IR 05000255/2017003

NRC Integrated Inspection Report 05000255/2017003

ML17299A146
Person / Time
Site:	Palisades
Issue date:	10/25/2017
From:	Eric Duncan Region 3 Branch 3
To:	Arnone C Entergy Nuclear Operations
References
IR 2017003
Download: ML17299A146 (65)

Text

UNITED STATES October 25, 2017

SUBJECT:

PALISADES NUCLEAR PLANTNRC INTEGRATED INSPECTION REPORT 05000255/2017003

Dear Mr. Arnone:

On September 30, 2017, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your Palisades Nuclear Plant. On October 18, 2017, the NRC inspectors discussed the results of this inspection with you and other members of your staff. The enclosed report represents the results of this inspection.

Based on the results of this inspection, the NRC has identified one issue that was evaluated under the risk significance determination process as having very low safety significance (Green). The NRC has also determined that a violation is associated with this issue. Because condition reports were initiated to address this issue, this violation is being treated as a Non-Cited Violation (NCV), consistent with Section 2.3.2 of the NRC Enforcement Policy. This NCV is described in the subject inspection report. Further, the inspectors documented a licensee-identified violation which was determined to be of very low safety significance in this report. The NRC is treating this violation as a NCV consistent with Section 2.3.2 of the NRC Enforcement Policy.

If you contest the violation or significance 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 copies to: (1) the Regional Administrator, Region III; (2) the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and (3) the NRC Resident Inspector at the Palisades Nuclear Plant.

In addition, if you disagree with the cross-cutting aspect assignment to the finding discussed 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 Palisades Nuclear Plant. This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with 10 CFR 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely,

/RA/

Eric Duncan, Chief Branch 3 Division of Reactor Projects Docket No. 50-255 License No. DPR-20 Enclosure:

Inspection Report 05000255/2017003 cc: Distribution via LISTSERV

SUMMARY

Inspection Report 05000255/2017003, 07/01/2017 - 09/30/2017; Palisades Nuclear Plant;

Problem Identification & Resolution.

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

The finding involved a Non-Cited Violation (NCV) of U.S. Nuclear Regulatory Commission (NRC) requirements. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using Inspection Manual Chapter (IMC) 0609, "Significance Determination Process," dated April 29, 2015.

Cross-cutting aspects are determined using IMC 0310, "Aspects Within the Cross-Cutting Areas," dated December 4, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated November 1, 2016. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process," Revision

NRC Identified

and Self-Revealed Findings

Cornerstone: Mitigating Systems

Green.

A finding of very low safety significance and an associated NCV of Technical Specification (TS) 5.4.1, Procedures, was self-revealed on March 31, 2017, when the 1-2 Diesel Generator (DG) tripped during performance of monthly TS surveillance procedure MO-7A-2, Emergency Diesel Generator 1-2. Specifically, during conduct of the monthly surveillance procedure, restoration activities associated with maintenance of breaker 152-213, 1-2 DG to Bus 1D, were being performed. When maintenance personnel closed the trip cutouts for the Z-phase of the 1-2 DG differential overcurrent relay, an unbalanced current flow into the differential relay resulted in relay actuation.

This actuation resulted in a trip of the output breaker and subsequently the 1-2 DG. The trip caused a delay in the TS surveillance activities and resulted in the extended unavailability and inoperability of the 1-2 DG. The licensee entered this issue into their corrective action program (CAP) as condition report (CR) CR-PLP-2017-01291.

Corrective actions included retesting the 1-2 DG and updating the work instructions associated with the differential overcurrent relays to include caution statements that opening or closing trip cutouts for the relays while the output breakers from the DGs to the associated buses were closed could cause the differential relays to actuate and trip the DG.

The issue was determined to be more than minor in accordance with IMC 0612,

Appendix B, Issue Screening, because it was associated with the Mitigating Systems cornerstone attribute of Procedure Quality and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. The finding screened as having very low safety significance (Green) in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2, since the inspectors answered No to all screening questions. The finding had a cross-cutting aspect in the area of Human Performance, in the Work Management aspect, for the licensees failure to identify and manage risk commensurate to the work (H.5). (Section 4OA2)

Licensee-Identified Violations

A violation of very low safety significance or Severity Level IV that was identified by the licensee has been reviewed by the inspectors. Corrective actions taken or planned by the licensee have been entered into the licensee's CAP. This violation and corrective action tracking number is listed in Section 4OA7 of this report.

REPORT DETAILS

Summary of Plant Status

The plant began the inspection period operating at full power. The unit operated at or near full power for the entire inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

.1 Readiness for Impending Adverse Weather ConditionGeo-Magnetic Storm Forecast

a. Inspection Scope

A geo-magnetic storm disturbance with a K-index greater than or equal to seven with the potential to influence the plant was forecast on September 7, 2017. The inspectors reviewed the licensees preparations for the impending weather conditions and conducted independent walkdowns of the plants alternating current (AC) power systems. The inspectors verified that plant procedures for the reliability and continued availability of the offsite and onsite power systems were appropriate. The inspectors also reviewed the licensees communications protocols between the transmission system operator and the plant to verify that the appropriate information was being exchanged in a timely manner when issues arose to take any necessary actions. The inspectors reviewed corrective action program (CAP) items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into their CAP in accordance with station corrective action procedures. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• B high pressure safety injection train;

• B service water train; and

• alternate chemical and volume control system dilution pathway.

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, the Updated Final Safety Analysis Report (UFSAR), 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

.1 Routine Resident Inspector Tours

a. Inspection Scope

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

• Fire Areas 6 & 8: diesel generator (DG) 1-2 and fuel oil day tank rooms, elevation 590;

• Fire Areas 5 & 7: DG 1-1 and fuel oil day tank rooms, elevation 590;

• Fire Area 26: southwest cable penetration room, elevations 590 and 607;

• Fire Area 3: 1D switchgear room and north cableway, elevations 607 and 625';

and

• Fire Area 9: screenhouse, elevation 590.

