Text

IR 05000373/2014004, 05000374/2014004; on 06/01/2014 - 09/30/2014; LaSalle County Station, Units 1 and 2; Post Maintenance Testing, Maintaining Emergency Preparedness
	ML14304A708
Person / Time
Site:	LaSalle
Issue date:	10/31/2014
From:	Michael Kunowski; NRC/RGN-III/DRP/B5
To:	Pacilio M; Exelon Generation Co, Exelon Nuclear
References
	IR 2014004
	Download: ML14304A708 (42)
	v • d • e

UNITED STATES ber 31, 2014

SUBJECT:

LASALLE COUNTY STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000373/2014004; 05000374/2014004

Dear Mr. Pacilio:

On September 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your LaSalle County Station, Units 1 and 2. On October 1, 2014, the NRC inspectors discussed the results of this inspection with the Site Vice-President, Mr. P. Karaba, and other members of your staff. The inspectors documented the results of this inspection in the enclosed inspection report.

The NRC inspectors documented one NRC-identified finding and one self-revealed finding of very low safety significance (Green) in this report. These findings involved violations of NRC requirements. The NRC is treating these violations as non-cited violations (NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy.

If you contest 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 Nuclear Regulatory Commission, ATTN:

Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Senior Resident Inspector at the LaSalle County Station.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a written 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 Senior Resident Inspector at the LaSalle County Station. In accordance with 10 CFR 2.390 of the NRC's "Rules of Practice," a copy of this letter and its enclosure, and your response (if any) will be available electronically for public inspection in the NRC Public Document Room or from the Publicly Available Records System (PARS)

component of NRC's Agencywide Documents Access and Management System (ADAMS),

accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).

Sincerely,

/RA/

Michael Kunowski, Chief Branch 5 Division of Reactor Projects Docket Nos. 50-373; 50-374 License Nos. NPF-11; NPF-18

Enclosure:

IR 05000373/2014004; 05000374/2014004 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 05000373; 05000374 License Nos: NPF-11; NPF-18 Report No: 05000373/2014004; 05000374/2014004 Licensee: Exelon Generation Company, LLC Facility: LaSalle County Station, Units 1 and 2 Location: Marseilles, IL Dates: July 1 through September 30, 2014 Inspectors: R. Ruiz, Senior Resident Inspector J. Robbins, Resident Inspector J. Neurauter, Senior Reactor Inspector D. McNeil, Senior Operations Engineer J. Jandovitz, Project Engineer R. Baker, Project Engineer R. Winter, Reactor Inspector R. Elliott, Reactor Engineer J. Laughlin, Emergency Preparedness Inspector, NSIR R. Zuffa, Illinois Emergency Management Agency (IEMA)

Resident Inspector Approved by: M. Kunowski, Chief Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000373/2014004, 05000374/2014004; 06/01/2014 - 09/30/2014;

LaSalle County Station, Units 1 and 2; Post-Maintenance Testing, Maintaining Emergency Preparedness.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Two Green findings were identified. The findings were considered non-cited violations (NCVs) of 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 IMC 0609, Significance Determination Process, dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Aspects Within the Cross-Cutting Areas, effective date January 1, 2014. All violations of NRC requirements are dispositioned in accordance with the NRCs Enforcement Policy, dated July 9, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process, Revision 5.

Cornerstone: Mitigating Systems

Green.

A self-revealed non-cited violation of 10 CFR Part 50, Appendix B, Criterion V,

Instructions, Procedures, and Drawings, was identified for the licensees failure to provide instructions appropriate to the circumstances for an activity affecting quality.

Specifically, the installation instructions for the reactor protection system (RPS) limit switch 1C71-N006B did not contain sufficient guidance to allow the component to be adjusted so that adequate clearance would exist during normal operation to ensure operability. The component failed its first in-service surveillance test. The licensee performed an apparent cause evaluation (ACE) and planned to evaluate maintenance training needs, potential procedure enhancements, and potential enhancements to model-work orders.

The finding was determined to be more than minor 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 (i.e., core damage).

Specifically, RPS limit switch 1C71-N006B is a safety-related component that, in conjunction with other inputs, can initiate a reactor scram. The finding was determined to be of very low safety significance (Green) in accordance with the Significance Determination Process (SDP) because the inspectors answered No to each of the screening questions. This finding has a cross-cutting aspect in the area of Human Performance, Training, because the licensee did not provide sufficient training and ensure knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values. Specifically, in this instance, the level of individual training was at such a level that the procedure needed to be of greater detail to be appropriate to the circumstances (H.9). (Section 1R19)

Cornerstone: Emergency Preparedness

Green.

