IR 05000266/2016001

NRC Integrated Inspection Report 05000266/2016001; 05000301/2016001

ML16124B058
Person / Time
Site:	Point Beach
Issue date:	05/03/2016
From:	Jamnes Cameron NRC Region 4
To:	Mccartney E Point Beach
References
IR 2016001
Download: ML16124B058 (57)

Text

UNITED STATES May 3, 2016

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 - NRC INTEGRATED INSPECTION REPORT 05000266/2016001; 05000301/2016001

Dear Mr. McCartney:

On March 31, 2016, 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 April 1, 2016, with you and other members of your staff.

Based on the results of this inspection, one self-revealed finding of very low safety significance was identified. This finding did not involve a violation of NRC requirements.

If you contest the significance of this finding, 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 copies to:

(1) the Regional Administrator, Region III; (2) the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and (3) the NRC Resident Inspector at the Point Beach Nuclear Plant.

In addition, if you disagree with the cross-cutting aspect assigned to the 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 05000266/2016001; 05000301/2016001

REGION III==

Docket Nos: 50-266; 50-301 License Nos: DPR-24; DPR-27 Report No: 05000266/2016001; 05000301/2016001 Licensee: NextEra Energy Point Beach, LLC Facility: Point Beach Nuclear Plant, Units 1 and 2 Location: Two Rivers, WI Dates: January 1, 2016, through March 31, 2016 Inspectors: D. Oliver, Senior Resident Inspector K. Barclay, Resident Inspector J. Draper, Resident Inspector M. Garza, Emergency Preparedness Inspector J. Rutkowski, Project Engineer V. Myers, Senior Health Physicist T. Bilik, Senior Reactor Inspector L. Alvarado, Inspector-in-Training Approved by: J. Cameron, Chief Branch 4 Division of Reactor Projects Enclosure

SUMMARY

Inspection Report 05000266/2016001; 05000301/2016001; 01/01/2016 - 03/31/2016;

Point Beach Nuclear Plant, Units 1 & 2; Identification and Resolution of Problems.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. One Green finding was self-revealed. This finding did not involve any violations of the U.S. Nuclear Regulatory Commission (NRC) requirements.

The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609,

"Significance Determination Process," dated April 29, 2015. Cross-cutting aspects are determined using IMC 0310, "Aspects Within the Cross-Cutting Areas," dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated February 4, 2015. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," dated February 2014.

Cornerstone: Initiating Events

Green.

A finding of very low safety significance was self-revealed for the licensees failure to follow electrical safety procedures when hanging danger tags on electrical components with exposed conductors. Specifically, danger tags were attached directly to the exposed energized portion of switchgear test switches, which exposed employees to an electrical hazard and contributed to the lockout of the 2X-01 main transformers and the subsequent Unit 2 plant transient. The licensees corrective actions included a change to tagging procedures to include specific direction for tagging knife switches.

The proposed changes included a prohibition for hanging tags on metal parts of the switches, and installing robust operational barriers using tags plus devices when danger tags are to be utilized.

The inspectors determined that the finding was more than minor because it was associated with the human performance attribute of the initiating events cornerstone, and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to use insulated tools on exposed electrical equipment greater than 50 volts presented an electrical injury hazard and actually resulted in a plant transient for Unit 2, which included lifting of a pressurizer power-operated relief valve (PORV), loss of forced reactor coolant system (RCS) flow, and actuation of the auxiliary feedwater (AFW) system. The inspectors determined the finding could be evaluated in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, because Unit 2 was in mode 3 at the time of the event. Additionally,

Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 1,

Initiating Events Screening Questions, dated June 19, 2012 applied. The inspectors concluded that the finding was of very low safety significance (Green), because the inspectors answered No to the Transient Initiators screening question. This finding has a cross-cutting aspect of Resources (H.1), in the area of Human Performance for failing to ensure that personnel, equipment procedures and other resources were available and adequate to support nuclear safety. Specifically, the licensee failed to ensure that employees had all necessary tools, direction, and supervision to support successful work performance. (Section 4OA2.3)

REPORT DETAILS

Summary of Plant Status

Unit 1 The unit operated at or near full power until March 2, 2016, when the unit began coastdown in preparation for the planned refueling outage (RFO) U1R36. The unit was shut down on March 11, 2016, for U1R36 and remained shutdown 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

.1 External Flooding

a. Inspection Scope

The inspectors evaluated the design, material condition, and procedures for coping with the design basis probable maximum precipitation and the facility features for handling that precipitation to prevent flooding or building failures. The evaluation included a review to check for deviations from the descriptions provided in the Final Safety Analysis Report (FSAR) for features intended to mitigate the potential for flooding from external factors. As part of this evaluation, the inspectors checked for obstructions that could prevent draining, checked that the roofs did not contain obvious loose items that could clog drains in the event of heavy precipitation, and determined that features required to mitigate the impacts from precipitation were in place and operable. Additionally, the inspectors performed a walkdown of the protected area to identify any modification to the site which would inhibit site drainage during a probable maximum precipitation event or allow water ingress past a barrier. The inspectors also walked down below-grade areas potentially susceptible to flooding from that contained multiple train or multiple function risk-significant cables. The inspectors also reviewed the abnormal operating procedure (AOP) for mitigating the design basis flood to ensure it could be implemented as written.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one external flooding sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings were identified.

.2 Readiness for Impending Adverse Weather ConditionHeavy Snowfall Conditions with

High Winds

a. Inspection Scope

On March 22, 2016, a winter weather advisory was issued for expected heavy snow with high gusting winds. The inspectors observed the licensees preparations and planning for the significant winter weather potential. The inspectors reviewed licensee procedures and discussed potential compensatory measures with operations and security personnel. The inspectors focused on plant managements actions for implementing the stations procedures for ensuring adequate personnel for safe plant operation and emergency response would be available. The inspectors conducted a site walkdown including walkdowns of various plant structures and systems to check for maintenance or other apparent deficiencies that could affect system operations during the predicted significant weather. The inspectors also reviewed corrective action program (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.

