IR 05000266/2014003

IR 05000266-14-003; 05000301-14-003; 04/01/2014 - 06/30/2014; Point Beach Nuclear Plant, Units 1 & 2; Outage Activities, and Identification and Resolution of Problems

ML14212A428
Person / Time
Site:	Point Beach
Issue date:	07/31/2014
From:	Jamnes Cameron Reactor Projects Region 3 Branch 4
To:	Mccartney E Point Beach
References
IR-14-003
Download: ML14212A428 (48)

Text

{{#Wiki_filter:UNITED STATES uly 31, 2014

SUBJECT:

POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000266/2014003; 05000301/2014003

Dear Mr. McCartney:

On June 30, 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 July 15, 2014, with you and other members of your staff.

Based on the results of this inspection, one NRC-identified and one self-revealed findings of very low safety significance were identified. The findings involved a violation of NRC requirements. Additionally, two licensee identified violations are listed in Section 4OA7 of this report. However, because of their very low safety significance, and because the issues were entered into your corrective action program, 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 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 NRC Public Document Room or from the Publicly Available Records System (PARS) component of 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 Bruce Bartlett, Acting for/ Jamnes L. Cameron, Chief Branch 4 Division of Reactor Projects Docket Nos. 50-266; 50-301 License Nos. DPR-24; DPR-27

Enclosure:

IR 05000266/2014003; 05000301/2014003 w/Attachment: Supplemental Information

REGION III== Docket Nos: 05000266; 05000301 License Nos: DPR-24; DPR-27 Report No: 05000266/2014003; 05000301/2014003 Licensee: NextEra Energy Point Beach, LLC Facility: Point Beach Nuclear Plant, Units 1 and 2 Location: Two Rivers, WI Dates: April 1, 2014 through June 30, 2014 Inspectors: D. Oliver, Senior Resident Inspector K. Barclay, Acting Senior Resident Inspector R. Elliott, Acting Resident Inspector T. Bilik, Senior Reactor Inspector V. Myers, Health Physicist Approved by: J. Cameron, Chief Branch 4 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000266/2014003; 05000301/2014003; 04/01/2014-06/30/2014; Point

Beach Nuclear Plant, Units 1 & 2; Outage Activities, and 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 identified by the inspectors and one green finding was self-revealed. The findings were considered non-cited violations of NRC regulations. 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 (SDP) 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 non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the failure to follow procedures. Specifically, while Unit 2 was in Mode 3, the licensee left buoyant items in containment that were neither anchored or tethered to a substantial structure nor located in an anchored storage box or receptacle, as required by NP 7.2.28, Containment Debris Control Program, Revision 5, Step 4.2.8(d)3. The licensee entered the issue into their corrective action program (CAP) and implemented short-term corrective actions, which included removing the material from containment and communicating to station personnel the importance of not leaving susceptible material unattended in containment while in Modes 1 through 4.

The licensees long-term corrective actions included creating a site specific procedure that places all the containment debris control requirements in one central location.

The inspectors determined that the finding was more than minor, because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone. The finding adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. 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 Training (H.9), in the area of Human Performance, for failing to provide training and ensure knowledge transfer to maintain a knowledgeable workforce. (Section 1R20.1)

Green.

A finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was self-revealed for the failure to replace safety-related inverter components at the vendor prescribed 10-year frequency. Specifically, after concluding that safety-related inverter relays were required to be replaced at a 10-year frequency, per vendor direction, the licensee failed to promptly replace the remaining relays that were eighteen years old or evaluate if the relays could remain in-service until the next scheduled 10-year inverter overhaul. The licensee entered the issue into their CAP and replaced the remaining K2 relays that were past their 10-year replacement frequency in April and June of 2014 and has plans to replace the remaining K1 relays, which provide alarm only function, in 2015.

The inspectors determined finding was more than minor because it was associated with the Equipment Performance attribute of the Mitigating System cornerstone and affected the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency resulted in three additional K2 relay failures in 2013 and 2014, two of which occurred while the inverters were carry instrument bus loads and caused the inoperability of the associated inverters. 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. Because the finding impacted the Mitigating Systems Cornerstone, the inspectors screened the finding through IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, using Exhibit 2, Mitigating Systems Screening Questions. 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 Resolution (P.3), in the area of Problem Identification and Resolution because the licensee failed to take effective corrective actions to address issues in a timely manner commensurate with their safety significance. (Section 4OA2.4)

Licensee-Identified Violations

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 throughout the quarter with one exception. On April 28, the unit was shut down to conduct containment dome truss inspections and implement repairs. The unit started-up on May 1 and reached full power on May 6.

Unit 2 The unit began the inspection period in a refueling outage (RFO) and remained shut down until April 17, when the unit was started-up. The unit reached full power on April 22 and operated at or near full power for the remainder of the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness of Offsite and Alternate Alternating Current Power Systems

a. Inspection Scope

The inspectors verified that plant features and procedures for operation and continued availability of offsite and alternate alternating current (AC) power systems during adverse weather were appropriate. The inspectors reviewed the licensees procedures affecting these areas and the communications protocols between the transmission system operator (TSO) and the plant to verify that the appropriate information was being exchanged when issues arose that could impact the offsite power system. Examples of aspects considered in the inspectors review included:

• coordination between the TSO and the plant during off-normal or emergency events;
• explanations for the events;
• estimates of when the offsite power system would be returned to a normal state; and
• notifications from the TSO to the plant when the offsite power system was returned to normal.