The NRC identified an non-citied violation of 10 CFR 50.54(q)(2) associated with 10 CFR 50.47(b)(10) and 10 CFR Part 50, Appendix E, Section IV.4, for failing to maintain the effectiveness of the LaSalle County Station Emergency Plan, as a result of failing to provide the station evacuation time estimate (ETE) to the responsible offsite response organizations (OROs) by the required date. Exelon submitted the LaSalle County

Station ETE to the NRC on December 12, 2012, prior to the required due date of December 22, 2012. The NRC completeness review found the ETEs to be incomplete due to Exelon fleet common and site-specific deficiencies; thereby, preventing Exelon from providing the ETEs to responsible OROs and from updating site-specific protective action strategies as necessary. The NRC discussed its concerns regarding the completeness of the ETE, in a teleconference with Exelon on June 10, 2013, and on September 5, 2013,

Exelon resubmitted the ETEs for its sites. The NRC again found the ETEs to be incomplete.

The issue is a performance deficiency because it involved a failure to comply with a regulation that was under Exelons control to identify and prevent. The finding is more than minor because it is associated with the Emergency Preparedness Cornerstone attribute of procedure quality and because it adversely affected the cornerstone objective of ensuring that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. The finding is of very low safety significance (Green) because it was a failure to comply with a non-risk significant portion of 10 CFR 50.47(b)(10). The licensee had entered this issue into its corrective action program (CAP) and re-submitted a new revision of the LaSalle County Station ETE to the NRC on April 30, 2014, which was found to be complete by the NRC.

The cause of the finding is related to cross-cutting element of Human Performance,

Documentation (H.7). (Section 1EP5)

REPORT DETAILS

Summary of Plant Status

Unit 1 The unit began the inspection period operating at full power. On September 6, 2014, power was reduced to approximately 65 percent for a control rod sequence exchange and scram time testing. Unit 1 was restored to full power the next day.

Unit 2 The unit began the inspection period operating at full power. On August 5, 2014, Unit 2 experienced an unplanned scram due to the unexpected failure of a main steam isolation valve (MSIV) that led to an automatic reactor scram. Unit 2 remained in forced outage until the failed MSIV was repaired, along with the other Unit 2 MSIVs of similar design, as a precaution.

Following completion of the repair activities, the unit was restarted and synchronized to the grid on August 18, and achieved full power on August

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Main article: IP 71111.01

.1 Readiness for Impending Adverse Weather ConditionSevere Thunderstorm Watch

a. Inspection Scope

Since thunderstorms with potential tornados and high winds were forecast in the vicinity of the facility for September 4, 2014, the inspectors reviewed the licensees overall preparations/protection for the expected weather conditions. On September 4, the inspectors walked down the plant exterior, focusing on the switchyard perimeter, in addition to the licensees emergency alternating current (AC) power systems, because their safety-related functions could be affected or required as a result of high winds or tornado-generated missiles or the loss of offsite power. The inspectors evaluated the licensee staffs preparations against the sites procedures and determined that the staffs actions were adequate. During the inspection, the inspectors focused on plant-specific design features and the licensees procedures used to respond to specified adverse weather conditions. The inspectors also toured the plant grounds to look for any loose debris that could become missiles during a tornado. The inspectors evaluated operator staffing and accessibility of controls and indications for those systems required to control the plant. Additionally, the inspectors reviewed the Updated Final Safety Analysis Report (UFSAR) and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures.

The inspectors also reviewed a sample of CAP items to verify that the licensee identified adverse weather issues at an appropriate threshold and dispositioned them through the 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

Main article: IP 71111.04

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

Unit 1 standby gas treatment (SBGT) while Unit 2 SBGT was out of service;

Unit 2 standby liquid control system;

Unit 1 low pressure core spray (LPCS); and,

Unit 2 A emergency diesel generator (EDG) while Unit-Common EDG was out of service.

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, 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 to this report.

These activities constituted four partial system walkdown samples as defined in IP 71111.04-05.

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

On September 24, 2014, the inspectors performed a complete system alignment inspection of the Unit 1 SBGT to verify the functional capability of the system. This system was selected because it was considered both safety significant and risk significant in the licensees probabilistic risk assessment. The inspectors walked down the system to review mechanical and electrical equipment lineups; electrical power availability; system pressure and temperature indications, as appropriate; component labeling; component lubrication; component and equipment cooling; hangers and supports; operability of support systems; and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the Attachment to this report.

These activities constituted one complete system walkdown sample as defined in IP 71111.04-05.

b. Findings

No findings were identified.

1R05 Fire Protection

Main article: IP 71111.05

.1 Routine Resident Inspector Tours

Main article: IP 71111.05Q

a. Inspection Scope

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

building 11;

fire door 443;

fire zone 8C1;

fire zone 2I4; and

fire zone 4F2.

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

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

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

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

.2 Annual Fire Protection Drill Observation

Main article: IP 71111.05A

a. Inspection Scope

On August 27, 2014, the inspectors observed a fire brigade activation for the 735 elevation of the turbine building; specifically, in response to a simulated fire at the TBY-17 switchgear location. Based on this observation, the inspectors evaluated the readiness of the plant fire brigade to fight fires. The inspectors verified that the licensee staff identified deficiencies, openly discussed them in a self-critical manner at the drill debrief, and took appropriate corrective actions. Specific attributes evaluated were:

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, however, did not constitute the completion of the annual fire protection inspection sample as defined in IP 71111.05-05, and were considered a partial sample to be competed in the 4th quarter of 2014.

b. Findings

No findings were identified.

1R06 Flooding

Main article: IP 71111.06

.1 Underground Vaults

a. Inspection Scope

The inspectors selected underground bunkers/manholes subject to flooding that contained cables whose failure could impact risk significant equipment. The inspectors determined that the cables were not submerged, that splices were intact, and that appropriate cable support structures were in place, and in cases where the cables were wetted, the licensee had corrective actions in place to address the issue. In those areas where dewatering devices were used, such as a sump pump, the inspectors verified the device was functional/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 submergence conditions. The inspectors also reviewed the licensees CAP documents with respect to past submerged cable issues identified in the CAP to verify the adequacy of the corrective actions.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

Main article: IP 71111.11

.1 Annual Operating Test Results

Main article: IP 71111.11A

a. Inspection Scope

The inspectors reviewed the overall pass/fail results of the Annual Operating Exam administered by the licensee from August 18 through September 26, 2014, required by 10 CFR 55.59. The results for the exam were compared to the thresholds established in Inspection Manual Chapter (IMC) 0609, Appendix I, Licensed Operator Requalification Significance Determination Process (SDP), to assess the overall adequacy of the licensees licensed operator requalification training (LORT) program to meet the requirements of 10 CFR 55.59. (02.02).

This inspection constituted one annual LORT examination results sample as defined in IP 71111.11-05.

b. Findings

No findings were identified

.2 Biennial Review

Main article: IP 71111.11B

a. Inspection Scope

The following inspection activities were conducted during the week of September 22, 2014, to assess: 1) the effectiveness and adequacy of the facility licensees implementation and maintenance of its systems approach to training based LORT program put into effect to satisfy the requirements of 10 CFR 55.59.

Licensee Requalification Examinations (10 CFR 55.59(c); Systems Approach To Training Element 4 as Defined in 10 CFR 55.4): The inspectors reviewed the licensees program for development and administration of the LORT annual operating tests to assess the licensees ability to develop and administer examinations that were acceptable for meeting the requirements of 10 CFR 55.59(a).

- The inspectors conducted a detailed review of five Job Performance Measures (JPMs) and two dynamic simulator scenarios to assess content, level of difficulty, and quality of the operating test materials. (02.04)

- The inspectors observed the administration of the annual operating test to assess the licensees effectiveness in conducting the examination(s),including the conduct of pre-examination briefings, evaluations of individual operator and crew performance, and post-examination analysis. The inspectors evaluated the performance of two simulator crews in parallel with the facility evaluators during four dynamic simulator scenarios and evaluated various licensed crew members concurrently with facility evaluators during the administration of several JPMs. (02.05)

Conformance with Examination Security Requirements (10 CFR 55.49): The inspectors reviewed the facility licensees examination security procedure and observed the implementation of physical security controls (e.g., access restrictions and simulator input/output controls) throughout the partial inspection period. (02.06)

Documents reviewed are listed in the Attachment to this report.

This inspection constituted a partial biennial LORT program inspection as defined in IP 71111.11-05 and did not count as a complete sample.

b. Findings

No findings were identified.

.3 Resident Inspector Quarterly Review of Licensed Operator Requalification

Main article: IP 71111.11Q

a. Inspection Scope

On September 4, 2014, the inspectors observed a crew of licensed operators in the plants simulator during LORT to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

licensed operator performance;

crews clarity and formality of communications;

ability to take timely actions in the conservative direction;

prioritization, interpretation, and verification of annunciator alarms;

correct use and implementation of abnormal and emergency procedures;

control board manipulations;

oversight and direction from supervisors; and

ability to identify and implement appropriate TS actions and emergency plan actions and notifications.

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

This inspection constituted one quarterly LORT program simulator sample as defined in IP 71111.11.

b. Findings

No findings were identified.

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

(71111.11Q)

a. Inspection Scope

On August 16, 2014, the inspectors observed the Unit 2 restart activities from the L2F44 forced outage. This was an activity that required heightened awareness and 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.

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

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

b. Findings

No findings were identified.

.5 Annual Operating Test Results

Main article: IP 71111.11A

a. Inspection Scope

The inspectors reviewed the overall pass/fail results of the Annual Operating Exam administered by the licensee from August 18 through September 26, 2014, required by 10 CFR 55.59. The results for the exam were compared to the thresholds established in IMC 0609, Appendix I, Licensed Operator Requalification Significance Determination Process (SDP), dated December 6, 2011, to assess the overall adequacy of the licensees LORT program to meet the requirements of 10 CFR 55.59. (02.02).

Documents reviewed are listed in the Attachment to this report.

This inspection constituted one annual LORT examination results sample as defined in IP 71111.11-05.

b. Findings

No findings were identified

.6 Biennial Review

Main article: IP 71111.11B

a. Inspection Scope

The following inspection activities were conducted during the week of September 22, 2014, to assess: 1) the effectiveness and adequacy of the facility licensees implementation and maintenance of its systems approach to training based LORT program put into effect to satisfy the requirements of 10 CFR 55.59.

Licensee Requalification Examinations (10 CFR 55.59(c); Systems Approach To Training Element 4 as Defined in 10 CFR 55.4): The inspectors reviewed the licensees program for development and administration of the LORT annual operating tests to assess the licensees ability to develop and administer examinations that are acceptable for meeting the requirements of 10 CFR 55.59(a).

- The inspectors conducted a detailed review of five JPMs and two dynamic simulator scenarios to assess content, level of difficulty, and quality of the operating test materials. (02.04)

- The inspectors observed the administration of the annual operating test to assess the licensees effectiveness in conducting the examination(s),including the conduct of pre-examination briefings, evaluations of individual operator and crew performance, and post-examination analysis. The inspectors evaluated the performance of two simulator crews in parallel with the facility evaluators during four dynamic simulator scenarios and evaluated various licensed crew members concurrently with facility evaluators during the administration of several JPMs. (02.05)

Conformance with Examination Security Requirements (10 CFR 55.49): The inspectors reviewed the facility licensees examination security procedure and observed the implementation of physical security controls (e.g., access restrictions and simulator input/output controls) throughout the partial inspection period. (02.06)

Documents reviewed are listed in the Attachment to this report.

This inspection constituted a partial biennial LORT program inspection as defined in IP 71111.11-05 and did not count as a complete sample.

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

Main article: IP 71111.12

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

Unit 1 MSIVs;

Unit 1 standby liquid control; and

Unit 1 LPCS.

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 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 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 three quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

Main article: IP 71111.13

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

impact of Unit 2 scram on scheduled work week;

inoperability of both trains of Unit-Common auxiliary electrical equipment room ventilation system; and,

both units in Yellow risk due to the Unit-Common EDG out of service.

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

Main article: IP 71111.15

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

Unit 1 MSIVs due to extent of condition from Unit 2;

Unit 1 turbine stop valve quarterly surveillance failure and possible effect on past operability;

Unit 1 A residual heat removal (RHR) Generic Letter 2008-01 emergency core cooling system gas void identified through ultrasonic testing; and

Unit 1 control rod 46-39 drifted out.

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.

These operability inspection activities constituted four samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

Main article: IP 71111.19

.1 Post-Maintenance Testing

a. Inspection Scope

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

Unit 2 SBGT control switch;

Unit 1 standby liquid control Engineering Change 391192;

Unit 2 A inboard MSIV;

Unit 2 B inboard MSIV;

Unit 2 C inboard MSIV;

Unit 2 D inboard MSIV; and

Unit 2 B EDG starting air recovery discharge pressure switch.

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 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 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.

.2 (Closed) Unresolved Item 05000373/2014003-03: Unit 1 Reactor Protection System

Limit Switch Testing Failure

a. Inspection Scope

The inspectors identified an Unresolved Item (URI) in the second quarter Integrated Inspection Report 2014003-03, concerning maintenance activities associated with Unit 1 RPS Limit Switch 1C71 N006B. The inspectors have reviewed the completed ACE.

The licensees ACE 1665272, Relay 1C71A-K10B Failed To De-Energize During LOS-RP-Q2, concluded that the first adjustment was not sufficient to ensure adequate clearance existed during normal operation with consideration to thermal growth of the components due to plant heat up and inherent vibration of the system. The licensee attributed this performance issue to Maintenance Practices - Worker Knowledge or Skill Deficiency.

This review did not constitute an additional sample as defined in IP 71111.19-05, as it was performed under IP 71111.15, and documented in section 1R15 of this report. In accordance with IMC 0612, if the closure of a URI resulted in the identification of a finding, the finding and/or associated violation should be documented in the inspectable area section of the report in which the original URI was documented. This URI originated in section 1R19 of NRC IR 05000373/2014003. Documents reviewed are listed in the Attachment to this report.

b. Findings

Unit 1 Reactor Protection System Limit Switch Testing Failure

Introduction:

A finding of very low safety significance (Green) and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed by the repeated failure of RPS limit switch 1C71-N006B due to the licensees failure to provide instructions appropriate to the circumstances. Specifically, the installation instructions did not contain sufficient guidance to allow RPS limit switch 1C71-N006B to be adjusted so that adequate clearance would exist during normal operation to ensure operability.

Description:

On May 29, 2014, the licensee was performing routine surveillance LOS-RP-Q2, Unit 1 Turbine Stop Valve Scram Functional Test. This test was performed quarterly and was the first test of these valves following the Unit 1 refueling outage in February 2014. One portion of the test verified that the equipment used to detect stop valve closure was working and that once detected, appropriate system responses occurred. Following test initiation, the expected system response was not obtained.

On February 14, during refueling outage L1R15, limit switch 1C71-N006B was replaced as part of a planned preventative maintenance activity. Following installation, the licensee identified that this switch was not providing proper system response during post-installation checks. This issue was entered into the licensees CAP as Action Request (AR) 01623484, Limit Switch 1C71-N006B Contact Found Closed. On February 25, licensee staff identified that the cause of the improper system response was mechanical interference between the limit switch mounting hardware and the actuating arm. The inspectors noted that the unit was shutdown during this entire time frame and that the system was not yet required to be operable.

Maintenance personnel adjusted the limit switch actuator arm to eliminate the mechanical interference. Specifically, the actuating arm was shifted farther down the splined shaft of the limit switch. Proper operation was demonstrated via testing. The procedure used for post maintenance testing was LES-EH-101, Unit 1 Turbine Stop Valve Limit Switch Calibration and Relay Test. Operators tested the turbine stop valves a second time using LOS-RP-Q2 prior to returning them to service. Both of these tests were performed while the component temperatures were below their normal operating temperatures.

On May 29, while the unit was operating normally at full power, the licensee performed LOS-RP-Q2 in support of routine testing requirements when 1C71-N006B failed to actuate. This issue was entered into the licensees CAP as AR 01665272, Relay 1C71A-K10B Failed to De-Energize During LOS-RP-Q2. This was the first test performed since the testing performed on February 25. Troubleshooting identified that the issue was mechanical interference between the limit switch mounting hardware and the actuating arm. Specifically, licensee staff identified that the mounting bolts were installed such that the excess length extended towards the path of the actuating arm. As an immediate corrective action, licensee staff reoriented the mounting bolts so that the excess length would not interfere with the path of the actuating arm. After the switch was remounted, the licensee adjusted the limit switch and successfully performed post-maintenance testing.

The inspectors reviewed how the installation and adjustment procedures specifically controlled the installation of the bolts and the acceptable clearance for the actuator arm of the limit switch. Procedure LEP-GM-101, Operating Check and Replacement of Namco Limit Switches and Operating Levers, did not contain specific direction for installing mounting bolts, a dimension for positioning the actuator arm on the limit switch splined shaft, or a stated clearance requirement between the actuator arm and other potential obstructions. The procedure instead included a generic check for proper operation.

Next, the inspectors reviewed WO 1522778, MSV1: Replace All Limit Switches at MSV-1. This work package directed that limit switch adjustments be performed in accordance with LEP-GM-101. The inspectors then reviewed WO 1518443, U-1 Turbine Stop Valve Closure Test and Adjustment. This work package directed that work be performed in accordance with LES-EH-101, Unit 1 Turbine Stop Valve Limit Switch Calibration and Relay Test. This procedure did include directions to adjust the limit switch, but no specific guidance was provided for installing mounting bolts, a dimension for positioning the actuator arm on the limit switch splined shaft, or a stated clearance requirement between the actuator arm and other potential obstructions.

On July 22, the licensee completed an ACE for this issue. The licensee identified maintenance practices as the apparent cause. Specifically, the licensee concluded that there was a worker knowledge or skill deficiency. The inspectors found that the following statement from the licensees ACE highlighted the issue succinctly: The first adjustment was not sufficient to ensure adequate clearance existed during normal operation with consideration to thermal growth of the components due to plant heat-up and inherent vibration of the system To address this deficiency, the licensee plans to evaluate: 1) maintenance training needs; 2) potential procedure enhancements; and, 3) potential enhancements to model-WOs.

Analysis:

The inspectors determined that the failure to provide procedures appropriate to the circumstances was contrary to Criterion V, Instructions, Procedures, and Drawings, of 10 CFR Part 50, Appendix B, and was a performance deficiency.

The finding was determined to be more than minor because the finding 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 (i.e., core damage). Specifically, RPS limit switch 1C71-N006B is a safety-related component that, in conjunction with other inputs, can initiate a reactor scram.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Attachment 0609.04, Phase 1 - Initial Screening and Characterization of Findings, Table 3 for the Mitigating System Cornerstone, dated June 19, 2012. Table 3 directs evaluation under Appendix A, The Significance Determination Process (SDP) for Findings At-Power. Under Exhibit 2 of Appendix A, Mitigating Systems Screening Questions, Section C, Reactivity Control Systems, the inspectors answered No to each of the questions; therefore, the issue screened as Green.

This finding has a cross-cutting aspect in the area of Human Performance, Training, because the licensee did not provide training and ensure knowledge transfer to maintain a knowledgeable, technically competent workforce and instill nuclear safety values.

Specifically, the successful completion of maintenance tasks, such as the installation and adjustment of RPS limit switch 1C71-N006B, requires appropriate procedures as well as training. It is generally understood that a balance must be struck between the level of individual training provided and the level of detail in any given work instruction/procedure. For example, if the procedures are highly detailed, the training may be more general in nature and vice versa. In this instance, the level of individual training was at such a level that the procedure needed to be of greater detail to be appropriate to the circumstances (H.9).

Enforcement:

10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, and drawings of a type appropriate to the circumstances and be accomplished in accordance with those instructions, procedures and drawings. The licensee established LEP-GM-101, Operating Check and Replacement of Namco Limit Switches and Operating Levers, Revision 6, and LES-EH-101, Unit 1 Turbine Stop Valve Limit Switch Calibration and Relay Test, Revision 20, as the implementing procedure for stop valve limit switch adjustment, an activity affecting quality.

Contrary to the above, on February 25, 2014, the licensee failed to have a procedure appropriate to the circumstance for adjustment of RPS limit switch 1C71-N006B.

Specifically, the procedures did not contain sufficient guidance to allow RPS limit switch 1C71-N006B to be adjusted so that adequate clearance would exist during normal operation to ensure operability.

This violation is being treated as an NCV consistent with Section 2.3.2.a of the Enforcement Policy because it was of very low safety significance, was entered into the licensees CAP (as AR 01623484), and was not willful (NCV 05000373/2014004-01, Unit 1 Reactor Protection System Limit Switch Testing Failure).

As corrective actions, the licensee plans to evaluate: 1) maintenance training needs; 2) potential procedure enhancements; and, 3) potential enhancements to model WOs.

1R20 Outage Activities

Main article: IP 71111.20

.1 Other Outage Activities

a. Inspection Scope

The inspectors evaluated Unit 2 outage activities for an unscheduled outage that was caused by the failure of the C inboard MSIV. The outage began on August 5, 2014, with an unplanned scram, and continued through August 18. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule. The forced-outage work scope included the upgrade/replacement of MSIV components on all four of the inboard MSIVs on Unit 2, to preclude any extent of condition vulnerabilities. Unit 2s outboard MSIVs had already been previously upgraded.

The inspectors observed or reviewed the reactor shutdown and cooldown, outage equipment configuration and risk management, electrical lineups, selected clearances, control and monitoring of decay heat removal, control of containment activities, personnel fatigue management, startup and heatup activities, and identification and resolution of problems associated with the outage. Additionally, the inspectors monitored the licensees troubleshooting/repair/maintenance activities on the inboard MSIVs. The majority of the MSIV-related inspections were conducted using a variety of other baseline inspection samples, e.g., 71111.19, Post-Maintenance Testing, and the results of those inspections are documented in the respective sections within this report.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R22 Surveillance Testing

Main article: IP 71111.22

.1 Surveillance Testing

a. Inspection Scope

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

LES-RH-106 Unit 1 B RHR minimum flow valve timing (Routine);

Unit 2 A reactor recirculation calibration (Routine);

Unit-Common EDG fast start test (Routine); and

Unit 1 SBGT (Inservice Testing--IST).

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 and one inservice testing sample as defined in IP 71111.22, Sections-02 and-05.

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP4 Emergency Action and Emergency Plan Changes

Main article: IP 71114.04

.1 Emergency Action and Emergency Plan Changes

a. Inspection Scope

The Nuclear Security and Incident Response headquarters staff performed an in-office review of the latest revision to Evacuation Time Estimate Analysis for LaSalle County Station, Units 1 and 2, located under NRC's Agencywide Documents Access and Management System (ADAMS) accession number ML14128A158 as listed in the

.

The staff performed a review using the guidance provided in NUREG/CR-7002, Criteria for Development of Evacuation Time Estimate Studies. The Updated Evacuation Time Estimate was found to be complete in accordance with 10 CFR Part 50, Appendix E.IV.3. The NRC review was only intended to verify consistent application of the evacuation time estimate guidance contained in NUREG/CR-7002; and therefore remains subject to future NRC inspection in its entirety. Documents reviewed are listed in the Attachment to this report.

This emergency plan review inspection constituted no samples as defined in Inspection Procedure 71114.04-06

b. Findings

No findings were identified.

1EP5 Maintaining Emergency Preparedness

Main article: IP 71114.05

.1 Maintaining Emergency Preparedness

a. Inspection Scope

Nuclear Regulatory Commission Emergency Preparedness rulemaking, which became effective on December 23, 2011, added a new regulation that required a licensee to develop an ETE analysis and submit it to the NRC by December 22, 2012. This inspection was a follow-up of issues identified by the NRC headquarters staff during its review of the Exelon submittal of the ETE for the ten sites that it operates. The NRC headquarters staff relayed those issues to Exelon, which provided responses through 2013 and into 2014. During this inspection period, regional Emergency Preparedness inspectors reviewed applicable licensee documents, conducted discussions with licensee personnel, and provided assessment of the Exelon response. Documents reviewed are listed in the Attachment to this report.

This emergency preparedness inspection constituted no samples as defined in Inspection Procedure 71114.05.

b. Findings

Inadequate Evacuation Time Estimate Submittals

Introduction:

The NRC identified a finding of very low safety significance (Green) and associated NCV of 10 CFR 50.54(q)(2) for failing to maintain the effectiveness of the LaSalle County Station Emergency Plan. Specifically, the licensee failed to provide the station ETE to responsible OROs and failed to update their site-specific protective action strategies as necessary as required by 10 CFR 50.47(b)(10), and Section IV, Paragraph 4 of Appendix E to 10 CFR Part 50.

Description:

The NRC issued final new and amended emergency preparedness regulations on November 23, 2011 (76 Federal Register 72560). This rulemaking, which became effective on December 23, 2011, amended 10 CFR 50.47(b)(10) to require licensees to update the ETE on a periodic basis. The rulemaking also added a new regulation 10 CFR Part 50, Appendix E, Section IV.4, which requires a licensee to develop an ETE analysis using the most recent decennial census data and submit it to the NRC within 365 days of December 23, 2011. Concurrently with the issuance of the rulemaking, the NRC published a new report entitled Criteria for Development of Evacuation Time Estimate Studies, NUREG/CR-7002. The Statements of Consideration for the rulemaking (76 Federal Register 72580) identified that the NRC would review the submitted ETEs for completeness using that document. The Statements also provided that the guidance of NUREG/CR-7002 was an acceptable template to meet the requirements, and that licensees should use the guidance or an appropriate alternative.

By individual letters dated December 12, 2012, Exelon submitted the ETEs for the sites for which it holds the operating licenses, including LaSalle County Station. By a letter dated January 23, 2013, Exelon submitted the NUREG/CR-7002 checklists for these ETEs. These checklists identified where a particular criterion was addressed in the ETEs, facilitating the NRC review.

As provided in the Statements of Consideration, the NRC performed a completeness review using the checklists and found the ETEs (including that for the LaSalle County Station) to be incomplete due to common and site-specific deficiencies. The NRC discussed its concerns regarding the completeness of the ETEs, in a teleconference with Exelon conducted on June 10, 2013. By letter dated September 5, 2013, Exelon resubmitted the ETEs and the associated checklists for its sites. The NRC performed another completeness review and again found the ETEs to be incomplete. Examples of information missing from the submittal included: peak and average attendance were not stated (NUREG/CR-7002 Criteria Item 2.1.2.a); the ETE used a value based on campsite and hotel capacity, vice an average value (2.1.2.b); basis for speed and capacity reduction factors due to weather was not provided (3.4.b); snow removal was not addressed (3.4.c); no bus routes or plans were included in the ETE analysis (4.1.2.a); and, no discussion on the means of evacuating ambulatory and nonambulatory residents was included (4.1.2.b).

Exelon entered this issue into its CAP as AR 01525923 and AR 01578649. Exelon submitted a third ETE for LaSalle County Station on April 30, 2014, and the NRCs review of that ETE was found complete and documented in Section 1EP4 of this report.

Analysis:

The inspectors determined that Exelons failure to submit a complete updated ETE for the LaSalle County Station by December 22, 2012, was a licensee performance deficiency because the issue was a failure to comply with a regulatory requirement and the issue was reasonably within the licensees ability to foresee and correct, and therefore should have been prevented, for both the December 12, 2012, and September 5, 2013, submittals.

Using IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, the inspector determined that the performance deficiency is associated with the Emergency Preparedness Cornerstone attribute of procedure quality and was more than minor because it adversely affected the cornerstone objective of ensuring that the licensee is capable of implementing adequate measures to protect the health and safety of the public in the event of a radiological emergency. The ETE is an input into the development of protective action strategies prior to an accident and to the protective action recommendation decision-making process during an accident. Inadequate ETEs have the potential to reduce the effectiveness of public protective actions implemented by the OROs.

The inspectors used IMC 0609, Appendix B, Emergency Preparedness (EP)

Significance Determination Process (SDP), to determine the significance of the performance deficiency. The performance deficiency was associated with planning standard 10 CFR 50.47(b)(10). Emergency Preparedness SDP Table 5.10-1, Significance Examples §50.47(b)(10), provides two Green significance examples:

ETEs and updates to the ETEs were not provided to responsible OROs, and The current public protective action strategies documented in emergency preparedness implementing procedures are not consistent with the current ETE. The inspectors concluded that, because the performance deficiency delayed the NRCs approval of the LaSalle County Station ETE, the ETE was not provided to the site OROs nor was it used to inform the site emergency preparedness implementing procedures as required by 10 CFR 50.47(b)(10), and Section IV, Paragraph 4 of Appendix E to 10 CFR Part 50.

Therefore, in accordance with Emergency Preparedness SDP Table 5.10-1, this finding screened as a Green finding.

This finding had a cross-cutting aspect in the area of Human Performance, Documentation, because Exelon personnel did not create and maintain complete, accurate, and up-to-date documentation. Specifically, the Emergency Preparedness organization did develop the LaSalle County Station ETE as required by the new regulation introduced by the NRCs Emergency Preparedness Rule (H.7).

Enforcement:

Requirements in 10 CFR 50.54(q)(2) state, in part, that a licensee shall follow and maintain the effectiveness of emergency plans which meet the standards in 10 CFR 50.47(b) and the requirements in Appendix E to this part. Title 10 CFR 50.47(b)(10), requires, in part, that licensees shall develop an evacuation time estimate and update it on a periodic basis. Title 10 CFR Part 50, Appendix E, Section IV.4, states that within 365 days of December 23, 2011, nuclear power reactor licensees shall develop an ETE analysis and submit it under § 50.4.

Contrary to the above, within 365 days of December 23, 2011, Exelon, the licensee for LaSalle County Station failed to develop a complete and adequate ETE analysis and submit it under 10 CFR 50.4. Immediate corrective actions taken by Exelon included entering this issue into its CAP and revising the ETE to satisfy NRC requirements.

Because this finding is of very low safety significance (Green) and was entered into Exelons CAP, this issue is being treated as an NCV consistent with Section 2.3.2.a. of the Enforcement Policy (NCV 05000373/2014004-02; 05000374/2014004-02, Inadequate Evacuation Time Estimate Submittals).

1EP6 Drill Evaluation

Main article: IP 71114.06

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on July 29, 2014, 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 to this report. Documents reviewed are 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.

OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and Emergency Preparedness

4OA1 Performance Indicator Verification

Main article: IP 71151

.1 Mitigating Systems Performance IndexEmergency AC Power System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - emergency AC power system performance indicator (PI) for Units 1 and 2 for the third quarter 2013 through the second quarter 2014. To determine the accuracy of the PI data reported, PI definitions and guidance in the Nuclear Energy Institute (NEI)

Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, were used. The inspectors reviewed the licensees operator narrative logs, MSPI derivation reports, issue reports, event reports, and NRC Integrated Inspection Reports for July 2013 through June 2014 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 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 systems PI for Units 1 and 2 for the third quarter 2013 through the second quarter 2014.

To determine the accuracy of the PI data reported, PI definitions and guidance contained in NEI 99-02 were used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports, and NRC Integrated Inspection Reports for July 2013 through June 2014 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 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 indicator for Units 1 and 2 for the third quarter 2013 through the second quarter 2014. To determine the accuracy of the PI data reported, PI definitions and guidance contained in NEI 99-02 were used. The inspectors reviewed the licensees operator narrative logs, issue reports, MSPI derivation reports, event reports, and NRC Integrated Inspection Reports for July 2013 through June 2014 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 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.

4OA2 Identification and Resolution of Problems

Main article: IP 71152

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

.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. Documents reviewed are listed in the 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

To assist with the identification of repetitive equipment failures and specific human performance issues for follow-up, 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. Documents reviewed are listed in the to this report.

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.

.3 Selected Issue Follow-Up Inspection: MSIV Operating Experience Review

a. Inspection Scope

During a review of items entered in the licensees CAP, the inspectors reviewed a CAP item documenting the unexpected failure of the Unit 2 C inboard MSIV, 2B21-F022C, which led to an unplanned scram and forced outage. At the time of the failure, the licensee initially performed a prompt investigation into the matter and preliminarily determined that the likely failure mechanism was identical to that of a 2002 failure seen elsewhere in the industry, which was the subject of numerous operating experience documents at the time. As a result, the inspectors located and reviewed the applicable operating experience documents related to the specific make/model of valve that failed at LaSalle; specifically, the Rockwell Y-pattern globe valve model 1612JMMNTY (At LaSalle there were 16 MSIVs total for both Units, 8 per Unit with 4 in the drywell and 4 outside of the drywell). The objective of the inspection was to gather available operating experience information and assess its applicability to LaSalles event. The inspectors concluded that the Nine Mile Point operating experience reports from the 2002-2003 timeframe were directly applicable.

It was noted by the inspectors that LaSalle took action in the 2003-2005 timeframe and began the process of upgrading all of the MSIVs on both units to preclude the occurrence of the events described in the operating experience reports. Specifically, those event reports revealed a characteristic of the valve design that made it particularly susceptible to certain failure mechanisms under normal operating conditions due to inadequate valve stem-to-disc torque loading. In that timeframe, LaSalle upgraded a total of 7 MSIVs but then deferred the remainder of the modifications.

At the time of this inspection, the licensee was in the process of performing a root cause investigation, which will be the subject of a future in-depth baseline inspection by the resident inspectors upon its completion, as will the forthcoming 50.73 licensee event report for this occurrence.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

.4 Annual Sample: Review of Operator Workarounds

a. Inspection Scope

The inspectors evaluated the licensees implementation of its 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 the operator workarounds (OWAs) on system availability and the potential for improper operation of the system, for potential impacts on multiple systems, and on the ability of operators to respond to plant transients or accidents.

The inspectors performed a review of the cumulative effects of OWAs. The 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 its 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 longstanding 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 OWAs. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

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

Main article: IP 71153

.1 Unit 2 Scram Response on August 5, 2014

a. Inspection Scope

The inspectors reviewed the plants response to the failure of the Unit 2 C inboard MSIV and its resultant unplanned scram-with-complications on August 5, 2014. The inspectors observed the stations initial response activities from the main control room, as well as from the outage control center.

The objective of this inspection was to evaluate the event and degraded conditions for plant status and mitigating actions in order to provide input in determining the need for a reactive inspection, e.g. Special Inspection.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

4OA6 Management Meetings

.1 Exit Meeting Summary

On October 1, 2014, the inspectors presented the inspection results to Mr. P. Karaba, 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

On September 8, 2014, an interim exit meeting was conducted by phone to present the results of the emergency preparedness program inspection to Mr. M. Hayworth.

On September 25, 2014, the inspectors presented the LORT program inspection results to Mr. T. Dean, LaSalle Station Operations Training Manager. The licensee acknowledged the issues presented.

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.

ATTACHMENT: