IR 05000373/2016003

NRC Integrated Inspection Report 05000373/2016003 and 05000374/2016003

ML16308A354
Person / Time
Site:	LaSalle
Issue date:	11/03/2016
From:	Billy Dickson NRC/RGN-III/DRP/RPB5
To:	Bryan Hanson Exelon Generation Co
References
IR 2016003
Download: ML16308A354 (35)

Text

UNITED STATES ber 3, 2016

SUBJECT:

LASALLE COUNTY STATION, UNITS 1 AND 2NRC INTEGRATED INSPECTION REPORT 05000373/2016003 AND 05000374/2016003

Dear Mr. Hanson:

On September 30, 2016, the U.S. Nuclear Regulatory Commission (NRC) completed an integrated inspection at your LaSalle County Station, Units 1 and 2. On October 4, 2016, the NRC inspectors discussed the results of this inspection with Mr. W. Trafton and other members of your staff. Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors examined activities conducted under your license as they relate to safety and compliance with the Commissions rules and regulations and with the conditions of your license.

The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel.

The NRC inspectors did not identify any findings or violations of more than minor significance.

In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter, its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records System (PARS) component of the NRC's Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Billy Dickson, Chief Branch 5 Division of Reactor Projects Docket Nos. 50-373 and 50-374 License Nos. NPF-11 and NPF-18

Enclosure:

IR 05000373/2016003; 05000374/2016003

REGION III==

Docket Nos: 05000373; 05000374 License Nos: NPF-11; NPF-18 Report No: 05000373/2016003; 05000374/2016003 Licensee: Exelon Generation Company, LLC Facility: LaSalle County Station, Units 1 and 2 Location: Marseilles, IL Dates: July 1 through September 30, 2016 Inspectors: R. Ruiz, Senior Resident Inspector J. Robbins, Resident Inspector C. Hunt, Resident Inspector T. Ospino, RIII Reactor Engineer J. Cassidy, RIII Senior Health Physicist R. Zuffa, (Illinois Emergency Management Agency), Resident Inspector Approved by: B. Dickson, Chief Branch 5 Division of Reactor Projects Enclosure

SUMMARY

Inspection Report 05000373/2016003, 05000374/2016003; 07/01/2016-09/30/2016; LaSalle

County Station, Units 1 & 2; Routine Integrated Inspection Report This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. No findings were identified. The U.S. Nuclear Regulatory Commissions (NRCs) program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 6, dated July 2016.

REPORT DETAILS

Summary of Plant Status

Unit 1 With the exception of minor power changes for rod pattern adjustments and turbine valve surveillance testing, the unit remained at or near full-power throughout the inspection period.

Unit 2 With the exception of minor power changes for rod pattern adjustments and turbine valve surveillance testing, the unit remained at or near full-power throughout the inspection period.

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• Unit 1 low pressure core spray;

• Unit 2 control rod drive (CRD) system during Unit 2 B diesel generator (DG)outage;

• Unit 1 A DG system during Unit 0 DG and low pressure core spray outage;

• Unit 2 high pressure core spray during reactor core isolation cooling outage; and

• Unit 1 B DG system following maintenance.

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, Updated Final Safety Analysis Report (UFSAR), Technical Specification (TS) requirements, outstanding work orders (WOs), action requests (ARs),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 corrective action program (CAP) with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

These activities constituted five partial system walkdown samples as defined in Inspection Procedure (IP) 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

.1 Routine Resident Inspector Tours

a. Inspection Scope

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

• fire zone 5B7, Unit 1, 731' elevation, hydrogen seal oil unit;

• fire zone 5B8, Unit 2, 731' elevation, hydrogen seal oil unit;

• fire zone 4E1, Unit 1, 731' elevation, auxiliary electrical equipment room;

• fire zone 4D3, Unit 1, electrical equipment room;

• fire zone 3E, Unit 2, 761' 0" elevation, general area & reactor water cleanup pump cubicles;

• fire zone 2E, Unit 1, 761' 0" elevation, general area & reactor water cleanup pump cubicles;

• fire zone 8B1, 710'6" elevation, high pressure core spray DG Room; and

• fire zone 8B2, Division II, 710' 6" elevation, standby DG room.

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

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

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

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On August 17, 2016, 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 and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

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

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

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

b. Findings

No findings were identified.

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

(71111.11Q)

a. Inspection Scope

On September 28, 2016, the inspectors observed operators in the control room during a period of increased activity due to concurrent, multiple surveillances. This activity required heightened awareness or was related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

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

• correct use and implementation of procedures;

• control board (or equipment) manipulations;

• oversight and direction from supervisors; and

• ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications (if applicable).

The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements.

This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11-05.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• Unit 1 CRD system;

• Unit 2 motor-driven reactor feed pump (MDRFP);

• Maintenance Rule system scoping review; and

• quality control review.

The inspectors reviewed events such as where 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 Title 10 of the Code of Federal Regulations (10 CFR) 50.65(b) of the maintenance rule;

• characterizing system reliability issues for performance;

• charging unavailability for performance;

• trending key parameters for condition monitoring;

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

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

The inspector performed a quality review 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 four quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• Unit 2 A DG maintenance work window (Yellow risk);

• Unit 2 B DG bus duct inspection (Yellow risk);

• Unit 0 DG outage and Units 1 and 2 A residual heat removal (RHR) work window; and

• Unit 1 B DG work window (Yellow risk).

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 four samples as defined in IP 71111.13-05.

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• RHR service water flow does not meet procedure LOS-RH-Q1 requirements;

• unexpected alarm 2H13-P603-A403, control rod drive high temperature;

• Unit 2 24 VDC charger not functioning properly; and

• Unit 1 B channel of reactor core isolation cooling level 2 initiation logic, 2B21-N710B, inoperable.

The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and 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 sampling of CAP 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 four samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

.2 Annual Sample: Review of Operator Workarounds

a. Inspection Scope

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

The inspectors performed a review of the cumulative effects of operator workarounds.

The documents listed in the Attachment were reviewed to accomplish the objectives of the inspection procedure. The inspectors reviewed both current and historical operational challenge records to determine whether the licensee was identifying operator challenges at an appropriate threshold, had entered them into their CAP and proposed or implemented appropriate and timely corrective actions which addressed each issue.

Reviews were conducted to determine if any operator challenge could increase the possibility of an initiating event, if the challenge was contrary to training, required a change from long-standing operational practices, or created the potential for inappropriate compensatory actions. Additionally, all temporary modifications were reviewed to identify any potential effect on the functionality of mitigating systems, impaired access to equipment, or required equipment uses for which the equipment was not designed. Daily plant and equipment status logs, degraded instrument logs, and operator aids or tools being used to compensate for material deficiencies were also assessed to identify any potential sources of unidentified operator workarounds.

This review constituted one operator workaround annual inspection sample as defined in IP 71115-02.

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed modification LST-2015-002, Increase Flow through Reactor Water Cleanup (50.59 Evaluation L-16-159).

The inspectors reviewed the configuration change and associated 10 CFR 50.59 safety evaluation screening against the design basis, the UFSAR, and the TS, as applicable, to verify that the modification did not affect the operability or availability of the affected system. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors reviewed the change to ensure that individuals were aware of how the operation with the process modification could impact overall plant performance. Documents reviewed are listed in the to this report.

This inspection constituted one permanent plant modification sample as defined in IP 71111.18-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

.1 Post-Maintenance Testing

a. Inspection Scope

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

• Procedure LOS-DG-Q2, Attachment A1, DG fuel oil transfer pump test, after the replacement of control relays for the diesel fuel oil transfer pump;

• Unit 2 Division III core standby cooling system pump room sump after maintenance;

• Unit 2 Division I 125 VDC battery room exhaust fan 2VX02C test following breaker replacement;

• Unit 2 B DG B starting air pressure regulator valve;

• Unit 2 B DG to bus 243 duct inspection;

• Unit 0 DG post-maintenance test following work window; and

• Unit 2 standby gas treatment system post-maintenance testing.

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 UFSAR, 10 CFR 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 CAP documents associated with post-maintenance tests to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R22 Surveillance Testing

.1 Surveillance Testing

a. Inspection Scope

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

• LEP-EQ-115, Klockner-Moeller circuit breakers and related motor control center (MCC) equipment (Routine);

• Unit 2 high pressure core spray (Routine);

• LOS-DG-M1, Unit 0 DG idle start (Routine);

• LOS-CS-Q1, Unit 1 secondary containment damper operability test (IST);

• LOS-CS-Q1, Unit 2 secondary containment damper operability test (IST);

• LOS-RH-Q1, Unit 2 A RHR service water (IST); and

• Unit 2 increased indication of reactor control system leakage (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 UFSAR, 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 three routine surveillance testing samples, three in-service test samples and one reactor coolant system leak detection inspection sample as defined in IP 71111.22, Sections-02 and-05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on September 9, 2016, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the technical 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.

2RS7 Radiological Environmental Monitoring Program

.1 Site Inspection

a. Inspection Scope

The inspectors walked down select air sampling stations and dosimeter monitoring stations to determine whether they were located as described in the Offsite Dose Calculation Manual (ODCM) and to determine the equipment material condition.

The inspectors reviewed calibration and maintenance records for select air samplers, dosimeters, and composite water samplers to evaluate whether they demonstrated adequate operability of these components.

The inspectors assessed whether the licensee had initiated sampling of other appropriate media upon loss of a required sampling station.

The inspectors observed the collection and preparation of environmental samples from select environmental media to determine if environmental sampling was representative of the release pathways specified in the ODCM and if sampling techniques were in accordance with procedures.

The inspectors assessed whether the meteorological instruments were operable, calibrated, and maintained in accordance with guidance contained in the UFSAR, the NRC Regulatory Guide 1.23, Meteorological Monitoring Programs for Nuclear Power Plants, and licensee procedures. The inspectors assessed whether the meteorological data readout and recording instruments were operable.

The inspectors evaluated whether missed and/or anomalous environmental samples were identified and reported in the Annual Environmental Monitoring Report. The inspectors selected events that involved a missed sample, inoperable sampler, lost dosimeter, or anomalous measurement to determine if the licensee had identified the cause and had implemented corrective actions. The inspectors reviewed the licensees assessment of any positive sample results and reviewed any associated radioactive effluent release data that was the source of the released material.

The inspectors selected structures, systems, or components that involve or could reasonably involve a credible mechanism for licensed material to reach ground water, and assessed whether the licensee had implemented a sampling and monitoring program sufficient to detect leakage to ground water.

The inspectors evaluated whether records important to decommissioning, as required by 10 CFR 50.75(g), were retained in a retrievable manner.

The inspectors reviewed any significant changes made by the licensee to the ODCM as the result of changes to the land census, long-term meteorological conditions, or modifications to the sampler stations since the last inspection. The inspectors reviewed technical justifications for any changed sampling locations to evaluate whether the licensee performed the reviews required to ensure that the changes did not affect its ability to monitor the impacts of radioactive effluent releases on the environment.

The inspectors assessed whether the appropriate detection sensitivities with respect to the ODCM where used for counting samples. The inspectors reviewed the Quality Control Program for analytical analysis.

The inspectors reviewed the results of the licensees Interlaboratory Comparison Program to evaluate the adequacy of environmental sample analyses performed by the licensee. The inspectors assessed whether the interlaboratory comparison test included the media/nuclide mix appropriate for the facility. The inspectors reviewed the licensees determination of any bias to the data and the overall effect on the Radiological Environmental Monitoring Program.

These inspection activities constituted one complete sample as defined in IP 71124.07-05.

b. Findings

No findings were identified.

.2 Groundwater Protection Initiative Implementation

a. Inspection Scope

The inspectors reviewed monitoring results of the Groundwater Protection Initiative to evaluate whether the licensee had implemented the program as intended and to assess whether the licensee had identified and addressed anomalous results and missed samples.

The inspectors evaluated the licensees implementation of the minimization of contamination and survey aspects of the Groundwater Protection Initiative and the Decommissioning Planning Rule requirements in 10 CFR 20.1406 and 10 CFR 20.1501.

The inspectors reviewed leak and spill events and 10 CFR 50.75

(g) records and assessed whether the source of the leak or spill was identified and appropriately mitigated.

The inspectors assessed whether unmonitored leaks and spills where evaluated to determine the type and amount of radioactive material that was discharged. The inspectors assessed whether the licensee completed offsite notifications in accordance with procedure.

The inspectors reviewed evaluations of discharges from onsite contaminated surface water bodies and the potential for groundwater leakage from them. The inspectors assessed whether the licensee properly accounted for these discharges as part of the Effluent Release Reports.

The inspectors assessed whether onsite groundwater sample results and descriptions of any significant onsite leaks or spills into groundwater were documented in the Annual Radiological Environmental Operating Report or the Annual Radiological Effluent Release Report.

The inspectors determined if significant new effluent discharge points where updated in the ODCM and the assumptions for dose calculations were updated as needed.

These inspection activities constituted one complete sample as defined in IP 71124.07-05.

b. Findings

No findings were identified

.3 Problem Identification and Resolution

a. Inspection Scope

The inspectors assessed whether problems associated with the radiological environmental monitoring program 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 the radiological environmental monitoring program.

These inspection activities constituted one complete sample as defined in IP 71124.07-05.

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 Mitigating Systems Performance IndexEmergency Alternating Current Power System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Emergency Alternating Current (AC) Power System performance indicator (PI) for Units 1 and 2 from the third quarter 2015 through the second quarter 2016. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the Nuclear Energy Institute (NEI)

Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, MSPI derivation reports, issue reports, event reports and NRC Integrated Inspection Reports from the third quarter 2015 through the second quarter 2016 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, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two MSPI emergency AC power system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance IndexHigh Pressure Injection Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - High Pressure Injection PI for Units 1 and 2 from the third quarter 2015 through the second quarter 2016. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection Reports from the third quarter 2015 through the second quarter 2016 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, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

.3 Mitigating Systems Performance IndexResidual Heat Removal System

a. Inspection Scope

The inspectors sampled licensee submittals for the MSPI - RHR System PI for Units 1 and 2 from the third quarter 2015 through the second quarter 2016. To determine the accuracy of the PI data reported during those periods, PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports and NRC Integrated Inspection Reports from the third quarter 2015 through the second quarter 2016 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, that the change was in accordance with applicable NEI guidance. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two MSPI RHR system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.4 Reactor Coolant System Specific Activity

a. Inspection Scope

The inspectors sampled licensee submittals for the reactor coolant system specific activity PI for LaSalle County Station, Units 1 and 2, from the first quarter 2015 through the second quarter 2016. The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 2013, to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees reactor coolant system chemistry samples, TS requirements, issue reports, event reports and U.S. Nuclear Regulatory Commission Integrated Inspection Reports to validate the accuracy of the submittals. The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two reactor coolant system specific activity samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.5 Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors sampled licensee submittals for the Occupational Exposure Control Effectiveness PI from the third quarter 2015 through the second quarter 2016. The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 2013, to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees assessment of the PI for occupational radiation safety to determine if the indicator related data was adequately assessed and reported. To assess the adequacy of the licensees PI data collection and analyses, the inspectors discussed with radiation protection staff the scope and breadth of its data review and the results of those reviews. The inspectors independently reviewed electronic personal dosimetry dose rate and accumulated dose alarms and dose reports and the dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized occurrences. The inspectors also conducted walkdowns of numerous locked high and very-high radiation area entrances to determine the adequacy of the controls in place for these areas. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

.6 Radiological Effluent Technical Specification/Offsite Dose Calculation Manual

Radiological Effluent Occurrences

a. Inspection Scope

The inspectors sampled licensee submittals for the Radiological Effluent TS/ODCM radiological effluent occurrences PI from the third quarter 2015 through the second quarter 2016. The inspectors used PI definitions and guidance contained in the NEI Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 2013, to determine the accuracy of the PI data reported during those periods. The inspectors reviewed the licensees issue report database and selected individual reports generated since this indicator was last reviewed to identify any potential occurrences such as unmonitored, uncontrolled, or improperly calculated effluent releases that may have impacted offsite dose. The inspectors reviewed gaseous effluent summary data and the results of associated offsite dose calculations for selected dates to determine if indicator results were accurately reported. The inspectors also reviewed the licensees methods for quantifying gaseous and liquid effluents and determining effluent dose. Documents reviewed are listed in the to this report.

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

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

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

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

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

b. Findings

No findings were identified.

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 (Closed) Licensee Event Report 05000374/2016-001-00, Secondary Containment

Inoperable Due to Door Interlock Failure On February 17, 2016, Unit 2 was in Mode 1 at 100 percent power and Unit 1 was in Mode 5 for refueling outage L1R16 with no fuel movements, core alterations, or operations with the potential to drain the reactor vessel in progress. At approximately 1035 hours0.012 days <br />0.288 hours <br />0.00171 weeks <br />3.938175e-4 months <br />, Operations received a report that an employee entered a secondary containment interlock and identified that both doors of the Unit 2 chemistry lab corridor/reactor building interlock (door number 247 and door number 248) were opened simultaneously.

The employee immediately secured both doors in the interlock and notified the main control room supervisor. Both doors in the interlock were open for approximately five seconds. With both doors open, TS surveillance requirement 3.6.4.1.2 was not met for Unit 2. This rendered secondary containment inoperable in accordance with TS 3.6.4.1.

Reactor Building differential pressure, as observed in the main control room, remained less than -0.25 inches vacuum water gauge at all times.

The cause of the event was the failure of the relays of the UR2-4 controller circuit card in the interlock door. The exact failure mechanism of the relays was unknown by the licensee at the time of this review; however, CAP tracking items had been created by the licensee to identify the cause and make changes to prevent the undesired circuit card service life issues experienced by the site. The immediate corrective action taken by the station was replacement of the defective controller circuit card. Controller circuit cards with failed relays were sent to PowerLabs for analysis. They would then be sent to the vendors for further failure analysis. The inspectors considered these corrective actions to be reasonable.

A technical evaluation was performed by the licensee that determined this event did not meet the NEI Document 99-02 definition of a safety system functional failure.

This licensee event report (LER) is closed.

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

.2 (Closed) Licensee Event Report 05000373/05000374/2016-001-00, Secondary

Containment Inoperable Due to Reactor Building Ventilation Damper Failure On February 10, 2016, Unit 1 was in Mode 1 at 91 percent power and Unit 2 was in Mode 1 at 100 percent power. At 2207 hours0.0255 days <br />0.613 hours <br />0.00365 weeks <br />8.397635e-4 months <br />, it was reported that the Unit 1 reactor building ventilation exhaust damper, 1VR05YA, failed and began to show dual indication.

As a result, the Unit 1 reactor building ventilation exhaust fans tripped off, causing a positive reactor building differential pressure for the shared unit reactor building. The damper and secondary containment were declared inoperable, and the appropriate TS action statements were entered.

The cause was an intermittent failure of a solenoid on one of the two half-damper blades on the 1VR05YA exhaust isolation damper, which led to the exhaust damper blade intermittently changing its position causing secondary containment pressure to go positive. The solenoid valves on both halves of the 1VR05YA exhaust damper were replaced, and the failed solenoid was sent to a vendor for failure analysis.

As corrective actions, the licensee replaced both solenoid valves on both halves of the 1VRO5YA exhaust damper blades. Additional corrective actions would be determined following the vendors component failure analysis. The inspectors considered these corrective actions to be reasonable.

This LER is closed.

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

.3 (Closed) Licensee Event Report 05000374/2015-003-00, Reactor Recirculation Loop

Discharge Isolation Valve Vent Line Leak Due to Weld Defect On August 7, 2015, Unit 2 was in Mode 3 for a planned maintenance outage. At 1300 hours0.015 days <br />0.361 hours <br />0.00215 weeks <br />4.9465e-4 months <br />, during the initial drywell entry, a steam leak was observed on the reactor recirculation (RR) system line 2RR94AB-3/4". At 1345 hours0.0156 days <br />0.374 hours <br />0.00222 weeks <br />5.117725e-4 months <br />, the leak was determined to be pressure boundary leakage and the appropriate TS 3.4.5, "RCS Operational Leakage," Required Actions C.1 and C.2 were entered.

The cause for the steam leak on line 2RR94AB-3/4" was determined to be poor weld quality and vibration-induced fatigue due to RR system operation. The leak was repaired by replacing line 2RR94AB-3/4". The inspectors determined this corrective action to be reasonable.

This LER is closed.

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

.4 (Closed) Licensee Event Report 05000374/2015-002-01, Two Main Steam Safety

Relief Valves Failed Inservice Lift Inspection Pressure Test During the February 2015 Unit 2 refueling outage L2R15, two main steam safety relief valves (SRV) did not pass TS Surveillance Requirement 3.4.4.1 and In-service Testing Program lift pressure requirements. Both SRVs lifted below their expected lift pressures.

Safety relief valve 2621-F013S was required to lift within plus or minus three percent of 1150 psi (i.e., 1150 psi plus or minus 34.5 psi), but actually lifted at 1099 psi.

SRV 2B21-F013M was required to lift within plus or minus three percent of 1195 psi (i.e., 1195 psi plus or minus 35.8 psi), but actually lifted at 1145 psi.

Disassembly and inspection of both valves was performed at NWS Technologies, LLC, to determine the cause for failure. The vendor reported that all of the spring tolerances were within the acceptance limits for both valves. There were no other signs of degradation or any other issue that would affect the setpoint. Second lift tests for both valves were satisfactory and were within the plus or minus three percent tolerance of the set pressure. The cause for 2B21-F013S and 2621-F013M to fail their set pressure test in L2R15 was found to be indeterminate. As a corrective action, the licensee replaced both SRVs during the refueling outage. The inspectors considered this corrective action to be reasonable.

This LER is closed.

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

4OA6 Management Meetings

.1 Exit Meeting Summary

On Tuesday, October 4, 2016, the inspectors presented the inspection results to Mr. W. Trafton, 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

An interim exit meeting was conducted for the inspection results of the radiation safety program review with Mr. M. Martin, Chemistry Manager, on August 12, 2016.

The inspectors confirmed that none of the potential report input discussed was considered proprietary.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

W. Trafton, Site Vice President

H. Vinyard, Plant Manager

J. Kowalski, Engineering Director

K. Aleshire, Corporate Emergency Preparedness Director

V. Cwietniewicz, Corporate Emergency Preparedness Manager

G. Ford, Regulatory Assurance Manager

J. Moser, Radiation Protection Manager

M. Hayworth, Emergency Preparedness Manager

R. Conley, Operation Manager

N. Faith, Corporate Cyber Security Program Manager

R. Dunning, Senior Maintenance Specialist

S. Tutoky, ODCM Specialist

U.S. Nuclear Regulatory Commission

B. Dickson, Chief, Reactor Projects Branch 5

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened

None

Closed

05000374/2016-001-00 LER Secondary Containment Inoperable Due to Door Interlock Failure (Section 4OA3)

05000373/2016-001-00 LER Secondary Containment Inoperable Due to Reactor

05000374/2016-001-00 Building Ventilation Damper Failure (Section 4OA3)

05000374/2015-003-00 LER Reactor Recirculation Loop Discharge Isolation Valve Vent Line Leak Due to Weld Defect (Section 4OA3)

05000374/2015-002-01 LER Two Main Steam Safety Relief Valves Failed Inservice Lift Inspection Pressure Test (Section 4OA3)