The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.

The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event.

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

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

.2 Annual Fire Protection Drill Observation

a. Inspection Scope

On September 15, September 20, and September 27, 2017, the inspectors observed fire brigade activation drills for a fire in bus 1B. Based on these observations, 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;

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

• search for victims and propagation of the fire into other plant areas;

• smoke removal operations;

• utilization of pre-planned strategies;

• adherence to the pre-planned drill scenario; and

• drill objectives.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R06 Flooding

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk-important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the UFSAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. The inspectors also reviewed the licensees corrective action documents with respect to past flood-related items identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following plant areas to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable, and that the licensee complied with its commitments:

• Service water pump screenhouse.

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

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

Because the licensee reported finding several hundred gallons of water, some of which covered cables in Manhole 4, the inspectors elected to also perform an underground cable vaults inspection sample. This inspection sample is documented in Section 1R06.2.

b. Findings

No findings were identified.

.2 Underground Vaults

a. Inspection Scope

The inspectors selected underground bunkers/manholes subject to flooding that contained cables whose failure could disable risk-significant equipment. The inspectors determined whether the cables were submerged, whether splices were intact, and whether appropriate cable support structures were in place. In those areas where dewatering devices were used, such as a sump pump, the inspectors determined whether the device was operable and level alarm circuits were set appropriately to ensure that the cables would not be submerged. In those areas without dewatering devices, the inspectors verified that drainage of the area was available, or that the cables were qualified for submerged conditions. The inspectors also reviewed the licensees corrective action documents with respect to past submerged cable issues identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the following underground bunkers/manholes subject to flooding:

• Manholes 1, 2, 3, and 4.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one underground vaults sample as defined in IP 71111.06-05.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On August 22, 2017, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training. The inspectors verified that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and that training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal, alarm response, and emergency operating procedures;

• timely control board operation and manipulations;

• oversight and direction from supervisors;

• group dynamics involved in crew performance; and

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

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

This inspection constituted one quarterly licensed operator requalification program simulator sample as defined in IP 71111.11-05.

b. Findings

No findings were identified.

.2 Annual Operating Test Results

a. Inspection Scope

The inspectors reviewed the overall pass/fail results of the Annual Operating Test administered by the licensee from February 27, 2017 through March 30, 2017, required by Title 10 of the Code of Federal Regulations (CFR) 55.59(a). The results were compared to the thresholds established in Inspection Manual Chapter (IMC) 0609, Appendix I, Licensed Operator Requalification Significance Determination Process, to assess the overall adequacy of the licensees licensed operator requalification training program to meet the requirements of 10 CFR 55.59. (02.02)

This inspection constituted one annual licensed operator requalification examination results sample as defined in Inspection Procedure 71111.11-05.

a. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• emergency DGs; and

• charging system.

The inspectors reviewed events including those in which ineffective equipment maintenance had 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 inspector performed a quality review for the DGs, as discussed in IP 71111.12, Section 02.02.

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 one quarterly maintenance effectiveness sample and one quality control sample as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• Emergent work on the control rod secondary position indication system concurrent with LS-1453, 1-2 DG fuel oil day tank level switch, modification;

• emergent troubleshooting and repairs to ESR1 & ESR2, 1-1 DG engine start relays; and

• increased plant risk for planned 1-2 DG overspeed trip test, diving activities, and emergent door 15 (part of the control room heating, ventilation and air conditioning boundary) repairs.

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

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

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

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• operability of containment sodium tetraborate baskets after not meeting the acceptance criteria of the surveillance test; and

• immediate operability of 1-1 DG after failure of CV-0884B, 1-1 DG service water inlet valve, to close.

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

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

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing

a. Inspection Scope

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

• 1-2 DG operability run after overspeed trip test;

• reactor protection system (RPS) surveillance testing after RPS/AD3 matrix relay replacement;

• left channel load sequencer surveillance testing after replacement;

• functional testing of RPS breaker after replacement; and

• test start of B charging pump after troubleshooting and emergent maintenance of baffle packing and adjusters.

These activities were selected based upon the SSCs ability to impact risk. The inspectors evaluated these activities for the following (as applicable): the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the UFSAR, 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 five post-maintenance testing samples as defined in IP 71111.19-05.

b. (Open) Unresolved Item: Left Train Emergency Diesel Generator Load Sequencer Failure

Introduction:

The inspectors identified an Unresolved Item (URI) associated with the failure of the left train emergency DG load sequencer to run its program. Since this sequencer is required for left train DG operability, this condition resulted in an unanticipated entry into a TS shutdown action statement. The cause of this failure is currently unknown, pending the results of a vendor evaluation of a failed load sequencer component.

Description:

On August 3, 2017, the control room received alarm EK-1145, Sequencer Trouble, unexpectedly. The operators identified that the indication lights were not lit on the left channel load sequencer, MC-34L101; declared the associated DG inoperable; and entered the appropriate TS action statement. The failed sequencer was removed and replaced with a new module that was satisfactorily post-maintenance tested and the left train EDG was subsequently declared operable on August 4, 2017.

The failed sequencer was sent to an on-site lab for further troubleshooting. No obvious visual signs of failure were identified and the electrolytic capacitors in the module all tested satisfactorily. The module was then bench tested using a test program, which identified that although it would power up, no program would run. The licensee completed an equipment failure evaluation to review the bench test data, along with information collected in the failure modes analysis, and determined that the direct cause of the failure was a memory fault within the sequencer module that caused the sequencer to lock-up and not run its program. A fault in the memory module, memory processing interface circuitry, or the executive module could have caused the sequencer to lock up. At the end of the inspection period, further examination by the vendor was required and in progress to determine the exact initiating point of the fault.

In addition to replacing the failed sequencer, the licensees immediate corrective actions included inspecting the right train load sequencer and completing the quarterly surveillance test to ensure proper operation; the results of which were satisfactory. A plant operating experience review was conducted and did not identify any prior memory failures on the load sequencers. Once the vendors evaluation is complete, the licensee plans to re-assess the failure mechanism and any additional corrective actions required.

This item is considered unresolved, pending the inspectors review of the vendor analysis and any changes made to the equipment failure evaluation, to determine if this issue constitutes a performance deficiency and/or violation of NRC requirements.

(URI 05000255/2017003-01, Left Train Emergency Diesel Generator Load Sequencer Failure)c. (Open) Unresolved Item: Failure Mechanism of 42-2/RPS Reactor Protection System Breaker Failure to Open

Introduction:

The inspectors identified an URI associated with the failure mechanism of the 42-2/RPS control rod clutch breaker failure to open. Specifically, at the end of the inspection period the licensee was working to understand the cause of the breaker failure and determine the actions required to address the failure mechanism.

Description:

On May 17, 2017, the licensee conducted a shutdown to complete emergent repairs to a leaking seal identified on control rod drive mechanism 40. In accordance with GOP-8, Power Reduction and Plant Shutdown to Mode 2 or Mode 3 525°F, the operators depressed the reactor trip pushbutton from the EC-06, reactor protection system panel. When the pushbutton was depressed, the reactor did not trip as expected. The operators successfully tripped the reactor using the reactor trip pushbutton on the EC-02, primary process and reactor controls console. The licensee identified that the 42-1/RPS breaker tripped as expected when the reactor trip pushbutton on the EC-06 panel was depressed, however, the 42-2/RPS breaker did not trip as expected. This resulted in the reactor trip not occurring as expected when the reactor trip pushbutton on the EC-06 panel was depressed as both breakers are required to open to result in a reactor trip.

The licensee performed troubleshooting activities to determine the cause of the 42-2/RPS breaker failure. The direct cause of the breaker failure was found to be the 42-2/RPS breaker undervoltage release mechanism failing to provide enough downward force to fully depress the trip plunger. This resulted in a physical failure of the breaker to open. At the end of the inspection period, the cause of this physical failure mode was unknown. The licensees equipment failure evaluation identified that it could be age-related degradation or a physical degradation of the breaker. As a corrective action, a failure analysis of the breaker was planned. Once the failure analysis is complete, the licensee plans to re-assess the failure mechanism and determine any additional corrective actions that are required to address the issue. This item is considered unresolved, pending the inspectors review of the failure analysis and any changes made to the equipment failure evaluation, to determine if this issue constitutes a performance deficiency and/or violation of NRC requirements. (URI 05000255/2017003-02, Cause of 42-2/Reactor Protection System Breaker Failure to Open)

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

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

• RE-135, battery charger No. 3 performance test (routine);

• RT-191, low power physics testing (routine);

• QO-21A, A auxiliary feedwater surveillance (inservice test); and

• reactor coolant system (RCS) leak rate surveillance (RCS leak rate test).

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

• did preconditioning occur;

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

• were acceptance criteria clearly stated, sufficient to demonstrate operational readiness, and consistent with the system design basis;

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

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

• was measuring and test equipment calibration current;

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

• did test frequencies meet TS requirements to demonstrate operability and reliability;

• were tests performed in accordance with the test procedures and other applicable procedures;

• were jumpers and lifted leads controlled and restored where used;

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

• was test equipment removed following testing;

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

• was the unavailability of the tested equipment appropriately considered in the performance indicator (PI) data;

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

• was the reference setting data accurately incorporated into the test procedure;

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

• were problems identified during the testing appropriately documented and dispositioned in the licensees CAP;

• were annunciators and other alarms demonstrated to be functional and were setpoints consistent with design requirements; and

• were alarm response procedure entry points and actions consistent with the plant design and licensing documents.

This inspection constituted two routine surveillance testing samples, one in-service test sample, and one reactor coolant system leak detection inspection sample, as defined in IP 71111.22, Sections-02 and-05.

b. Findings

No findings were identified.

1EP2 Alert and Notification System Evaluation

.1 Alert and Notification System Evaluation

a. Inspection Scope

The inspectors reviewed documents, and conducted discussions with Emergency Preparedness (EP) staff and management regarding the operation, maintenance, and periodic testing of the back-up and primary Alert and Notification System (ANS) in Palisade Nuclear Plants plume pathway Emergency Planning Zone. The inspectors reviewed monthly trend reports and the daily and monthly operability records from July 2015 through July 2017. Information gathered during document reviews and interviews was used to determine whether the ANS equipment was maintained and tested in accordance with Emergency Plan commitments and procedures. Documents reviewed are listed in the Attachment to this report.

This ANS inspection constituted one sample as defined in IP 71114.02

b. Findings

No findings were identified.

1EP3 Emergency Response Organization Staffing and Augmentation System

.1 Emergency Response Organization Staffing and Augmentation System

a. Inspection Scope

The inspectors reviewed and discussed with plant EP management and staff the emergency plan commitments and procedures that addressed the primary and alternate methods of initiating an Emergency Response Organization (ERO) activation to augment the on-shift staff as well as the provisions for maintaining the plants ERO team and qualification lists. The inspectors reviewed reports and a sample of CAP records of unannounced off-hour augmentation drills and call-in tests, which were conducted from July 2015 through July 2017, to determine the adequacy of the drill critiques and associated corrective actions. The inspectors also reviewed a sample of the training records of approximately 15 ERO personnel who were assigned to key and support positions, to determine the status of their training as it related to their assigned ERO positions. Documents reviewed are listed in the Attachment to this report.

This ERO augmentation testing inspection constituted one sample as defined in IP 71114.03.

b. Findings

No findings were identified.

