

Fire Zone 228: battery room D-105;

Fire Zone 304N: AFW pump room (2P-29); and

Fire Zone 304S: AFW pump room (1P-29).

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event.

Using the documents listed in the Attachment to this report, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP.

Documents reviewed are listed in the Attachment to this report.

These activities constituted seven quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

.2 Annual Fire Protection Drill Observation

Main article: IP 71111.05A

a. Inspection Scope

On November 13, 2014, the inspectors observed a fire brigade activation for a simulated fire of the 1X-01 phase A transformer. Based on this observation, the inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies openly discussed them in a self-critical manner at the drill debrief, and took appropriate corrective actions. Documents reviewed are listed in the Attachment to this report. Specific attributes evaluated were:

proper wearing of turnout gear;

proper use and layout of fire hoses;

employment of appropriate firefighting techniques;

sufficient firefighting equipment brought to the scene;

effectiveness of fire brigade leader communications, command, and control;

utilization of pre-planned strategies;

adherence to the pre-planned drill scenario; and

drill objectives.

These activities constituted the completion of the one annual fire protection inspection sample as defined in IP 71111.05-05 that begun during the second quarter of 2014.

b. Findings

No findings were identified.

1R06 Flooding

Main article: IP 71111.06

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the FSAR, engineering calculations, and abnormal operating procedures In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the fire suppression or the circulating water systems. The inspectors also reviewed the licensees corrective action documents with respect to past flood-related items identified in the CAP to verify the adequacy of the corrective actions.

Documents reviewed during this inspection are listed in the Attachment to this report.

The inspectors performed a walkdown of the following plant area(s) to assess the adequacy of watertight barriers and flood water level alarms, and that equipment needed for safe shutdown was installed at an elevation above the maximum calculated design water level:

auxiliary building-19 foot level containing the Unit 1 and Unit 2 residual heat removal (RHR) pumps.

This inspection constituted one internal flooding sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

.2 Underground Vaults

a. Inspection Scope

The inspectors selected underground bunkers/manholes subject to flooding that contained cables whose failure could disable risk-significant equipment. The inspectors determined that the cables were not submerged, that splices were intact, and that appropriate cable support structures were in place. In those areas where dewatering devices were used, such as a sump pump, the device was operable and level alarm circuits were set appropriately to ensure that the cables would not be submerged. The inspectors also reviewed the licensees corrective action documents with respect to past submerged cable issues identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following underground bunkers/manholes subject to flooding:

manhole Z-066A;

manhole Z-067A; and

manhole Z-068.

Specific documents reviewed during this inspection are listed in the Attachment to this report. This inspection constituted one underground vaults sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

Main article: IP 71111.08

From October 6-17, 2014, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system (RCS), risk significant piping and components, and containment systems.

The inservice inspections described in Sections 1R08.1 and 1R08.5 below constituted one inspection sample as defined in IP 71111.08.

.1 Piping Systems Inservice Inspections

a. Inspection Scope

The inspectors observed or reviewed records of the following nondestructive examinations mandated by the American Society of Mechanical Engineers (ASME)

Section XI Code to evaluate compliance with the ASME Code Section XI and Section V requirements and if any indications and defects were detected, to determine if these were dispositioned in accordance with the ASME Code or an NRC-approved alternative requirement:

ultrasonic examination of reactor vessel closure head penetration welds;

eddy current examination of reactor vessel closure head vent line;

ultrasonic examination of steam generator a shell to stub barrel weld;

ultrasonic examination of steam generator a lower head to tube sheet weld;

visual examination of reactor vessel closure head seismic support structure; and

ultrasonic examination of reactor vessel threads in flange.

The inspectors reviewed the following examination records with relevant/recordable conditions/indications identified by the licensee to determine whether acceptance of these indications for continued service was in accordance with the ASME Code Section XI or an NRC-approved alternative:

Report No. 2013-010; Chemical and Volume Control Elbow to Pipe Socket Weld; and

Report No. 2013-011; Chemical and Volume Control Pipe to Elbow Weld.

The inspectors reviewed records of the following pressure boundary welds completed for a risk significant systems since the last Unit 1 refuelling outage to determine if the welding activities and any applicable non-destructive examination performed were completed in accordance with the ASME Code or NRC-approved alternative.

WO 00391697-01; SW-00007 Cut Out and Replace Valve.

b. Findings

No findings were identified.

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

For the Unit 1 reactor pressure vessel upper head, a volumetric (ultrasonic examination)and examination on all upper head penetrations was required this outage pursuant to 10 CFR 50.55a(g)(6)(ii)(D).

The inspectors observed and reviewed records of the volumetric examination conducted on the Unit 1 reactor vessel upper head penetrations to determine whether the activities were conducted in accordance with the requirements of ASME Code Case N-729-1 and 10 CFR 50.55a(g)(6)(ii)(D). In particular, the inspectors confirmed that:

the required examination scope (volumetric and surface coverage) was achieved and limitations (if applicable were recorded) in accordance with the licensee procedures;

the ultrasonic examination equipment and procedures used were demonstrated by blind demonstration testing;

if indications or defects were identified, the licensee documented the conditions in examination reports and/or entered this condition into the corrective action system and implemented appropriate corrective actions; and

if indications were accepted for continued service the licensee evaluation and acceptance criteria were in accordance with the ASME Section XI Code, 10 CFR 50.55a(g)(6)(ii)(D) or an NRC-approved alternative.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control

a. Inspection Scope

On October 4, 2014, the inspectors observed the licensee staff performing visual examinations of the RCS within containment to determine if these examinations focused on locations where boric acid leaks could cause degradation of safety significant components. Additionally, the inspectors conducted an independent Mode 3 containment as-found walkdown focusing on the identification of boric acid residue on plant systems, structures, and components.