The inspectors also verified that plant procedures addressed measures to monitor and maintain availability and reliability of both the offsite AC power system and the onsite alternate AC power system prior to or during adverse weather conditions. Specifically, the inspectors verified that the procedures addressed the following:

• actions to be taken when notified by the TSO that the post-trip voltage of the offsite power system at the plant would not be acceptable to assure the continued operation of the safety-related loads without transferring to the onsite power supply;
• re-assessment of plant risk based on maintenance activities which could affect grid reliability, or the ability of the transmission system to provide offsite power; and
• communications between the plant and the TSO when changes at the plant could impact the transmission system, or when the capability of the transmission system to provide adequate offsite power was challenged.

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

This inspection constituted one readiness of offsite and alternate AC power systems sample as defined in Inspection Procedure (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-29 turbine driven auxiliary feedwater pump;
• G-02 emergency diesel generator; and
• safety injection train B.

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, Final Safety Analysis Report (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 Attachment 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 (71111.05Q and A)

.1 Routine Resident Inspector Tours

[[IP sample::

=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 304 N: 2P-29 AFW Pump Room;
• Fire Zone 304 S: 1P-29 AFW Pump Room;
• Fire Zone 305: 4160 V Vital Switchgear Room;
• Fire Zone 237: Component Cooling Heat Exchanger Room; and
• Fire Zone 552: Service Water Pump House.

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 five quarterly fire protection inspection samples as defined in IP 71111.05-05.

b. Findings

No findings were identified.

.2 Annual Fire Protection Drill Observation

a. Inspection Scope

On April 25, 2014, the inspectors observed fire brigade activation for a fire in a trailer south of the circulating pump house. 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. Specific attributes evaluated were:

• proper wearing of turnout gear and self-contained breathing apparatus;
• proper use and layout of fire hoses;
• employment of appropriate firefighting techniques;
• sufficient firefighting equipment brought to the scene; and
• effectiveness of fire brigade leader communications, command, and control.

Documents reviewed are listed in the Attachment to this report.

These activities constituted a partial annual fire protection inspection sample as defined in IP 71111.05-05.

b. Findings

No findings were identified.

1R06 Flooding

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk important plant design features intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed design documents, drawings, and the FSAR. The specific documents reviewed are listed in the Attachment to this report. 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 performed a walkdown of the following plant area to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable:

• residual heat removal pump cubicles.

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

This inspection constituted one partial internal flooding sample as defined in IP 71111.06-05. This partial sample will be completed in the third or fourth quarter of 2014.

b. Findings

No findings were identified.

1R07 Annual Heat Sink Performance

.1 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of HX-55B, the G-02 emergency diesel generators heat exchanger, to verify its readiness and availability and to confirm that potential heat exchanger deficiencies are identified. This review included evaluating the licensees inspection documentation and photographs to assess the cleanliness of the heat exchanger tubes, as well as, observing the licensees bio-fouling controls during their semiannual continuous chlorination of service water system for mussel control.

The inspectors also reviewed the licensees CAP to verify that the licensee was documenting heat exchanger and heat sink problems at an appropriate threshold and that corrective actions were appropriate. Documents reviewed for this inspection are listed in the Attachment to this document.

This annual heat sink performance inspection constituted one sample as defined in IP 71111.07-05.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On May 14, 2014, the inspectors observed a crew of 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 of Heightened Activity or Risk

a. Inspection Scope

On April 12, 2014, the inspectors observed the Unit 2 plant heat-up and drawing of a bubble in the pressurizer. 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 (or equipment) manipulations;
• oversight and direction from supervisors; and
• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications (if applicable).

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

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• 120 VAC instrument and control system; and
• Nuclear instruments.

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:

• May 27, 1P-53 AFW Pump unavailable with switchyard activities in-progress on Unit 1, and
• May 28, 1P-11B CCW pump unavailable with switchyard activities and reactor protection and safeguards containment pressure calibration 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 Part 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 two 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:

• Increase in load profile for battery D-106 and battery D-305 supplying bus D-04; and
• P-32E service water pump anchor bolt sleeve missing grout.

The inspectors selected this potential operability issue 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

The inspectors observed and documented one licensee identified violation of 10 CFR Part 50, Appendix B, Criterion III, Design Control, which is documented in Section 4OA7.

.2 (Closed) Unresolved Item 05000266/2011003-02; 05000301/2011003-02, Seismic

Qualification of the Condensate Storage Tank and Related Flooding Barriers During the performance of Temporary Instruction (TI) 2515/183, the inspectors identified a potential deficiency associated with the seismic qualification of the condensate storage tank (CST), the flooding barriers between the CST and the vital switchgear room, and the ability to protect the related vital switch gear. The inspectors, in consultation with the Region III civil engineer, performed an evaluation of the licensees determination of operability for the issue. The inspectors found that the licensee utilized various elements of seismic qualification users group (SQUG) methodology and complex calculations to justify operability of the equipment. The inspectors concluded that this issue was unresolved pending a review of the related calculations, use of SQUG methodology, and a review of the Point Beach licensing basis for seismic qualifications.