This inspection constituted one readiness for impending adverse weather condition sample as defined in IP 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• 2P-53 motor-driven auxiliary feedwater (AFW) pump after testing;

• G-04 emergency diesel generator (EDG) with G-02 EDG out-of-service (OOS) for maintenance; and

• service water system following IT-70D/E; P-32D/E service water pump quarterly surveillance.

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, Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. 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

.1 Routine Resident Inspector Tours

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 305: 4160V vital switchgear room;

• Fire Zone 308: diesel room G01;

• Fire Zone 309: diesel room G02; and

• Fire Zone 310: air compressor room.

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 OOS, 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 four quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R08 Inservice Inspection Activities

From March 14, 2016, through March 25, 2016, the inspectors conducted a review of the implementation of the licensees Inservice Inspection (ISI) Program for monitoring degradation of the reactor coolant system, steam generator tubes, emergency feedwater systems, risk-significant piping and components, and containment systems.

The inspections described in Sections 1R08.1, 1R08.2, 1R08.3, 1R08.4 and 1R08.5 below constituted one inservice inspection sample as defined in IP 71111.08.

.1 Piping Systems ISI

a. Inspection Scope

The inspectors either observed or reviewed the following non-destructive examinations mandated by the American Society for 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 U.S. Nuclear Regulatory Commission (NRC)-approved alternative requirement:

• Ultrasonic (UT) examination of feedwater pipe-to-expander weld FW-16-FW-1002-17;

• UT of 3 tee-to-pipe weld, RC-03-PSF-1002-03;

• UT of 3 pipe-to-elbow weld, RC-03-PSF-1002-04;

• UT of 3 elbow-to-pipe weld, RC-03-PSF-1002-05;

• UT of upper head to upper shell weld, PZR-Cweld-1;

• UT of upper shell vertical weld (AZ 255), PZR-Vweld-1;

• Dye Penetrant (PT) examination of coupling-to-pipe weld, CH-2501R-6, weld W5;

• PT of pipe-to-elbow welds, CH-2501R-6, welds W3, 4;

• Magnetic particle (MT) examination of feedwater nozzle-to-shell weld, SG-B-6;

• MT of shell-to-main steam nozzle weld, SG-B-7;

• Visual examination (VT-3) of reactor coolant spring hanger RC-2501R-2-RC14;

• VT-1 of reactor pressure vessel (RPV) closure head washers, 33-48; and

• VT-1 of RPV closure head nuts, 33-48.

The inspectors reviewed the following examinations completed during the previous outage with relevant/recordable conditions/indications accepted for continued service to determine if acceptance was in accordance with the ASME Code, Section XI or an NRC-approved alternative:

• VT-1, welded attachment service water (SW) supply header on 46 FT U1 CTMT, (WO 40254351);

• VT-3, U1 spring hanger on RCS surge line, (IDR 2014-039);

• VT-3, spring hanger, (IDR 2014-041);

• MT/PT, piping near 1FE-4037; (WO 40419947); and

• PT, turbine-driven auxiliary feedwater (TDAFW) pump (spare), (IDR 2015-019).

The inspectors either observed or reviewed the following pressure boundary welds completed for risk-significant systems since the beginning of the last refueling outage to determine if the licensee applied the preservice non-destructive examinations and acceptance criteria required by the Construction Code and ASME Code, Section XI.

Additionally, the inspectors reviewed the welding procedure specification and supporting weld procedure qualification records to determine if the weld procedures were qualified in accordance with the requirements of Construction Code and the ASME Code, Section IX:

• WO 40223237; TDAFW cross-tie, tie-in AFW piping;

• WO 40098756; IP-029-T replace turbines, governors, and correct issue;

• WO 40311384; 1LT-00972/Install EC 281572 to increase sensing line size; and

• WO 40454445; 1CV-200B, 2 socket welds 3-5.

b. Findings

No findings were identified.

.2 Reactor Pressure Vessel Upper Head Penetration Inspection Activities

a. Inspection Scope

No exams were required this outage. Therefore, no NRC review was completed for this inspection procedure attribute.

The licensee did not perform any welded repairs to vessel head penetrations since the beginning of the preceding outage. Therefore, no NRC review was completed for this inspection procedure attribute.

b. Findings

No findings were identified.

.3 Boric Acid Corrosion Control

a. Inspection Scope

The inspectors performed an independent walkdown of the reactor coolant system and related lines in the containment, which had received a recent licensee boric acid walkdown and verified whether the licensees boric acid corrosion control visual examinations emphasized locations where boric acid leaks can cause degradation of safety-significant components.

The inspectors reviewed the following licensee evaluations of reactor coolant system components with boric acid deposits to determine if degraded components were documented in the CAP. The inspectors also evaluated corrective actions for any degraded reactor coolant system components to determine if they met the ASME Section XI Code:

• 1HX-011B, Boric Acid at Bolted Connection;

• 1RH-720, Boric Acid at Bolted Connection;

• 1FE-661, Boric Acid at Bolted Connection;

• 1P-14A/B, Boric Acid at Bolted Connection; and

• 1SC-966B, Boric Acid at Bolted Connection.

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

• AR 01995570; Active Boric Acid Leakage on 1SI-888B;

• AR 01995709; Valves in IT-540C with Boric Acid Build-Up on Packing; and

• AR 02015711; Walkdown BA Indication.

b. Findings

No findings were identified.