1EP5 Maintenance of Emergency Preparedness

.1 Maintenance of Emergency Preparedness

a. Inspection Scope

The inspectors reviewed a sample of nuclear oversight staff audits of the EP Program to determine whether these independent assessments met the requirements of 10 CFR 50.54(t). The inspectors also reviewed critique reports and samples of CAP records associated with the 2016 biennial exercise, as well as various EP drills conducted in 2015, 2016 and 2017 to determine whether the licensee fulfilled drill commitments and to evaluate the licensees efforts to identify, track, and resolve issues identified during these activities. The inspectors reviewed a sample of EP items and corrective actions related to the licensee's EP Program and activities to determine whether corrective actions were completed in accordance with the sites CAP.

Documents reviewed are listed in the Attachment to this report.

This correction of EP weaknesses and deficiencies inspection constituted one sample as defined in IP 71114.05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee EP drill on August 16, 2017, to identify any weaknesses or deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the control room simulator, technical support center, and operations support center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures. The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the CAP. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report.

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

b. Findings

No findings were identified.

2RS1 Radiological Hazard Assessment and Exposure Controls

.1 High Radiation Area and Very High Radiation Area Controls (02.06)

a. Inspection Scope

The inspectors assessed the controls for high radiation areas (HRAs) greater than 1 rem/hour and areas with the potential to become high radiation areas greater than 1 rem/hour for compliance with TSs and procedures.

These inspection activities supplemented those documented in IR 05000255/2017002 and constituted a complete sample as defined in IP 71124.01-05.

b. Findings

No findings were identified.

2RS5 Radiation Monitoring Instrumentation

.1 Walkdowns and Observations (02.02)

a. Inspection Scope

The inspectors assessed select portable survey instruments that were available for use for current calibration and source check stickers, and instrument material condition and operability.

The inspectors observed licensee staff demonstrate performance checks of various types of portable survey instruments. The inspectors assessed whether high-range instruments responded to radiation on all appropriate scales.

The inspectors walked down area radiation monitors and continuous air monitors to determine whether they were appropriately positioned relative to the radiation sources or areas they were intended to monitor. The inspectors compared monitor response with actual area conditions for selected monitors.

The inspectors assessed the functional checks for select personnel contamination monitors, portal monitors, and small article monitors to verify they were performed in accordance with the manufacturers recommendations and licensee procedures.

These inspection activities constituted one complete sample as defined in IP 71124.05-05.

b. Findings

No findings were identified.

.2 Calibration and Testing Program (02.03)

a. Inspection Scope

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

The inspectors reviewed the methods and sources used to perform whole body count functional checks before daily use and assessed whether check sources were appropriate and aligned with the plants isotopic mix. The inspectors reviewed whole body count calibration records since the last inspection and evaluated whether calibration sources were representative of the plant source term and that appropriate calibration phantoms were used. The inspectors looked for anomalous results or other indications of instrument performance problems.

The inspectors reviewed select containment high-range monitor calibration and assessed whether an electronic calibration was completed for all range decades, with at least one decade at or below 10 rem/hour calibrated using an appropriate radiation source, and calibration acceptance criteria was reasonable.

The inspectors reviewed select monitors used to survey personnel and equipment for unrestricted release to assess whether the alarm setpoints were reasonable under the circumstances to ensure that licensed material was not released from the site. The inspectors reviewed the calibration documentation for each instrument selected and discussed the calibration methods with the licensee to determine consistency with the manufacturers recommendations.

The inspectors reviewed calibration documentation for select portable survey instruments, area radiation monitors, and air samplers. The inspectors reviewed detector measurement geometry and calibration methods for portable survey instruments and area radiation monitors calibrated onsite and observed the licensee demonstrate use of the instrument calibrator. The inspectors assessed whether appropriate corrective actions were taken for instruments that failed performance checks or were found significantly out of calibration, and whether the licensee had evaluated the possible consequences of instrument use since the last successful calibration or performance check.

The inspectors reviewed the current output values for instrument calibrators. The inspectors assessed whether the licensee periodically measured calibrator output over the range of the instruments used with measuring devices that had been calibrated by a facility using National Institute of Standards and Technology traceable sources and whether corrective factors for these measuring devices were properly applied in its output verification.

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

These inspection activities constituted one complete sample as defined in IP 71124.05-05.

b. Findings

No findings were identified.

.3 Problem Identification and Resolution (02.04)

a. Inspection Scope

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

These inspection activities constituted one complete sample as defined in IP 71124.05-05.

b. Findings

No findings were identified.

2RS6 Radioactive Gaseous and Liquid Effluent Treatment

.1 Walkdowns and Observations (02.02)

a. Inspection Scope

The inspectors walked down select effluent radiation monitoring systems to evaluate whether the monitor configurations aligned with Offsite Dose Calculation Manual (ODCM) descriptions and to observe the material condition of the systems.

The inspectors walked down selected components of the gaseous and liquid discharge systems to evaluate whether equipment configuration and flow paths aligned with plant documentation and to assess equipment material condition. The inspectors also assessed whether there were potential unmonitored release points, building alterations which could impact effluent controls, and ventilation system leakage that communicated directly with the environment.

For equipment or areas associated with the systems selected for review that were not readily accessible, the inspectors reviewed the licensee's material condition surveillance records.

The inspectors walked down filtered ventilation systems to assess for conditions such as degraded high efficiency particulate air/charcoal banks, improper alignment, or system installation issues that would impact the performance or the effluent monitoring capability of the effluent system.

As available, the inspectors observed selected portions of the routine processing and discharge of radioactive gaseous effluents to evaluate whether appropriate treatment equipment was used and the processing activities aligned with discharge permits.

The inspectors determined if the licensee had made significant changes to their effluent release points.

As available, the inspectors observed selected portions of the routine processing and discharging of liquid waste to determine if appropriate effluent treatment equipment was being used, and whether radioactive liquid waste was being processed and discharged in accordance with procedure requirements and aligned with discharge permits.