The inspectors reviewed the FSAR, historical internal flooding correspondence, and the licensees assessment and determined that defense in depth existed even with a small breach of the flood barrier to maintain the ability to safety shutdown the plant.

Specifically, most of the water from a ruptured CST would have been directed off of the 26 foot elevation wall down to the 8 foot elevation. Additionally, any water entering the non-vital bus area and exceeding the 2 lip height for the non-vital bus ducts would have been directed to the non-vital buses in the vital bus room below. The inspectors concluded that any water that would have gone into the vital bus room, would escape under the vital bus room doors prior to reaching a height of concern for the safety-related 4160 volt buses or battery chargers. The licensee has reinforced the portion of the block wall in question and has plans to modify the CST to make it Seismic Class I as part of the Mitigating Strategy modifications. This unresolved item (URI) is closed.

.3 (Closed) Unresolved Item 05000266/2011003-03; 05000301/2011003-03, RHR Pump

Operability with Tanks in Auxiliary Building Not Seismically Qualified During the performance of TI 2515/183 the inspectors identified a potential deficiency associated with the seismic qualification of the RHR pumps because several tanks in auxiliary building were not seismically qualified. The inspectors, in consultation with the Region III civil engineer, performed an evaluation of the licensees determination of operability for the issue. The inspectors found that the licensee utilized various elements of SQUG methodology and complex calculations to justify operability of the equipment.

The inspectors concluded that this issue was unresolved pending a review of the related calculations, use of SQUG methodology, and a review of the Point Beach licensing basis for seismic qualifications.

The inspectors detailed review of licensees FSAR and historical internal flooding correspondence between the licensee and the agency found that the Point Beachs internal flooding licensing basis did not require more than one non-seismic tank to rupture at a time. The inspectors also confirmed that contents of a single ruptured tank would not cause a loss of safety function of the RHR system or prevent the safe shutdown of the plant. This URI is closed.

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modification:

• EC 272529 Unit 2 AFW turbine replacement.

The inspectors reviewed the configuration changes and associated 10 CFR Part 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. 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 one 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-11B CCW pump testing after oil change;
• G-05 gas turbine generator testing after maintenance; and
• 2P-29 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 three 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 continued their inspection of the Unit 2 RFO that was in progress at the beginning of the quarter. During the RFO, the inspectors 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 primary 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 refueling outage sample as defined in IP 71111.20-05.

b. Findings

(1) Failure to Maintain Control of Loose Material in Containment

Introduction:

A finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified by the inspectors for the failure follow procedures. Specifically, while Unit 2 was in Mode 3, the licensee left buoyant items in containment that were neither anchored or tethered to a substantial structure or located in an anchored storage box or receptacle, as required by NP 7.2.28, Containment Debris Control Program, Revision 5, Step 4.2.8(d)3.

Description:

On April 14, 2014, while Unit 2 was in Mode 3, inspectors observed numerous buoyant items unattended in containment that were neither anchored or tethered to a substantial structure nor located in an anchored storage box or receptacle.

The specific items included boxes of protective gloves, poly bags, rags, mop heads, and other items that could float in water. The inspectors informed the licensee and the licensee promptly removed the items from containment. The inspectors reviewed NP 7.2.28, Containment Debris Control Program, Revision 5, and found that Step 4.2.8(d)3 required, when the units are in Modes 1 through 4, that items having a tendency to float in water be anchored or tethered to a substantial structure or located in an anchored storage box or receptacle. The licensee performed a past operability review of the items left in containment and initially concluded that RHR pump operability was maintained because the items were located in an area that prevented their transport to the containment sump and would not have clogged the RHR pump suction strainers.

The licensees basis for this conclusion was that the items were not near any potential loss of coolant accident (LOCA) sources and because the overhead ceiling would have prevented containment spray wash-down from transporting the items to the containment sump. The inspectors reviewed the licensees evaluation and questioned the assumption that the overhead ceiling protected the items. The inspectors recalled that some of the items were near a stairwell and inquired about the potential for containment spray wash-down to impact the items through the overhead stairwell opening. The licensee re-evaluated the issue and concluded that containment spray wash-down could have impacted the unsecured material and enough material could have been transported to the containment sump strainers, such that one train of RHR needed to be considered inoperable. The licensee entered the issue of debris unsecured in containment into their CAP and performed an apparent cause evaluation (ACE). The licensee concluded in their ACE that personnel were not clear in their understanding of the requirements for the control of items in containment during Modes 1 through 4 and that a large contributor to this was that the requirements were spread out among several different procedures.