.4 Steam Generator Tube Inspection Activities

a. Inspection Scope

The NRC inspectors observed acquisition of eddy current (ET) data, interviewed ET data analysts, and reviewed documentation related to the steam generator (SG) ISI program to determine if:

• In-situ SG tube pressure testing screening criteria used were consistent with those identified in the Electric Power Research Institute (EPRI) TR-1025132, Steam Generator In-Situ Pressure Test Guidelines and that these criteria were properly applied to screen degraded SG tubes for in-situ pressure testing;

• the numbers and sizes of SG tube flaws/degradation identified was bound by the licensees previous outage Operational Assessment predictions;

• the SG tube ET examination scope and expansion criteria were sufficient to meet the TS, and the EPRI 1013706, Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7;

• the SG tube ET examination scope included potential areas of tube degradation identified in prior outage SG tube inspections and/or as identified in NRC generic industry operating experience applicable to these SG tubes;

• the licensee identified new tube degradation mechanisms and implemented adequate extent of condition inspection scope and repairs for the new tube degradation mechanism;

• the licensee implemented repair methods which were consistent with the repair processes allowed in the plant TS requirements and to determine if qualified depth sizing methods were applied to degraded tubes accepted for continued service;

• the licensee implemented an inappropriate plug on detection tube repair threshold (e.g., no attempt at sizing of flaws to confirm tube integrity);

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

• the ET probes and equipment configurations used to acquire data from the SG tubes were qualified to detect the known/expected types of SG tube degradation in accordance with Appendix H, Performance Demonstration for Eddy Current Examination of EPRI 1013706, Pressurized Water Reactor Steam Generator Examination Guidelines, Revision 7; and

• the licensee performed secondary side SG inspections for location and removal of foreign materials.

The licensee did not perform in-situ pressure testing of SG tubes. Therefore, no NRC review was completed for this inspection attribute.

b. Findings

No findings were identified.

.5 Identification and Resolution of Problems

a. Inspection Scope

The inspectors performed a review of ISI/SG 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/SG 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 Title 10 of the Code of Federal Regulations (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

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On February 11, 2016, the inspectors observed crew B licensed operators in the plants simulator during licensed operator requalification training. The inspectors verified that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and that 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 71111.11-05.

b. Findings

No findings were identified.

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

(71111.11Q)

a. Inspection Scope

On March 11, 2016, the inspectors observed the Unit 1 reactor shutdown for RFO U1R36. 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;

• correct use and implementation of 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 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 71111.11-05.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• chemical and volume control system (CVCS) using a problem-oriented approach; and

• review of the licensees 10 CFR 50.65(a)(3) periodic evaluation.

The inspectors reviewed events such as where ineffective equipment maintenance had or could have resulted in valid or invalid automatic actuations of engineered safeguards systems and 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 (SSCs)/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 two 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

.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:

• January 19, 2016: 1P-14A containment spray pump, switchyard line Q-303, P-23B service water pump, and 1DY-03 white channel instrument bus inverter OOS;

• March 1, 2016: D-108 battery charger, 1P-2C charging pump, and 1P-10B residual heat removal (RHR) pump OOS with switchyard maintenance in progress;

• March 14, 2016: Unit 1 drain down with switchyard maintenance and abnormal electrical alignments; and

• March 16, 2016: Unit 1 in lowered inventory with maintenance in-progress.

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 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 four samples as defined in IP 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• POD 02103921: 1DY-03 overloaded alarms; and

• POD 02112145: W-46A Ventilation Support Contacting SW Piping.

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 two samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

.2 Annual Sample: Review of Operator Workarounds

a. Inspection Scope

The inspectors evaluated the licensees implementation of their process used to identify, document, track, and resolve operational challenges. Inspection activities included, but were not limited to, a review of the cumulative effects of operator workarounds (OWAs)on system availability and the potential for improper operation of the system, for potential impacts on multiple systems, and on the ability of operators to respond to plant transients or accidents.

The inspectors performed a review of the cumulative effects of OWAs. The documents listed in the Attachment were reviewed to accomplish the objectives of the inspection procedure. The inspectors reviewed both current and historical operational challenge records to determine whether the licensee was identifying operator challenges at an appropriate threshold, had entered them into their CAP and proposed or implemented appropriate and timely corrective actions which addressed each issue. Reviews were conducted to determine if any operator challenge could increase the possibility of an Initiating Event, if the challenge was contrary to training, required a change from long-standing operational practices, or created the potential for inappropriate compensatory actions. Additionally, all temporary modifications were reviewed to identify any potential effect on the functionality of Mitigating Systems, impaired access to equipment, or required equipment uses for which the equipment was not designed.

Daily plant and equipment status logs, degraded instrument logs, and operator aids or tools being used to compensate for material deficiencies were also assessed to identify any potential sources of unidentified operator workarounds.

This review constituted one operator workaround annual inspection sample as defined in IP 7111502.

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification(s):

• EC 272841: Unit 1 Charging Pump Low Net Positive Suction Head Trip; and

• EC 279310: NFPA 805 Modification For Conduit D04-7 Fire Wrap.

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. 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

.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:

• 1P-2A charging pump testing after maintenance;

• 2P-10A RHR pump testing after oil change and circuit breaker replacement;

• degraded voltage relay 2-274/A05 testing after replacement; and

• WL-1723/1728 unit 1 sump A drain containment isolation valve testing after solenoid replacement.

These activities were selected based upon the structure, system, or components (SSCs) 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, and licensee procedures, 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 four post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R20 Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

The inspectors reviewed the Outage Safety Plan (OSP) and contingency plans for the Unit 1 RFO, which began March 12, 2016, 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;

• 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;

• maintenance of secondary containment as required by TS;

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

• refueling activities, including fuel handling and sipping to detect fuel assembly leakage; 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 partial RFO sample as defined in IP 71111.20-05.

The remaining portions of RFO inspection will be completed in the second quarter.

b. Findings

No findings were identified.

1R22 Surveillance Testing

.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:

• Degraded Voltage Surveillance (routine);

• Unit 2 Reactor Protection System Logic Train B Surveillance Test (routine);

• IT 80: Main Steam Valves (Quarterly) Unit 1 (in-service testing); and

• ORT 42: local leak rate testing of RMUW to Unit 1 Containment (isolation valve).