These inspection activities constituted one complete sample as defined in IP 71124.06-05.

b. Findings

No findings were identified.

.2 Calibration and Testing Program (02.03)

a. Inspection Scope

The inspectors reviewed calibration and functional tests for select effluent monitors to evaluate whether they were performed consistent with the ODCM. The inspectors assessed whether National Institute of Standards and Technology traceable sources were used, primary calibration represented the plant nuclide mix, secondary calibrations verified the primary calibration, and calibration encompassed the alarm setpoints.

The inspectors assessed whether effluent monitor alarm setpoints were established as provided in the ODCM and procedures.

The inspectors evaluated the basis for changes to effluent monitor alarm setpoints.

These inspection activities constituted one complete sample as defined in IP 71124.06-05.

b. Findings

No findings were identified.

.3 Sampling and Analyses (02.04)

a. Inspection Scope

The inspectors reviewed select effluent sampling activities and assessed whether adequate controls had been implemented to ensure representative samples were obtained.

The inspectors reviewed select effluent discharges made with inoperable effluent radiation monitors and assessed whether controls were in place to ensure compensatory sampling was performed consistent with the ODCM and that those controls were adequate to prevent the release of unmonitored effluents.

The inspectors determined whether the facility was routinely relying on the use of compensatory sampling in lieu of adequate system maintenance.

The inspectors reviewed the results of the inter-laboratory comparison program to evaluate the quality of the radioactive effluent sample analyses and assessed whether the inter-laboratory comparison program included hard-to-detect isotopes as appropriate.

These inspection activities constituted one complete sample as defined in IP 71124.06-05.

b. Findings

No findings were identified.

.4 Instrumentation and Equipment (02.05)

a. Inspection Scope

The inspectors reviewed the methodology used to determine the effluent stack and vent flow rates to determine if the flow rates were consistent with plant documentation, and whether differences between assumed and actual stack and vent flow rates affected the results of the projected public dose.

The inspectors assessed whether surveillance test results for TS required ventilation effluent discharge systems met TS acceptance criteria.

The inspectors assessed calibration and availability for select effluent monitors used for triggering emergency action levels or for determining protective action recommendations.

These inspection activities constituted one complete sample as defined in IP 71124.06-05.

b. Findings

No findings were identified.

.5 Dose Calculations (02.06)

a. Inspection Scope

The inspectors reviewed significant changes in reported dose values compared to the previous radiological effluent release report to evaluate the factors which may have resulted in the change.

The inspectors reviewed radioactive liquid and gaseous waste discharge permits to assess whether the projected dose to members of the public were accurate.

The inspectors evaluated the isotopes included in the source term to assess whether analysis methods were sufficient to satisfy detectability standards. The review included the current Part 61 analyses to ensure hard-to-detect radionuclides were included in the source term.

The inspectors reviewed changes in the licensees offsite dose calculations and evaluated whether those changes were consistent with the ODCM and Regulatory Guide 1.109. The inspectors reviewed meteorological dispersion and deposition factors used in the ODCM and effluent dose calculations and determined whether appropriate factors were being used for public dose calculations.

The inspectors reviewed the latest Land Use Census to assess whether changes had been factored into the dose calculations.

For select radioactive waste discharges, the inspectors evaluated whether the calculated doses were within the 10 CFR, Part 50, Appendix I and TS dose criteria.

The inspectors reviewed select records of abnormal radioactive waste discharges to ensure the discharges were monitored by the discharge point effluent monitor.

Discharges made with inoperable effluent radiation monitors, or unmonitored leakages were reviewed to ensure that an evaluation was made to account for the source term and projected dose to the public.

These inspection activities constituted one complete sample as defined in IP 71124.06-05.

b. Findings

No findings were identified.

.6 Problem Identification and Resolution (02.07)

a. Inspection Scope

The inspectors assessed whether problems associated with the effluent monitoring and control program were being identified by the licensee at an appropriate threshold and were properly addressed for resolution. In addition, the inspectors evaluated the appropriateness of the corrective actions for a selected sample of problems documented by the licensee involving radiation monitoring and exposure controls.

These inspection activities constituted one complete sample as defined in IP 71124.06-05.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Drill/Exercise Performance

a. Inspection Scope

The inspectors sampled licensee submittals for the Drill/Exercise Performance (DEP)performance indicator (PI) for the period from the second quarter 2016 through the second quarter 2017. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in Nuclear Energy Institute (NEI) 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, were used. The inspectors reviewed the licensees records associated with the PI to verify that the licensee accurately reported the DEP indicator in accordance with relevant procedures and the NEI guidance. Specifically, the inspectors reviewed licensee records and processes, including procedural guidance on assessing opportunities for the PI; assessments of PI opportunities during pre-designated control room simulator training sessions; performance during the 2016 biennial exercise; and performance during other drills. Specific documents reviewed are listed in the Attachment to this report.

This inspection constitutes one DEP sample as defined in IP 71151.

b. Findings

No findings were identified.

.2 Emergency Response Organization Readiness

a. Inspection Scope

The inspectors sampled licensee submittals for the ERO Drill Participation PI for the period from the second quarter of 2016 through the second quarter of 2017. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, were used. The inspectors reviewed the licensees records associated with the PI to verify that the licensee accurately reported the indicator in accordance with relevant procedures, and NEI guidance. Specifically, the inspectors reviewed licensee records and processes, including procedural guidance on assessing opportunities for the PI; performance during the 2016 biennial exercise; and other drills; and revisions of the roster of personnel assigned to key ERO positions. Specific documents reviewed are listed in the Attachment to this report.

This inspection constitutes one ERO drill participation sample as defined in IP 71151.

b. Findings

No findings were identified.

.3 Alert and Notification System Reliability

a. Inspection Scope

The inspectors sampled licensee submittals for the ANS PI for the period from the second quarter 2016 through the second quarter 2017. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, were used. The inspectors reviewed the licensees records associated with the PI to verify that the licensee accurately reported the indicator in accordance with relevant procedures and the NEI Guidance. Specifically, the inspectors reviewed licensee records and processes including procedural guidance on assessing opportunities for the PI and results of periodic ANS operability tests. Specific documents reviewed are listed in the Attachment to this report.

This inspection constitutes one ANS sample as defined in IP 71151.

b. Findings

No findings were identified.

.4 Mitigating Systems Performance IndexHigh Pressure Injection System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - High Pressure Injection System PI for the period from the third quarter 2016 through the second quarter 2017. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, CRs, MSPI derivation reports, event reports and NRC Integrated IRs for the period of the third quarter 2016 through the second quarter 2017 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, whether the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees CR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one MSPI high pressure injection system sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.5 Mitigating Systems Performance IndexResidual Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - Residual Heat Removal System PI for the period from the third quarter 2016 through the second quarter 2017.

To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, CRs, MSPI derivation reports, event reports and NRC IRs for the period of the third quarter 2016 through the second quarter 2017 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent in value since the previous inspection, and if so, whether the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees CR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one MSPI residual heat removal system sample as defined in IP 71151-05.

b. Findings

No findings were identified.

.6 Reactor Coolant System Leakage

a. Inspection Scope

The inspectors sampled licensee submittals for the RCS Leakage PI for the period from the third quarter 2016 through the second quarter 2017. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in NEI 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, RCS leakage tracking data, CRs, event reports and NRC IRs for the period of the third quarter 2016 through the second quarter 2017 to validate the accuracy of the submittals. The inspectors also reviewed the licensees CR database to determine if any problems had been identified with the PI data collected or transmitted for this indicator. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one reactor coolant system leakage sample as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

a. Inspection Scope

As discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify they were being entered into the licensees corrective action program at an appropriate threshold, adequate attention was being given to timely corrective actions, and adverse trends were identified and addressed. Some minor issues were entered into the licensees corrective action program as a result of the inspectors observations; however, they are not discussed in this report.

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

b. Findings

No findings were identified.

.2 Annual Follow-up of Selected Issues: 1-2 Diesel Generator Issues Resulting in

Additional Inoperability

a. Inspection Scope

The inspectors selected the following condition reports for in-depth review:

• CR-PLP-2017-00609, Received Alarm EK-0555, Diesel Generator Breaker 152-213 Trip, Unexpectedly;

• CR-PLP-2017-01291, While Performing MO-7A-2, Breaker 152-213 Opened and K-6B, Emergency Diesel Generator 1-2, Tripped; and

• CR-PLP-2017-02655, Failure of P-18A to Shutoff at the Desired Setpoint.

Between January 2017 and July 2017, the licensee initiated multiple condition reports involving the 1-2 DG for issues that resulted in additional inoperability of the system.

The inspectors reviewed these condition reports and their associated work orders.

As appropriate, the inspectors verified the following attributes during their review of the licensee's corrective actions for the above condition reports and other related condition reports:

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

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

• evaluation and disposition of operability/functionality/reportability issues;

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

• identification of the apparent and contributing causes of the problem; and

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

• completion of corrective actions in a timely manner commensurate with the safety significance of the issue; and

• evaluation of the applicability for operating experience and communication of applicable lessons learned to appropriate organizations.

The inspectors discussed the corrective actions and associated evaluations with licensee personnel.

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

b. Observations and Assessments The inspectors reviewed the adverse condition analyses (ACA) associated with CR-PLP-2017-00609 and CR-PLP-2017-02655, and the disposition associated with CR-PLP-2017-01291. The inspectors did not identify any significant issues associated with the licensees CAP processes for these condition reports. However, the inspectors noted the licensees conclusions in the ACA associated with CR-PLP-2017-02655.

The licensees ACA for the issue identified in CR-PLP-2017-02655, which occurred on May 23, 2017, discussed previous occurrences of similar failures. On May 23, 2017, during performance a monthly surveillance test on the 1-2 DG, the P-18A fuel oil transfer pump would not stop auto-filling the 1-2 DG fuel oil day tank. The licensee manually stopped the pump and, although the 1-2 DG was already inoperable due to the surveillance test, declared the 1-2 DG inoperable due to the P-18A auto-fill function not operating as expected. The licensee performed troubleshooting and identified that LS-1453, the 1-2 DG fuel oil day tank low level switch, contacts did not open as expected when sufficient level in the 1-2 DG fuel oil day tank was reached. As a result of this condition, the P-18A fuel oil transfer pump did not stop auto-filling as anticipated.

Through troubleshooting the licensee identified that the probable cause was binding due to air entrapment of the level switch float in the upper portion of the float chamber. The resulting actions were to adjust the level switch mechanism to prevent air entrapment in LS-1453.

The ACA discussed similar failures of level switch LS-1453 that had occurred on four other occasions since 2013. An apparent cause evaluation (ACE) was performed for one of these failures on May 18, 2015. In this case, when the automatic fill function for the 1-2 DG fuel oil day tank was placed into service, P-18A started to fill the tank, even though tank level was sufficient and the operators expected P-18A to remain off. The licensee determined the cause of the event to be contact between the level switch and a seismic support for the tank, which resulted in binding due to a misalignment of the internal float in LS-1453. Additionally, it was discussed in the ACE that, due to the contact, the level switch and associated piping was not plumb. This was identified as a legacy issue associated with inadequate understanding of the impact of interference when the level switch was installed. For this event, the level switch internals were modified to eliminate the binding. Additionally, a corrective action was created to evaluate rework of the piping for the level switch and eliminate the contact with the seismic support. It was decided that the piping rework was an enhancement action and no active rework of the piping was pursued.