Analysis:

The inspectors determined that the licensees failure to anchor or tether loose material to a substantial structure or locate it in an anchored storage box or receptacle was contrary to the requirements of procedure NP 7.2.28, Revision 5, Step 4.2.8(d)3 and was a performance deficiency. The inspectors determined that the finding was more than minor, because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone. The finding adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

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 Training (H.9),in the area of Human Performance, for failing to provide training and ensure knowledge transfer to maintain a knowledgeable workforce. Specifically, the licensee did not ensure that personnel were knowledgeable of need, during Modes 1 through 4, to anchor or tether buoyant material in containment to a substantial structure or locate it in an anchored storage box or receptacle.

Enforcement:

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. Procedure NP 7.2.8, Containment Debris Control Program, Revision 5, step 4.2.8(d)3 requires, in part, that items having a tendency to float in water shall be anchored or tethered to a substantial structure or located in an anchored storage box or receptacle.

Contrary to the above, on April 14, 2014, the licensee failed to ensure that that items having a tendency to float in water were anchored or tethered to a substantial structure or located in an anchored storage box or receptacle. Specifically, personnel performing maintenance activities in the Unit 2 containment, while in Mode 3, left boxes of protective gloves, poly bags, rags, mop heads, and other items that could float in water; unattended without anchoring or tethering them or locating them within an anchored storage box or receptacle. Because this violation is of very low safety significance and the licensee entered it into the CAP as AR 01958167 and AR 01958153, it is being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000301/2014003-001; Failure to Maintain Control of Loose Material in Containment). The licensees short-term corrective actions included removing the material from containment and communicating to station personnel the importance of not leaving susceptible material unattended in containment while in Modes 1 through 4. The licensees long-term corrective actions included creating a site specific procedure that places all the containment debris control requirements in one central location.

.2 Other Outage Activities

a. Inspection Scope

The inspectors evaluated outage activities for an unscheduled outage that began on April 28, 2014, and continued through May 1, 2014. The purpose of the unplanned outage was to conduct containment dome truss inspections and implement repairs. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule.

The inspectors observed or reviewed the reactor shutdown, outage equipment configuration and risk management, electrical lineups, control and monitoring of decay heat removal, control of containment activities, startup activities, and identification and resolution of problems associated with the outage.

Documents reviewed are listed in the Attachment to this report.

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

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:

• IT 45 Train A; Safety Injection Valves Train A Unit 2 (Routine);
• IT 07F P-32F Service Water Pump Quarterly Test (IST);
• ORT 3A Safety Injection Actuation with Loss of Engineered Safeguards AC (Routine);
• RESP 4.1; BOL Power Physics Testing (Routine);
• IT 05 Train A Containment Spray Pump and Valve Test Unit 1 (Routine); and
• OI 55; Primary Leak Rate Calculation (RCS).

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 four routine surveillance testing samples, one inservice testing sample, and one reactor coolant system leak detection inspection sample as defined in IP 71111.22, Sections-02 and-05.

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 May 13, 2014, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the 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 corrective action program. 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 71114.06-05.

b. Findings

No findings were identified.

.2 Training Observation

a. Inspection Scope

The inspectors observed a simulator training evolution for licensed operators on May 28, 2014, 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 corrective action program. 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

2RS5 Radiation Monitoring Instrumentation

This inspection constituted a partial sample as defined in IP 71124.05-05.

.1 Inspection Planning (02.01)

a. Inspection Scope

The inspectors reviewed the plant FSAR to identify radiation instruments associated with monitoring area radiological conditions including airborne radioactivity, process streams, effluents, materials/articles, and workers. Additionally, the inspectors reviewed the instrumentation and the associated TS requirements for post-accident monitoring instrumentation, including instruments used for remote emergency assessment.

The inspectors reviewed a listing of in-service survey instrumentation including air samplers and small article monitors, along with instruments used to detect and analyze workers external contamination. Additionally, the inspectors reviewed personnel contamination monitors and portal monitors, including whole body counters, to detect workers internal contamination. The inspectors reviewed this list to assess whether an adequate number and type of instruments were available to support operations.

The inspectors reviewed licensee and third-party evaluation reports of the Radiation Monitoring Program since the last inspection. These reports were reviewed for insights into the licensees program and to aid in selecting areas for review (smart sampling).

The inspectors reviewed procedures that govern instrument source checks and calibrations, focusing on instruments used for monitoring transient high radiological conditions, including instruments used for underwater surveys. The inspectors reviewed the calibration and source check procedures for adequacy and as an aid to smart sampling.

The inspectors reviewed the area radiation monitor alarm setpoint values and setpoint bases as provided in the TSs and the FSAR.

The inspectors reviewed effluent monitor alarm setpoint bases and the calculational methods provided in the Offsite Dose Calculation Manual (ODCM).

b. Findings

No findings were identified.

.2 Walkdowns and Observations (02.02)

a. Inspection Scope

The inspectors walked down effluent radiation monitoring systems, including at least one liquid and one airborne system. Focus was placed on flow measurement devices and all accessible point-of-discharge liquid and gaseous effluent monitors of the selected systems. The inspectors assessed whether the effluent/process monitor configurations aligned with ODCM descriptions and observed monitors for degradation and out-of-service tags.

The inspectors selected portable survey instruments that were in use or available for issuance and assessed calibration and source check stickers for currency as well as instrument material condition and operability.