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, American Society of Mechanical Engineers 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 two routine surveillance testing samples, one in-service test sample, and one containment isolation valve sample as defined in IP 71111.22, Sections-02 and-05.

b. Findings

No findings were identified.

1EP5 Maintenance of Emergency Preparedness

.1 Maintenance of Emergency Preparedness

a. Inspection Scope

The inspectors reviewed AR 02098401, Potentially Missed Event Classification, in order to evaluate the licensees efforts to identify, evaluate, and resolve an issue identified by the sites Nuclear Oversight group. The inspectors evaluated the licensees actions and plant indications to determine if conditions warranted an event classification of HA2, Fire or Explosion Affecting the Operability of Plant Systems Required to Establish or Maintain Safe Shutdown, when the 2P-11B component cooling water pump failed on December 17, 2015. Documents reviewed are listed in the Attachment to this report.

The review of the licensees evaluation counted as a partial sample. The entire sample of this inspection will be completed by the end of calendar year 2016.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on February 23, 2016, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities.

The inspectors observed emergency response operations in the Control Room Simulator, Technical Support Center, and Emergency Operations Facility, to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the CAP. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report.

This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-06.

b. Findings

No findings were identified.

.2 Training Observation

a. Inspection Scope

The inspector observed a simulator training evolution for licensed operators on February 4, 2016, which required emergency plan implementation by a licensee operations crew. This evolution was planned to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew.

The inspectors also attended the post-evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that the licensee evaluators noted the same issues and entered them into the CAP. As part of the inspection, the inspectors reviewed the scenario package and other documents listed in the Attachment to this report.

This inspection of the licensees training evolution with emergency preparedness drill aspects constituted one sample as defined in IP 71114.06-06.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

2RS1 Radiological Hazard Assessment and Exposure Controls

.1 Radiological Hazard Assessment (02.02)

a. Inspection Scope

The inspectors assessed whether changes to the stations radiological profile due to operating protocols, primary chemistry changes, and plant modifications were adequately addressed in the licensees radiation protection survey program. The inspectors conducted walk-downs of various locations and reviewed surveys to evaluate radiological conditions.

These inspection activities constituted one sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

.2 Instructions to Workers (02.03)

a. Inspection Scope

The inspectors assessed whether workers were adequately informed of radiological hazards present through radiation work permits, alarming dosimeter set points, area postings, and labelling of containers.

These inspection activities constituted one sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

.3 Contamination and Radioactive Material Control (02.04)

a. Inspection Scope

The inspectors determined whether workers and materials were adequately assessed for radioactive contamination before leaving the radiologically controlled area(s). Additionally, the inspectors assessed whether sealed sources were adequately identified, stored, and did not leak.

These inspection activities constituted one sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

.4 Radiological Hazards Control and Work Coverage (02.05)

a. Inspection Scope

The inspectors observed work in progress and reviewed processes to ensure adequate implementation of:

• Radiological controls;

• Radiation protection job coverage;

• Dosimeter selection and placement;

• Airborne radioactive materials monitoring and controls; and

• Controls for highly activated materials stored in the spent fuel pool.

These inspection activities constituted one sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

.5 High-Radiation Area and Very-High Radiation Area Controls (02.06)

a. Inspection Scope

The inspectors observed the physical controls for high-radiation areas and very-high radiation areas. The inspectors ensured the controls prevented an individual from gaining unauthorized access to very-high radiation areas.

These inspection activities constituted one sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

.6 Radiation Worker Performance and Radiation Protection Technician Proficiency (02.07)

a. Inspection Scope

The inspectors observed radiation workers and radiation protection technicians to assess whether they were aware the radiological conditions in their workplace and whether their performance reflected the radiological hazards that were present.

These inspection activities constituted one sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

.7 Identification and Resolution of Problems (02.08)

a. Inspection Scope

The inspectors assessed whether problems associated with radiation surveys, radiological controls, and exposure control are being identified by the licensee at an appropriate threshold and are properly addressed for resolution. For selected issues, the inspectors assessed the appropriateness of the corrective actions. Additionally, the inspectors reviewed events that were caused by radiation worker error or radiation protection technician error to assess whether the corrective action approach taken by the licensee was adequate to resolve the reported problems.

These inspection activities constituted one sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

2RS2 Occupational As-Low-As-Reasonably-Achievable Planning and Controls

.1 Implementation of As-Low-As-Reasonably-Achievable and Radiological Work

Controls (02.04)

a. Inspection Scope

The inspectors observed in-plant work to assess whether the planned radiological administrative, operational, and engineering controls were discussed during pre-job briefs and implemented as intended. The inspectors assessed whether methods for tracking work in progress ensured prompt communications and actions to reduce dose. The inspectors reviewed emergent work activities to assess whether this work received an appropriate level of review from station management, as-low-as-reasonably-achievable (ALARA) staff, and the affected work group(s).

These inspection activities constituted one sample as defined in IP 71124.02-05.

b. Findings

No findings were identified.

.2 Radiation Worker Performance (02.05)

a. Inspection Scope

The inspectors observed radiation worker and radiation protection technician performance during work activities being performed in radiation areas, airborne radioactivity areas, or high-radiation areas to assess the ALARA philosophy as applied and whether the skill level displayed was sufficient with respect to the radiological hazards that were present. The inspectors interviewed individuals to assess their knowledge and awareness of planned and/or implemented radiological and ALARA work controls.

These inspection activities constituted one sample as defined in IP 71124.02-05.

b. Findings

No findings were identified.

2RS3 In-Plant Airborne Radioactivity Control and Mitigation

.1 Engineering Controls (02.02)

a. Inspection Scope

The inspectors assessed the licensees use of ventilation systems as engineering controls to reduce the amount of airborne radioactivity to the extent practicable.