The inspectors reviewed the following licensee evaluations of RCS components with boric acid deposits to determine if degraded components were documented in the CAP.

The inspectors also evaluated corrective actions for any degraded RCS components to determine if they met the component Construction Code, ASME Section XI Code, and/or an NRC approved alternative:

Boric Acid Corrosion Control (BACC) Evaluation No. 13-111-E; BACC Evaluation for Boric Acid Leak on Containment Spray Pump Flow Isolation Valve 1SI-860B;

BACC Evaluation No. 14-157-E; BACC Evaluation for Boric Acid Leak on Containment Spray Pump Suction from 2HX-11B RHR HX;

BACC Evaluation No. 14-078-E; BACC Evaluation for Boric Acid Leak on P-15A SI Pump Discharge Vent; and

BACC Evaluation No. 13-073-E; BACC Evaluation for Boric Acid Leak on F-6 Filter Return to Spent Fuel Pool.

The inspectors reviewed the following corrective actions related to evidence of boric acid leakage to determine whether the corrective actions completed were consistent with the requirements of the ASME Code Section XI and 10 CFR Part 50, Appendix B, Criterion XVI:

AR 01846341; Clean Bolt and Perform VT-3 for Boric Acid Packing Leak on SFP Filter Return;

AR 01948376; Boric Acid Leakage Noted on Vent Cap for 2SI-V-29; and

AR 01949894; Active Boric Acid Leak Identified on 2SI-871B.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

No examinations were required during the current refueling outage pursuant to TS requirement for the Steam Generator Program. Therefore, the licensee did not conduct Steam Generator (SG) tube examinations and only a portion of the NRC IP could be completed for this review area. Specifically, from October 6-17, 2014, the inspectors performed an on-site review of documentation related to the SG ISI Program to determine if:

the size of SG tube flaws/degradation predicted by the licensees Operational Assessment would remain within structural integrity limits until the next scheduled tube inspection (e.g., until the end of the next operating cycle);and

primary-to-secondary leakage (e.g., SG tube leakage) was below 3 gallons-per-day or the detection threshold during the previous operating cycle.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI-related problems entered into the licensees CAP and conducted interviews with licensee staff to determine if:

the licensee had established an appropriate threshold for identifying ISI related problems;

the licensee had performed a root cause (if applicable) and taken appropriate corrective actions; and

the licensee had evaluated operating experience and industry generic issues related to ISI and pressure boundary integrity.

The inspectors performed these reviews to evaluate compliance with 10 CFR Part 50, Appendix B, Criterion XVI, Corrective Action, requirements. The corrective action documents reviewed by the inspectors are listed in the Attachment to this report.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

Main article: IP 71111.11

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

Main article: IP 71111.11Q

a. Inspection Scope

On December 8, 2014, the inspectors observed Crew F licensed operators in the plants simulator during licensed operator requalification training to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

licensed operator performance;

crews clarity and formality of communications;

ability to take timely actions in the conservative direction;

prioritization, interpretation, and verification of annunciator alarms;

correct use and implementation of abnormal and emergency procedures;

control board manipulations;

oversight and direction from supervisors; and

ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator requalification program simulator sample as defined in IP 71111.11.

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation During Periods of Heightened Activity or Risk

(71111.11Q)

a. Inspection Scope

On October 20, 2014, the inspectors observed the actions of the Unit 1 licensed operators during the Unit 1 reactor cavity draindown following core reload during U1R35.

This was an activity that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas:

licensed operator performance;

crews clarity and formality of communications;

ability to take timely actions in the conservative direction;

prioritization, interpretation, and verification of annunciator alarms (if applicable);

correct use and implementation of procedures;

control board and equipment manipulations;

oversight and direction from supervisors; and

ability to identify and implement appropriate TS actions.

The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

Main article: IP 71111.12

.1 Routine Quarterly Evaluations

a. Inspection Scope

The inspectors evaluated degraded performance issues involving the following risk-significant systems:

EDG expansion joint leaks;

pressurizer power operated relief valve nitrogen regulator failures; and

SW pump breaker failure.

The inspectors independently verified the licensee's actions to address system performance or condition problems in terms of the following:

implementing appropriate work practices;

identifying and addressing common cause failures;

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

characterizing system reliability issues for performance;

charging unavailability for performance;

trending key parameters for condition monitoring;

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

verifying appropriate performance criteria for structures, systems, and components/functions classified as (a)(2), or appropriate and adequate goals and corrective actions for systems classified as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

This inspection constituted three quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

Main article: IP 71111.13

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

October 1, 2014, Unit 1 IT-530C with A train RHR and safety injection out of service;

October 6, 2014, Unit 2 IT-04, train B with Unit 1 in Mode 5-reduced inventory;

October 6, 2014, SW pump P-32D tripped due to motor failure (emergent);

October 15, 2014, 2 ICP 2.13 with switchyard factor in effect; and

December 17, 2014; fire pump unavailability during the replacement of the fire pump cross-connect isolation valve FP-32.

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

These maintenance risk assessments and emergent work control activities constituted five samples as defined in IP 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

Main article: IP 71111.15

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

FA 2001720; D-501 Battery High Inter-Tier Cable Connection Resistances;

POD 01996698; Failure to Replace EQ O-Rings During Calibration;

POD 01987680; Two Turbine Building Truck Bay Doors Found to be Stronger than Assumed in an Internal Flooding Calculation; and

AR 01983501; Door 019 Needs Repair or Replacement.

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

This operability inspection constituted four samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R18 Plant Modifications

Main article: IP 71111.18

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification(s):

EC 260347; 120V Vital Cable Short Circuit Protection for Units 1 and 2; and

EC 278750; Turbine Driven Auxiliary Feedwater Pump Cross-Tie.