The inspectors observed licensee staff performance as the staff demonstrated source checks for various types of portable survey instruments. The inspectors assessed whether high-range instruments were source checked on all appropriate scales.

The inspectors walked down area radiation monitors and continuous air monitors to determine whether they were appropriately positioned relative to the radiation sources or areas they were intended to monitor. Selectively, the inspectors compared monitor response (via local or remote control room indications) with actual area conditions for consistency.

The inspectors selected personnel contamination monitors, portal monitors, and small article monitors and evaluated whether the periodic source checks were performed in accordance with the manufacturers recommendations and the licensees procedures.

b. Findings

No findings were identified.

.3 Calibration and Testing Program (02.03)

Laboratory Instrumentation

a. Inspection Scope

The inspectors assessed laboratory analytical instruments used for radiological analyses to determine whether daily performance checks and calibration data indicated that the frequency of the calibrations was adequate and there were no indications of degraded instrument performance.

The inspectors assessed whether appropriate corrective actions were implemented in response to indications of degraded instrument performance.

b. Findings

No findings were identified.

Whole Body Counter

a. Inspection Scope

The inspectors reviewed the methods and sources used to perform whole body count functional checks before daily use of the instrument and assessed whether check sources were appropriate and aligned with the plants isotopic mix.

The inspectors reviewed whole body count calibration records since the last inspection and evaluated whether calibration sources were representative of the plant source term and that appropriate calibration phantoms were used. The inspectors looked for anomalous results or other indications of instrument performance problems.

b. Findings

No findings were identified.

Post-Accident Monitoring Instrumentation

a. Inspection Scope

Inspectors selected containment high-range monitors and reviewed the calibration documentation since the last inspection.

The inspectors assessed whether an electronic calibration was completed for all range decades above 10 rem/hour and whether at least 1 decade at or below 10 rem/hour was calibrated using an appropriate radiation source.

The inspectors assessed whether calibration acceptance criteria were reasonable; accounting for the large measuring range and the intended purpose of the instruments.

The inspectors selected effluent/process monitors that were relied on by the licensee in its emergency operating procedures as a basis for triggering emergency action levels and subsequent emergency classifications, or to make protective action recommendations during an accident. The inspectors evaluated the calibration and availability of these instruments.

The inspectors reviewed the licensees capability to collect high-range, post-accident iodine effluent samples.

As available, the inspectors observed electronic and radiation calibration of these instruments to assess conformity with the licensees calibration and test protocols.

b. Findings

No findings were identified.

Portal Monitors, Personnel Contamination Monitors, and Small Article Monitors

a. Inspection Scope

For each type of these instruments used on site, the inspectors assessed whether the alarm setpoint values were reasonable under the circumstances to ensure that licensed material is not released from the site.

The inspectors reviewed the calibration documentation for each instrument selected and discussed the calibration methods with the licensee to determine consistency with the manufacturers recommendations.

b. Findings

No findings were identified.

Portable Survey Instruments, Area Radiation Monitors, Electronic Dosimetry, and Air Samplers/Continuous Air Monitors

a. Inspection Scope

The inspectors reviewed calibration documentation for at least one of each type of instrument. For portable survey instruments and area radiation monitors, the inspectors reviewed detector measurement geometry and calibration methods and had the licensee demonstrate use of its instrument calibrator as applicable. The inspectors conducted comparison of instrument readings versus an NRC survey instrument if problems were suspected.

As available, the inspectors selected portable survey instruments that did not meet acceptance criteria during calibration or source checks to assess whether the licensee had taken appropriate corrective action for instruments found significantly out of calibration (e.g., greater than 50 percent). The inspectors evaluated whether the licensee evaluated the possible consequences of instrument use since the last successful calibration or source check.

b. Findings

No findings were identified.

Instrument Calibrator

a. Inspection Scope

As applicable, the inspectors reviewed the current output values for the licensees portable survey and area radiation monitor instrument calibrator unit(s). The inspectors assessed whether the licensee periodically measures calibrator output over the range of the instruments used through measurements by ion chamber/electrometer.

The inspectors assessed whether the measuring devices had been calibrated by a facility using National Institute of Standards and Technology traceable sources and whether corrective factors for these measuring devices were properly applied by the licensee in its output verification.

b. Findings

No findings were identified.

Calibration and Check Sources

a. Inspection Scope

The inspectors reviewed the licensees 10 CFR Part 61, Licensing Requirements for Land Disposal of Radioactive Waste, source term to assess whether calibration sources used were representative of the types and energies of radiation encountered in the plant.

b. Findings

No findings were identified.

.4 Problem Identification and Resolution (02.04)

a. Inspection Scope

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

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Reactor Coolant System Leakage

a. Inspection Scope

The inspectors sampled licensee submittals for the reactor coolant system (RCS) Leakage performance indicator for Units 1 and 2, for the period from the second quarter 2013 through the first quarter 2014. To determine the accuracy of the performance indicator (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, were used. The inspectors reviewed the licensees operator logs, RCS leakage tracking data, issue reports, event reports and NRC Integrated Inspection Reports 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 reactor coolant system leakage 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 condition reports.

