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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:	Cameron J L; Reactor Projects Region 3 Branch 4
To:	McCartney E; Point Beach
References
	IR-14-003
	Download: ML14212A428 (48)
	v • d • e

July 31, 2014

Mr. Eric McCartney Site Vice President NextEra Energy Point Beach, LLC 6610 Nuclear Road Two Rivers, WI 54241

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 cc w/encl: Distribution via LISTSERV Enclosure U.S. NUCLEAR REGULATORY COMMISSION 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

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 NRC's 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 2014.

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 licensee's 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)3

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 licensee's CAP. These violations and CAP tracking numbers are listed in Section 4OA7 of this report.

4

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

Main article: IP 71111.01

.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 licensee's 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

Main article: IP 71111.04

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

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

Main article: IP 71111.05Q

a. Inspection Scope

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

Fire Zone 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 licensee's fire plan. The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plant's 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 plant's 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 licensee's 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

Main article: IP 71111.05A

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

Main article: IP 71111.06

.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

Main article: IP 71111.07

.1 Heat Sink Performance

a. Inspection Scope

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

Main article: IP 71111.11

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

Main article: IP 71111.11Q

a. Inspection Scope

On May 14, 2014, the inspectors observed a crew of licensed operators in the plant's 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;

crew's 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 crew's 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

Main article: IP 71111.11Q

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;

crew's 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

Main article: IP 71111.12

.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

Main article: IP 71111.13

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

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

Main article: IP 71111.15

.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 licensee's 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 Attachment 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 licensee's 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 licensee's 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 licensee's 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 licensee's FSAR and historical internal flooding correspondence between the licensee and the agency found that the Point Beach's 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

Main article: IP 71111.18

.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

Main article: IP 71111.19

.1 Post-Maintenance Testing

a. Inspection Scope

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

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

Main article: IP 71111.20

.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 licensee's 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 licensee's 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 licensee's 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 licensee's 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 licensee's 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

Main article: IP 71111.22

.1 Surveillance Testing

a. Inspection Scope

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

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.

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

2RS5 Radiation Monitoring Instrumentation

Main article: IP 71124.05

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

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 licensee's 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 licensee's 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 licensee's 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 licensee's actions to assess and correct the trend. The inspectors review included an assessment of the licensee's corrective actions associated with the following documents:

AR 01920169: "Declining Trend in [human performance] HU for Operation's 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 operation's 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 operation's 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 licensee's corrective actions will be effective and produce sustainable results. The inspectors' semi-annual trend review also included assessing the licensee's progress in addressing the emerging cross-cutting theme in the aspect of P.2, Evaluation. The inspectors review included an assessment of the licensee's corrective actions associated with RCE 01954549, "Cross-cutting Theme for Aspect P.2, Evaluation." The licensee's 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 licensee's past operability determination (POD) associated with the NCV in Section 1R20. During the inspector's review of the licensee's 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 licensee's 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 licensee's 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 licensee's 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 licensee's 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, CLOSED AND DISCUSSED

Opened

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

05000266/2014003-02

05000301/2014003-02 NCV Age Related Relay Failures Result in Inoperable Inverters (Section 4OA2.4)

Closed

05000266/2014003-01

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

05000266/2014003-02

05000301/FIN-2014003-02 NCV Age Related Relay Failures Result in Inoperable Inverters (Section 4OA2.4)

05000266/2011003-02

05000301/FIN-2011003-02

URI Seismic Qualification of the Qualification of the Condensate Storage Tank and Related Flooding Barriers

(Section 1R15.2)

05000266/2011003-03;

05000301/FIN-2011003-03 URI RHR Pump Operability With Tanks In Auxiliary Building Not Seismically Qualified (Section 1R15.3)

LIST OF DOCUMENTS REVIEWED

The following is a partial list of documents reviewed during the inspection.

Inclusion on this list does not imply that the NRC inspector reviewed the documents in their entirety, but rather that selected sections or portions of the documents were evaluated as part of the overall inspection effort.

Inclusion of a document on this list does not imply NRC acceptance of the document or any part of it, unless this is stated in the body of the inspection report. 1R01 Adverse Weather Protection (71111.01) -

AOP 13-C; Severe Weather Conditions -

OP-AA-102-1002; Seasonal Readiness; Revision 3

- OP 2B; 345 KV Transmission System Impacts Upon PBNP Station Operations; Revision 8 1R04 Equipment Alignment (71111.04) - Drawing 110E029 Sheet 1; Auxiliary Coolant System; Revision 55 - Drawing 110E035 Sheet 1; Safety Injection System; Revision 54 - Drawing 110E035 Sheet 2; Safety Injection System; Revision 56

- Drawing M-209; Sheet 12; E.M Diesel Air Starting System; Revision 22

- Drawing M-217; Sheet 1; Auxiliary Feedwater System; Revision 99

- Drawing M-219; Sheet 1; Fuel Oil System; Revision 50

- Drawing M-219; Sheet 2; Fuel Oil System; Revision 14 -

IT 45 Train B; Safety Injection Valves Train B Unit 2; Revision 3 - Procedure

CL 13E Part 1; Auxiliary Feedwater Valve Lineup Turbine-Driven; Revision 26 1R05 Fire Protection (71111.05) -