The inspectors reviewed the configuration changes and associated 10 CFR 50.59 safety evaluation screening against the design basis, the FSAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected system(s). The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors discussed the plant modification with operations, engineering, and training personnel to ensure that the individuals were aware of how the operation with the plant modification in place could impact overall plant performance. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two permanent plant modification samples as defined in IP 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

Main article: IP 71111.19

.1 Post-Maintenance Testing

a. Inspection Scope

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

RMP 9216-3 and IT-7D service water pump IST and electrical tests for P-32D following motor replacement;

IT-7B service water pump IST for P-32B following complete pump and motor replacement (EC 272153);

Procedure IT-230, NOP/NOT leak tests of class 1 components following U1R35 (WO 40254160);

OI-62B operability run following quarterly 1P-29 TDAFWP oil sample/change;

Incore flux map verifications for unit 1 core cycle 36;

G-04 EDG operability run following torqueing expansion joint XJ-3344B (WR 94107513); and

Unit 1 TDAFW pump testing after turbine replacement.

These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):

the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the FSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed corrective action documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

This inspection constituted seven post-maintenance testing (PMT) samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R20 Outage Activities

Main article: IP 71111.20

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the Unit 1 Refueling Outage (RFO), U1R35, conducted October 4 to November 1, 2014, to confirm that the licensee had appropriately considered risk, industry experience, and previous site-specific problems in developing and implementing a plan that assured maintenance of defense-in-depth. During the RFO, the inspectors observed portions of the shutdown and cooldown processes and monitored licensee controls over the outage activities listed below:

licensee configuration management, including maintenance of defense-in-depth commensurate with the OSP for key safety functions and compliance with the applicable TS when taking equipment out of service;

implementation of clearance activities and confirmation that tags were properly hung and equipment appropriately configured to safely support the work or testing;

installation and configuration of reactor coolant pressure, level, and temperature instruments to provide accurate indication, accounting for instrument error;

controls over the status and configuration of electrical systems to ensure that TS and OSP requirements were met, and controls over switchyard activities;

monitoring of decay heat removal processes, systems, and components;

controls to ensure that outage work was not impacting the ability of the operators to operate the spent fuel pool cooling system;

reactor water inventory controls including flow paths, configurations, and alternative means for inventory addition, and controls to prevent inventory loss;

controls over activities that could affect reactivity;

licensee fatigue management, as required by 10 CFR 26, Subpart I;

refueling activities, including fuel handling;

startup and ascension to full power operation, tracking of startup prerequisites, walkdown of the containment to verify that debris had not been left which could block emergency core cooling system suction strainers, and reactor physics testing; and

licensee identification and resolution of problems related to RFO activities.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one RFO sample as defined in IP 71111.20-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

Main article: IP 71111.22

.1 Surveillance Testing

a. Inspection Scope

The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:

TS 82; G-02 Emergency Diesel Generator Monthly (Routine);

ORT 3B; Safety Injection Actuation With Loss of Engineered Safeguards AC (Train B) Unit 1 (CIV); and

IT 14 G-02; Fuel Oil Transfer System Pumps and Valves (IST).

The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:

did preconditioning occur;

the effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing;

acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis;

plant equipment calibration was correct, accurate, and properly documented;

as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the FSAR, procedures, and applicable commitments;

measuring and test equipment calibration was current;

test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied;

test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;

test data and results were accurate, complete, within limits, and valid;

test equipment was removed after testing;

where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, ASME code, and reference values were consistent with the system design basis;

where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;

where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure;

where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;

prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;

equipment was returned to a position or status required to support the performance of its safety functions; and

all problems identified during the testing were appropriately documented and dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one routine surveillance testing sample, one inservice testing sample, and one containment isolation valve sample as defined in IP 71111.22, Sections-02 and-05.

b. Findings

No findings were identified.

1EP4 Emergency Action Level and Emergency Plan Changes (IP 71114.04)

a. Inspection Scope

The regional inspectors performed an in-office review of the latest revisions to the Emergency Plan and Emergency Plan Implementing Procedures as listed in the to this report.

The licensee transmitted the Emergency Plan and Emergency Action Level revisions to the NRC pursuant to the requirements of 10 CFR Part 50, Appendix E, Section V, Implementing Procedures. 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 to this report.

This Emergency Action Level and Emergency Plan Change inspection constituted one sample as defined in IP 71114.04-06.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Public Radiation Safety, and Occupational Radiation Safety

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

Main article: IP 71124.03

This inspection constituted one complete sample as defined in IP 71124.03-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed the plant FSAR to identify areas of the plant designed as potential airborne radiation areas and any associated ventilation systems or airborne monitoring instrumentation. Instrumentation review included continuous air monitors and particulate-iodine-noble-gas-type instruments used to identify changing airborne radiological conditions such that actions to prevent an overexposure may be taken. The review included an overview of the respiratory protection program and a description of the types of devices used. The inspectors reviewed FSAR, TSs, and emergency planning documents to identify location and quantity of respiratory protection devices stored for emergency use.

Inspectors reviewed the licensees procedures for maintenance, inspection, and use of respiratory protection equipment including self-contained breathing apparatus as well as procedures for air quality maintenance.

The inspectors reviewed any reported performance indicators (PIs) related to unintended dose resulting from intakes of radioactive material.

b. Findings

No findings were identified.

.2 Engineering Controls (02.02)

a. Inspection Scope

The inspectors reviewed the licensees use of permanent and temporary ventilation to determine whether the licensee uses ventilation systems as part of its engineering controls (in lieu of respiratory protection devices) to control airborne radioactivity. The inspectors reviewed procedural guidance for use of installed plant systems, such as containment purge, spent fuel pool ventilation, and auxiliary building ventilation, and assessed whether the systems are used, to the extent practicable, during high-risk activities (e.g., using containment purge during cavity flood-up).

The inspectors selected installed ventilation systems used to mitigate the potential for airborne radioactivity, and evaluated whether the ventilation airflow capacity, flow path (including the alignment of the suction and discharges), and filter/charcoal unit efficiencies, as appropriate, were consistent with maintaining concentrations of airborne radioactivity in work areas below the concentrations of an airborne area to the extent practicable.

The inspectors selected temporary ventilation system setups (high-efficiency particulate air/charcoal negative pressure units, down draft tables, tents, metal Kelly Buildings, and other enclosures) used to support work in contaminated areas. The inspectors assessed whether the use of these systems is consistent with licensee procedural guidance and as-low-as-reasonably-achievable (ALARA) concept.

The inspectors reviewed airborne monitoring protocols by selecting installed systems used to monitor and warn of changing airborne concentrations in the plant and evaluated whether the alarms and setpoints were sufficient to prompt licensee/worker action to ensure that doses are maintained within the limits of 10 CFR Part 20 and the ALARA concept.

The inspectors assessed whether the licensee had established trigger points (e.g., the Electric Power Research Institutes Alpha Monitoring Guidelines for Operating Nuclear Power Stations) for evaluating levels of airborne beta-emitting (e.g., plutonium-241)and alpha-emitting radionuclides.

b. Findings

No findings were identified.

.3 Use of Respiratory Protection Devices (02.03)

a. Inspection Scope

For those situations where it is impractical to employ engineering controls to minimize airborne radioactivity, the inspectors assessed whether the licensee provided respiratory protective devices such that occupational doses are ALARA. The inspectors selected work activities where respiratory protection devices were used to limit the intake of radioactive materials, and assessed whether the licensee performed an evaluation concluding that further engineering controls were not practical and that the use of respirators is ALARA. The inspectors also evaluated whether the licensee had established means (such as routine bioassay) to determine if the level of protection (protection factor) provided by the respiratory protection devices during use was at least as good as that assumed in the licensees work controls and dose assessment.

The inspectors assessed whether respiratory protection devices used to limit the intake of radioactive materials were certified by the National Institute for Occupational Safety and Health/Mine Safety and Health Administration or have been approved by the NRC per 10 CFR 20.1703(b). The inspectors selected work activities where respiratory protection devices were used. The inspectors evaluated whether the devices were used consistent with their National Institute for Occupational Safety and Health/Mine Safety and Health Administration certification or any conditions of their NRC approval.

The inspectors reviewed records of air testing for supplied-air devices and self-contained breathing apparatus bottles to assess whether the air used in these devices meets or exceeds Grade D quality. The inspectors reviewed plant breathing air supply systems to determine whether they meet the minimum pressure and airflow requirements for the devices in use.

The inspectors selected several individuals qualified to use respiratory protection devices, and assessed whether they have been deemed fit to use the devices by a physician.

Due to limited in-field observations, the inspectors reviewed training curricula for users of respiratory protection device.

The inspectors chose multiple respiratory protection devices staged and ready for use in the plant or stocked for issuance for use. The inspectors assessed the physical condition of the device components (mask or hood, harnesses, air lines, regulators, air bottles, etc.) and reviewed records of routine inspection for each. The inspectors selected several of the devices and reviewed records of maintenance on the vital components (e.g., pressure regulators, inhalation/exhalation valves, hose couplings).

The inspectors reviewed the respirator Vital Components Maintenance Program to ensure that the repairs of vital components were performed by the respirators manufacturer.

b. Findings

No findings were identified.

.4 Self-Contained Breathing Apparatus for Emergency Use (02.04)

a. Inspection Scope

Based on the FSAR, TSs, and emergency operating procedure requirements, the inspectors reviewed the status and surveillance records of self-contained breathing apparatuses staged in-plant for use during emergencies. The inspectors reviewed the licensees capability for refilling and transporting self-contained breathing apparatus air bottles to and from the control room and operations support center during emergency conditions.

The inspectors selected several individuals on control room shift crews and from designated departments currently assigned emergency duties (e.g., onsite search and rescue duties) to assess whether control room operators and other emergency response and radiation protection personnel (assigned in-plant search and rescue duties or as required by emergency operating procedures or the emergency plan) were trained and qualified in the use of self-contained breathing apparatuses (including personal bottle change-out). The inspectors evaluated whether personnel assigned to refill bottles were trained and qualified for that task.

The inspectors determined whether appropriate mask sizes and types are available for use (i.e., in-field mask size and type match what was used in fit-testing). The inspectors determined whether on-shift operators had no facial hair that would interfere with the sealing of the mask to the face and whether vision correction (e.g., glasses inserts or corrected lenses) was available as appropriate.

The inspectors reviewed the past two years of maintenance records for select self-contained breathing apparatus units used to support operator activities during accident conditions and designated as ready for service to assess whether any maintenance or repairs on any self-contained breathing apparatus units vital components were performed by an individual, or individuals, certified by the manufacturer of the device to perform the work. The vital components typically are the pressure-demand air regulator and the low-pressure alarm. The inspectors reviewed the onsite maintenance procedures governing vital component work to determine any inconsistencies with the self-contained breathing apparatus manufacturers recommended practices. For those Self-contained breathing apparatuses designated as ready for service, the inspectors determined whether the required, periodic air cylinder hydrostatic testing was documented and up to date, and the retest air cylinder markings required by the U.S. Department of Transportation were in place.

b. Findings

No findings were identified.

.5 Problem Identification and Resolution (02.05)

a. Inspection Scope

The inspectors 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 CAP. The inspectors 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.

2RS4 Occupational Dose Assessment

Main article: IP 71124.04

This inspection constituted a partial sample as defined in IP 71124.04-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed the results of radiation protection program audits related to internal and external dosimetry (e.g., licensees quality assurance audits, self-assessments, or other independent audits) to gain insights into overall licensee performance in the area of dose assessment and focus the inspection activities consistent with the principle of smart sampling.

The inspectors reviewed the most recent National Voluntary Laboratory Accreditation Program accreditation report on the vendors most recent results to determine the status of the contractors accreditation.

A review was conducted of the licensee procedures associated with dosimetry operations, including issuance/use of external dosimetry (routine, multi-badging, extremity, neutron, etc.), assessment of internal dose (operation of whole body counter, assignment of dose based on derived air concentration-hours, urinalysis, etc.), and evaluation of and dose assessment for radiological incidents (distributed contamination, hot particles, loss of dosimetry, etc.).

The inspectors evaluated whether the licensee had established procedural requirements for determining when external and internal dosimetry is required.

b. Findings

No findings were identified.

.2 External Dosimetry (02.02)

a. Inspection Scope

The inspectors evaluated whether the licensees dosimetry vendor is National Voluntary Laboratory Accreditation Program accredited and if the approved irradiation test categories for each type of personnel dosimeter used are consistent with the types and energies of the radiation present and the way the dosimeter is being used (e.g., to measure deep dose equivalent, shallow dose equivalent, or lens dose equivalent).

The inspectors evaluated the onsite storage of dosimeters before their issuance, during use, and before processing/reading. The inspectors also reviewed the guidance provided to rad-workers with respect to care and storage of dosimeters.

The inspectors assessed whether Non-National Voluntary Laboratory Accreditation Program accredited passive dosimeters (e.g., direct ion storage sight read dosimeters)were used according to licensee procedures that provide for periodic calibration, application of calibration factors, usage, reading (dose assessment) and zeroing.

The inspectors assessed the use of active dosimeters (electronic personal dosimeters)to determine if the licensee uses a correction factor to address the response of the electronic personal dosimeter as compared to the passive dosimeter for situations when the electronic personal dosimeter must be used to assign dose. The inspectors also assessed whether the correction factor is based on sound technical principles.

The inspectors reviewed dosimetry occurrence reports or CAP documents for adverse trends related to electronic personal dosimeters, such as interference from electromagnetic frequency, dropping or bumping, failure to hear alarms, etc. The inspectors assessed whether the licensee had identified any trends and implemented appropriate corrective actions.

b. Findings

No findings were identified.

.3 Internal Dosimetry (02.03)

Special Bioassay (In Vitro)

a. Inspection Scope

The inspectors reviewed and assessed the adequacy of the licensees program for in vitro monitoring (i.e., urinalysis and fecal analysis) of radionuclides (tritium, fission products, and activation products), including collection and storage of samples.

The inspectors reviewed the vendor laboratory quality assurance program and assessed whether the laboratory participated in an industry recognized cross-check program including whether out-of-tolerance results were resolved appropriately.

b. Findings

No findings were identified.

Internal Dose Assessment-Airborne Monitoring

a. Inspection Scope

The inspectors reviewed the licensee's program for airborne radioactivity assessment and dose assessment, as applicable, based on airborne monitoring and calculations of derived air concentration. The inspectors determined whether flow rates and collection times for air sampling equipment were adequate to allow lower limits of detection to be obtained. The inspectors also reviewed the adequacy of procedural guidance to assess internal dose if respiratory protection was used.

b. Findings

No findings were identified.

Internal Dose Assessment-Whole Body Count Analyses

a. Inspection Scope

The inspectors reviewed several dose assessments performed by the licensee using the results of whole body count analyses. The inspectors determined whether affected personnel were properly monitored with calibrated equipment and that internal exposures were assessed consistent with the licensee's procedures.

b. Findings

No findings were identified.

.4 Special Dosimetric Situations (02.04)

Declared Pregnant Workers

a. Inspection Scope

The inspectors assessed whether the licensee informs workers, as appropriate, of the risks of radiation exposure to the embryo/fetus, the regulatory aspects of declaring a pregnancy, and the specific process to be used for (voluntarily) declaring a pregnancy.

The inspectors selected individuals who had declared pregnancy during the current assessment period and evaluated whether the licensees radiological monitoring program (internal and external) for declared pregnant workers is technically adequate to assess the dose to the embryo/fetus. The inspectors reviewed exposure results and monitoring controls employed by the licensee and with respect to the requirements of 10 CFR Part 20.

b. Findings

No findings were identified.

Dosimeter Placement and Assessment of Effective Dose Equivalent for External Exposures

a. Inspection Scope

The inspectors reviewed the licensee's methodology for monitoring external dose in non-uniform radiation fields or where large dose gradients exist. The inspectors evaluated the licensee's criteria for determining when alternate monitoring, such as use of multi-badging, was to be implemented.

No findings were identified.

The inspectors sampled licensee submittals for the Occupational Exposure Control Effectiveness PI for the period from the second quarter 2013 through the second quarter 2014. The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 2013 to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees assessment of the PI for occupational radiation safety to determine if the indicator related data was adequately assessed and reported. To assess the adequacy of the licensees PI data collection and analyses, the inspectors discussed with radiation protection staff the scope and breadth of its data review and the results of those reviews. The inspectors independently reviewed electronic personal dosimetry dose rate and accumulated dose alarms and dose reports and the dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized occurrences. The inspectors also conducted walkdowns of numerous locked high and very-high radiation area entrances to determine the adequacy of the controls in place for these areas. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one occupational exposure control effectiveness sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.6 Radiological Effluent Technical Specification/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the radiological effluent Technical Specification/Offsite Dose Calculation Manual (ODCM) radiological effluent occurrences PI for the period from the first quarter 2013 through the second quarter 2014. The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 2013, to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees issue report database and selected individual reports generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous effluent summary data and the results of associated offsite dose calculations for selected dates to determine if indicator results were accurately reported. The inspectors also reviewed the licensees methods for quantifying gaseous and liquid effluents and determining effluent dose.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one Radiological Effluent Technical Specification/ODCM radiological effluent occurrences sample as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

Main article: IP 71152

.1 Routine Review of Items Entered into the Corrective Action Program

a. Inspection Scope

As part of the various baseline IPs discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.

Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the Attachment to this report.

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in Section 1 of this report.

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

In order to assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, the inspectors performed a screening of items entered into the licensees CAP. This review was accomplished through inspection of the stations daily condition report packages or equivalent.

These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.

b. Findings

No findings were identified.

.3 Semi-Annual Trend Review

a. Inspection Scope

The inspectors performed a review of the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the period of the second quarter of 2014 through the third quarter of 2014, although some examples expanded beyond those dates where the scope of the trend warranted.

The review also included issues documented outside the normal CAP in major equipment problem lists; repetitive and/or rework maintenance lists; departmental problem/challenges lists; system health reports; quality assurance audit/surveillance reports; self-assessment reports; and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy. Documents reviewed are listed in the Attachment to this report.

This review constituted one semi-annual trend inspection sample as defined in IP 71152-05.

Observations As part of their assessment the inspectors reviewed the licensees last two quarterly trend assessments and then performed an independent trend analysis of the licensees corrective action system database. The inspectors noted that the licensee identified a number of statistical trends and ensured that, as required, the corrective actions were in progress. The inspectors identified a trend that the licensee did not identify.

The inspectors requested a sort of the corrective action database for the last 2 years of flooding issues. The inspectors noted that there was one AR in 2012, 29 ARs in 2013, and 334 in 2014 (as of the date of the inspection). Since July 1, 2014, there had been 243 flood related ARs issued by the licensee. This was clearly a trend, yet the trend had not been identified by the licensee during their trend analysis.

A number of the flood related ARs had been written in response to a White finding related to an external flood threat in 2013 and subsequent NRC inspection. But the NRC inspection did not close out the White finding and the licensee performed new assessments, evaluations, and corrective actions. The licensee made a large number of inspections and corrective actions, which resulted in a significant fraction of the flood related ARs. In response to requests from the NRC in Fukushima related generic documents, the licensee performed additional flood related assessments and plant changes. This also resulted in a large number of flood related ARs.

The licensee did not designate the flood related ARs as a trend, even though they met the definition of a trend. The trend should have been brought out as such, and then the licensee should have ensured that further analysis was performed to further assess the trend.

Flood related ARs tied to the White finding and subsequent revisions by the licensee will be assessed as part of the IP 95002 effort currently scheduled for the early part of 2015.

Flood related ARs associated with the Fukushima assessment will be sampled as part of the NRC verification effort related to the Fukushima Near Term Task Force recommendations.

b. Findings

No findings were identified.

.4 Selected Issue Follow-Up Inspection: Never Performed Technical Specification

Surveillance Requirement 3.3.3.2

a. Inspection Scope

During a review of the licensees CAP, the inspectors recognized a corrective action item documenting a concern that TS surveillance requirement (SR) 3.3.3.2 had never been completed for the RCS wide range hot and cold leg resistance temperature detectors (RTDs). The licensees SR 3.3.3.2 required the performance of a channel calibration of post-accident monitoring instrumentation, which included RCS wide range hot and cold leg instrumentation at an 18 month frequency. Per the licensees TS definitions, a channel calibration shall be the adjustment, as necessary, of the channel output such that it responds within the necessary range and accuracy to known values of the parameters that the channel monitors. The channel calibration shall encompass all devices in the channel required for channel operability and that, calibration of instrument channels with resistance temperature detector or thermocouple sensors may consist of an in-place qualitative assessment of sensor behavior and normal calibration of the remaining adjustable devices in the channel.

The licensee determined that there was not an existing procedure that performed a channel calibration of the RCS wide range RTDs; and therefore, SR 3.3.3.2 for the required wide range RCS RTD functions had never been performed. The inspectors performed a review of the licensees corrective action for the affected instrumentation on both units to confirm adequate resolution of this issue. Specifically, the inspectors verified the following attributes during their review of the licensees corrective actions for the affected instrumentation:

complete and accurate identification of the problem in a timely manner commensurate with its safety significance and ease of discovery;

consideration of the extent of condition, generic implications, common cause, and previous occurrences;

evaluation and disposition of operability/reportability issues;

classification and prioritization of the resolution of the problem, commensurate with safety significance;

identification of the apparent and/or contributing causes of the problem; and

identification of corrective actions, which were appropriately focused to correct the problem.

The inspectors determined that the failure to perform SR 3.3.3.2 was a failure to implement a requirement. The inspectors used the examples of IMC 0609, Appendix E, Examples of Minor Issues, dated August 11, 2009, to inform their characterization of this issue and determined that it had no safety impact since a qualitative assessment was performed by the licensee using a review of traces of the RTDs response for several previous years, and no abnormalities were noted.

This review constituted one in-depth problem identification and resolution sample as defined in IP 71152-05.

b. Findings

No findings were identified.

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

Main article: IP 71153

.1 Failure and Inoperability of P-32D Service Water Pump with P-32B Pump

Out-of-Service

a. Inspection Scope

On October 7, 2014, Control Room personnel declared the P-32D SW pump inoperable due to an unexpected pump trip. Initial investigation by the licensee revealed large amounts of carbon at the base of the P-32D motor, and acrid odor in the vicinity of the SW pumps. At the time of the P-32D SW pump trip, unit 1 was in mode 6 for refueling and unit 2 was in mode 1. On October 5, 2014, the P-32B SW pump was removed from service for a planned pump and motor replacement during the unit 1 outage. This resulted in an unplanned TS entry for inoperable SW pumps on unit 2 with a 72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> action statement to restore a SW pump, or be in mode 3. The inspectors monitored operator actions and equipment status from the control room, and performed field observations of the SW pump room. The inspectors also discussed the equipment inoperability, operator performance, and expected actions considering the defueling of unit 1 reactor with operations department management following this event. Documents reviewed are listed in the Attachment to this report.

This event follow-up review constituted one sample as defined in IP 71153-05.

b. Findings

No findings were identified.

.2 Manual Reactor Trip Due to Failure of Condensate Pump 1P-25B

a. Inspection Scope

On December 2, 2014, at approximately 8:36 pm, equipment operators locally observed unusual noise and vibrations at condensate pump 1P-25B. In response to the degradation of the pump, operators entered their abnormal operating procedures and commenced a rapid power reduction. At approximately 8:50, operators locally observed the 1P-25B pump conditions further degrading and smoke coming from the bearings.

The licensee determined that failure of the condensate pump was imminent and manually tripped unit 1 from 62 percent power. All equipment functioned as designed, including the auxiliary feedwater (AFW) system that automatically started on low steam generator water level. The licensees initial investigation revealed that the 1P-25B motor had a phase-to-phase short and that the condensate pump assembly required complete removal for further inspection to be performed at a later time to completely determine the cause of the failure.

A reactor startup was commenced on December 3, 2014, and the main generator was synchronized to the grid on December 4, 2014.

This event was reported by the licensee (event number 50649) in accordance with 10 CFR 50.72(b)(2)(iv)(B), and 10 CFR 50.72(b)(3)(iv)(A) for the manual RPS actuation and the automatic system actuation of the AFW system. Documents reviewed are listed in the Attachment to this report.

This event follow-up review constituted one sample as defined in IP 71153-05.

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On January 15, 2015, the inspectors presented the inspection results to Mr. E. McCartney and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.

.2 Interim Exit Meetings

Interim exits were conducted for:

On October 10, 2014, the results of the in-plant airborne radioactivity control and mitigation, occupational dose assessment, RCS specific activity, occupational exposure control effectiveness, and RETS/ODCM radiological effluent occurrences PI verification were discussed with Mr. E. McCartney.

On October 17, 2014, the results of the inservice inspection were discussed with Mr. E. McCartney.

On December 11, 2014, the annual review of Emergency Action Level and Emergency Plan changes were discussed with Mr. R. Seizert.

The inspectors confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.

4OA7 Licensee-Identified Violations

The following violations of very low significance (Green) were identified by the licensee and are violations of NRC requirements which meet the criteria of the NRC Enforcement Policy for being dispositioned as an NCV.

The licensee identified a NCV of TS 5.4.1, Procedures for the failure to follow the defined heavy load shipping path inside containment as specified in procedure, SLP-1, Safe Load Path and Rigging Manual, which resulted in the movement of the polar crane main block over exposed reactor fuel.

The licensees TS 5.4.1 required, in part, that written procedures shall be implemented covering refueling activities. The licensees refueling procedure governing the movement of the unit 1 containment crane was SLP-1, which described the predefined safe load travel paths and laydown areas in containment during refueling operations that have been pre-analyzed per the FSAR and NUREG-0612. Procedure SLP-1 stated that the main load block of the polar crane was considered a heavy load because it is not single failure proof and weighed approximately 8,550 pounds; and therefore, shall not be moved over the reactor vessel when the head is removed and fuel is in the vessel, with the exception to lift the vessel internals.

Contrary to the above, on October 11, 2014, while unit 1 was in mode 6 with the reactor vessel head removed, the cavity flooded in excess of 23 feet, and irradiated fuel in the reactor vessel during defueling; the licensee moved the main load block of the polar crane over the reactor vessel during the performance of daily crane checks.

The licensee entered this issue into the CAP as AR 01998150 and AR 02020076.

The inspectors determined that this issue was of very low safety significance (Green)after reviewing IMC 0609, Appendix G, Shutdown Operations Significance Determination Process, Attachment 1, dated May 9, 2014. The inspectors answered "No" to all questions in Exhibit 2 for Initiating Events. Therefore the finding screened as Green (very low safety significance).

The licensee identified a NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the failure to incorporate vendor torque specifications into applicable maintenance procedures for all four of the plants EDGs.

On October 25, 2014, during a fast start test of the G-01 EDG, a six-inch expansion joint coupling on the engines jacket water system began leaking upon start, and stopped leaking shortly after the EDG reached rated speed. The licensee found upon initial investigation that the coupling band, which secured the joint assembly together, was less than snug tight. The licensee identified this condition in AR 02002147 and noted that the facilitys maintenance procedures, RMP 9043 series procedures, did not contain a torque value for this and other similar couplings located on EDG components.

On November 7, 2014, during a monthly run of the G-04 EDG, the six-inch engine jacket water coupling began leaking in a similar fashion to that as the above described leak for the G-01 EDG. The licensee identified this condition in AR 02005324 and AR 02005443. These ARs included an attachment, vendor technical information, which specified torque values for the couplings of concern. On November 17, 2014, the licensee initiated AR 02007284 which stated that the licensees system engineering had the vendor information with the torque values since December 2012, but had not initiated changes to the EDG maintenance procedures until the November 7, 2014 condition was discovered.

Title 10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality be prescribed and accomplished by procedures appropriate to the circumstance, and in accordance with those instructions and procedures.

Additionally, instructions and procedures shall include appropriate quantitative or qualitative acceptance criteria for determining that important activities have been satisfactorily accomplished.

Contrary to the above, from December 2012 to November 7, 2014, the licensees RMP 9043 series procedures did not contain final torque values for the flexible fittings used in the EDGs jacket water cooling and oil systems. The licensee entered this issue into the CAP as AR 02007284 and AR 02020080, and initiated procedure changes to incorporate the torque specifications for these fittings. Additionally, the licensee updated future WOs to perform torque checks on these fittings prior to the next EDG maintenance runs. The inspectors determined that this issue was of very low safety significance (Green) after reviewing IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated July 1, 2012 and IMC 0609, Appendix A, The Significance Determination Process For Findings At-Power, dated July 1, 2012. The inspectors answered "NO" to all questions in Exhibit 2, Section A, Mitigating structures systems components (SSCs) and Functionality. Therefore, the finding screened as very low safety significance (Green).

The licensee identified a finding of very low safety significance (Green)and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, which requires, in part, that activities affecting quality shall be accomplished in accordance with instructions, procedures, and drawings.

During the performance of WO 40118062, on breaker B52-DB50-078, the licensee failed to correctly perform the steps in section 5.4.5 of procedure RMP 9303, DB-50 Breaker Routine Maintenance. Procedure RMP 9303 inspected and bent as necessary, the control relay contacts for the breaker to obtain the proper contact alignment. The breaker was subsequently installed and used in the P-32C SW pump breaker cubicle, 1B52-20C, and failed to close on May 29, 2014, during surveillance testing. The licensee concluded that oxide buildup on the control relay contacts had prevented them from making up, which prevented the breaker from closing. The oxide buildup was the result of improper contact alignment, which inhibited the proper wiping action needed to clean the contacts each time they were cycled. The licensee concluded, based on the contact arms being rigid, that the misalignment was present since the new control relay was installed and RMP 9303 performed in July 2012.

Title 10 CFR Part 50, Appendix B, Criterion V, requires, in part, that activities affecting quality shall be accomplished in accordance with instructions, procedures, and drawings. RMP 9303 is the licensees procedure containing instructions for the inspection and adjustment of safety-related control relay contacts, an activity affecting quality.

Contrary to the above, between July 11, 2012 and July 24, 2012, the licensee failed to properly complete RMP 9303 Section 5.4.5, which required the licensee to inspect and adjust contacts to ensure that the contacts had the appropriate gap, contacted in the appropriate sequence, and contacted in the approximate center. The inspectors determined that this issue was more than minor as it impacted the equipment performance attribute of the Mitigation Systems Cornerstone. The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, and Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012. Since the breaker operated successfully on May 7 and failed to operate on May 29, the inspectors answered "Yes" to the mitigating systems screening question number 3, and consulted regional senior risk analysts to perform a detailed risk evaluation. The senior risk analysts performed a detailed risk evaluation for the finding as described below.

Since the time of actual failure of the breaker for the P32C SW pump cannot be determined, a T/2 evaluation provides an exposure time of 11 days (i.e., 22 days from May 7, 2014 to May 29, 2014 divided by 2 or 11 days). The T/2 exposure time is appropriate based on Risk Assessment Standardization Project manual guidance.

The Point Beach Standardized Plant Analysis Risk model version 8.22, Systems Analysis Programs for Hands-on Integrated Reliability Evaluations (SAPHIRE)version 8.1.2 software, and the Support System Initiating Event (SSIE) methodology that is incorporated into the Standardized Plant Analysis Risk model was used to obtain a CDF of 1.29E-7/yr for internal events for the failure-to-start of the P32C SW pump due to the breaker failure. The dominant core damage sequences involve a loss-of-offsite-power (LOOP) with the failure of AFW and the failure of high pressure recirculation.

Since the total estimated change in core damage frequency was greater than 1.0E-7/yr, an evaluation was performed for external event delta risk contributions.

The total CDF was found to be the sum of the CDF contributions from internal events, fire, and seismic or 4.46E-7/yr [i.e., 1.29E-7/yr + 3.21E-7/yr + 8.4E-11/yr

= 4.50E-7/yr].

Large Early Release Frequency Since the total estimated change in core damage frequency was greater than 1.0E-7/yr, IMC 0609 Appendix H, Containment Integrity Significance Determination Process was used to determine the potential risk contribution due to large early release frequency. Each Point Beach Unit is a 2-loop Westinghouse Pressurized Water Reactor with a large dry containment. Sequences important to large early release frequency include steam generator tube rupture events and inter-system loss-of-coolant-accident events. These were not the dominant core damage sequences for this finding.

Based on the Detailed Risk Evaluation, the inspectors determined that the finding was of very low safety-significance (Green). This issue was entered into the CAP as AR 01968602 and AR 02020073.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

E. McCartney, Site Vice President

D. DeBoer, Plant General Manager

S. Aerts, Performance Improvement Manager

R. Clark, Regulatory Assurance

M. Durbin, Maintenance Instrumentation and Controls Department Head

S. Forsha, Program Engineering

R. Harrsch, Site Engineering Director

L. Hawki, Engineering Site Manager - ERRT

W. Jensen, Site NDE Level III

B. Kopetsky, Security Site Manager

D. Lauterbur, Training Site Manager

C. McMillan, Online Manager

M. Millen, Licensing Manager

R. Parker, Chemistry Manager

T. Schneider, Senior Engineer

R. Seizert, Emergency Preparedness Manager

R. Webber, Operations Site Director

R. Welty, Radiation Protection Manager

J. Wilson, Maintenance Director

Nuclear Regulatory Commission

J. Cameron, Chief, Reactor Projects Branch 4

LIST OF ITEMS

OPENED, CLOSED AND DISCUSSED

Opened

05000301/2014005-01 NCV Failure to Promptly Correct a Failed Emergency Diesel Generator Day Tank Room Heater (Section 1R01.1)

Closed

05000301/2014005-01 NCV Failure to Promptly Correct a Failed Emergency Diesel Generator Day Tank Room Heater (Section 1R01.1)

LIST OF DOCUMENTS REVIEWED