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

The inspectors observed and documented one licensee identified violation of 10 CFR 50, Criterion VI, Document Control, which is documented in Section 4OA7.

.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 fourth quarter of 2013 through the first 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, such as, major equipment problem lists, repetitive and/or rework maintenance lists, maintenance rule evaluations, and other sources. The inspectors also reviewed the licensees progress in addressing the emerging cross-cutting theme in the aspect of P.2, Evaluation. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports.

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

Observations After the inspectors observed multiple condition reports related to operations department human performance errors, the inspectors allocated a portion of the semi-annual trend review to evaluate the error trend and the licensees actions to assess and correct the trend.

The inspectors review included an assessment of the licensees corrective actions associated with the following documents:

• AR 01920169: Declining Trend in [human performance] HU for Operations Field Activities; November 12, 2013;
• AR 01929649: Common Cause Needed for Ops ACEs/RCE in 2013-Adverse Trend; December 26, 2013; and
• AR 01937025: Operations Human Performance Has Been Declining Since Q4 2013; January 29, 2014.

The inspectors found that the licensee recognized the adverse operations performance trend in late 2013, and as the operations human performance events continued, recognized that their recovery plan was ineffective in precluding further operational events. The licensee took actions to modify their recovery plan in February of 2014.

Action items in the recovery plan included, but were not limited to:

• A period of observation of backshift and weekend observations completed for field activities and control room activities, which included immediate feedback and coaching.
• An Assistant Operations Manager was in the control room and participated in Just-In-Time-Training for planned plant maneuvers validating acceptable standards for operations fundamentals and human performance.
• All Shift Managers met with the Site Director to ensure expectations are understood and to identify issues to be addressed.
• A focus on three human performance fundamentals: procedure use and adherence; evolution briefing; and peer checks during required observations each shift by each senior reactor operator on the crew.
• Complete a training needs analysis for the declining trend in operations human performance.
• Implement an operations standards seminar for all shift crews.

The licensee also completed a common cause analysis (CCA) for the declining operations performance. The CCA identified two common causes. The first common cause was, shortcuts with task performances are not being recognized with management validations and reinforcement efforts to correct deficiencies with maintaining standards. The second common cause was Inconsistent and inadequate shift engagement with assessment of operations events for ownership of crew actions necessary to recognize and correct shift behavioral declines and share lessons learned with the department.

The inspectors overall assessment concluded that some improvement in operations performance has been observed in second quarter but more time is needed to determine if the licensees corrective actions will be effective and produce sustainable results.

The inspectors semi-annual trend review also included assessing the licensees progress in addressing the emerging cross-cutting theme in the aspect of P.2, Evaluation. The inspectors review included an assessment of the licensees corrective actions associated with RCE 01954549, Cross-cutting Theme for Aspect P.2, Evaluation. The licensees evaluation identified the following causes:

• Root Cause 1-Less than adequate questioning attitude and rigor when performing evaluations based on safety significance;
• Root Cause 2-Less than adequate review and approval (oversight) of evaluations by the line organizations and / or governing bodies (MRC, CARB, etc.);
• Contributing Cause 1-Less than adequate understanding of the design and licensing basis when performing evaluations; and
• Contributing Cause 2-Less than adequate procedure use and adherence relative to evaluations processes and procedures (IOD, 50.59, ECs, etc.).

The inspectors concluded that the licensee appropriately identified the causes of the emerging cross-cutting theme, but found that not enough time had elapsed to consider the corrective actions effective. One example supporting that more time is necessary, is the licensees past operability determination (POD) associated with the NCV in Section 1R20. During the inspectors review of the licensees POD of the material left unattended in containment, the inspectors identified two errors. The first error was related to the location of the material identified in containment and whether it would be transported to the containment sump. The licensee corrected this error, which changed their initial operability conclusion from fully operable to one train of RHR inoperable. The inspectors reviewed the second revision of the POD and checked the control room logs for the time period in question. The inspectors found that one train of RHR had been inoperable for maintenance when the material was discovered in containment, which would render the second train of RHR inoperable. The licensee is performing a third revision to the past operability determination to include a more sophisticated analysis of containment flow during accident conditions in an effort to show that one train of RHR would have remained operable. The inspectors will review that POD in the third quarter of 2014. The issues identified by the inspectors during review of the POD contain attributes from both of the licensee identified root causes, further supporting that more time is needed to address the P.2, Evaluation aspect.

b. Findings

No findings were identified.

.4 Selected Issue Follow-Up Inspection: Aging Management of Inverter Relays

a. Inspection Scope

During the performance of a maintenance rule inspection of the 120 VAC vital instrument power system, the inspectors identified a trend of inverter failures going back to the 2008 timeframe. The inspectors did not identify a violation of the maintenance rule, but were concerned with potential corrective action program weaknesses associated with the issue. The inspectors performed a selected issue follow-up of the issue to assess the licensees corrective actions from the 2009 failure of an inverter and subsequent failures up to and including the failures in the first quarter of 2014.