The inspectors also assessed whether airborne monitoring protocols included adequate alarm setpoints as well as provisions for alpha monitoring.

These inspection activities constituted one sample as defined in IP 71124.03-05.

b. Findings

No findings were identified.

2RS4 Occupational Dose Assessment

.1 Source Term Characterization (02.02)

a. Inspection Scope

The inspectors assessed whether the radiation types and energies being monitored have been adequately characterized and have developed scaling factors to quantify difficult to detect radionuclides, include alpha emitters for internal dose assessments.

These inspection activities constituted one sample as defined in IP 71124.04-05.

b. Findings

No findings were identified.

.2 External Dosimetry (02.03)

a. Inspection Scope

The inspectors reviewed the parameters used to routinely monitor individuals, including setup, storage, and use of passive and active dosimeters to assess the ability to adequately determine the dose received by workers.

These inspection activities constituted one sample as defined in IP 71124.04-05.

b. Findings

No findings were identified.

4. OTHER ACTIVITES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Security

4OA1 Performance Indicator Verification

.1 Unplanned Scrams per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams per 7000 Critical Hours performance indicator (PI) (IE01) for Point Beach Nuclear Plant, Units 1 and 2, for the first quarter through the fourth quarter of 2015. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, was used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC integrated inspection reports (IRs) during this time period to validate the accuracy of the submittals.

The inspectors also reviewed the licensees CAP database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two unplanned scrams per 7000 critical hours samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Unplanned Scrams with Complications

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Scrams with Complications PI (IE04) for Point Beach Nuclear Plant, Units 1 and 2, for the first quarter through the fourth quarter of 2015. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, was used. The inspectors reviewed the licensees operator narrative logs, issue reports, event reports, and NRC Integrated IRs during this time period to validate the accuracy of the submittals. The inspectors also reviewed the licensees CAP database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two unplanned scrams with complications samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.3 Unplanned Transients per 7000 Critical Hours

a. Inspection Scope

The inspectors sampled licensee submittals for the Unplanned Transients per 7000 Critical Hours PI (IE03) for Point Beach Nuclear Plant, Units 1 and 2, for the first quarter through the fourth quarter of 2015. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, was used. The inspectors reviewed the licensees operator narrative logs, CAP reports, maintenance rule records, event reports, and NRC Integrated IRs during this time period to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two unplanned transients per 7000 critical hours samples as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

a. Inspection Scope

As part of the various baseline inspection procedures 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 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 Annual Follow-up of Selected Issues: 2X-01 Main Transformer Lockout in Mode 3

a. Inspection Scope

During a review of Licensee Event Report (LER) 05000301/2015-005-00/01; Main Transformer Lockout and Associated Loss of Busses Results in System Actuation, the inspectors determined that a detailed review of the corrective actions resulting from the licensees root cause evaluation was necessary. A description of this event, which was characterized by the licensee as a significant condition adverse to quality, is documented in section 4OA3 of this report.

The inspectors verified the following attributes during their review of the licensees corrective actions for the event:

• complete accurate and timely documentation of the identified problem in the CAP;

• evaluation and time disposition of operability and reportability issues;

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

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

• identification of root and contributing causes of the problem;

• identification of corrective actions that are appropriately focused to address the root and contributing causes;

• actions taken in the correction of the identified problems;

• identification of negative or worsening trends associated with equipment performance either directly or indirectly caused by the event; and

• operating experience was adequately evaluated for applicably, and lessons learned were to be communicated to the appropriate organizations for implementation.

b. Observations:

The inspectors review of the licensees root cause evaluation (RCE), corrective actions, control room logs, and transient assessment documentation revealed that the licensee identified a single root cause and two main contributing causes. The licensee determined that the transformer lockout occurred during the task of clearing danger tags for the Unit 2 main transformer, 2X-01. During this activity, the licensee induced a short-circuit between two adjacent open knife switches when a conductive cutting tool was used to cut tie wraps that affixed danger tags directly to the knife portion of the switches. This caused the 2X-01 transformer to trip and lockout, resulting in the loss of power to non-vital 4kV busses and a subsequent plant transient.

(1) Complete, accurate, and timely documentation:

During the course of this review, the inspectors determined that the licensee did not implement procedures for equipment quarantine and for the plant transient review immediately following the event. As a result, the inspectors observed that useful relevant information was not preserved that was pertinent to the RCE, but ultimately did not affect the corrective actions resulting from the RCE. Both the RCE and the licensees LER describe the event in a manner that lead the reader to conclude that the operating crew encountered little or no difficulty in the course of the event. While the inspectors acknowledge that the operating crew was able to effectively work as a team and utilize their training and knowledge in an uncertain condition, the direction provided by the licensees procedure, AOP-18; Electrical System Malfunction, focused solely on the restoration of the lost electrical busses and provided no direction for the effects of the lost busses. Consequently, prioritization and specific information was not provided in a readily evident way to give direction for securing the AFW system, establishing and monitoring natural circulation RCS decay heat removal, or for managing RCS inventory.

Concerns with the procedural direction that were raised by the operating crew were in the form of a routine work task after the fact and independent of the root cause analysis team, rather than as an Action Request (AR), and not through the established programmatic transient review process. This prevented the deficiencies from being brought to the light of the licensees management until concerns were raised by the inspectors.

Root cause evaluation, extent considerations, and resulting actions: The licensee concluded that the root cause of the event was that Revision 7 of procedure 2-SOP-19KV- 001 removed the use of detailed temporary information tags for configuration control of knife switches for the 2X-01 transformer lockout circuit in favor of danger tags. The licensee determined that the use of danger tags was inappropriate because personnel protection was not factor in the application of these particular tags.