AR 01290079; Treatment of Safe Shutdown Manual Actions During NFPA 805 TR -

AR 01318680;

RIS 2006-10 Noncompliant SSD Man. Actions Fire Areas A23N/S

-

AR 01347157; Appendix R Common Enclosure Unanalyzed Condition

-

AR 01875052;

NFPA-805 Electrical Review Short Time Pick-up Concerns

-

AR 01934302; Needs Improvement Items From Crew E Fire Drill -

AR 01937223; Operations Assuming Fire Rounds Responsibility From Security -

AR 01937527; Control Building Fire Door-75 Has 3/4 inch by 6 Foot Air Gap -

AR 01940308; Needs Improvement Identified on Fire Drill

-

AR 01953811; DGB Door 601 Not Closing Properly

-

AR 01957740; Door-140 Aux BLDG To Unit 1 Façade Door Seal Damaged

-

AR 01963382; Door 485, D-105 Battery Room, Does Not Close Under Own Force -

CE 01934302; Needs Improvement Items From Crew E Fire Drill - FEP 4.10; Auxiliary Building - EL. 46' CCW HX Room, GS Equipment Room; EL. 26' Truck Access, Drum Prep; Revision 8 - FEP 4.12; Auxiliary Feedwater Pump and Vital Switchgear Area; Revision 9

- FHAR Fire Hazards Analysis Report; Revision 6

- Fire Round Performance Sheet - Miscellaneous Areas for June 22, 2014; Four Hour Rounds - Fire Round Performance Sheet - PAB for June 22, 2014; Four Hour Rounds - Fire Round Performance Sheet - PAB for June 22, 2014; One Hour Rounds

- Fire Round Performance Sheet - Turbine Hall for June 22, 2014; Four Hour Rounds

- Fire Round Performance Sheet - Turbine Hall for June 22, 2014; One Hour Rounds

- NP 1.9.9; Transient Combustible Control; Revision 25 - OM 3.27; Control of Fire Protection & Appendix R Safe Shutdown Equipment; Revision 52

-

PBC-219 Sheet 26; Fire Emergency Procedure 4.12 Turbine Building & Aux Building Elev. 8' - 0"; Revision 12 -

PBC-219 Sheet 41; Fire Emergency Procedure 4.19 Circulating Water Pumphouse; Revision 3 - Reader Transaction History for Cable Spreading Room Doors; June 16, 2014 to June 23, 2014 - Reader Transaction History for Operation's Fire Technicians on June 22, 2014 1R06 Flooding (71111.06) - Letter from U.S. Atomic Energy Commission to Wisconsin Electric Power Company Containing Internal flood Protection Guidelines; dated December 10, 1974 - NRC Safety Evaluation to Point Beach; Regarding The Potential for Flooding From Postulated Ruptures of Non-Category I (Seismic) Systems; dated November 20, 1975

-

AR 01948109; Internal Flooding Hazards in PAB Not Fully Evaluated

1R07 Annual Heat Sink Performance (71111.07) -

AR01837285;

HX-13A Spent Fuel Pool Heat Exchanger Has Leak -

AR01884793; Indications of Bio-fouling on

HX-12C Outlet Tubesheet -

AR01897256;

HX-13B Has Areas Below Trigger Value

-

AR01902506; SW Chlorination Frequency Requirements Not Met Per NP 3.2.7

-

AR01912411; SW Chlorination Frequency Requirements No[t] Met Per NP 3.2.7

-

AR01935356; No Urgency For Fixing Chlorination Leaks -

GL 89-13 Program Document; Revision 11 - NP 3.2.7; Service/Circulating Water Monitoring and Bio-fouling Program; Revision 2

- NP 3.2.8; Open Cooling Water Systems Optimization Plan; Revision 0

- NP 7.7.15; Bio-fouling Control Methods; Revision 8

-

OI 155; Chemical Treatment of Service Water For Mussels; Revision 38

-

OI 155A; Continuous Chlorination of Service Water For Mussel Control; Revision 1

-

PBF-7061; Bio/Silt Fouling Inspection Form; Revision 2; Completed Feb 11, 2014 for

HX-55B 1R11 Licensed Operator Requalification Program (71111.11) -

FP-T-SAT-81; Simulator Testing And Documentation; Revision 8 -

OP-AA-100-100; Conduct of Operations; Revision 3 -

OP-AA-100-1000; Conduct of Operations; Revision 14

- OP 1A; Cold Shutdown to Hot Standby Unit 2; Revision 7

- OP 5B; Blender Operation/Dilution/Boration; Revision 40

- OP 7B; Removing A Train Residual Heat Removal System from Operation; Revision 51 -

OP 13A Unit 2; Secondary System Startup Unit 2; Revision 9 1R12 Maintenance Effectiveness (71111.12) - 1RMP 9036-2; 1DY-01 Channel Instrument Bus Static Inverter Maintenance Procedure; Revision 8 -

ACE 01935654 01; 1DY-02, Blue Inverter auto swapped to Back-up power supply -

AR 01911043; Blue Inverted

DY-0B failed to start after PM Work Completed -

AR 01935654; 1DY-02, Blue Inverter auto swapped to Back-up power supply

-

AR 01948719; 2DY-02 Blue Inverter shifted to standby power

-

AR 01948729; 2N-31 No Counts After Energization

-

AR 01948731; 2N-31 Indication Did Not Come Up 2R33 Shutdown -

AR 01957729; 2N-40A WR Gammametrics Indicator Failed Low

-

AR 1952186; 2DY-02 Swapped to Bypass Source Power Unexpectedly -

CR 01948719 04; Change Request Approval; March 22, 2014

-

ER-AA-100-2002; Maintenance Rule Program Administration; Revision 1 -

FP-PE-PM-01; Preventative Maintenance Program; Revision 3 - Function list for NI Nuclear Instrument; August 10, 1995

- Function list for Y Vital Instrument Bus 120 VAC; August 10, 1995

- Maintenance Rule (a)(1) Action plan; System Y; May 5, 2014

- NP 7.7.4; Scope and Risk Significant Determination for the Maintenance Rule; Revision 23

- NP 7.7.5; Maintenance Rule Monitoring; Revision 24 - NP 7.7.7; Maintenance Rule Periodic Evaluation; Revision 6 -

OP-AA-108; Oversight and Control of Operator Burdens; Revision 1

-

PBF-7029; Maintenance Rule Performance Criteria, Nuclear Instruments (NI); June 28, 2012

-

PBF-7029; Maintenance Rule Performance Criteria, Vital 120 VAC (Y); September 22, 2010

- Performance Criteria assessments for NI as of April 29, 2014 - Performance Criteria assessments for Y as of April 23, 2014 - UFSAR 2013

- UFSAR; Appendix A; 2013 - Vendor Manual 01446 1R13

Maintenance Risk Assessments and Emergent Work Control (71111.13) - 1ICP 13.016L; Reactor Protection and Safeguards Analog Racks Containment Pressure 18 Month Calibration; Revision 7 - Control Room Logs; May 28, 2014

-

CSP-ST.0 Unit 1;Critical Safety Function Status Trees; Revision 7 - Daily Morning Production Meeting Package; May 27, 2014 - Daily Morning Production Meeting Package; May 28, 2014

-

NP 10.3.7; On-Line Safety Assessment; Revision 33

-

OP-AA-102-1003; Guarded Equipment; Revision 4

-

RMP 9046-1; Station Battery 92 Day 12 Month Surveillance Tests - Unit 1 Risk Safety Monitor for May 27, 2014 - Unit 1 Risk Safety Monitor for May 28, 2014 - Unit 2 Risk Safety Monitor for May 28, 2014 1R15 Operability Determinations and Functional Assessments (71111.15) -

AR 01633384; IER1 11-1 Unanalyzed Challenge From Non-Seismic Int Flooding -

AR 01813170; Issues Identified in Calk N-93-058 (DC Calk for D-105)

-

AR 01904519; Action Plan for URI on Seismic Tanks

-

AR 01915750; Extent of Condition Review Calk N-93-059 (DC Calk door D-106)

-

AR 01948109; Internal Flooding Hazards in PAB Not Fully Evaluated

-

AR 01950740; DC Calculation Issues Identified -

AR 01968602; P-32C SW Pump Failed to Auto Start or Manually Start -

AR 01969003; Mis-Operation of 1B52-494

-

AR 01969108;

FP-3742 Failed to Stroke During Performance of 0-PT-FP-006

-

AR01909269; SW Pump Anchor Bolt Replacement for the New SW Pumps

-

AR01951778; P-32E Sole Plate, Anchor and Grout As Found Condition -

AR01952142; As-Found Condition of P-32E Anchors - Calculation 2011-0010; Reinforce Masonry Wall on the East Side of the Non-Vital Switchgear Room; Revision 0 - Calculation 2014-0006; Lateral Loads on Service Water Pump Anchorage; March 27, 2014

- Drawing EPB31EDCK000002; Single Line Diagram 125 Volt D.C. System; Revision 19 - FSAR Appendix A.7; Internal Flooding; 2013

- Letter from U.S. Atomic Energy Commission to Wisconsin Electric Power Company Containing Internal flood Protection Guidelines; December 10, 1974 - Letter from U.S. Atomic Energy Commission to Wisconsin Electric Power Company; Subject: Flooding Resulting From Failures of Non-Category I Equipment; September 26, 1972 - Letter from U.S. NRC to Wisconsin Electric Power Company; Subject: Seismic Qualification of the Auxiliary Feedwater System at Point Beach Nuclear Plant, Units 1 and 2;

September 16, 1986 - Letter from U.S. NRC to Wisconsin Electric Power Company; Subject:

Generic Letter 81-14 Request for Additional Information; January 1982 - Letter from U.S. NRC to Wisconsin Electric Power Company; Subject:

Generic Letter 81-14; January 16, 1985 - Letter from U.S. NRC to Wisconsin Electric Power Company; Subject:

Request for Additional Information; September 29, 1975 - Letter from Wisconsin Electric Power Company to U.S. NRC; Flooding Resulting From Failures of Non-Category I Equipment; April 28, 1975 - Letter from Wisconsin Electric Power Company to U.S. NRC; Flooding Resulting From Failures of Non-Category I Equipment; October 24, 1975 - Letter from Wisconsin Electric Power Company to U.S. NRC; Flooding Resulting From Non-Category I Failure; February 17, 1975 - Letter from Wisconsin Electric Power Company to U.S. NRC; Subject:

Generic Letter 81-14; July 16, 1981 - Letter from Wisconsin Electric Power Company to U.S. NRC; Subject:

Generic Letter 81-14 Seismic Qualification of Auxiliary Feedwater Systems; April 26, 1985 - Letter from Wisconsin Electric Power Company to U.S. NRC; Subject:

Generic Letter 81-14; July 16, 1981 - Meeting Notes Generic Letter 81-14 Seismic Qualification of Auxiliary Feedwater Systems; December 19, 1985 - Modification 83-046*A; -19' Sump Indication; June 13, 1991 - NRC Safety Evaluation to Point Beach; Regarding The Potential for Flooding From Postulated Ruptures of Non-Category I (Seismic) Systems; dated November 20, 1975 -

POD 01947039; Increase in Load Profile for D-106 & D-305 Supplying D-04; March 15, 2014

-

POD 01952174; Battery Testing Non-Conforming to CLB Requirements; April 9, 2014

-

RMP 9046-1; Station Battery 92 Day 12 Month Surveillance Tests; May 27, 2014

- Task Interface Agreement - Evaluation of Application of Technical Specification 4.0.3, "Surveillance Requirement Applicability," at Pilgrim (TIA2008-004) -

TI 2515/88; Inspection of the Licensee's Actions Taken to Implement NRC Guidelines For Protection From Flooding of Equipment Important to Safety; April 6, 1987 - U.S. NRC; Standard Review Plan; Section 3.4.1; Flood Protection; Revision 2 - July 1981

- Wisconsin Electric Power Company Point Beach Nuclear Plants Units 1 & 2 USNRC USI A-46 Resolution; Section 2; June 1995 -

WO 40202962-01; D-106, Battery M2PT Discharge Test; August 30, 2013 1R18 Plant Modifications (71111.18) -

AOP-10A; Safe Shutdown - Local Control; Revision 66 -

AR 01958056; 2P-29 Outboard Packing Has Less Than Ideal Leakage -

AR 01958060; Unexpected Acceleration of 2P-29 TDAFP During

PBTP-255 Testing

-

AR 01958070; 2P-29 Failed to Start During PBTP 255

-

AR 01959281; Too Fast Stroke Time of 2MS-2020

-

CSP-H.1 Unit 2 Red; Response To Loss of Secondary Heat Sink -

EC 272529; Unit 2 Auxiliary Feedwater Pump Turbine Replacement -

PBTP-255; 2P-29 Turbine Driven Auxiliary Feed Pump Site Acceptance Criteria; Revision 1 -

QF-1010-01a; Needs Assessment Worksheet; AFWP Turbine Replacement Project; March 21, 2014 -

TWR 01747309; OPT Actions For TDAFW Pump Turbine and Governor Replacement - TWR Simulator Report; June 23, 2014 1R19 Post-Maintenance Testing (71111.19) -

AR 01893787; (P)

PC 29 - Gas Turbine and Auxiliary Diesel Load -

AR 01958773; 2p-29 Unexpected Deceleration During Testing

-

AR 01958970; Question on New AFP Steam Supply Piping

-

AR 01958978; U2R33 TDAFWP Testing Review PORC Meeting -

AR01919510;

IT 12 Train B - 1P-11B, Component Cooling Water -

AR01955068; P-032E SW Pump Vibration Accelerometers Not Working

-

AR01955461; 2MS-2020-O MOV Failed to Open Completely

-

AR01967398; Immersion Heater Does Not Appear To Be Working

-

AR01968529; 1P-11B Inboard Pump Oiler Bulb Excessive Vibration

- Certificate of Calibration; M&TE

CEAC-019; June 11, 2014 - Certificate of Calibration; M&TE

OPSDT-005; Stroboscope; October 9, 2013 -

IT 12 Train B; 1P-11B, Component Cooling Water Pump and Valves Unit 1; Revision 6

-

MA-AA-101-1000; FME Guidance; Revision 10

- PBTP 255; 2P-29 Turbine Driven Auxiliary Feed Pump Site Acceptance Test; Revision 1

-

PC 29; Gas Turbine and Auxiliary Diesel Load Test; Revision 57 -

RMP 9021-1; Gas Turbine Generator G-05 and Auxiliary Equipment Mechanical Preventive Maintenance; Revision 19 -

RMP 9021-2; Gas Turbine Generator G-05 and Auxiliary Equipment Maintenance; Revision 11

-

WO 40241051; G-05 Two Year Electrical Inspection

-

WO 40276980; G-05 Annual Electrical Inspection -

WO 40277267; 1P-11B Change Oil, Flush Bearings and Clean Intake Grills -

WO 40288601; Group E Mechanical Maintenance Items 1R20 Outage Activities (71111.20) - 2-PT-CC-2; Component Cooling Water System Pressure Test - Inside Containment

Unit 2 ; Revision 4 - 2-PT-RCS-1; Reactor Coolant System Pressure Test - Inside/Outside Containment Unit 2; Revision 5 -

ACE 01956941; Bus Section 4 Lockout When Attempting to Re-Energize 2X-01

-

ACE 01968076; NRC Proposed NCV - Containment Debris

-

ACE 01969278; Past Operability Review for

AR 01958167 in Error -

AR 01892251; FSAR Revision For Containment Dome Trusses -

AR 01949761; Chlorination Line Contacted During P-32E Motor Removal

-

AR 01951381; Load Deflection Fuel Assembly KK69

-

AR 01951425; Fuel Assembly Load Deflection

-

AR 01953955; Rod Latch Load Defection Not As Expected -

AR 01954652; As Found Conditions with the Unit 2 Containment Dome Truss -

AR 01955106;

IT 02A Test Unsat

-

AR 01955834; Unit 1 Containment Dome Truss Extent of Condition

-

AR 01957414; NRC Resident Items Noted U2 Containment U235

-

AR 01958153; Items Were in Containment After Mode Change -

AR 01958167; NRC Identified Items In Unit 2 Containment

-

AR 01959449; U2 IRPIS Fail Flux Map Review Criteria -

AR 01975950; Reportable Condition Due to Both Trains of ECCS Inop. - Background Information For Westinghouse Owners Group Emergency Response Guidelines; Generic Issue: Natural Circulation; HP/LP-Rev.2; April 30, 2005 - BG

SEP-2.1; Shutdown LOCA with RHR Aligned for Low Head Injection; Background Document; Revision 17 - Calculation 66-9093957; Point Beach Test Report for ECCS Strainer Performance Testing; Revision 2 - Calculation

CN-CPS-07-2; Pressurizer Water Level Instrumentation Setpoint & Uncertainty Calculation; Revision 3 - Calculation

CN-NO-07-3; Point Beach Natural Circulation Cooldown Evaluations for Time to Residual Heat Removal (RHR) Cut In To Support the MWt Uprating; Revision 1 - Calculation

CN-NO-08-5; Point Beach Units 1 & 2 Appendix R and Main Steam Line Break (MSLB) Cooldown Evaluations to RHR Cut-In Conditions for the 1800 MWt Uprating;

Revision 0 - Calculation N-89-040; Accuracy of Level Indication From

LT-447; August 28, 1989

- Calculation

PBNP-IC-16; Average In-Core Temperature Instrument Loop Uncertainty Calculation; Revision 5 - Calculation

PBNP-IC-46; Pressurizer Level Loop Scaling; Revision 7

-

CE 01953955; Rod Latch Load Defection Not As Expected

-

CL 20A; Unit 2 Containment Closeout Inspection; Revision 2

- CL 2A; Defueled to Mode 6 Checklist; Revision 14; Completed on March 31, 2014

- CL 2B; Mode 6 to Mode 5 Checklist; Revision 14; Completed on April 5, 2014 - CL 2C; Mode 5 to Mode 4 Checklist; Revision 20 - CL 2C; Mode 5 to Mode 4 Checklist; Revision 20; Completed on April 12, 2014

- CL 2D; Mode 4 to Mode 3 Checklist; Revision 19; Completed on April 13, 2014

- CL 2E; Mode 3 to Mode 2 Checklist; Revision 21; Completed on April 17, 2014

- CL 2E; Mode 3 to Mode 2 Checklist; Revision 21; Completed on May 1, 2014 - CL 2F; Mode 2 to Mode 1 Checklist; Revision 20; Completed on April 17, 2014 - CL 2F; Mode 2 to Mode 1 Checklist; Revision 20; Completed on May 1, 2014

- Clearance Coversheet and Tag List; Clearance 2 AF P-29 R/R; April 12, 2014

- Clearance Coversheet and Tag List; Clearance 2

OP-3C Accum Outlet; April 12, 2014

- Clearance Coversheet and Tag List; Clearance 2

OP-3C P-15A; April 12, 2014

- Control Room Logs; April 12, 2014 through April 14, 2014 - Daily PBNP Shutdown Safety Assessment and Fire Condition Checklists for Outage 2R33 -