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

b. Findings

1) Age Related Relay Failures Result in Inoperable Inverters

Introduction:

A finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion III, Design Control, was self-revealed for the failure to replace safety-related inverter components at the vendor prescribed 10-year frequency. Specifically, after concluding that safety-related inverter relays were required to be replaced at a 10-year frequency, per vendor direction, the licensee failed to promptly replace the remaining relays that were eighteen years old or evaluate if the relays could remain in-service until the next scheduled 10-year inverter overhaul.

Description:

During a maintenance rule sample and historical review of the 120 VAC vital instrument power (Y) system, the inspectors identified a trend going back to 2008 of Agastat time delay relays failing in the red and blue channel instrument bus inverters.

The licensee has three red and three blue channel instrument bus inverters, which utilize identical Agastat relays for two separate functions; one relay location within each the inverter is designated as K1 and functions to initiate an alarm in the control room, while the other relay location is designated as K2 and functions to transfer the inverter to its non-safety related power supply after a loss of its safety-related supply. The K2 relay is continuously energized and its failure causes the associated inverter to unnecessarily transfer to its non-safety related backup power source and results in the inoperability of the inverter. The licensees analysis of the failed K2 relays sampled three of the four failed relays and found that the same internal components of the relays failed. The licensees analysis stated that the relays are continually energized and failure occurs when the board components burn out. The inspectors found that the licensee performed a condition evaluation after the 2009 K2 relay failure and the evaluation concluded that the K2 relays should have been replaced at a 10-year frequency. Further review by the inspectors, found that two failures had occurred prior to the 2009 failure. Specifically, one K2 relay had failed in 2002 and one K1 relay had failed in 2008. Since the 2009 relay failure, the inspectors found that the inverters have had six K1 or K2 relay failures, all of which were the original relays from the 1991 inverter installations. The inspectors found that the condition evaluation corrective actions from the 2009 relay failure added the relay replacements to the scheduled 10-year inverter overhauls, but failed to evaluate if the remaining K2 relays, which were already 8 years past their prescribed replacement date, could remain in-service until the scheduled overhauls, which in some cases took the relays out to 23 years of in-service time. The licensee replaced the remaining K2 relays that were past their 10-year replacement frequency in April and June of 2014 and has plans to replace the remaining K1 relays, which function to provide alarm only, in 2015.

Analysis:

The inspectors determined that the licensees failure to establish measures for the review for suitability of application of materials was contrary to 10 CFR Part 50, Appendix B, Criterion III and was a performance deficiency. Specifically, the licensee failed to replace safety-related inverter relays that were past their 10-year vendor prescribed replacement period or evaluate if the relays could remain in-service until the next 10-year inverter overhaul. This performance deficiency was determined to be more than minor because it was associated with the Equipment Performance attribute of the Mitigating Systems cornerstone and affected the cornerstone objective of ensuring the availability, reliability and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the performance deficiency resulted in three additional K2 relay failures in 2013 and 2014, two of which occurred while the inverters were carry instrument bus loads and caused the inoperability of the associated inverters.

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. Because the finding impacted the Mitigating Systems Cornerstone, the inspectors screened the finding through IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, using Exhibit 2, Mitigating Systems Screening Questions. 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 Resolution (P.3), in the area of Problem Identification and Resolution because the licensee failed to take effective corrective actions to address issues in a timely manner commensurate with their safety significance. Specifically, after identifying that installed inverter relays were past their vendor prescribed 10-year replacement frequency, the licensee failed to promptly replace the remaining relays or evaluate if the relays could remain in-service until the next scheduled 10-year inverter overhaul. The inspectors determined that the finding was reflective of current performance because the licensee had multiple opportunities to implement effective corrective actions with each subsequent relay failure in 2010, 2012, 2013, and 2014.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion III, Design Control, requires in part, that the licensee shall establish measures for the selection and review for suitability of application of materials, parts, equipment, and processes that are essential to the safety-related functions of structures, systems, and components. Contrary to this, from November 18, 2009 to June 30, 2014, the licensee failed to establish measures for the review for suitability of application of materials. Specifically, the licensee did not evaluate for suitability of the use of K2 relays in the red and blue channel instrument bus inverters beyond the vendor prescribed service life, which lead to multiple K2 relay failures without further evaluation of acceptability. Because this violation was of very low safety significance and the licensee entered it into the CAP as AR 01377231 and AR 01935654, it is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy. (NCV 05000266/2014003-002; 05000301/2014003-002; Age Related Relay Failures Result in Inoperable Inverters). The licensee replaced the remaining K2 relays that were past their 10-year replacement frequency in April and June of 2014 and has plans to replace the remaining K1 relays, which provide alarm only function, in 2015.

4OA6 Management Meetings

.1 Exit Meeting Summary

On July 15, 2014, the inspectors presented the inspection results to 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:

• the inspection results for the area of radiation monitoring instrumentation with Mr. E. McCarthy, Site Vice President, on May 2, 2014.