When using danger tags, the licensees procedure OP-AA-101-1000; Clearance and Tagging, required operators to apply additional measures called tags plus, which provides an additional barrier of personal protection. The licensees RCE stated that the task of removing the combination of danger tags and tags plus measures created an unnecessary and difficult situation that ultimately led to the event. As a result, one of the corrective actions to prevent recurrence (CAPR) to address the root cause was to specify the use of caution tags when required by 2-SOP-19KV-001, as well as for 1-SOP-19KV-001. Inspectors determined that the licensees decision to use caution tags rather than returning to the use of temporary information tags (which could be taped to panels near the knife switches) was due to temporary information tags being considered a weak configuration control barrier. Inspectors performed a detailed review of 2-SOP-19KV-001, and determined that the type of tags to be hung on the knife switches was actually not specified. The use of danger tags and caution tags are controlled under OP-AA-101-1000, which does not differentiate between the types of tags with respect to how they are physically hung. The inspectors confirmed, based upon interviews of operators qualified to apply these tags, that regardless of tag type prior to this event, tags would have been attached directly to the knife portion of the switch, and would have applied additional measures in the form of tags plus regardless of the tag type.

Additionally, the inspectors determined that the knife switches described above were located on various electrical switchgear components throughout the plant and on the back of the main control boards. Prior to this event, OP-AA-101-1000, the licensees procedure for hanging information, caution, and danger tags, failed to provide any specific direction on how to tags and apply the tags plus methodology to these knife switches. The inspectors concluded that failure to provide this direction did not meet nuclear and electrical utility industry standards and contributed to the finding documented below as well as unknowingly exposed employees to the potential for injury from electrical hazards.

The licensee determined that the lack of guidance in OP-AA-101-1000, a NextEra fleet procedure, was a contributing cause for the event. As a result, the licensee created an action to change the fleet procedure to include specific direction for this activity. The inspectors concluded that the CAPR created to address the root cause by itself would not have prevented recurrence because it created a reliance on a procedure determined by the licensee as flawed and was determined to be a contributing cause of the event.

Inspectors reviewed the licensees root cause analysis procedure PI-AA-100-1005, and determined that the lack of guidance contained in OP-AA-101-1000 should have been considered a second root cause or that a second CAPR was needed to address tagging procedures.

The licensees RCE stressed that the brief for the final danger tag removal was not adequate because the site specific tagging pre-job brief was not utilized, and among other things, electrical hazards were not discussed. The inspectors noted that the RCE did not discuss the pre-job brief and supervision for the initial tag hang. The inspectors determined that, based on the evidence provided in the RCE, this failed barrier was more pertinent because it was instrumental in setting up the conditions for the event.

(2) Operating experience, lessons learned, and industry practices:

The inspectors research into Point Beachs internal operating experience also revealed that tagging issues in the 2009 timeframe were partially attributed to a multitude of procedures that were in existence to accomplish tagging components. At some point since then, a decision was made to create a single fleet standard procedure under OP-AA-101-1000 that was applicable to all sites. Despite several revisions since its inception, OP-AA-101-1000 contains a collection of site specific attachments with general tagging information that is not unique and could be part of the main procedure.

For example, the Point Beach site specific attachment has specific direction for hanging tags on panel, field, and instrument fuses. Inspectors confirmed that Point Beachs physical design does not differ from the other plants in the NextEra fleet with respect to much of the site specific information. Similarly, the inspectors confirmed that other sites in the licensees fleet have knife switches in a similar configuration as Point Beach, but no specific direction on how to hang tags on knife switches was able to be historically found.

The inspectors determined from reviewing both industry and site-specific operating experience that, generally, test switches are not considered an appropriate energy isolation boundary to establish a zone of protection for danger tagging. Accordingly, inspectors were unable to find substantial industry guidance for danger tagging these components. The inspectors concluded from this review that the lack of direction contained in OP-AA-101-1000 regarding knife switches was likely due to the aforementioned considerations.

Inspectors also noted that OP-AA-101-1000, with limited specific exceptions, failed to address the inherent risks involved with physical tag hang and clear activities, including reference to electrical safety precautions.

As a final observation, the inspectors communicated to the licensees management their concerns with the practices and culture that have created an assumption of safety among workers, rather than challenging assumptions.

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

c. Findings

(1) Failure to Follow Electrical Safety Procedures Results in Plant Transient

Introduction:

A finding of very low safety significance (Green) was self-revealed for the licensees failure to follow electrical safety procedures when hanging danger tags on electrical components with exposed conductors. Specifically, danger tags were attached directly to the exposed energized portion of switchgear test switches, which exposed employees to an electrical hazard and contributed to the lockout of the 2X-01 main transformers and the subsequent Unit 2 plant transient.

Description:

On October 3, 2015, the licensee hung danger tags on switchgear knife switches on the back of the main control boards for routine outage work on the 2X-01 main transformer. These knife switches isolated 125 VDC from a multifunction relay, which included 2X-01 main transformer trip and lockout logic. This work was sequenced using the licensees procedure 2-SOP-19KV-001, and the danger tags were attached directly to the exposed metal knife portion of the switch, using plastic cable ties. The licensees procedure, OP-AA-101-1000; Clearance and Tagging, required the use of tags plus when danger tagging components. Tags plus was defined by the licensee as the practice that provides for the additional means to be considered as part of the demonstration of full employee protection and includes the implementation of additional safety measures such as the removal of an isolating circuit element, blocking of a controlling switch, opening of an extra disconnecting device, or the removal of a valve handle to reduce the likelihood of an inadvertent energizing. The use of cable ties was a typical practice for operators applying tags plus in conjunction with danger tagging components. In the case of the knife switches above, an additional cable tie was attached to each knife switch as a tags plus device, independent of the cable tie already affixing the danger tag. This created the need for a second action besides removing the tag itself to allow the knife switch to be closed.

According to the licensees RCE 02086949, licensee personnel applied the danger tags and tags plus cable ties without knowledge of the operating voltages present (125 VDC),and under the assumption that the energy source, once the switch was open, was only on the fixed portion of the switch, and not on the metal knife switch.

On October 20, 2015, the licensee performed a temporary lift of the danger tags on the knife switches without incident, and on October 24, 2015, danger tags were re-hung with tags plus as in the same configuration described for the October 3, 2015, hang activity.

On October 29, 2015, at approximately 2:48 AM, the licensee conducted a pre-job brief for the work to be performed for 2-SOP-19KV-001, which included the clearing of the danger tags from the 2X-01 knife switches. According to the licensees RCE, this pre-job brief did not include discussion of electrical safety requirements, location of energy sources and did not include a tagging specific pre-job discussion, required by OP-AA-101-1000. As described by the licensees RCE, the licensees personnel were successful in removing the first danger tag and additional cable tie from one knife switch using a pair of metal side cutters. The licensee described that this removal was difficult due to positioning and tightness of the cable ties. Because of the difficulty encountered during the removal of the first tag, the licensee decided to remove the danger tag from the second knife switch, while leaving the first knife switch open, believing that an equipment actuation would not be possible with one switch open. During an attempt to cut the cable tie from the second knife switch, the metal side cutters contacted both open energized knife switches and created a short, causing the 2X-01 trip and lockout circuitry to actuate.

The inspectors determined that the licensees procedure FP-MA-ES-01; Electrical Safety, applied to work involving voltages of 50 volts or greater, and prescribed specific requirements for work on exposed and energized equipment including the level of supervision required, qualifications of personnel, requirements for the use of insulated tools, personal protective equipment and other pertinent and specific information that was applicable to the above described work. The inspectors concluded that the appropriate electrical safety precautions and instructions described in FP-MA-ES-01, which are standard for the industry where electrical hazards are present and are in place for employee protection, were not utilized.

Analysis:

The inspectors determined that the licensees failure to take appropriate electrical safety precautions when hanging danger tags on exposed energized equipment was contrary to the licensees procedure FP-MA-ES-01; Electrical Safety, and was a performance deficiency. The finding was determined to be more than minor because it was associated with the human performance attribute of the initiating events cornerstone, and adversely affected the cornerstone objective of limiting the likelihood of events that upset plant stability and challenge critical safety functions during shutdown as well as power operations. Specifically, the failure to use insulated tools on exposed electrical equipment greater than 50 volts presented an electrical injury hazard and actually resulted in a plant transient for Unit 2 that included lifting of a pressurizer PORV, loss of forced RCS flow, and actuation of the AFW system.

The inspectors determined the finding could be evaluated using IMC 0609, Significance Determination Process, Attachment 0609.04, Initial Characterization of Findings, dated June 19, 2012, because Unit 2 was in mode 3 at the time of the event.

Additionally, Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 1, Initiating Events Screening Questions, dated June 19, 2012, was applicable. The inspectors concluded that the finding was of very low safety significance (Green), because the inspectors answered No to the transient initiators screening question.

This finding has a cross-cutting aspect of Resources (H.1), in the area of Human Performance for failing to ensure that personnel, equipment procedures and other resources are available and adequate to support nuclear safety. Specifically, the licensee failed ensure that employees had all necessary tools, direction, and supervision to support successful work performance.

Enforcement:

This finding does not involve enforcement action because no violation of a regulatory requirement was identified. As corrective actions, the licensee created procedure changes for procedure OP-AA-101-1000, to include specific direction for tagging knife switches. The proposed changes included a prohibition for hanging tags on metal parts of the switches, and installing robust operational barriers as tags plus devices when danger tags are to be utilized. Because this finding does not involve a violation and is of very low safety significance, it is identified as a finding.

(FIN 05000301/2016001-01, Failure to Follow Electrical Safety Procedures Results in Plant Transient).

.4 Annual Follow-up of Selected Issues: Records Management and Implementation of

Electronic Work Packages

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors selected numerous corrective action items concerning the implementation of the licenses Electronic Work Package (EWP) program. Specifically, the licensees CAP documented errors in the archiving and transfer of information from the online electronic storage to the offline permanent databases.

The inspectors performed a detailed review of the licensees corrective actions for this and related issues regarding handling and retention of quality assurance (QA) records.

Specifically, the inspectors verified the following attributes during their review of the licensees corrective actions:

• complete, accurate and timely documentation of the identified problem in the CAP;

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

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

• action taken in the correction of the identified problem.

Observations: The inspectors conducted a historical review of the condition and sampled safety-related QA records for both Unit 1 and 2 completed surveillance and maintenance activities to evaluate the licensees corrective actions respective to the attributes listed above. Inspectors determined that the condition had existed since the implementation of EWP. Several ARs were written for difficulties encountered during the transition to EWP, including instances of lost data requiring, in some cases, the complete re-performance of surveillances. The inspectors sampled several technical specification required surveillances completed between the third quarter and fourth quarters of 2015. This sampling revealed that several surveillances were completed in EWP, an online system, and remained in EWP rather than being transferred to the licensees approved QA records permanent storage location. Licensee procedures and industry standards related to electronic storage of QA records required the licensee to transfer these records to their approved offline archive facility within 90 days of creation and certification of the record. Based on the inspectors observations, the licensee determined that over 3,200 QA records were not archived. Furthermore, the licensee determined that this backlog of records not being archived was due to sequencing of steps taken by users during work task completion. The inspectors determined that multiple performance deficiencies existed related to this selected issue. The inspectors dispositioned these issues as minor because the inspectors determined that all required QA records of completed surveillances and other maintenance activities affecting quality existed in an unalterable form with two sets of redundant in-process databases. Prior to this in-depth review, the licensee had discovered instances where surveillance data had been completely lost, but in those cases, the licensee immediately re-performed the surveillances satisfactorily and completely documented the condition of lost data, with corrective actions pending or concluding at the time of this review.

Numerous corrective actions taken or planned by the licensee for this selected issue included the creation of a plan to close out the backlog of unarchived QA records, improve operations department coordination of work activities, and the creation of standard instructions for individuals responsible for work task completion to facilitate the proper auto-archival process.

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

a. Findings

No findings were identified.

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

.1 (Closed) Licensee Event Reports 05000301/2015-005-00; 05000301/2015-005-01:

Main Transformer Lockout and Associated Loss of Busses Results in System Actuation

a. Inspection Scope

On October 29, 2015, during the process of clearing a tagout for the Unit 2 main transformer, 2X-01, the licensee induced a short-circuit which caused the 2X-01 to trip and lockout, resulting in the loss of power to non-vital 4kV busses. Unit 2 was in mode 3, with preparations for startup from the scheduled refueling outage at the time.

On December 16, 2015, this event was reported by the licensee in accordance with 10 CFR 50.73(a)(2)(iv)(A) for the actuation of the a specified safety system, which was subsequently clarified with Revision 1 of the LER on December 28, 2015 as the actuation of the AFW system.

The inspectors reviewed the information contained in the original revision of the LER and determined that the licensee failed to describe pertinent details of the event.

Specifically, as a result of the 2X-01 lockout, power was lost to busses for all running reactor coolant pumps (RCPs), causing the plant to enter a natural circulation condition.

The AFW system actuated from the Anticipated Transient without Scram Mitigation System Actuation Circuitry sensing a loss of RCPs, which resulted in the Unit 2 TDAFW and motor-driven AFW pumps feeding SGs along with the standby SG feed pumps, which had been supplying feedwater flow the SGs prior to the event. Additionally, the licensee was maximizing letdown flow from the CVCS system in preparation for reactor startup. The above factors resulted in a rapid lowering of pressurizer level, until letdown automatically isolated, followed by a rapid rise in pressurizer level. While operators were in the process of restoring normal charging and letdown flow, a pressurizer PORV (2RC-430) lifted once as a consequence of the combination of the natural circulation condition and the volume of water charged into the RCS. The inspectors assessed the failure to describe all aspects of the complete event to be a minor performance deficiency. The licensee entered the issue into their CAP as AR 02099249 and revised the LER.

Based on a review of the LER, the licensees root cause analysis of the failure, and the proposed corrective actions, the inspectors determined that one self-revealed finding existed, which is documented in Section 4OA2 of this report. Documents reviewed are listed in the Attachment to this report. Both the original and revised LER are closed.

These event follow-up reviews constituted two samples as defined in IP 71153-05.

b. Findings

One self-revealed finding was documented in Section 4OA2 of this report.

.2 (Closed) Licensee Event Reports (LERs) 05000266/2015-006-00;

05000266/2015-006-01: Unit 1 Automatic Reactor Trip

a. Inspection Scope

On November 28, 2015, Unit 1 automatically tripped from full power as previously documented in IR 05000266/2015004; 05000301/2015004. A reactor startup was commenced on December 2, 2015, and the main generator was synchronized to the grid later that day. On December 16, 2015, this event was reported by the licensee in accordance with 10 CFR 50.73(a)(2)(iv)(A) for the manual reactor protection system actuation.

The inspectors reviewed the information contained in the original revision of the LER and determined that the licensee failed to report that AFW actuated during the event as a result of low steam generator water level. The inspectors assessed the failure to report the actuation of AFW to be a minor performance deficiency. The licensee entered the issue into their CAP as AR 02099249 and revised the LER.

Based on a review of the revised LER, the licensees root cause analysis of the failure, and the proposed corrective actions, the inspectors determined that no findings or violations of NRC requirements existed. Documents reviewed are listed in the to this report. Both the original and revised LER are closed.

These event follow-up reviews constituted two samples as defined in IP 71153-05.

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On April 1, 2016, 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 February 3, 2016, the inspection results of the emergency preparedness AR report review were discussed with Mr. R. Seizert, Emergency Preparedness Manager;

• On March 18, 2016, the inspection results for the areas of radiological hazard assessment and exposure controls; occupational ALARA planning and controls; in-plant airborne radioactivity control and mitigation; and occupational dose assessment with Mr. E. McCartney, Site Vice President; and

• On March 25, 2016, the inspection results of the Inservice Inspection were discussed with Mr. E. McCartney, Site Vice President.

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

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

E. McCartney, Site Vice President

D. DeBoer, Plant General Manager

S. Aerts, Performance Improvement Manager

M. Blew, Principal Engineering Analyst

C. Ford, Maintenance Support Department Head

S. Forsha, Principal Engineer

B. Gerbers, Engineering Supervisor

R. Harrsch, Engineering Site Director

W. Jensen, Principal Engineering Analyst

R. Parker, Chemistry Manager

J. Ramski, Outage Manager

T. Schneider, Senior Engineer

R. Seizert, Emergency Preparedness Manager

G. Strharsky, Site Quality Manager

R. Webber, Site Operations Director

R. Welty, Radiation Protection Manager

B. Woyak, Licensing Manager

J. Yindra, Procedure Writer

U.S. Nuclear Regulatory Commission

J. Cameron, Chief, Reactor Projects Branch 4

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000301/2016001-01 FIN Failure to Follow Electrical Safety Procedures Results in Plant Transient (Section 4OA2.3)

Closed

05000301/2016001-01 FIN Failure to Follow Electrical Safety Procedures Results in Plant Transient (Section 4OA2.3)

05000301/2015-005-00 LER Main Transformer Lockout and Associated Loss of Busses Results in System Actuation (Section 4OA3.1)

05000301/2015-005-01 LER Main Transformer Lockout and Associated Loss of Busses Results in System Actuation (Section 4OA3.1)

05000266/2015-006-00 LER Unit 1 Automatic Reactor Trip (Section 4OA3.2)

05000266/2015-006-01 LER Unit 1 Automatic Reactor Trip (Section 4OA3.2)