IR 05000373/2014003

IR 05000373-14-003, 05000374-14-003; on 04/01/2014 - 06/30/2014; LaSalle County Station, Units 1 and 2; Equipment Alignment and Refueling and Other Outage Activities

ML14213A361
Person / Time
Site:	LaSalle
Issue date:	08/01/2014
From:	Michael Kunowski NRC/RGN-III/DRP/B5
To:	Pacilio M Exelon Generation Co, Exelon Nuclear
References
IR-14-003
Download: ML14213A361 (40)

Text

UNITED STATES ust 1, 2014

SUBJECT:

LASALLE COUNTY STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000373/2014003; 05000374/2014003

Dear Mr. Pacilio:

On June 30, 2014, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your LaSalle County Station, Units 1 and 2. On July 2, the NRC inspectors discussed the results of this inspection with the Plant Manager, Mr. H. Vinyard, and other members of your staff. The inspectors documented the results of this inspection in the enclosed inspection report.

The NRC inspectors documented two findings 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 Resident Inspector at LaSalle County Station.

If you disagree with the cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Senior Resident Inspector at LaSalle County Station. In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding, of the NRC's "Rules of Practice," a copy of this letter 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).

ADAMS is 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 05000373/2014003; 05000374/2014003 w/Attachment: Supplemental Information

REGION III==

Docket Nos: 05000373; 05000374 License Nos: NPF-11; NPF-18 Report No: 05000373/2014003; 05000374/2014003 Licensee: Exelon Generation Company, LLC Facility: LaSalle County Station, Units 1 and 2 Location: Marseilles, IL Dates: April 1 through June 30, 2014 Inspectors: R. Ruiz, Senior Resident Inspector J. Robbins, Resident Inspector J. Beavers, Acting Resident Inspector R. Baker, Region III Operations Engineer I. Hafeez, Region III Reactor Inspector G. Roach, Senior Resident Inspector, Dresden M. Holmberg, Region III Senior Reactor Inspector D. Chyu, Region III Reactor Engineer R. Zuffa, IEMA (Illinois Emergency Management Agency), Resident Inspector Approved by: M. Kunowski, Chief Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report 05000373/2014003, 05000374/2014003; 04/01/2014 - 06/30/2014; LaSalle

County Station, Units 1 and 2; Equipment Alignment and Refueling and Other Outage Activities This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Two Green findings were identified by the inspectors. The findings were considered non-cited violations (NCVs) of NRC regulations. The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green,

White, Yellow, Red) and determined using Inspection Manual Chapter (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.

The inspectors identified a finding of very low safety significance (Green) and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions,

Procedures, and Drawings, for the licensees failure to follow written instructions, prominently displayed on signs and placards, which prohibit the storage of items that can potentially clog the floor drains in safety-related flood control areas of the plant.

Specifically, on several occasions, the inspectors identified materials that were placed either on or near the floor of emergency core cooling system (ECCS) corner rooms such that the materials would have posed a potential clogging hazard for the floor drains during a flooding event. Upon notification by the inspectors of the presence of prohibited materials, the licensee promptly removed the items from the areas. The most recent occurrence was entered into the licensees corrective action program (CAP) as Action Request (AR) 01661788, and a number of interim compensatory measures, such as shiftly walkdowns by operations and radiation protection (RP), were implemented to ensure that the areas remained clear of prohibited items until more permanent corrective actions were developed and put in place. An apparent cause evaluation (ACE) was performed to determine the underlying cause of the performance deficiency, and to develop appropriate corrective actions.

The finding was determined to be more than minor because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and adversely affected the cornerstones objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.

Specifically, the failure to adhere to the written instructions of the postings in the ECCS corner rooms led to the storage of prohibited items within those areas, which could have potentially challenged equipment availability during a flooding event. The finding was determined to be of very low safety significance (Green) in accordance with the Significance Determination Process (SDP) because the performance deficiency did not result in the inoperability of any structures, systems, or components (SSCs). This finding had a cross-cutting aspect in the area of Human Performance, Training, because the organization did not ensure that the appropriate knowledge was transferred to the staff (H.9). Specifically, the staff was not effectively trained on the features of the flood control areas; therefore, the importance of keeping prohibited items out of the areas for flood mitigation purposes was not sufficiently understood. (Section 1R04)

Cornerstone: Occupational Radiation Safety

Green.

A finding of very low safety significance and associated non-cited violation of Technical Specification 5.4.1.a, Procedures, was self-revealed for the licensees failure to have appropriate procedures in place per Regulatory Guide (RG) 1.33, Revision 2, for filling and draining the reactor vessel. Specifically, procedures MA-AB-756-601,

Reactor Reassembly, LGP-3-5, Refueling Operations, and LOP-FC-16, Reactor Vessel/Cavity Draindown Via RHR SDC did not contain appropriate detail and direction to ensure that the reactor vessel level could be accurately controlled and maintained below the flange to prevent water from overflowing the unsealed vessel before the head was re-tensioned. This lapse in reactor water level control resulted in the evacuation of personnel from the refuel floor and led to six instances of external personnel contamination and eleven instances of internal personnel contamination. The licensee immediately corrected the vessel level and entered the issue into its CAP as AR 01655617. An ACE was performed and corrective actions were developed to revise the above procedures to incorporate an appropriate level of guidance and information, to prevent recurrence.

The finding was determined to be more than minor because it was associated with the program and process (procedures) attribute of the Occupational Radiation Safety Cornerstone, and adversely affected the cornerstones objective of ensuring the adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian reactor operation. Specifically, the failure to have adequate procedures in place to allow operators to accurately control vessel level directly resulted in adverse radiological conditions that impacted some of the plant workers on the refuel floor, and resulted in unplanned external and internal contamination events. The finding was determined to be of very low safety significance (Green) in accordance with Inspection Manual Chapter (IMC) 0609 Appendix C,

Occupational Radiation Safety Significance Determination Process. This finding had a cross-cutting aspect in the area of Human Performance, Resources, because the licensee did not ensure that procedures with appropriate guidance were available to the operators to support nuclear safety (H.1). Specifically, critical information regarding the proper strategy to control vessel level and moderator temperature prior to and following vessel disassembly and reassembly was not provided within the applicable procedures.

(Section 1R20)

REPORT DETAILS

Summary of Plant Status

Unit 1 The unit began the inspection period operating at full power. On May 17, 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 April 26, 2014, Unit 2 began shutting down for a mid-cycle maintenance outage, L2M17, to locate and replace leaking fuel assemblies, and replace a leaking safety relief valve. The outage began on April 27 when the unit was disconnected from the grid. Following completion of the maintenance activities, the unit was restarted and synchronized to the grid on May 6. Full power was achieved on May

REACTOR SAFETY

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

1R01 Adverse Weather Protection

.1 Readiness of Offsite and Alternate AC Power Systems

a. Inspection Scope

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

• coordination between the TSO and the plant during off-normal or emergency events;

• explanations for the events;

• estimates of when the offsite power system would be returned to a normal state; and

• notifications from the TSO to the plant when the offsite power system was returned to normal.

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

• actions to be taken when notified by the TSO that the post-trip voltage of the offsite power system at the plant would not be acceptable to assure the continued operation of the safety-related loads without transferring to the onsite power supply;

• compensatory actions identified to be performed if it would not be possible to predict the post-trip voltage at the plant for the current grid conditions;

• re-assessment of plant risk based on maintenance activities which could affect grid reliability, or the ability of the transmission system to provide offsite power; and

• communications between the plant and the TSO when changes at the plant could impact the transmission system, or when the capability of the transmission system to provide adequate offsite power was challenged.

Documents reviewed are listed in the Attachment to this report. The inspectors also reviewed CAP items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into the CAP in accordance with station corrective action procedures.

This inspection constituted one readiness of offsite and alternate AC power systems sample as defined in Inspection Procedure (IP) 71111.01-05.

b. Findings

No findings were identified.

.2 Summer Seasonal Readiness Preparations

a. Inspection Scope

The inspectors performed a review of the licensees preparations for summer weather for selected systems, including conditions that could lead to an extended drought.

During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions.

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. Documents reviewed are listed in the Attachment to this report. The inspectors also reviewed CAP items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into the CAP in accordance with station corrective action procedures. The inspectors reviews focused specifically on the following plant systems:

• residual heat removal (RHR) service water (SW) system; and

• essential switchgear room ventilation.

This inspection constituted one seasonal adverse weather sample as defined in IP 71111.01-05.

b. Findings

No findings were identified.

1R04 Equipment Alignment

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

• Unit 1 standby gas treatment (SBGT) system;

• Unit 2 Division II RHR and RHRSW systems with Division I out of service; and

• Unit 2 standby liquid control (SBLC) system; 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), 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 CAP with the appropriate significance characterization. Documents reviewed are listed in the to this report.

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

b. Findings

Failure to Adhere to Postings Led to Prohibited Items Being Left in ECCS Corner Rooms

Introduction:

The inspectors identified a finding of very low safety significance and associated NCV of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, for the licensees failure to follow written instructions, which prohibit the storage of items that could potentially clog the floor drains, flood-out (short-circuit)safety-related pump motors and adversely affect the systems availability and station response during an internal flooding event. Specifically, on several occasions, inspectors identified materials that were placed either on the floor or on a surface that was below the maximum safe operating water level for the room, such that the materials would have posed a potential clogging hazard for the floor drains during a flooding event.

Description:

On May 19, 2014, during a walkdown of the Unit 2 B/C RHR pump corner room (a protected train system at the time), inspectors identified a number of items on the floor (or other horizontal surfaces like a pump skid less than 20 inches from the floor), such as a plastic bucket containing rubber gloves and other loose materials; a plastic bag; knee pads; an oil absorbent pad; and a rag. The inspectors, aware that this specific room is a flood control area, recognized that these materials could have the potential to clog the floor drains in the room during a flooding event, and the inspectors immediately notified the operations shift manager. Operations personnel subsequently removed the items, entered the issue into the CAP, and assessed that the presence of the items did not challenge the operability of the systems.

The inspectors verified that the permanent placard and signage near the entrance of the room were present and visible. The written instructions on these signs read You are entering a flood control area. Do not store material on the corner room floors Elevation 673, that may be swept into the floor drains by a flooding event; and No floatable material or materials that could plug floor drains may be stored in this area.

The storage of material in these areas was also discussed in emergency operating procedure LGA 002, Secondary Containment Control. For areas listed in Table W of the procedure, comprising the ECCS corner rooms and reactor building raceways, the procedure discussed that if materials were to clog the floor drains during an internal flooding event, the systems availability, and station response to the event, could be adversely impacted. With clogged floor drains, the amount of time that it would take for accumulating water to reach a height that would impact local safety systems ability to perform their functions would be decreased because the waters ability to get pumped out by the sump pump would be impeded. The stations response to high water conditions in flood control areas (per LGA-002) could have also been adversely impacted by clogged drains if water that would have otherwise been within the capacity of sump pumps to remove, accumulated to the point of driving otherwise avoidable actions such as scramming the unit per section 28 of the procedure.

The inspectors noted that on two previous occasions in 2013 (ARs 01501319 and 014964572), prohibited items were identified by the NRC within LGA-002 Detail W areas, but the quantity of material present was smaller than that of the May 2014 occurrence and did not impact system operability. The inspectors also noted that in each instance, corrective actions were taken by the licensee, but that they were not effective at preventing this problem from recurring.

The licensee performed an ACE in response to this issue and determined that the apparent cause was a lack of knowledge of requirements for floatable material in flood protected areas. Additionally, through the licensees ACE report, four other recent instances were noted (ARs 0992753, 01008439, 01036321, and 01292900) of prohibited items being found in Detail W locations by the licensee.

Analysis:

The inspectors determined that the licensees placement of prohibited, floatable items in these flood protected zones was contrary to signs prominently posted on the walls near the entrances to the applicable zones and was a performance deficiency.

The finding was determined to be more than minor in accordance with IMC 0612, Appendix B, Issue Screening, dated September 7, 2012, because it was associated with the equipment performance attribute of the Mitigating Systems Cornerstone, and adversely affected the cornerstones objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences. Specifically, the failure to adhere to the written instructions of the postings in the ECCS corner rooms led to the existence of unattended, prohibited items within those areas which could have potentially challenged equipment availability or adversely impacted the station response to a postulated internal flooding event.

The inspectors determined the finding could be evaluated using the SDP in accordance with IMC 0609, Significance Determination Process, Appendix A, Exhibit 2, Mitigating Systems Screening Questions, dated June 19, 2012. The inspectors answered Yes to question 1 of Section A; therefore, the finding screened out as having very low safety significance (Green) because the finding was a qualification deficiency confirmed not to result in loss of operability or functionality. This finding had a cross-cutting aspect in the area of Human Performance, Training, because the organization did not ensure that the appropriate knowledge was transferred to the staff (H.9). Specifically, the staff was not effectively trained on the features of the ECCS corner rooms and reactor building raceways, such that the importance of keeping prohibited items out of those areas for flood mitigation purposes was not sufficiently understood.

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 of a type appropriate to the circumstances and be accomplished in accordance with these instructions. The licensee posted signs in the ECCS cornor rooms probhibiting the storage of materials that could block the floor drains and result in a high water that would cause the motors of the safety-related pumps to become inoperable (short-out), an activity affecting quality.

Contrary to the above, on May 19, 2014, multiple prohibited items, such as a plastic bucket containing rubber gloves and other loose materials; a plastic bag and knee pads; an oil absorbent pad; and a rag, were discovered by inspectors to have been stored by the licensee in the Unit 2 B/C RHR Corner Room. Previously, the inspectors identified the storage of a smaller quantity of prohibited items in ECCS corner rooms on January 18 and April 12, 2013; the licensee had entered both instances in its CAP.

For corrective actions, the licensee immediately removed the prohibited items and entered the issues into its CAP (as AR 01661788), and a number of interim compensatory measures, such as shiftly walkdowns by operations and RP staff, were implemented to ensure that the areas remained clear of prohibited items until more permanent corrective actions were developed and put in place. An ACE was performed and corrective actions were developed to better define the types of prohibited items; to include steps within all WOs in flood control areas to ensure all materials are removed; to place permanent storage containers in the rooms; and to disseminate the appropriate information to staff regarding the specific requirements of the flood control areas, to prevent recurrence. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy (NCV 05000373;05000374/2014003-01, Failure to Adhere to Postings Led to Prohibited Items Being Left in ECCS Corner Rooms).

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:

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

• Unit 2 Division II diesel generator (DG) room, fire zone 8B2;

• Unit 1 cable spreading room, fire zone 4D1;

• Unit 2 cable spreading room, fire zone 4D2; and

• Unit 1 balance of plant cable area FZ 5A4.

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.

1R06 Flooding

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk-important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the UFSAR, engineering calculations, and abnormal operating procedures to identify licensee commitments. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the fire suppression or the circulating water systems. The inspectors also reviewed the licensees CAP documents with respect to past flood-related items identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the plant area associated with the following item to assess the adequacy of watertight doors and verify drains and sumps were clear of debris and were operable, and that the licensee complied with its commitments:

• Ice melt line break internal flooding scenario Documents reviewed are listed in the Attachment to this report. This inspection constituted one internal flooding sample as defined in IP 71111.06-05.

b. Findings

No findings were identified.

1R07 Annual Heat Sink Performance

.1 Heat Sink Performance

a. Inspection Scope

The inspectors reviewed the licensees testing of 1B RHR seal cooler heat exchanger to verify that potential deficiencies did not mask the licensees ability to detect degraded performance, to identify any common cause issues that had the potential to increase risk, and to ensure that the licensee was adequately addressing problems that could result in initiating events that would cause an increase in risk. The inspectors reviewed the licensees observations and acceptance criteria, the correlation of scheduled testing and the frequency of testing, and the impact of instrument inaccuracies on test results.

The inspectors also verified that test acceptance criteria considered differences between test conditions, design conditions, and testing conditions. Documents reviewed are listed in the Attachment to this document.

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

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

a. Inspection Scope

On April 21, 2014, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

• prioritization, interpretation, and verification of annunciator alarms;

• correct use and implementation of abnormal and emergency procedures;

• control board manipulations;

• oversight and direction from supervisors; and

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

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

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

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

a. Inspection Scope

On April 27, 2014, the inspectors observed operators in the control room during the Unit 2 shutdown. This was an activity that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas:

• licensed operator performance;

• crews clarity and formality of communications;

• ability to take timely actions in the conservative direction;

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

• correct use and implementation of procedures;

• control board (or equipment) manipulations; and

• oversight and direction from supervisors.

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

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

b. Findings

No findings were identified.

1R12 Maintenance Effectiveness

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

• Unit 1 RHR; and

• periodic evaluation.

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 SSCs/functions classified as (a)(2),or appropriate and adequate goals and corrective actions for systems classified as (a)(1).

The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two quarterly maintenance effectiveness samples as defined in IP 71111.12-05.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

• Unit 1 yellow risk due to planned Division I RHR work;

• both units yellow risk due to planned SBGT maintenance;

• Unit 2 emergent work following reactor water level control issue in maintenance outage L2M17;

• Unit 2 offgas pre-treatment Hi-Hi alarm and emergent setpoint change; and

• Unit 1 A DG inoperable.

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 are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R15 Operability Determinations and Functional Assessments

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

• Operability Evaluation 13-003, General Electric Part 21;

• Operability Evaluation 13-005, inservice inspection (ISI) instrument calibration accuracy;

• reactor core isolation cooling (RCIC) valve movement caused direct current ground;

• Unit 2 Division III corner room watertight door;

• Unit 2 Division III DG circulating water heat exchanger;

• Operability Evaluation 13-004; and

• Unit 1 A RHRSW system.

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 seven samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R18 Plant Modifications

.1 Plant Modifications

a. Inspection Scope

The inspectors reviewed the following modifications:

• Engineering Change (EC) 374750, 2DG020 Valve Replacement (permanent);and

• EC 394003, Temporary Reinforcement Pad on line 2RH83AB-20 (temporary).

The inspectors reviewed the configuration changes 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 systems. The inspectors, as applicable, observed ongoing and completed work activities to ensure that the modifications were installed as directed and consistent with the design control documents; the modifications operated as expected; post-modification testing adequately demonstrated continued system operability, availability, and reliability; and that operation of the modifications did not impact the operability of any interfacing systems. As applicable, the inspectors verified that relevant procedure, design, and licensing documents were properly updated. Lastly, the inspectors discussed the plant modification with operations, engineering, and training personnel to ensure that the individuals were aware of how the operation with the plant modification in place could impact overall plant performance. Documents reviewed are listed in the Attachment to this report.

This inspection constituted one temporary modification sample and 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 testing (PMT) activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:

• Unit 1 Division I RHRSW discharge check valves;

• Unit 2 bus 242Y crosstie breaker relay calibrations;

• Unit 2 SBGT hydromotor replacement;

• Unit 1 B RPS (Reactor Protection System) motor generator set;

• Unit common control room ventilation 15YA damper;

• Unit 2 main steam 'S' safety relief valve;

• Unit 1 turbine stop valve failure (AR1665272); and

• Unit 1 DG ventilation-D08 temperature control unit.

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 eight post-maintenance testing samples as defined in IP 71111.19-05.

b. Findings

Unit 1 Reactor Protection System Limit Switch Testing Failure

Introduction:

The inspectors identified an Unresolved Item (URI) concerning maintenance activities associated with Unit 1 reactor protection system (RPS) Limit Switch 1C71-N006B.

Description:

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

Troubleshooting led the licensee to conclude that the RPS limit switch was the component most likely to generate the specific failure mode. Field checks identified that the limit switch actuation arm appeared to be making physical contact with (rubbing)some of the switch mounting hardware. This issue was corrected by making a small change in the physical configuration of the switch; specifically, the actuating arm was shifted farther down the shaft of the limit switch. This adjustment created additional clearance, allowing the switch to operate normally. Subsequent to this repair, the test was re-performed and the expected system response was obtained.

At the time of the writing of this report, the licensee was still examining the factors associated with this event and had initiated an ACE to document its conclusions.

This issue is an Unresolved Item (URI) pending NRC evaluation of the additional information being developed by the licensee (URI 05000373/2014003-03, Unit 1 Reactor Protection System Limit Switch Testing Failure).

1R20 Outage Activities

.1 Other Outage Activities

a. Inspection Scope

The inspectors evaluated outage activities for a scheduled Unit 2 mid-cycle maintenance outage (L2M17) that began on April 26, 2014, and continued through May 6, 2014. The inspectors reviewed activities to ensure that the licensee considered risk in developing, planning, and implementing the outage schedule.

The inspectors observed or reviewed the reactor shutdown 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. The purpose of the maintenance outage was primarily to remove and replace any leaking fuel bundles inside the reactor vessel, and to also replace a leaking main steam safety relief valve.

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

Lack of Appropriate Procedure Guidance Led to Reactor Vessel Level Excursion

Introduction:

A finding of very low safety significance (Green) and associated NCV of T.S. 5.4.1.a, Procedures, was self-revealed for the failure to have appropriate procedures in place per Regulatory Guide 1.33, Revision 2, for filling and draining the reactor vessel. Specifically, instructions/procedures MA-AB-756 601, Reactor Reassembly, LGP-3-5, Refueling Operations, and LOP-FC-16, Reactor Vessel/Cavity Draindown Via RHR SDC [shutdown cooling], did not contain appropriate detail and direction to ensure that the reactor vessel level would be accurately controlled below the flange before the head was re-tensioned.

Description:

On May 3, 2014, during the L2M17 Unit 2 mid-cycle maintenance outage, following reactor head placement, the reactor coolant level was inadvertently raised above the vessel flange before the head was re-tensioned. This resulted in reactor coolant water leaking from the flange/head seal area and prompted an evacuation of personnel from the refuel floor due to airborne contamination concerns. Subsequent radiological surveys of the evacuated personnel revealed that 6 individuals had facial contamination around the nose and mouth area, and 11 individuals were internally contaminated.

Just prior to this event, reactor pressure vessel (RPV) level was being maintained approximately 1 inch below the flange to provide maximum shielding to workers in the area, according to the licensee. LaSalle Reactor Services Process Control Document MA-AB-756-601, Reactor Reassembly, Attachment 2, simply specified to Lower RPV Level to approximately 6 inches below the vessel flange, which resulted in reduced margin.

The licensees ACE 01655617, Alternate Vessel Level Indication During Head Installation, confirmed that this event was caused by procedural guidance for the operation of the alternate vessel level instrumentation that was insufficient to control reactor water level within the required band during reactor head reassembly.

Specifically, there was no guidance in LGP-3-5, Refueling Operations, nor LOP-FC-16, Reactor Vessel/Cavity Draindown Via RHR SDC, regarding which level instrument was preferred, nor the effects of pressure and temperature on the alternate level instruments.

Once the head was set, level could no longer be visually verified, so alternate instrumentation was the only means of determining vessel level until head vent piping was re-installed and the normal shutdown range level instrument was restored. Until then, both alternate instruments were susceptible to offset due to vessel pressure and temperature effects when the head was installed because the instruments did not have a reference leg and would, therefore, become inaccurate when the RPV was at anything but atmospheric pressure.

Since both of the alternate level instruments were previously known to be susceptible to this offset phenomena, as cautioned briefly in procedure LGP-3-5, and since this evolution was part of the planned head assembly sequence, the inspectors determined that the lack of specific prescribed guidance on how to account for the level control vulnerability was inappropriate to the circumstances of this activity affecting quality.

Analysis:

The inspectors determined that the licensees failure to have appropriate procedures in place for filling and draining the reactor vessel and was a performance deficiency.

The finding was determined to be more than minor because it was associated with the program and process (procedures) attribute of the Occupational Radiation Safety Cornerstone, and adversely affected the cornerstones objective of ensuring the adequate protection of worker health and safety from exposure to radiation from radioactive material during routine civilian reactor operation. Specifically, the failure to have adequate procedures in place to allow operators to accurately control vessel level directly resulted in adverse radiological conditions that impacted some of the plant workers on the refuel floor, and resulted in unplanned external and internal contamination events.

The inspectors determined that the finding could be evaluated in accordance with IMC 0609, Appendix C, Occupational Radiation Safety Significance Determination Process, dated August 19, 2008. The finding was determined to have very low safety significance (Green) because it did not result in an overexposure, nor was there a substantial potential for one, and the licensees ability to assess dose was not compromised.

This finding has a cross-cutting aspect in the area of human performance, resources, because the licensee did not ensure that procedures with appropriate guidance were available to the operators to support nuclear safety (H.1). Specifically, critical information regarding the proper strategy to control vessel level and moderator temperature prior to and following vessel disassembly and reassembly was not provided within the applicable procedures.

Enforcement:

Technical Specification 5.4.1.a, Procedures, requires, in part, that written procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A, be established, implemented, and maintained. Section 4.a. of Appendix A specifies, in part, procedures for the filling and draining of the boiling water reactor vessel. The licensee established instructions/procedures MA-AB-756-601, Reactor Reassembly, LGP-3-5, Refueling Operations, and LOP-FC-016, Reactor Vessel/Cavity Draindown Via RHR SDC, as the implementing instructions/procedures for controlling reactor vessel level while the head was not yet tensioned.

Contrary to the above, on May 3, 2014, the licensee failed to establish adequate procedures for controlling reactor vessel level when the head was set, but still not tensioned. Specifically, critical information regarding the proper strategy to control vessel level prior to and following vessel disassembly and reassembly was not provided within the applicable procedures.

For corrective actions, the licensee immediately corrected the vessel level and entered the issue into its CAP as AR 01655617. An ACE was performed and corrective actions were developed to revise the above procedures to incorporate an appropriate level of guidance and information, to prevent recurrence. This violation is being treated as an NCV, consistent with Section 2.3.2 of the Enforcement Policy (NCV 05000374/2014003-02, Lack of Appropriate Procedure Guidance Led to Reactor Vessel Level Excursion).

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:

• Unit 2 fuel pool cooling emergency makeup pump (Routine);

• Unit 1 anticipated transient without Scram (ATWS) high pressure logic (Routine);

• Unit 1 ATWS low water level logic (Routine);

• Unit 2 A SBLC pump (Routine);

• Unit 1 low pressure core spray system (Routine);

• Unit 1 Division I RHRSW pump and valve test (Inservice test); and

• Unit 1 reactor coolant system (RCS) 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 five routine surveillance testing samples, one inservice testing sample, and one RCS leak detection inspection sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

1EP6 Drill Evaluation

.1 Training Observation

a. Inspection Scope

The inspector observed a simulator training evolution for licensed operators on June 10, 2014, which required emergency plan implementation by a licensee operations crew. The inspectors observed event classification and notification activities performed by licensed personnel. The inspectors also attended the post-evolution critique for the scenario. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews performance and ensure that the licensee evaluators noted the same issues and entered them into the CAP. As part of the inspection, the inspectors reviewed the scenario package and other documents listed in the Attachment to this report.

This inspection of the licensees training evolution with emergency preparedness drill aspects constituted one sample as defined in IP 71114.06-06.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

.1 Reactor Coolant System Leakage

a. Inspection Scope

The inspectors sampled licensee submittals for the RCS Performance Indicator (PI) for Units 1 and 2 for the second quarter 2013 through the first quarter 2014. To determine the accuracy of the PI data reported during this period, PI definitions and guidance contained in the Nuclear Energy Institute 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 7, dated August 31, 2013, were used. The inspectors reviewed the licensees operator logs, RCS leakage tracking data, issue reports, event reports, and NRC Integrated Inspection Reports for the period 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 to this report.

This inspection constituted two RCS leakage samples as defined in IP 71151-05.

b. Findings

No findings were identified.

4OA2 Identification and Resolution of Problems

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

a. Inspection Scope

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

Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the Attachment to this report.

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

b. Findings

No findings were identified.

.2 Daily Corrective Action Program Reviews

a. Inspection Scope

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.

.3 Semiannual Trend Review

a. Inspection Scope

The inspectors reviewed the licensees CAP and associated documents to identify trends that could indicate the existence of a more significant safety issue. The inspectors review was focused on repetitive equipment issues, but also considered the results of daily inspector CAP item screening discussed in Section 4OA2.2 above, licensee trending efforts, and licensee human performance results. The inspectors review nominally considered the 6-month period of January through June 2014, although some examples expanded beyond those dates where the scope of the trend warranted.

The review also included issues documented outside the normal CAP in major equipment problem lists, repetitive and/or rework maintenance lists, departmental problem/challenges lists, system health reports, quality assurance audit/surveillance reports, self-assessment reports, and Maintenance Rule assessments. The inspectors compared and contrasted their results with the results contained in the licensees CAP trending reports. Corrective actions associated with a sample of the issues identified in the licensees trending reports were reviewed for adequacy.

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

b. Findings

No findings were identified.

4OA3 Followup of Events and Notices of Enforcement Discretion

.1 (Closed) Licensee Event Report (LER) 05000374-2013-003-00: Average Power Range

Monitors Declared Inoperable Due to Non-Conservative Drift During Load Drop

a. Inspection Scope

This event occurred on December 7, 2013, with Unit 2 in Mode 1 at 60 percent reactor power. During a scheduled load reduction for surveillance testing and control rod sequence exchange, the licensee evaluated data from the core monitoring software system and determined that all three Average Power Range Monitor (APRM) channels in the 'A' RPS trip system were inoperable. The gains were adjusted for all three APRM channels to return indicated power to within the acceptable range within 23 minutes of the condition being discovered. This was less than the 2 hours2.314815e-5 days <br />5.555556e-4 hours <br />3.306878e-6 weeks <br />7.61e-7 months <br /> allowed by TS 3.3.1.1.

The transient analysis assumes average power range monitor trips are initiated approximately 6% above the nominal setpoint used by the station; and with APRMs 2.5% non-conservative, a trip would have occurred earlier than that assumed by the transient analysis. This occurrence was reportable under 10 CFR 50.73(a)(2)(v)(A) as an event or condition that could have prevented the fulfillment of the safety function of the structures or systems that are needed to shutdown the reactor and maintain it in a safe shutdown condition. This event constituted a safety system functional failure for Unit 2. The cause of the event was an unexpected degree of APRM indication drift, following planned control rod movement. Corrective actions include training and procedure revisions to minimize the possibility of future occurrences. The inspectors concluded the licensees implemented and planned corrective actions were reasonable to prevent recurrence. Documents reviewed are listed in the Attachment to this report.

This LER is closed.

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

b. Findings

No findings were identified.

.2 (Closed) LER 05000373-2013-006-00: Inadvertent Automatic Start of the 1A DG

Cooling Water Pump Due to Improper Adjustment of Mechanically Operated Contact Switch This event occurred on August 13, 2013, with Unit 1 in Mode 1 at 100 percent reactor power. Technicians were inspecting the circuit breaker cubicle for the Unit 1 C RHR pump. While the technicians were cleaning the lower cubicle, the associated pump cubicle cooler fan started which, per design, resulted in the Unit 1 A DG cooling water pump starting. The DG pump ran, until secured by the operators, with no abnormalities noted. The unexpected start did not result in any other system actuations or plant transients. This occurrence was reportable under 10 CFR 50.73(a)(2)(iv)(A) as an event that resulted in the automatic actuation of a system listed in 10 CFR 50.73(a)(2)(iv)(B)(9). The cause of the event was the inadvertent bumping of a mechanically operated contact (MOC) switch in the bottom of the RHR pump breaker cubicle during the cleaning. Further investigation found that the MOC switch linkages were misadjusted, which allowed the contacts of the MOC switch to close from very light casual contact of the switch linkage. The misadjustment of the switch was due to the lack of adjustment guidance under previous revisions of the maintenance procedures.

Corrective actions included ensuring correct adjustment of internal cabinet switch contacts and incorporating procedural guidance to preclude inadvertent actuations prior to cleaning and inspecting breaker cubicles. The inspectors concluded the licensees implemented and planned corrective actions were reasonable to prevent recurrence.

Documents reviewed are listed in the Attachment to this report. This LER is closed.

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

.3 (Closed) Licensee Event Report (LER) 05000373-2013-008-00; 05000374-2013-008-00:

Control Room Heating, Ventilation, and Air Conditioning Inoperable Due to Failed Fan Motor This event occurred on November 22, 2013, with Units 1 and 2 both in Mode 1 at 100 percent reactor power. The 'A' train of Main Control RoomHVAC was inoperable due to an emergent repair of a Freon leak. Subsequently, the Main Control Room received a trouble alarm associated with 'B' train. The rounds operator responded to the panel and reported that the 'B' fan was not turning. An acrid smell was detected coming from the fan motor control center breaker and the 'B' train was declared inoperable. The 'A' train of Main Control Room ventilation was repaired and restored to operable within 13.8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> of the condition being discovered. This was less than the 72-hour completion time allowed by TS 3.7.5. Main Control Room temperature did not exceed 90 degrees, and online risk remained Green throughout the event. This occurrence was reportable under 10 CFR 50.73(a)(2)(v)(D) as an event or condition that could have prevented the fulfillment of the safety function of structures or systems needed to mitigate the consequences of an accident. This event constituted a safety system functional failure for Units 1 and 2. The cause of the event was a winding failure of the 'B' Auxiliary Electric Equipment Room Cooler Condenser fan motor. Corrective actions included replacing the failed fan motor and performing a failure analysis to determine the cause of the winding failure. The inspectors concluded the licensees implemented and planned corrective actions were reasonable to prevent recurrence. Documents reviewed are listed in the Attachment to this report. 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 July 2, 2014, the inspectors presented the inspection results to Mr. H. Vinyard 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.

ATTACHMENT:

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee

P. Karaba, Site Vice President

H. Vinyard, Plant Manager

J. Kowalski, Engineering Manager

B. Maze, Project Management

A. Schierer, Engineering Programs

K. Hall, Buried Piping Program Owner

V. Chopra, Engineering Programs

G. Ford, Regulatory Assurance Manager

L. Blunk, Regulatory Assurance

S. Shields, Regulatory Assurance

D. Anthony, Exelon NDES Manager West

B. Casey, ISI Programs Engineering

J. Miller, Corporate NDES Level III

B. Hilton, Design Manager

J. Houston, Nuclear Oversight Manager

L. Ekern, Nuclear Oversight

D. Amezaga, Design Engineer

J. Bendis, Engineer

J. Hughes, Emergency Preparedness Coordinator

J. Shields, Invessel Visual Inspection Program Supervisor

S. Tanton, Engineer

A. Daniels, Exelon Emergency Preparedness Manager

M. Hayworth, Emergency Preparedness Manager

S. Tutoky, Senior Chemist

M. Martin, Chemistry Manager

T. Halliday, Radiation Protection

J. Moser, Radiation Protection Manager

C. Howard, Radiation Protection

S. Koval, Radwaste Shipping Specialist

A. Baker, Dosimetry Specialist

J. Bauer, Training Director

T. Dean, Operations Training Manager

Nuclear Regulatory Commission

M. Kunowski, Chief, Reactor Projects Branch 5

LIST OF ITEMS

Opened

05000373/2014003-01; NCV Failure to Adhere to Postings Led to Prohibited Items

05000374/2014003-01 Being Left in ECCS Corner Rooms (Section 1R04)

05000373/2014003-03 URI Unit 1 Reactor Protection System (RPS) Limit Switch Testing Failure (Section 1R19)

05000374/2014003-02 NCV Lack of Appropriate Procedure Guidance Led to Reactor Vessel Level Excursion (Section 1R20)

Closed

05000373/2014003-01; NCV Failure to Adhere to Postings Led to Prohibited Items

05000374/2014003-01 Being Left in ECCS Corner Rooms (Section 1R04)

05000374/2014003-02 NCV Lack of Appropriate Procedure Guidance Led to Reactor Vessel Level Excursion (Section 1R20)

05000374-2013-003-00 LER Average Power Range Monitors Declared Inoperable Due to Non-Conservative Drift During Load Drop (Section 4OA3)

05000373-2013-008-00; LER Control Room HVAC Inoperable Due to Failed Fan Motor

05000374-2013-008-00 (Section 4OA3)

05000373-2013-006-00 LER Inadvertent Automatic Start of the 1A Diesel Generator Cooling Water Pump Due to Improper Adjustment of Mechanically Operated Contact Switch (Section 4OA3)