Two of the similar failures occurred in January 2017 and April 2017. In each of these instances, the licensee identified possible failure mechanisms and implemented corrective actions to restore operability. However, the licensee determined, for these events, that there were several possible causes that could not be eliminated through the troubleshooting process. The ACA identified that corrective actions in the previous events did not adequately eliminate the identified possible failure mechanisms. The identified possible failure mechanisms were mitigated, but not eliminated completely.

The inspectors noted that the ACA also discussed that rework of the level switch piping, which was identified as an enhancement in 2015, would eliminate all possible causes.

The licensees corrective action to rework the level switch piping and replace LS-1453 was completed on July 28, 2017. This resulted in the assurance that the level switch piping was plumb and the contact between LS-1453 and the seismic support was eliminated.

c. Findings

Introduction:

A finding of very low safety significance (Green) and an associated non-cited violation (NCV) of TS 5.4.1, Procedures, was self-revealed on March 31, 2017, when the 1-2 DG tripped during performance of monthly TS surveillance procedure MO-7A-2, Emergency Diesel Generator 1-2. Specifically, during conduct of the monthly surveillance procedure, restoration activities associated with maintenance of breaker 152-213, 1-2 DG to Bus 1D, were being performed. When maintenance personnel closed the trip cutouts for the Z-phase of the 1-2 DG differential overcurrent relay, an unbalanced current flow into the differential relay resulted in relay actuation. This actuation resulted in a trip of the output breaker and subsequently a trip of the 1-2 DG. The trip caused a delay in the TS surveillance activities, and resulted in extended unavailability and inoperability of the 1-2 DG.

Description:

On March 31, 2017, the monthly TS surveillance procedure for the 1-2 DG was scheduled to start at 12:00 p.m. The preventive maintenance associated with the 1-2 DG differential overcurrent relay was scheduled to end at 1:00 p.m. This indicated to operators that these work activities were not bound by any logic tie and the activities could be overlapped.

When maintenance personnel performing the maintenance activities associated with the relay work identified that the 1-2 DG was running, they requested permission from the control room to place the Z-phase differential relay back into service prior to closing breaker 152-213, 1-2 DG to Bus 1D output breaker. The operators informed the maintenance personnel that they could return the relay to service when breaker 152-213 was closed. Once breaker 152-213 was closed during the surveillance procedure, the maintenance workers were restoring the relay when it tripped, causing breaker 152-213 and the 1-2 DG to trip. The maintenance personnel immediately informed the control room of their activities and promptly revealed the cause of the DG trip. This sequence of events caused additional inoperability and unavailability time of the 1-2 DG due to time taken for evaluation of the trip and re-performing the surveillance test. Prior to the start of the surveillance test, the licensee had declared the 1-2 DG inoperable and appropriately entered TS 3.8.1, Condition B. The licensee restored the differential overcurrent trip relay circuitry and successfully re-performed the test. Once those activities were completed, the DG was declared operable.

As discussed in the licensees disposition evaluation for this issue, this event was directly caused by restoration of the differential relay while the DG output breaker was closed. The engineering staff identified that the differential relay properly actuated as designed, which resulted in the trip of the 1-2 DG. As corrective actions, the licensee updated work instructions associated with the differential overcurrent relays to include caution statements that opening or closing trip cutouts for the differential relays while the output breakers from the DGs to the associated buses were closed could cause the differential relays to actuate.

Analysis:

The inspectors determined that the failure to adequately pre-plan and perform maintenance that could affect the performance of safety-related equipment in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances was contrary to the requirements of TS 5.4.1, Procedures, and was a performance deficiency warranting further review.

The performance deficiency was determined to be more than minor, and thus a finding, in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the Mitigating Systems cornerstone attribute of Procedure Quality and 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 Significance Determination Process in accordance with IMC 0609, Appendix A, The Significance Determination Process for Findings At-Power, Exhibit 2, dated June 19, 2012. The inspectors reviewed the Mitigating Systems Screening Questions in Appendix A, Exhibit 2 and answered No to all questions. As a result, the finding was determined to be very of low safety significance (Green).

This finding had a cross-cutting aspect in the area of Human Performance, in the Work Management aspect, for the failure to identify and manage risk commensurate to the work. Specifically, the licensee committed a human performance error by failing to adequately plan, control, and execute electrical maintenance activities associated with the 1-2 DG during the monthly TS surveillance test of the DG. The licensee did not appropriately assess and coordinate the work activities of different work groups to address the impact of those work activities on the plant, which resulted in the 1-2 DG being inoperable longer than planned (H.5).

Enforcement:

TS Section 5.4.1 states, in part, that written procedures shall be established, implemented, and maintained covering the applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, dated February 1978.

NRC Regulatory Guide 1.33, Appendix A, Section 9a, states, in part, that maintenance that can affect the performance of safety-related equipment should be properly pre-planned and performed in accordance with written procedures, documented instructions, or drawings appropriate to the circumstances.

Contrary to the above, on March 31, 2017, while performing monthly TS surveillance procedure MO-7A-2, Emergency Diesel Generator 1-2, in conjunction with electrical maintenance procedure WI-SPS-E-09, Calibration of Bus 1D Protective Relays, the licensee failed to properly pre-plan and perform maintenance that affected the 1-2 DG by failing to understand the impact of restoration of the Z-phase differential overcurrent relay while the 1-2 DG output breaker was closed. Specifically, performance of these two activities in conjunction with each other resulted in unbalanced current flow into the differential relay and a trip of the 1-2 DG. The issue was entered into the licensees CAP as CR-PLP-2017-01291, While Performing MO-7A-2, Breaker 152-213 Opened and K-6B, Emergency Diesel Generator 1-2, Tripped.

Because this violation was of very low safety significance and it was entered into the licensees CAP as CR-PLP-2017-01291, this violation is being treated as a NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy.

(NCV 05000255/2017003-03, 1-2 Diesel Generator Trip During Maintenance Resulting in Additional Unavailability of the 1-2 DG)

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

.1 (Closed) Licensee Event Report 05000255/2017002-00: Reactor Protection System

Actuation While the Reactor was Shutdown On May 19, 2017, an unexpected actuation of the RPS occurred during the performance of procedure PO-1, Operations Pre-Startup Tests. While testing the function of RPS actuation from a loss of main generator load input signal, the operator performing the test incorrectly determined MOD-389, the Main Generator Motor-Operated Disconnect, to be open when it was actually closed. The PO-1 procedure required that either MOD-389 be in the open position or that the main generator protective trip circuitry be bypassed. Because the operator incorrectly determined the state of the motor-operated disconnect, the aforementioned conditional step was erroneously performed, and the main generator protective trip circuitry was not bypassed as required, leading to the unplanned RPS actuation. At the time of the actuation, the reactor was shutdown in Mode 5 with all control rods inserted and the RPS responded as expected for the plant conditions. The operator was given remediation training and enhancements to procedure guidance were briefed to all operating crews on the execution of conditional steps. Also, the licensee increased required behavioral observations and supervisory oversight within the operations department.

The inspectors determined that the failure of the operator to correctly perform procedure PO-1, Operations Pre-Startup Tests, constituted a performance deficiency and that this performance deficiency was similar to Example 4.b of IMC 0612, Appendix E, Examples of Minor Issues. For this issue, the unexpected RPS actuation produced a valid RPS signal for a reactor trip. However, the trip did not result in any upset to plant stability since control rods were fully inserted due to the plant being shutdown.

Therefore, the failure to follow the RPS testing procedure constituted a minor violation that is not subject to enforcement action in accordance with the NRCs Enforcement Policy. This licensee event report (LER) is closed.

Documents reviewed are listed in the Attachment to this report.

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

4OA6 Management Meetings

.1 Exit Meeting Summary

On October 18, 2017, the inspectors presented the inspection results to Mr. C. Arnone, Site Vice President, 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 of the Emergency Preparedness Program with Mr. C. Arnone, Site Vice President, and licensee staff on July 20, 2017; and

• the inspection results for the Radiation Safety Program review with Mr. D. Corbin, General Manager Plant Operations, and licensee staff on July 14, 2017.

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 licensee-identified violation of U.S. Nuclear Regulatory Commission requirements was determined to be of very low safety significance or Severity Level IV and meet the U.S. Nuclear Regulatory Commission Enforcement Policy criteria for being dispositioned as a Non-Cited Violation.

• The licensee identified a finding of very low safety significance (Green) and an associated NCV of TS 5.7.2, which requires, in part, that each entryway into High Radiation Areas (HRAs) with dose rates greater than 1.0 rem/hour at 30 centimeters from the radiation source or any surface penetrated by the radiation, but less than 500 rads/hour at 1 meter from the radiation source or from any surface penetrated by the radiation source shall be provided with a locked or continuously guarded door or gate that prevents unauthorized entry. Contrary to the above, on May 4, 2017, the licensee failed to lock or continuously guard an entryway into a HRA with dose rates greater than 1.0 rem/hour at 30 centimeters from the radiation source or any surface penetrated by the radiation, but less than 500 rads/hour at 1 meter from the radiation source or from any surface penetrated by the radiation source. Specifically, an entryway was left unguarded when the individual assigned to guard the entryway left the area prior to another guard being stationed. This issue was identified by a radiation protection technician who immediately stationed another guard. This issue was entered into the licensees CAP as CR-PL-2017-02160.

The failure to continuously guard the HRA entryway was a performance deficiency that was within the licensees ability to foresee and should have been prevented. The performance deficiency was more than minor because it was associated with the Program and Process attribute of the Occupational Radiation Safety cornerstone and adversely affected the cornerstone objective of ensuring the adequate protection of worker health and safety from exposure to radiation.

The finding was determined to be of very low safety significance (Green)because it did not involve as-low-as-reasonably-achievable planning or work controls, there was no overexposure or substantial potential for an overexposure, and the licensees ability to assess dose was not compromised.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

C. Arnone, Site Vice President

D. Corbin, General Manager Plant Operations

B. Baker, Operations Manager - Shift

J. Borah, Engineering Manager, Systems and Components

T. Davis, Regulatory Assurance

N. DeMaster, Outage Manager

B. Dotson, Regulatory Assurance

J. Erickson, Regulatory Assurance

O. Gustafson, Director of Regulatory and Performance Improvement

J. Hardy, Regulatory Assurance Manager

J. Haumersen, Site Projects and Maintenance Services Manager

G. Heisterman, Maintenance Manager

K. Howard, Emergency Preparedness Specialist

M. Lee, Operations Manager - Support

D. Lucy, Production Manager

D. Malone, Emergency Planning Manager

T. Mulford, Operations Manager

W. Nelson, Training Manager

D. Nestle, Radiation Protection Manager

C. Plachta, Nuclear Independent Oversight Manager

M. Mylnarek, Nuclear Independent Oversight Manager

K. OConnor, Site Engineering Director

M. Schultheis, Performance Improvement Manager

M. Soja, Chemistry Manager

J. Tharp, Security Manager

U.S. Nuclear Regulatory Commission

E. Duncan, Chief, Reactor Projects Branch 3

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

05000255/2017003-01 URI Left Train Emergency Diesel Generator Load Sequencer Failure (Section 1R19.1.b)

05000255/2017003-02 URI Cause of 42-2/RPS Breaker Failure to Open (Section 1R19.1.c)

05000255/2017003-03 NCV 1-2 Diesel Generator Trip During Maintenance Resulting in Additional Unavailability of the 1-2 DG (Section 4OA2.2.c)

Closed

05000255/2017002-00 LER Reactor Protection System Actuation While the Reactor was Shutdown (Section 4OA3.1)

05000255/2017003-03 NCV 1-2 Diesel Generator Trip During Maintenance Resulting in Additional Unavailability of the 1-2 DG (Section 4OA2.2.c)

Discussed

None