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 safety 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 NCVs:

• The licensee identified a NCV of the 10 CFR Part 50, Appendix B, Criterion III, Design Control of very low safety significance (Green) for the failure to ensure that tests on safety-related batteries D-05, D-06, D-105, D-106 and D-305 were performed in accordance with Technical Specifications Surveillance Requirements (SRs). Point Beach Nuclear Plant SR 3.8.4.8 requires verification that battery capacity is greater than or equal to 80 percent of the manufactures rating when subjected to either a performance of modified performance discharge test.

Surveillance Requirement 3.8.4.7 is modified by a note stating that it may also be satisfied every 18 months by the performance of 3.8.4.8.

Contrary to the above, from March 15, 2007, the licensee failed to perform either SR 3.8.4.7 or SR 3.8.4.8 or declare LCO 3.8.4 not met due to not meeting the SRs.

Specifically, on March 15, 2007, the licensee changed TS Bases for SR 3.8.4.8 which removed specific details for the performance of the modified performance testing of safety-related batteries. Prior to their removal from the TS Bases, the specific details for performing modified discharge tests were consistent with the guidance of IEEE 450-1995; however, the licensee remained committed to the 1987 version of the IEEE standard which does not provide a method for performing modified discharge tests. Since the licensee remained committed to IEEE 450-1987, the March 15, 2007 revision to the TS Bases were not screened as having an adverse consequence though the change to the Bases for SR 3.8.4.8 modified the requirements of the surveillance test and made the description of the testing more vague. Subsequently, maintenance procedures to perform the testing were revised and did not maintain the required specific battery profiles that would be necessary to meet the criteria of a modified discharge test. Consequently, since March 15, 2007, the licensee has taken credit for the performance of SR 3.8.4.8 in lieu of SR 3.8.4.7 without testing to the proper battery performance profiling. The licensee generated AR 01947039, 01950740 and 01952174 to address this issue.

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 (SDP) For Findings At-Power, dated July 1, 2012. The inspectors answered NO to all questions in Exhibit 2, Section A, Mitigating SSCs and Functionality. Therefore, the finding screened as Green (very low safety significance).

• The licensee identified an NCV of the 10 CFR Part 50, Appendix B, Criterion VI, Document Control of very low safety significance (Green) for the failure to ensure that procedures, including changes, are reviewed for adequacy and approved for release by authorized personnel. Specifically, while updating ECA-0.0, Unit 1, Loss of All AC Power, the licensee inadvertently deleted portions of the procedure that were not intended to be removed and did not review those changes for adequacy.

The most significant portion deleted within the procedure was step 6(a), Energize AC safeguards bus with diesel generators. The procedure was issued on March 26, 2014 and was corrected on April 15, 2014.

Title 10 CFR Part 50, Appendix B, Criterion VI, requires, in part, that measures be established to control the issuance of documents, such as instructions, procedures, and drawings, including changes thereto, which prescribe all activities affecting quality. These measures shall assure that documents, including changes, are reviewed for adequacy and approved for release by authorized personnel.

Contrary to the above, on March 26, 2014, the licensee issued for use ECA-0.0, Unit 1, Revision 59, a procedure prescribing activities affecting quality, which contained changes that were not reviewed for adequacy. The licensee entered this into their CAP as AR 01958472 and AR 01958542. 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 (SDP) For Findings At-Power, dated July 1, 2012. The inspectors answered NO to all questions in Exhibit 2, Section A, Mitigating SSCs and Functionality. Therefore, the finding screened as Green (very low safety significance).

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

E. McCartney, Site Vice President

R. Wright, Plant General Manager

B. Kopetsky, Security Site Manager

B. Scherwinski, Engineering Analyst II

D. Lauterbur, Training Site Manager

G. Strharsky, NOS Manager

G. Worley, Radiation Protection Manager - Acting

J. Wilson, Maintenance Site Director

K. Locke, Engineering Analyst Senior

K. Mott, Document Control & Records Supervisor

R. Clark, Licensing

R. Harrsch, Engineering Site Director

R. Parker, Chemistry Section Supervisor

R. Seizert, Licensing Supervisor/EP Manager Acting

R. Webber, Operations Site Director

R. Welty, Radiation Protection Manager

T. Schneider, Engineer Senior

Nuclear Regulatory Commission

J. Cameron, Chief, Reactor Projects Branch 4

LIST OF ITEMS

Opened

05000301/2014003-01 NCV Failure to Maintain Control of Loose Material in Containment (Section 1R20.1)

05000266/2014003-02 NCV Age Related Relay Failures Result in Inoperable Inverters

05000301/2014003-02 (Section 4OA2.4)

Closed

05000266/2014003-01 NCV Failure to Maintain Control of Loose Material in

05000301/2014003-01 Containment (Section 1R20.1)

05000266/2014003-02 NCV Age Related Relay Failures Result in Inoperable Inverters

05000301/2014003-02 (Section 4OA2.4)

05000266/2011003-02 URI Seismic Qualification of the Qualification of the

05000301/2011003-02 Condensate Storage Tank and Related Flooding Barriers (Section 1R15.2)

05000266/2011003-03; URI RHR Pump Operability With Tanks In Auxiliary Building

05000301/2011003-03 Not Seismically Qualified (Section 1R15.3)

==LIST OF DOCUMENTS REVIEWED==| ]]