EC 280227; Figure 2: Point Beach Unit 2 Cycle 34 Reference Core Loading Pattern

-

EOP-0.2 Unit 2; Natural Circulation Cooldown; Revision 29

-

IT 04A; RHR Pump and Valve Test in DHR Mode (Cold Shutdown) Unit 2; Completed March 31, 2014 - NP 7.2.28; Containment Debris Control Program; Revision 5 -

OP-AA-100-100; Conduct of Operations; Revision 3

-

OP-AA-103-1000; Reactivity Management; Revision 2

-

POR 01958167; NRC Identified Items In Unit 2 Containment; June 9, 2014

-

POR 01958167; NRC Identified Items In Unit 2 Containment; May 8, 2014

- RESP 7.1; Fuel Assembly Storage Verification; Revision 3 -

ROD 11; Core Layout Information; Revision 21 -

SEP-2.1; Shutdown LOCA with RHR Aligned for Low Head Injection; Revision 19

- Spent Fuel Pool Map; May 13, 2014

-

WO 40095478; 2ICP 4.3-1 - Pressurizer Level XMTR Cal -

WO 40095482; 2ICP 4.4-1 - RCS Pressure Transmitter Outage Cal

-

WO 40095496; 2ICP 5.61 - Pressurizer Cold Level Transmitter Outage Cal

-

WO 40208260; 2ICP 5.64 - Reactor Vessel Level Transmitters Outage Cal 1R22 Surveillance Testing (71111.22) - 2009-0076; Changes to

IT 07F Following Replacement/Re-baseline of P-32F SW Pump; May 15, 2009 -

IT 05 Train A; Train A Containment Spray Pump and Valves Unit 1; Revision 2; Completed on May 23, 2014 -

IT 07F; P-32F Service Water Pump (Quarterly); Revision 33; Completed on May 14, 2014

- IT 4 U2; Safety Injection Valves (Quarterly) Unit 2, 2SI-857A; February 14, 1999

-

IT 45 Train A; Safety Injection Valves Train A Unit 2; Revision 2 -

MWR 940388; 2SI-846, Valve Stroke Verification; February 24, 1994 -

OI 55; Primary leak Rate Calculation; Revision 28

- OM 3.19; Reactor Coolant System Leakage Determination; Revision 7

- ORT 3A; Safety Injection Actuation With Loss of Engineered Safeguards AC (Train A) Unit 2; Revision 44 - PBF - 2131; Control Room Miscellaneous Shift Log-Modes 1-3 Unit 1; Revision 15 - Point Beach Unit 2 Cycle 34 RSE; Revision 0 - RESP 4.1; BOL Physics Tests; Revision 27

-

SCR 2007-0073; Revisions to

IT 05 and

IT 05B Following Re-baseline of 1P-14A Containment Spray Pump; April 27, 2007 -

SCR 2007-0225; Revisions to

IT 45,

IT 45B and

IT 536 Following 2SI-850A Solenoid Replacement; December 19, 2007 -

SCR 2010-0154;

IT 07F, Re-baseline of P-32F Service Water Pump After Analysis; July 7, 2014 -

SCR 2011-0085; 1/2SI-860A/C Acceptance Criteria for Stroke Time to Closed Position; May 19, 2011 -

SCR 2012-0170; Changes to

IT 07F Following Analysis of P-32F Service Water Pump Performance; October 30, 2012 -

WO 9404483; 2SI-866A, Valve Stroke Verification; October 24, 1994

-

WO 9407945; 2SI-851A, Valve Stroke Verification; October 12, 1994 -

WO 9408677; 2SI-896A, Valve Stroke Verification; October 11, 1994 1EP6 Drill Evaluation (71114.06) -

OP-AA-100-100; Conduct of Operations; Revision 3 - EPIP 1.2; Emergency Classification; Revision 52

- EPIP 1.2.1; Emergency Action Level Technical Basis; Revision 14 - EPIP 1.3; Dose Assessment and Protective Action Recommendations; Revision 46 2RS5 Radiation Monitoring Instrumentation (71124.05) - HPCAL 3.2; Area Monitor Calibration Procedure DA 1-1 and DA 1-6 Detector Assemblies; December 19, 2012 - HPCAL 3.11; Containment High Range Detector Response Check; various - HPCAL 3.4; SPING Calibration; August 30, 2013

- HPCAL 3.7; Steam Line Radiation Monitor Calibration; April 12, 2013

- HPCAL 3.5; ING Calibration; December 19, 2012

- HPCAL 3.1.8; 1(2)

RE-219 Monitor Calibration; September 25, 2012 - HPIP 7.51; Monthly Check of the Radiation Monitoring System; Revision 16

- NP 3.2.1; PBNP analytical Quality Assurance Program; Revision 21 - HPCAL 1.1; Radiation Protection Instrument Calibration, Repair, and Response Checks; Revision 33 - CAMP 300; MCA Calibrations and Quality Assurance; Revision 16

-

PBF-4055b; GEM Calibration Sheet; February 3, 2014

-

PBF-4055a; ARGOS 5AB Calibration Sheet; January 25, 2014

-

PBF-4085u;

AMS-4 Calibration Sheet; January 21, 2014 -

PBF-4085j; Ludlum 3 Calibration Sheet; January 21, 2014 -

PBF-4085ff; iSolo Calibration Sheet; November 8, 2013

-

PBF-4085x; TelePole W2 Calibration Sheet; December 9, 2013

-

PBF-4085y;

RO-20 Calibration Sheet; February 28, 2014

- HPCAL 2.15; Small Articles Monitor Type

SAM-9/11 Calibration and Efficiency - Calibration of the Canberra FastScan WBC System; November 20, 2013 -

AR 01752246; Telepole "As-Found" Cal Factors Different Than As Left

-

AR 01832936; Telepole Calibration Factors Found Changed

-

AR 01815540;

AMP-50 Cal Factors

-

AR 01927358; IDC Dosimeter Calibrator Produced Uncharacteristic Results -

AR 01802963; RP Calibrator V&V Data Point Failure -

AR 01889918; RMS Detector Setpoint Concerns 4OA1 Performance Indicator Verification (71151) -

NEI 99-02; Regulatory Assessment Performance Indicator Guideline; Revision 6; - NP 5.2.16; NRC Performance Indicators; Revision 18 - NRC Occupational Exposure Performance Indicator Data; Various Dates

- PB Unit 1; Reactor Coolant System Leakage; 1Q2014

- Performance Indicators; Reactor Coolant System Leakage, Units 1 And 2; 2Q/2013 to 1Q/2014 - PI Data; April 1, 2013 to March 31, 2014 4OA2 Identification and Resolution of Problems (71152) - 1RMP 9036-2; 1DY-01 Channel Instrument Bus Static Inverter Maintenance Procedure; Revision 8 -

ACE 01935654 01; 1DY-02, Blue Inverter Auto Swapped to Back-up Power Supply - Analysis of Failed K2 Relays; June 10, 2014

-

AR 01762802; Unit 1 Yellow Inverter transferred to Non-Safeguard P/S

-

AR 01875289; DY0B Blue Inverter Swapped to Backup Power

-

AR 01910204; Cognitive Trend - 1(2)RE-216 Lake Grass Fouling

-

AR 01911043; Blue Inverted

DY-0B Failed to Start After PM Work Completed -

AR 01918688; RM System Health Report is Yellow for Q4 -

AR 01920169; Declining Trend in HU For Operations Field Activities

-

AR 01921089; Recent Decline in Operations Performance

-

AR 01922273; Potential Trend - CR Initiation Rate

-

AR 01922287; Potential Trend - Reactivity Management Events -

AR 01922342; Potential Trend - Anonymous Condition Reports -

AR 01929649; Common Cause Needed For OPS ACEs/RCE in 2013 - Adverse Trend

-

AR 01931972; Cognitive Trend - Flow Switch Issues

-

AR 01933277; Reactivity Challenges in 4Q13

-

AR 01935654; 1DY-02, Blue Inverter Auto Swapped to Back-up Power Supply -

AR 01937025; Operation Human Performance Has Been Declining Since Q4 2013

-

AR 01937570; Cognitive Trend: 1(2)P-15A/B Dropped Flags -

AR 01937603; Cognitive Trend: HU Events at PBN -

AR 01940754; Procedure Conflicts and Tech Spec Non-Complaince

-

AR 01943408; Pressurizer Level Not Adequate for License Requirements

-

AR 01943702; Declining Trend in Procedure Use & Adherence in Maintenance

-

AR 01943977; Equipment Reliability - Infant Mortality

-

AR 01945658; Increase in PBNP Anonymous Condition Report Submittals -

AR 01948719; 2DY-02 Blue Inverter Shifted to Standby Power -

AR 01948729; 2N-31 No Counts After Energization

-

AR 01948731; 2N-31 Indication Did Not Come Up 2R33 Shutdown

-

AR 01952186; 2DY-02 Swapped to Bypass source power unexpectedly

-

AR 01957729; 2N-40A WR Gammametrics Indicator Failed Low -

AR 01958472;

ECA-0.0 Unit 1 Missing Step 6.a in Rev 59 -

AR 01958542;

ECA-0.0 For Both Unit s Has Incorrect Steps

- AR Searches for Keyword; Rework; Dates: October 1, 2013 through June 16, 2014

-

CCE 01929649; Common Cause Needed for OPS ACEs/RCE in 2013 - Adverse Trend

- Condition Evaluation

011615954 01; December 10, 2009 -

CR 01948719 04; Change Request Approval; March 22, 2014 -

DBD-17; Vital 120 VAC System Design Basis Document; February 9, 2009

-

ECA-0.0 Unit 1; Loss of AC Power; Revision 59

-

ECA-0.0 Unit 1; Loss of AC Power; Revision 60

-

ECA-0.0 Unit 2; Loss of AC Power; Revision 62

-

FP-PE-PM-01; Preventative Maintenance Program; Revision 3 - Function list for Y Vital Instrument Bus 120 VAC; August 10, 1995 - Maintenance Rule (a)(1) Action Plan; System Y; May 5, 2014

-

OP-AA-108; Oversight and Control of Operator Burdens; Revision 1

-

PBF-7029; Maintenance Rule Performance Criteria, Vital 120 VAC (Y); September 22, 2010

- Performance Criteria Assessments for Y as of April 23, 2014 - Point Beach Unit 1 Top 10 Equipment Reliability Issues List; June 10, 2014 - Point Beach Unit 2 Top 10 Equipment Reliability Issues List; June 10, 2014

-

RCE 01954549; Cross-cutting Theme For Aspect P.2, Evaluation

- Training Needs Analysis; Declining Trend in HU for Operations Field Activities; January 31, 2014 - UFSAR 2013

- Vendor Manual 01446

LIST OF ACRONYMS

USED [[]]

AC Alternating Current

ACE Apparent Cause Evaluation

ADAMS Agencywide Document Access Management System

AFW Auxiliary Feedwater System

AR Action Request

CAP Corrective Action Program

CCA Common Cause Analysis

CCW Component Cooling Water

CFR Code of Federal Regulations

CST Condensate Storage Tank

DRP Division of Reactor Projects

FSAR Final Safety Analysis Report

HU Human Performance

IEEE Institute of Electrical and Electronics Engineers

IMC Inspection Manual Chapter

IP Inspection Procedure

LOCA Loss of Coolant Accident

NCV Non-Cited Violation

NEI Nuclear Energy Institute

NRC Nuclear Regulatory Commission

ODCM Off-Site Dose Calculation Manual

OSP Outage Safety Plan

PARS Publicly Available Records

PBNP Point Beach Nuclear Plant

PI Performance Indicator

POD Prompt Operability Determination

RC Reactor Coolant

RCE Root Cause Evaluation

RCS Reactor Coolant System

RFO Refueling Outage

RHR Residual Heat Removal

SDP Significance Determination Process

SQUG Seismic Qualification Users Group

SR Surveillance Requirement

SSC Structures Systems Component

TI Temporary Instruction

TS Technical Specification

TSO Transmission System Operator

URI Unresolved Item

VAC Volts Alternating Current

WO Work Order

E. McCartney -2-

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 cc w/encl: Distribution via LISTSERV

DISTRIBUTION w/encl: See next page

DOCUME NT NAME: Point Beach

IR 2014 003 Publicly Available Non-Publicly Available Sensitive Non-Sensitive To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy

OFFICE [[]]

RIII [[]]

NAME [[]]

JR utkowski:mt JCameron/RA Bruce Bartlett Acting for/

DATE 07/29/14 07/31/14

OFFICI AL

RECORD [[]]

COPY

Letter to Eric McCartney from Jamnes Cameron dated July 31, 2014

SUBJEC T:

POINT [[]]

BEACH NUCLEAR PLANT,

UNITS 1

AND [[]]

2 NRC [[]]

INTEGR ATED INSPECTION

REPORT 05000266/2014003; 05000301/2014003

DISTRIBUTION w/encl: Anthony Bowers

RidsNrrDorlLpl3-1 Resource

RidsNrrPMPointBeach RidsNrrDirsIrib Resource Cynthia Pederson

Darrell Roberts

Steven Orth

Allan Barker Carole Ariano Linda Linn

DRPIII [[]]

DRSIII Patricia Buckley Carmen Olteanu ROPreports.Resource@nrc.gov

@@ Line 2: / Line 2: @@
 | number = ML14212A428
 | issue date = 07/31/2014
-| title = 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
+| title = 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
 | author name = Cameron J L
 | author affiliation = NRC/RGN-III/DRP/B4

IR 05000266/2014003: Difference between revisions

Revision as of 10:08, 13 February 2018

Text

Dear Mr. McCartney:

Enclosure:

w/Attachment:

SUMMARY OF FINDINGS

NRC-Identified

Cornerstone: Mitigating Systems

Licensee-Identified Violations

REPORT DETAILS

REACTOR SAFETY

1R01 Adverse Weather Protection

.1 Readiness of Offsite and Alternate Alternating Current Power Systems

a. Inspection Scope

b. Findings

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

b. Findings

1R05 Fire Protection (71111.05Q and A)

.1 Routine Resident Inspector Tours

a. Inspection Scope

b. Findings

.2 Annual Fire Protection Drill Observation

a. Inspection Scope

b. Findings

1R06 Flooding

.1 Internal Flooding

a. Inspection Scope

b. Findings

1R07 Annual Heat Sink Performance

.1 Heat Sink Performance

a. Inspection Scope

b. Findings

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

b. Findings

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

b. Findings

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

b. Findings

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

b. Findings

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

b. Findings

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

b. Findings

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing

a. Inspection Scope

b. Findings

1R20 Outage Activities

.1 Refueling Outage Activities

a. Inspection Scope

b. Findings

Introduction:

Description:

Analysis:

Enforcement:

.2 Other Outage Activities

a. Inspection Scope

b. Findings

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

b. Findings

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope