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{{Adams
#REDIRECT [[IR 05000373/2013004]]
| number = ML13319B253
| issue date = 11/15/2013
| title = IR 05000373-13-004 & 05000374-13-004, on 07/01/2013 - 09/30/2013, LaSalle County Station, Units 1 & 2, Followup of Events and Notices of Enforcement Discretion
| author name = O'Brien K G
| author affiliation = NRC/RGN-III/DRP
| addressee name = Pacilio M J
| addressee affiliation = Exelon Generation Co, LLC, Exelon Nuclear
| docket = 05000373, 05000374
| license number = NPF-011, NPF-018
| contact person =
| case reference number = EA-13-221
| document report number = IR-13-004
| document type = Inspection Report, Letter
| page count = 52
}}
See also: [[followed by::IR 05000373/2013004]]
 
=Text=
{{#Wiki_filter:
[[Issue date::November 15, 2013]]
 
EA-13-221 Mr. Michael Senior Vice President, Exelon Generation Co., LLC President and Chief Nuclear Officer, Exelon Nuclear 4300 Winfield Road Warrenville, IL 60555
 
SUBJECT: LASALLE COUNTY STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000373/2013004; 05000374/2013004 AND UNIT 2 PRELIMINARY WHITE FINDING
 
==Dear Mr. Pacilio:==
On September 30, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your LaSalle County Station, Units 1 and 2. The enclosed report documents the inspection results which were discussed on Wednesday, October 2, 2013, with the Site Vice President, Mr. P. Karaba, and other members of your staff. The enclosed inspection report discusses a finding on Unit 2 that has preliminarily been determined to be White, a finding with low-to-moderate safety significance, that may result in additional NRC inspection. As described in Section 4OA3 of this report, a self-revealed finding was identified for the failure of station personnel to follow procedure LOP-CW-10, "Dewatering the Circulating Water System," Revision 32, on April 25, 2013. Specifically, operators performed the waterbox dewatering evolution in a manner inconsistent with procedural guidance by manually adjusting the circulating water isolation valves while the waterbox manways were open. Adjustment of the inlet isolation valve caused a loss of isolation resulting in flooding of the condenser pit and a resultant circulating water pump trip, loss of the normal heat sink, and a manual reactor scram. This finding was assessed based on the best available information, using the applicable Significance Determination Process (SDP). The inspectors used Inspection Manual Chapter (IMC) 0609, Appendix A, "The Significance Determination Process (SDP) for Findings At-Power," Exhibit 1, dated June 19, 2012, for the Initiating Events cornerstone. Because the finding caused a reactor trip AND the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition, a detailed risk evaluation was required. The Senior Reactor Analysts (SRAs) used the LaSalle Standardized Plant Analysis Risk (SPAR) model to perform the detailed risk evaluation. In accordance with Risk Assessment of Operational Events Handbook guidance, the initiating event "Loss of Condenser Heat Sink" was set to 1.0 using the events and condition assessment module of the Systems Analysis Program for Hands-On Integrated Reliability Evaluations (SAPHIRE), Version 8. The calculated conditional core damage probability for the event was 1.6E-6, which represents a finding of low to moderate safety significance (White). As described in NRC Inspection Manual Chapter 0612, "Power Reactor Inspection Reports," dated January 24, 2013, a finding may or may not be associated with regulatory non-compliance and, therefore, may or may not result in a violation. Based on the review of this issue and in accordance with NRC Inspection Manual Chapter 0612, the NRC determined that no violation of a regulatory requirement occurred. In accordance with NRC Inspection Manual Chapter 0609, we intend to complete our evaluation using the best available information and issue our final determination of safety significance within 90 days of the date of this letter. The significance determination process encourages an open dialogue between the NRC staff and the licensee; however, the dialogue should not impact the timeliness of the staff's final determination. Before we make a final decision on this matter, we are providing you with an opportunity to (1) attend a Regulatory Conference where you can present to the NRC your perspective on the facts and assumptions the NRC used to arrive at the finding and assess its significance, or (2) submit your position on the finding to the NRC in writing. If you request a Regulatory Conference, it should be held within 30 days of the receipt of this letter and we encourage you to submit supporting documentation at least one week prior to the conference in an effort to make the conference more efficient and effective. The focus of the Regulatory Conference is to discuss the significance of the finding and not necessarily the root cause(s) or corrective action(s) associated with the finding. If a Regulatory Conference is held, it will be open for public observation. If you decide to submit only a written response, such submittal should be sent to the NRC within 30 days of your receipt of this letter. If you decline to request a Regulatory Conference or to submit a written response, you relinquish your right to appeal the final SDP determination, in that by not doing either, you fail to meet the appeal requirements stated in the Prerequisite and Limitation sections of Attachment 2 of NRC Inspection Manual Chapter 0609. Please contact Michael Kunowski at (630) 829-9618 and in writing within 10 days from the issue date of this letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we will continue with our significance determination and enforcement decision. The final resolution of this matter will be conveyed in a separate correspondence. In addition to the finding discussed above, one self-identified violation of very low safety significance (Green) was identified during this inspection. This finding was determined to involve a violation of NRC requirements and the NRC is treating it as a non-cited violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy. If you contest the violation or significance of the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U. S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to 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 the 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 Resident Inspector at LaSalle County Station. In accordance with Title 10 of the Code of Federal Regulations 2.390, "Public Inspections, Exemptions, Requests for Withholdings," 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's 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 by Julio Lara for/ Kenneth G. O'Brien, Acting Director Division of Reactor Projects Docket Nos. 50-373 and 50-374 License Nos. NPF-11 and NPF-18
 
===Enclosure:===
Inspection Report 05000373/2013004; 05000374/2013004
 
===w/Attachment:===
Supplemental Information cc w/encl: Distribution via ListServTM Enclosure U.S. NUCLEAR REGULATORY COMMISSION REGION III Docket Nos: 05000373; 05000374 License Nos: NPF-11; NPF-18 Report No: 05000373/2013004; 05000374/2013004 Licensee: Exelon Generation Company, LLC Facility: LaSalle County Station, Units 1 and 2 Location: Marseilles, IL Dates: July 1, 2013 - September 30, 2013 Inspectors: R. Ruiz, Senior Resident Inspector M. Ziolkowski, Acting Resident Inspector K. Carrington, Acting Resident Inspector G. Roach, Senior Resident Inspector, Dresden D. Chyu, Region III Reactor Engineer I. Hafeez, Region III Reactor Inspector C. Phillips, Project Engineer T. Go, Health Physicist
 
Approved by: M. Kunowski, Chief Branch 5 Division of Reactor Projects Enclosure
 
=SUMMARY OF FINDINGS=
Inspection Report (IR) 05000373/2013004, 05000374/2013004; 07/01/2013-09/30/2013; LaSalle County Station, Units 1 & 2; Followup of Events and Notices of Enforcement Discretion. This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Two findings were identified during the inspection.
 
One finding was preliminarily determined to be White and one finding was determined to be a Green non-cited violation (NCV). 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, "Components Within the Cross Cutting Areas" dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRC's Enforcement Policy dated January 28, 2013. The NRC's program for overseeing the safe operation of commercial nuclear power reactors is described in NUREG-1649, "Reactor Oversight Process" Revision 4.
 
===A. NRC-Identified===
and Self-Revealed Findings
 
===Cornerstone: Initiating Events ===
* Preliminary White:  A self-revealed finding preliminarily determined to be of low-to-moderate safety significance was identified for the licensee's failure to follow procedure LOP-CW-10, "Dewatering the Circulating Water System," Revision 32, on Unit 2.
 
Specifically, on April 25, 2013, with Unit 2 at 56 percent power, operators appointed to plan and execute the dewatering of the main condenser waterbox did so in a manner inconsistent with procedural guidance by manually adjusting the circulating water isolation valves while condenser manways were still open. The subsequent loss of isolation led to the flooding of the condenser pit and a resultant circulating water pump trip, loss of the normal heat sink, and a reactor scram. The licensee entered this issue into its corrective action program (CAP) as action report (AR) 1506809 and performed a root cause analysis to identify the root and contributing causes of the event, as well as to determine the appropriate corrective actions, such as providing training and revising procedures. The inspectors determined that the licensee's failure to follow the prescribed steps of procedure LOP-CW-10 was a performance deficiency warranting a significance determination. The inspectors used Inspection Manual Chapter (IMC) 0609,  Appendix A, "The Significance Determination Process (SDP) for Findings At-Power," Exhibit 1, dated June 19, 2012, for the Initiating Events cornerstone. Because the finding caused a reactor trip AND the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition, a detailed risk evaluation was required. The Senior Reactor Analysts (SRAs) used the LaSalle Standardized Plant Analysis Risk (SPAR) model to perform the detailed risk evaluation. In accordance with Risk Assessment of Operational Events Handbook guidance, the initiating event "Loss of Condenser Heat Sink" was set to 1.0 using the events and condition assessment module of the Systems Analysis Program for Hands-On Integrated Reliability Evaluations (SAPHIRE), Version 8. The calculated conditional core damage probability for the event was 1.6E-6, which represents a finding of low-to-moderate safety significance (White). The finding had a cross-cutting aspect in the area of human performance, decision-making, because the licensee failed to use conservative assumptions when planning and executing the dewatering evolution. Specifically, the incorrect assumption that this evolution performed at-power could be treated the same as when performed during a shutdown condition enabled operators to stray from strict procedure adherence and into knowledge space (H.1(b)).  (Section 4OA3)
 
===Cornerstone: Mitigating Systems and Barrier Integrity ===
* Green:  A self-revealed finding of very low safety significance and associated non-cited violation of Title 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," was identified for the failure to have procedures adequate for the circumstances during long-term operation of the high pressure core spray (HPCS) system on minimum flow. Specifically, three small holes developed in the Unit 2 HPCS minimum flow line elbow due to cavitation and other flow-related wear caused by inconsistent procedural guidance regarding operation in the minimum-flow mode.
 
The licensee promptly repaired the system leak and entered the issue into its CAP as ARs 1503825 and 1530682, which included the performance of an apparent cause evaluation. Further corrective actions included the revision of the affected procedures. The finding was determined to be more than minor because it was associated with the Mitigating Systems and Barrier Integrity cornerstone attributes of Procedure Quality and adversely affected the cornerstone objectives of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the procedural guidance given to operate the HPCS system was inadequate to prevent long-term operation of the system in the minimum flow mode of operation, which led to cavitation and flow-induced wear, causing the failure of the Unit 2 HPCS minimum flow line and inoperability of the HPCS system as well as the primary containment boundary.
 
The inspectors determined that the finding could be evaluated in accordance with IMC 0609, Appendix A, "The Significance Determination for Findings At-Power," and Appendix H, "Containment Integrity Significance Determination Process."  Further, it was determined that a phase two risk assessment was necessary because the finding impacted suppression pool integrity, and through that process, this issue screened as
: '''Green.'''
The inspectors did not identify a cross-cutting aspect associated with this finding.  (Section 4OA3)
 
=REPORT DETAILS=
Summary of Plant Status Unit 1 The unit began the inspection period operating at full power. On September 7, 2013, power was reduced to approximately 65 percent for a control rod sequence exchange and scram time testing. Unit 1 was restored to full power on September 8. Unit 2 The unit began the inspection period operating at full power. On August 31, 2013, power was reduced to approximately 65 percent for a control rod sequence exchange and scram time testing. Unit 2 was restored to full power on September 1. Additionally, on September 27, power was reduced to approximately 60 percent for power suppression testing to identify a leaking fuel element. Upon the successful completion of that evolution, Unit 2 was restored to approximately full power on September
 
==REACTOR SAFETY==
Cornerstones:  Initiating Events, Mitigating Systems, and Barrier Integrity
{{a|1R01}}
==1R01 Adverse Weather Protection==
{{IP sample|IP=IP 71111.01}}
===.1 Summer Seasonal Readiness Preparations===
 
====a. Inspection Scope====
The inspectors reviewed the licensee's 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 licensee's procedures used to mitigate or respond to adverse weather conditions.
 
Additionally, the inspectors reviewed the 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 CAP items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into its CAP in accordance with station CAP procedures. The inspectors' reviews focused specifically on the ultimate heat sink and core standby cooling system (CSCS). Documents reviewed are listed in the Attachment to this report. This inspection constituted one seasonal adverse weather sample as defined in Inspection Procedure (IP) 71111.01-05.
 
====b. Findings====
No findings were identified.
{{a|1R04}}
==1R04 Equipment Alignment==
{{IP sample|IP=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 'A' diesel generator (DG) walkdown following 1 'B' DG idle start;
* Unit 1 standby gas treatment system;
* Unit 1 'A' standby liquid control system; and
* Unit 1 reactor core isolation cooling (RCIC). 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 Attachment 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 August 22, 2013, the inspectors performed a complete system alignment inspection of the Units 1 and 2 Division II DGs with the Division I DG out of service to verify the functional capability of the system. This system was selected because it was considered both safety significant and risk significant in the licensee's 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 to this report. These activities constituted one complete system walkdown sample as defined in IP 71111.04-05.
 
====b. Findings====
No findings were identified.
{{a|1R05}}
==1R05 Fire Protection==
{{IP sample|IP=IP 71111.05}}
===.1 Routine Resident Inspector Tours===
{{IP sample|IP=IP 71111.05Q}}
 
====a. Inspection Scope====
The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:
* fire zone 2I4 U1 low pressure core spray (LPCS)/RCIC room;
* fire zone 8C4 Unit 2 Division II residual heat removal system southwest corner room;
* Unit 1 Division 1 essential switchgear room 4F1;
* Unit 1 Division II DG room 7B2; and
* Unit 2 Division II DG room 8B2. The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded, or inoperable fire protection equipment, systems, or features in accordance with the licensee's fire plan.
 
The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plant's Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plant's ability to respond to a security event. Using the documents listed in the Attachment to this report, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensee's CAP. Documents reviewed are listed in the Attachment to this report. These activities constituted five quarterly fire protection inspection samples as defined in IP 71111.05-05.
 
====b. Findings====
No findings were identified.
{{a|1R06}}
==1R06 Flooding==
{{IP sample|IP=IP 71111.06}}
===.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 licensee's 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 following plant area(s) 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:
* Unit 1 and Unit 2 CSCS pump rooms and ventilation room dampers. 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.
 
===.2 Underground Vaults===
 
====a. Inspection Scope====
The inspectors selected underground bunkers/manholes subject to flooding that contained cables whose failure could disable risk-significant equipment. The inspectors determined 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 licensee's CAP documents with respect to past submerged cable issues identified in the CAP program to verify the adequacy of the corrective actions. The inspectors performed a walkdown of manholes 1 through 6, which are subject to flooding. 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.
{{a|1R11}}
==1R11 Licensed Operator Requalification Program==
{{IP sample|IP=IP 71111.11}}
===.1 Resident Inspector Quarterly Review of Licensed Operator Requalification===
{{IP sample|IP=IP 71111.11Q}}
 
====a. Inspection Scope====
On August 8, 2013, the inspectors observed a crew of licensed operators in the plant's simulator during licensed operator requalification training to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:
* licensed operator performance;
* crew's clarity and formality of communications;
* ability to take timely actions in the conservative direction;
* prioritization, interpretation, and verification of annunciator alarms;
* correct use and implementation of abnormal and emergency procedures;
* control board manipulations;
* oversight and direction from supervisors; and
* ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications. The crew's performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report. This inspection constituted one quarterly licensed operator requalification program simulator sample as defined in IP 71111.11.
 
====b. Findings====
No findings were identified.
 
===.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk===
{{IP sample|IP=IP 71111.11Q}}
 
====a. Inspection Scope====
On September 4, 2013, the inspectors observed control room operators during the performance of the secondary containment leak rate test. This was an activity that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas:
* licensed operator performance;
* crew's clarity and formality of communications;
* ability to take timely actions in the conservative direction;
* prioritization, interpretation, and verification of annunciator alarms (if applicable);
* correct use and implementation of procedures;
* control board (or equipment) manipulations;
* oversight and direction from supervisors; and
* ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications (if applicable). The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements. Documents reviewed are listed in the Attachment to this report. This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11.
 
====b. Findings====
No findings were identified.
{{a|1R12}}
==1R12 Maintenance Effectiveness==
{{IP sample|IP=IP 71111.12}}
===.1 Routine Quarterly Evaluations===
 
====a. Inspection Scope====
The inspectors evaluated degraded performance issues involving the following risk-significant systems:
* Unit Common 'B' diesel fire pump following a failure to start;
* Unit 1 circulating water system; and
* Unit 2 circulating water system. 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 systems, structures, 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.
{{a|1R13}}
==1R13 Maintenance Risk Assessments and Emergent Work Control==
{{IP sample|IP=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:
* failed fuel inspection;
* 345-kiloVolt (kV) lightning strike on line 0104;
* automatic start of 1 'A' DG cooling water pump results in extended yellow risk condition;
* yellow risk condition for Unit 1 standby gas treatment work; and
* Unit 2 downpower for power suppression testing. 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.
{{a|1R15}}
==1R15 Operability Determinations and Functional Assessments==
{{IP sample|IP=IP 71111.15}}
===.1 Operability Evaluations===
 
====a. Inspection Scope====
The inspectors reviewed the following issues:
* Unit Common 'B' control room ventilation charcoal filters potentially impacted by Freon leak;
* Unit 2 high drywell temperatures;
* AR 01476770 Operability Evaluation (Op Eval) 04-006 may be non-conservative;
* General Electric-Hitachi Part 21 issued for reactor protection system electrically monitored protective assemblies in molded case circuit breakers; and
* Unit 1 #1 turbine stop valve. 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 licensee's evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of 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 five samples as defined in IP 71111.15-05.
 
====b. Findings====
No findings were identified.
{{a|1R19}}
==1R19 Post-Maintenance Testing==
{{IP sample|IP=IP 71111.19}}
===.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 Common 'A' auxiliary electrical equipment room ventilation train following compressor replacement;
* Unit 2 standby gas treatment;
* Unit 1 '1B' standby liquid control;
* Unit 1 'C' residual heat removal (RHR) breaker preventive maintenance;
* Unit 1 RCIC high steam line flow instrumentation replacement;
* Unit 2 hydraulic control unit 38-43; and
* Unit 1 'A' DG following preventive and corrective maintenance. 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 PMT 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 PMT samples as defined in IP 71111.19-05.
 
====b. Findings====
No findings were identified.
{{a|1R22}}
==1R22 Surveillance Testing==
{{IP sample|IP=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:
* LIS-NR-303A/B average power range monitor (APRM) functional surveillance (Routine);
* Unit 1 Division II 125-Vdc (Volts direct current) battery surveillance  (Routine);
* Unit 2 RHR quarterly surveillance (LOS-RH-Q1)  (Routine); and
* Unit 2 'B' DG cooling water pump (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
{{a|1EP6}}
==1EP6 Drill Evaluation==
{{IP sample|IP=IP 71114.06}}
===.1 Emergency Preparedness Drill Observation===
 
====a. Inspection Scope====
The inspectors evaluated the conduct of a routine licensee emergency drill on July 16, 2013, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator, technical support center and operational support center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures.
 
The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the CAP. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report. This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-05.
 
====b. Findings====
No findings were identified.
 
===.2 Training Observation===
 
====a. Inspection Scope====
The inspector observed simulator training evolutions for licensed operators on August 6 and September 17, 2013, which required emergency plan implementations by a licensee operations crew. These evolutions were planned to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post-evolution critiques for the scenarios. The focus of the inspectors' activities was to note any weaknesses and deficiencies in the crew's performances 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 packages and other documents listed in the Attachment to this report.
 
This inspection of the licensee's training evolutions with emergency preparedness drill aspects constituted two samples as defined in IP 71114.06-06.
 
====b. Findings====
No findings were identified.
 
==RADIATION SAFETY==
Cornerstones:  Public Radiation Safety and Occupational Radiation Safety
{{a|2RS8}}
==2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and Transportation==
{{IP sample|IP=IP 71124.08}}
This inspection constituted one complete sample as defined in IP 71124.08-05.
 
===.1 Inspection Planning (02.01)===
 
====a. Inspection Scope====
The inspectors reviewed the solid radioactive waste system description in the UFSAR, the Process Control Program, and the recent radiological effluent release report for information on the types, amounts, and processing of radioactive waste disposed. The inspectors reviewed the scope of any quality assurance audits in this area since the last inspection to gain insights into the licensee's performance and inform the "smart sampling" inspection planning.
 
====b. Findings====
No findings were identified.
 
===.2 Radioactive Material Storage (02.02)===
 
====a. Inspection Scope====
The inspectors selected areas where containers of radioactive waste are stored and evaluated whether the containers were labeled in accordance with 10 CFR 20.1904, "Labeling Containers," or controlled in accordance with 10 CFR 20.1905, "Exemptions to Labeling Requirements," as appropriate. The inspectors assessed whether the radioactive material storage areas were controlled and posted in accordance with the requirements of 10 CFR Part 20, "Standards for Protection Against Radiation."  For materials stored or used in the controlled or unrestricted areas, the inspectors evaluated whether they were secured against unauthorized removal and controlled in accordance with 10 CFR 20.1801, "Security of Stored Material," and 10 CFR 20.1802, "Control of Material Not in Storage," as appropriate. The inspectors assessed whether the licensee established a process for monitoring the impact of long-term storage (e.g., buildup of any gases produced by waste decomposition, chemical reactions, container deformation, loss of container integrity, or re-release of free-flowing water) that was sufficient to identify potential unmonitored, unplanned releases or non-conformance with waste disposal requirements. The inspectors selected containers of stored radioactive material, and assessed for signs of swelling, leakage, and deformation.
 
====b. Findings====
No findings were identified.
 
===.3 Radioactive Waste System Walkdown (02.03)===
 
====a. Inspection Scope====
The inspectors walked down accessible portions of select radioactive waste processing systems to assess whether the current system configuration and operation agreed with the descriptions in the UFSARt, Offsite Dose Calculation Manual, and Process Control Program. The inspectors reviewed administrative and/or physical controls (i.e., drainage and isolation of the system from other systems) to assess whether the equipment that was not in service or was abandoned in place would not contribute to an unmonitored release path and/or affect operating systems or be a source of unnecessary personnel exposure. The inspectors assessed whether the licensee reviewed the safety significance of systems and equipment abandoned in place in accordance with 10 CFR 50.59, "Changes, Tests, and Experiments."
 
The inspectors reviewed the adequacy of changes made to the radioactive waste processing systems since the last inspection. The inspectors evaluated whether changes from what is described in the UFSAR were reviewed and documented in accordance with 10 CFR 50.59, as appropriate, and to assess the impact on radiation doses to members of the public. The inspectors selected processes for transferring radioactive waste resin and/or sludge discharges into shipping/disposal containers and assessed whether the waste stream mixing, sampling procedures, and methodology for waste concentration averaging were consistent with the Process Control Program, and provided representative samples of the waste product for the purposes of waste classification as described in 10 CFR 61.55, "Waste Classification."  For those systems that provide tank recirculation, the inspectors evaluated whether the tank recirculation procedures provided sufficient mixing. The inspectors assessed whether the licensee's Process Control Program correctly described the current methods and procedures for dewatering and waste stabilization (e.g., removal of freestanding liquid).
 
====b. Findings====
No findings were identified.
 
===.4 Waste Characterization and Classification (02.04)===
 
====a. Inspection Scope====
The inspectors selected the following radioactive waste streams for review:
* LW12-032; Radioactive Material, LSA-II, 7, UN 3321, Pre-Filter Septa Liner in 14-215 Cask Containing Dry Active Waste To Be Processed at Energy Solutions Bear Creek Facility, Oak Ridge Tennessee; August 16, 2012;
* LW13-024; Radioactive Material, LSA-II, 7, UN 3321; Condensate Pre-Filter Septa Liner to Energy Solutions Bear Creek Facility, Oak Ridge Tennessee; July 25, 2013;
* LM13-128; Radioactive Material, LSA-II, 7, UN 3321; Seven Boxes of Areva Equipment to Areva NP, Lynchburg, VA; August 15, 2013; and
* LW13-022; Radioactive Material, LSA-II, 7, UN 3321; CP Pre-Filtered Septa Liners in 14-215H-25 to Energy Solutions Bear Creek Facility, Oak Ridge Tennessee; July 25, 2013. For the waste streams listed above, the inspectors assessed whether the licensee's radiochemical sample analysis results (i.e., "10 CFR Part 61" analysis) were sufficient to support radioactive waste characterization as required by 10 CFR Part 61, "Licensing Requirements for Land Disposal of Radioactive Waste."  The inspectors evaluated whether the licensee's use of scaling factors and calculations to account for difficult-to-measure radionuclides was technically sound and based on current 10 CFR Part 61 analyses for the selected radioactive waste streams.
 
The inspectors evaluated whether changes to plant operational parameters were taken into account to:  (1) maintain the validity of the waste stream composition data between the annual or biennial sample analysis update; and (2) assure that waste shipments continued to meet the requirements of 10 CFR Part 61 for the waste streams selected above. The inspectors evaluated whether the licensee had established and maintained an adequate Quality Assurance Program to ensure compliance with the waste classification and characterization requirements of 10 CFR 61.55, "Waste Classification," and 10 CFR 61.56, "Waste Characteristics."
 
====b. Findings====
No findings were identified.
 
===.5 Shipment Preparation (02.05)===
 
====a. Inspection Scope====
The inspectors observed shipment packaging, surveying, labeling, marking, placarding, vehicle checks, emergency instructions, disposal manifest, shipping papers provided to the driver, and licensee verification of shipment readiness. The inspectors assessed whether the requirements of applicable transport cask certificate of compliance had been met. The inspectors evaluated whether the receiving licensee was authorized to receive the shipment packages. The inspectors evaluated whether the licensee's procedures for cask loading and closure procedures were consistent with the vendor's current approved procedures. The inspectors observed radiation workers during the conduct of radioactive waste processing and radioactive material shipment preparation and receipt activities.
 
The inspectors assessed whether the shippers were knowledgeable of the shipping regulations and whether shipping personnel demonstrated adequate skills to accomplish the package preparation requirements for public transport with respect to the following:
* The licensee's response to NRC Bulletin 79-19, "Packaging of Low-Level Radioactive Waste for Transport and Burial," dated August 10, 1979; and
* Title 49 CFR Part 172, "Hazardous Materials Table, Special Provisions, Hazardous Materials Communication, Emergency Response Information, Training Requirements, and Security Plans," Subpart H, "Training."  Due to limited opportunities for direct observation, the inspectors reviewed the technical instructions presented to workers during routine training. The inspectors assessed whether the licensee's training program provided training to personnel responsible for the conduct of radioactive waste processing and radioactive material shipment preparation activities.
 
====b. Findings====
No findings were identified.
 
===.6 Shipping Records (02.06)===
 
====a. Inspection Scope====
The inspectors evaluated whether the shipping documents indicated the proper shipper name; emergency response information and a 24-hour contact telephone number; accurate curie content and volume of material; and appropriate waste classification, transport index, and UN number for the following radioactive shipments:
* LW12-006; Radioactive Material, LSA-I, 7, UN 2912, 40-Foot Seavan Containing Dry Active Waste To Be Processed at Energy Solutions Bear Creek Facility, Oak Ridge Tennessee; February 15, 2012;
* LW13-024; Radioactive Material, LSA-II, 7, UN 3321; Condensate Pre-Filter Septa Liner to Energy Solutions Bear Creek Facility, Oak Ridge Tennessee; July 25, 2013;
* LW12-037; Radioactive Material, LSA-II, 7, UN 3321; 21-300FR Liner of Dewatered Bead Resin in 14-215H-26 Cask; to Clive Disposal Facility, Utah; October 12, 2012; and
* LW12-002; Radioactive Material, LSA-II, 7, UN 3321; Fissile Excepted; Dewatered Bead Resin; Clive Disposal Facility, Clive, Utah; January 10, 2012. Additionally, the inspectors assessed whether the shipment placarding was consistent with the information in the shipping documentation.
 
====b. Findings====
No findings were identified.
 
===.7 Identification and Resolution of Problems (02.07)===
 
====a. Inspection Scope====
The inspectors assessed whether problems associated with radioactive waste processing, handling, storage, and transportation were being identified by the licensee at an appropriate threshold, were properly characterized, and were properly addressed for resolution in the licensee's CAP. Additionally, the inspectors evaluated whether the corrective actions were appropriate for a selected sample of problems documented by the licensee that involve radioactive waste processing, handling, storage, and transportation. The inspectors reviewed results of selected audits performed since the last inspection of this program and evaluated the adequacy of the licensee's corrective actions for issues identified during those audits.
 
====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
{{a|4OA1}}
==4OA1 Performance Indicator Verification==
{{IP sample|IP=IP 71151}}
===.1 Mitigating Systems Performance Index - Emergency AC Power System===
 
====a. Inspection Scope====
The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Emergency AC Power System performance indicator for Units 1 and 2 for the third quarter 2012 through the second quarter 2013. To determine the accuracy of the performance indicator (PI) data reported, PI definitions and guidance in Nuclear Energy Institute (NEI) Document 99-02, "Regulatory Assessment Performance Indicator Guideline," Revision 6, were used. The inspectors reviewed the licensee's operator narrative logs, MSPI derivation reports, issue reports, event reports, and NRC Integrated Inspection Reports for July 2012 through June 2013 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 licensee's 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 Index - High Pressure Injection Systems===
 
====a. Inspection Scope====
The inspectors sampled licensee submittals for the Mitigating Systems Performance Index - High Pressure Injection Systems PI for Units 1 and 2 for the third quarter 2012 through the second quarter 2013. To determine the accuracy of the PI data reported, PI definitions and guidance in NEI 99-02 were used. The inspectors reviewed the licensee's operator narrative logs, issue reports, MSPI derivation reports, event reports, and NRC Integrated Inspection Reports for July 2012 through June 2013 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 licensee's 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 Index - Residual Heat Removal System===
 
====a. Inspection Scope====
The inspectors sampled licensee submittals for the Mitigating Systems Performance Index - Residual Heat Removal System PI for Units 1 and 2 for the third quarter 2012 through the second quarter 2013. To determine the accuracy of the PI data reported, PI definitions and guidance in NEI 99-02 were used. The inspectors reviewed the licensee's operator narrative logs, issue reports, MSPI derivation reports, event reports, and NRC Integrated Inspection Reports for July 2012 through June 2013 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 licensee's 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 residual heat removal system samples as defined in IP 71151-05.
 
====b. Findings====
No findings were identified.
 
===.4 Mitigating Systems Performance Index - Cooling Water Systems===
 
====a. Inspection Scope====
The inspectors sampled licensee submittals for the Mitigating Systems Performance Index - Cooling Water Systems PI for Units 1 and 2 for the fourth quarter 2012 through the second quarter 2013. To determine the accuracy of the PI data reported,  PI definitions and guidance in NEI 99-02 were used. The inspectors reviewed the licensee's operator narrative logs, issue reports, MSPI derivation reports, event reports, and NRC Integrated Inspection Reports for October 2012 through June 2013 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 licensee's 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 cooling water system samples as defined in IP 71151-05.
 
====b. Findings====
No findings were identified.
 
===.5 Occupational Exposure Control Effectiveness===
 
====a. Inspection Scope====
The inspectors sampled licensee submittals for the occupational radiological occurrences PI for the first quarter 2012 through the second quarter 2013. The inspectors used PI definitions and guidance in NEI 99-02 to determine the accuracy of the PI data reported. The inspectors reviewed the licensee's assessment of the PI for occupational radiation safety to determine whether indicator-related data were adequately assessed and reported. To assess the adequacy of the licensee's PI data collection and analyses, the inspectors discussed with radiation protection staff the scope and breadth of their data review and the results of those reviews. The inspectors independently reviewed electronic personal dosimetry dose rate and accumulated dose alarms, dose reports, and the dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized PI occurrences.
 
The inspectors also conducted walkdowns of numerous locked high and very high radiation area entrances to determine the adequacy of the controls in place for these areas. Documents reviewed are listed in the Attachment to this report. This inspection constituted one occupational exposure control effectiveness sample as defined in IP 71151-05.
 
====b. Findings====
No findings were identified.
{{a|4OA2}}
==4OA2 Identification and Resolution of Problems==
{{IP sample|IP=IP 71152}}
===.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 licensee's 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 licensee's 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 Sections 1 and 2 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 licensee's CAP. This review was accomplished through inspection of the station's 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.
{{a|4OA3}}
==4OA3 Follow-Up of Events and Notices of Enforcement Discretion==
===
{{IP sample|IP=IP 71153}}
 
===.1 (Closed) Licensee Event Report (LER) 05000374/2013-002-00:===
Manual Reactor Scram Following Trip of Circulating Water Pumps
 
====a. Inspection Scope====
This event, which occurred on April 25, 2013, involved an evolution designed to enable the licensee to access and repair a condenser tube leak identified on the Unit 2 main condenser east waterbox. An existing procedure was utilized to allow the unit to stay at power while the affected half of the waterbox was isolated and drained. However, during the execution of this evolution, the circulating water (CW) system had its isolation boundary challenged by operators while the waterbox manway covers were still open, which resulted in the flooding of the condenser pit, a CW pump trip, and manual scram. Documents reviewed are listed in the Attachment to this report. This LER is closed.
 
This event follow-up review constituted one sample as defined in IP 71153-05.
 
====b. Findings====
Failure to Follow Procedure Led to Manual Scram with Complications
 
=====Introduction:=====
A self-revealed finding preliminarily determined to be of low-to-moderate safety significance (White) was identified for the licensee's failure to follow procedure LOP-CW-10, "Dewatering the Circulating Water System," Revision 32, on Unit 2. Specifically, operators executed the condenser waterbox dewatering evolution in a manner inconsistent with procedural guidance, resulting in a circulating water pump trip, loss of the normal heat sink, and reactor scram.
 
=====Description:=====
On April 25, 2013, during Unit 2's restart from a recent forced outage, the licensee identified that a condenser tube leak existed, based on chemistry samples, and a repair was pursued. Activities were initiated to identify the tube leak in the east waterbox of the main condenser while the unit was at 56 percent power, as allowed by procedure LOP-CW-10, "Dewatering the Circulating Water System," Revision 32. In the pre-job briefing for the waterbox dewatering evolution, operators decided to add a step to the evolution that was inconsistent with the procedure. Specifically, when the CW isolation motor-operated valves (2CW007A and C) were electrically closed from the control room handswitch per LOP-CW-10, equipment operators were then instructed to manually close the valves further to achieve tighter closure. This added step to manually seat the isolation valves as a part of the planned activity was a departure from the procedure. Attachment B of LOP-CW-10, "Waterbox Isolation Valve Adjustment Troubleshooting Guidelines," which was to be used as a contingency in case of rising waterbox water levels, did contain steps to manually adjust the isolation valves, but also included the crucial step to verify all waterbox manways had first been closed and tightened prior to adjusting the valves. Since the licensee never entered Attachment B, the waterbox hatches remained open while the valves were manually closed. These manual valve manipulations were not executed in accordance with LOP-CW-10. As a result, when the CW inlet isolation valve (2CW007A) was inadvertently over-travelled 1/4-inch past its closed match mark, CW flow rapidly filled up the waterbox and overflowed the open upper hatches, spilling into the condenser pit. The 2A and 2B CW pumps automatically tripped when water collecting in the pit reached the high water level setpoint of 12 inches. Control room operators then manually scrammed the reactor.
 
=====Analysis:=====
The inspectors determined that the licensee's failure to follow the prescribed steps of procedure LOP-CW-10 was reasonably within the licensee's ability to foresee and correct and should have been prevented, and is therefore considered a performance deficiency warranting a significance determination. The inspectors used Inspection Manual Chapter (IMC) 0609 Appendix A, "The Significance Determination Process (SDP) for Findings At-Power" Exhibit 1, dated June 19, 2012, for the Initiating Events cornerstone. The inspectors answered "yes" to the screening question, "Did the finding cause a reactor trip AND the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown conditions?"  The loss of a condenser is cited as an example of such an event. A detailed risk evaluation was required. The Senior Reactor Analysts (SRAs) used the LaSalle Unit 1 SPAR model as a surrogate for the Unit 2 performance deficiency to perform the detailed risk evaluation.
 
The SPAR model revision was 8.21. Several modifications were performed by Idaho National Laboratory to appropriately model plant response to a loss of condenser heat sink event. In accordance with Risk Assessment of Operational Events Handbook guidance, for findings that cause initiating events to occur, the initiating event that was observed is set to 1.0 or "True" and the conditional core damage probability is calculated. The conditional core damage probability is multiplied by one inverse year (yr-1) to equate this to a change in core damage frequency for the performance deficiency. For this finding, the initiating event "Loss of Condenser Heat Sink" was set to 1.0 using the events and condition assessment module of the Systems Analysis Program for Hands-On Integrated Reliability Evaluations (SAPHIRE), Version 8. The calculated conditional core damage probability for a loss of condenser heat sink event was 1.6E-6, which represents a finding of low to moderate safety significance (White). The dominant sequence is a loss of condenser heat sink event with loss of all decay heat removal due to failure of suppression pool cooling and failure of containment venting. Late injection after containment failure is also failed.
 
LaSalle Unit 2 has a Mark II containment. The SRAs used IMC 0609 Appendix H, "Containment Integrity Significance Determination Process" dated May 6, 2004, to evaluate the potential risk contribution due to large early release frequency. The finding was a "Type A" finding" in which the finding has an impact on core damage frequency. The dominant sequences involved long-term accident sequences that involve failure of containment heat removal that eventually progresses to containment failure. These sequences do not contribute to large early release frequency because it is assumed that effective emergency response actions can be taken within the long time frame of the accident sequences. The licensee also performed an analysis of the performance deficiency using the LaSalle probabilistic risk assessment (PRA) model and provided it to the NRC for information. The analysis used several different methodologies which produced slightly different results. The SRAs determined that the licensee analysis was consistent with the NRC analysis if similar assumptions were applied. However, the overall conclusion of the licensee analysis was that this performance deficiency was best represented by a finding of very low safety significance (Green). The NRC determined that the NRC evaluation using standard SDP and Risk Assessment of Operational Events Handbook guidance and the modified SPAR model were appropriate tools for the SDP evaluation and the finding was best characterized as a finding of low to moderate safety significance (White). The finding had a cross-cutting aspect in the area of human performance, decision-making, because the licensee failed to use conservative assumptions when planning and executing the dewatering evolution. Specifically, the incorrect assumption that this evolution performed at-power could be treated the same as when performed during a shutdown condition enabled operators to stray from strict procedure adherence and into knowledge space (H.1(b)).
 
=====Enforcement:=====
This finding preliminarily determined to be of low-to-moderate safety significance (White) did not involve a violation of regulatory requirements because the systems involved were not safety-related and the evolution was not considered an activity affecting quality. The event was captured in the licensee's CAP as AR 01506809 and is being documented as FIN 05000374/2013004-01, "Failure to Follow Procedure Led to Manual Scram with Complications."  Corrective actions included various training activities for operators, procedure revisions, and potential physical enhancements to the CW isolation valves.
 
===.2 (Closed) LER 050002013-001-00:===
Pin Hole Leaks Identified in High Pressure Core Spray Piping On April 18, 2013, Unit 2 was in Mode 3 following a scram and a loss of offsite power that had occurred on both units the previous day. Three pin-hole through-wall leaks in the U2 HPCS minimum flow line piping were discovered. The leaks were on the outside bend of the first elbow downstream of the minimum flow restricting orifice, and appeared to be leaking a total of approximately 0.5 gallons per minute (gpm) with the HPCS pump not running. Unit 2 HPCS was declared inoperable and, because the HPCS minimum flow line is in direct communication with the suppression pool, primary containment was also declared inoperable. The direct cause of the event was a combination of cavitation and mechanical wear/erosion of the piping wall. Corrective actions included replacing the leaking pipe elbow, and performing ultrasonic inspections of susceptible piping on both Units. Also, HPCS operating procedures were reviewed and revised. Documents reviewed are listed in the Attachment to this report. This LER is closed. This event follow-up review constituted one sample as defined in IP 71153-05.
 
Findings Inadequate Procedures Led to Pin Hole Leaks in High Pressure Core Spray Piping
 
=====Introduction:=====
A finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, "Instructions, Procedures, and Drawings," was self-revealed for the failure to have procedures adequate for the circumstances during long-term operation of the HPCS system on minimum flow.
 
=====Description:=====
On April 17, 2013, following a station dual-unit loss of offsite power, the HPCS system started on both units. Unit 2 HPCS system ran in minimum flow mode for about 17 hours and Unit 1 HPCS system ran in minimum flow mode for about 15 hours before they were secured. On April 18, 2013, three small holes developed in the  Unit 2 HPCS minimum flow line elbow. Total leakage was about 0.5 gpm. The licensee determined in the Apparent Cause Evaluation (AR 1503825-08) that these holes were caused by cavitation and other flow related wear. The licensee's apparent cause for the through-wall leak of the HPCS minimum flow (min-flow) line was "inconsistent procedural guidance regarding operation in the min-flow mode."  The inspector reviewed the HPCS operating procedures and agreed with the licensee's assessment. In response to NRC Bulletin 88-04, "Potential Safety Related Pump Loss," the licensee stated that they would put precautions in operating procedures not to run the pump in min-flow mode for extended periods. The vendor information available at that time stated that extended operation was anything over 3 hours.
 
Licensee procedure LOP-HP-04, "Shutdown of High Pressure Core Spray System After An Automatic Initiation," Revision 11, had a precaution statement that, "In order to minimize pump degradation, consideration should be made to secure the HPCS pump when extended periods of operation on minimum flow is expected."  In addition, there was a note in the body of the procedure that says that if the pump is to be run in the min-flow mode for longer than 30 minutes then an additional flow path should be provided by running in the full flow test mode. However, these warnings do not specify that the pump cannot be run in min-flow for long periods of time; instead, the procedure only specifies that the pump "should not" be operated in min-flow for long periods of time. Finally, LOP-HP-04 neither had any procedural guidance on how to operate in the full flow test mode with a high drywell pressure signal present nor did it reference any other procedure on how to operate the system in this manner.
 
=====Analysis:=====
The inspectors determined that having HPCS operating procedures that were inadequate for the circumstances of running HPCS in the minimum flow mode for extended periods was contrary to 10 CFR 50, Appendix B, Criterion V, 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. Specifically, the procedural guidance given to operate the HPCS system was inadequate to prevent long-term operation of the system in the minimum flow mode of operation that led to cavitation and flow-induced wear which resulted in 3 pin hole leaks in the  Unit 2 HPCS min-flow line. The inspectors determined that the finding could be evaluated in accordance with  IMC 0609, Appendix A, "The Significance Determination for Findings At-Power," dated June 19, 2012, and Appendix H, "Containment Integrity Significance Determination Process," dated May 6, 2004. The inspectors used Section A of Exhibit 2 of Appendix A, "Mitigating Systems Screening Questions."  The inspectors answered all four questions "No" because even with the holes in the minimum flow line the HPCS could still inject and therefore did not lose its safety function.
 
The inspectors also reviewed IMC 0609, Appendix H, Section 6.0, "Procedure For  Type B Findings."  A Type B finding is one that has no effect on delta-core damage frequency. The inspectors entered Table 6.1 and determined that a phase two review was necessary because LaSalle has a Mark II containment and the finding impacted suppression pool integrity. The inspectors then entered Table 6.2 which stated that if the leakage from the drywell was less than 100 percent of the drywell volume per day then the issue screened as Green. The inspectors determined that leakage from the drywell to the environment was less than 100 percent per day based on information from IMC 0308, Appendix H, "Technical Basis, Containment Integrity Significance Determination Process (IMC 0609, App H) For Type A and Type B Findings Full Power and Shutdown Operations," dated May 6, 2004. Inspection Manual Chapter 0308, Section 2.2, stated that the hole size that would result in leakage equivalent to greater than 100 percent of the containment volume per day would have a diameter of greater that one inch. A circle around all the holes combined found in the HPCS piping was less than 0.5 inches in diameter. Therefore, this issue screens as Green. The inspectors did not identify a cross-cutting aspect associated with this finding.
 
=====Enforcement:=====
Title 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, or drawings, of a type appropriate to the circumstances and be accomplished in accordance with these instructions, procedures, or drawings. Procedure LOP-HP-04, "Shutdown of High Pressure Core Spray System After an Automatic Initiation," Revision 11, is considered an activity affecting quality by the licensee as well as by the NRC. Contrary to the above, on April 17, 2013, the licensee failed to have procedures of a type appropriate to the circumstances needed to operate and shut down the HPCS system.
 
Specifically, the procedural guidance available to the operators allowed them to operate the HPCS system in the min-flow mode for 17 hours on Unit 2 and 15 hours on Unit 1, which resulted in an unisolable leak hole in the Unit 2 HPCS min-flow line (and ultimately in the suppression chamber) and degraded the Unit 1 HPCS min-flow piping. Because this violation was of very low safety significance and it was entered into the licensee's CAP (as ARs 1503825 and 1530682), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000373/2013004-02; 05000374/2013004-02, Inadequate Procedures Led to Pin Hole Leaks in High Pressure Core Spray Piping). As corrective actions, the licensee immediately declared the HPCS system and the primary containment inoperable and entered the applicable TS actions. The affected pipe elbow was then promptly replaced and the systems returned to service.
 
Additionally, an extent of condition examination was performed on other potentially effected sections of piping. Finally, to prevent recurrence, the licensee revised the effected procedures.
 
===.3 (Closed) LER 050002012-001-00:===
2B DG Declared Inoperable Due to Excessive Air Start Receiver Blowdown Caused by a Degraded Drain Valve This event, which occurred on August 31, 2012, involved preventive maintenance that was being performed on the 2B DG 'A' train starting air receiver, which was not intended to cause the system to be inoperable. While operators were blowing down the air receiver, the pressure decreased below the minimum allowable 165 pounds per square inch (psig) required for DG operability per TS 3.8.3 Condition D. The licensee declared the system out of service and entered the appropriate TS action statement. Shortly thereafter, system pressure was restored and the 2B DG was declared operable. The cause of the event was determined to be a degraded drain valve on the receiver. The licensee replaced the valve at a later date to prevent recurrence. No findings were identified. This LER is closed. This event follow-up review constituted one sample as defined in IP 71153-05
 
===.4 (Closed) LER 050002013-003-00:===
Low Pressure Core Spray System Declared Inoperable Due to Faulty Control Switch This event occurred on April 18, 2013, while Unit 1 was in Mode 3 following a loss of offsite power event and dual unit scram the previous day. While attempting to raise Unit 1 reactor water level using the Low Pressure Core Spray (LPCS) system, LPCS injection motor-operated valve 1 E21-F005 failed to open when its control switch was held in the "OPEN" position. The LPCS system was declared inoperable but available, and the appropriate TS action statement was entered, requiring that LPCS be restored to operable status within seven days.
 
The cause of the event was determined to be the failure of the control switch due to the buildup of oxidation on the contact surfaces. All other contacts in the switch were found to be working normally. The corrective action was to replace the control switch.
 
A sample of similar switches has been scheduled to be tested to determine if electrical contact erosion is starting to occur on other switches with similar in-service life installed in similar electrical circuits. This event was also discussed in greater detail and was associated with a non-cited violation previously documented in NRC Special Inspection Report 05000373/2013009; 05000374/2013009. No additional findings were identified during this LER review. This LER is closed. This event follow-up review constituted one sample as defined in IP 71153-05.
 
===.5 (Discussed) LER 05000373/2012-001-00, 374/2012-001-00:===
Secondary Containment Inoperable Due to Interlock Doors Open As previously described in NRC inspection report 05000373/2013003; 05000374/2013003 02, the inspectors are in the process of reviewing the adequacy of the licensee's implemented and planned corrective actions in response to the events described in the subject LER. Since resolution of the associated unresolved item (URI) is necessary to determine if there are any violations of NRC requirements, this LER review will not be closed at this time.
 
Documents reviewed are listed in the Attachment to this report. This LER is not closed. This continuation of an event follow-up review did not constitute a completed sample as defined in IP 71153-05.
 
===.6 (Discussed) LER 05000373/2013-001-00, 374/2013-001-00:===
Secondary Containment Inoperable Due to Interlock Doors Open As previously described in NRC inspection report 05000373/2013003; 05000374/2013003 02, the inspectors are in the process of reviewing the adequacy of the licensee's implemented and planned corrective actions in response to the events described in the subject LER. Since resolution of the associated URI is necessary to determine if there are any violations of NRC requirements, this LER review will not be closed at this time.
 
Documents reviewed are listed in the Attachment to this report. This LER is not closed.
 
This continuation of an event follow-up review did not constitute a completed sample as defined in IP 71153-05.
 
===.7 (Closed) LER 050002013-004-00:===
Reactor Pressure Exceeded 150 psig With Reactor Core Isolation Cooling Inoperable  This event occurred on April 22, 2013, while Unit 1 was in Mode 2, Startup. Reactor pressure was increased to above 150 psig with the RCIC system isolated and inoperable. This was an action prohibited by TS and was previously discussed and documented as a Licensee-Identified Green NCV in NRC Inspection Report 05000373/2013002; 05000374/2013002, Section 4OA7. No additional findings were identified. Documents reviewed are listed in the Attachment to this report. This LER is closed. This event follow-up review constituted one sample as defined in IP 71153-05.
 
===.8 Review of Event Notification EN 49167 Retraction On July 1, 2013, the licensee made a 10 CFR 50.72 event notification (EN 49167) for the Unit 2 HPCS minimum flow valve pressure switch setpoint found outside of===
 
tolerance. The setpoint was found at 112.6 psig instead of greater than or equal to 113.2 psig. At the time of notification, the licensee determined that this was a condition that could have prevented fulfillment of a safety function needed to mitigate the consequences of an accident. On August 5, 2013, the licensee determined that premature opening of the HPCS minimum flow valve would not have prevented the HPCS from fulfilling its safety function since the licensee's emergency core cooling system loss-of-coolant accident analysis assumed that the HPCS minimum flow valves is open during an injection. In addition, the pressure switch in conjunction with the pump discharge flow switch would still provide adequate pump protection during low flow conditions. The inspectors did not identify any safety-significant issues with the licensee's retraction. Documents reviewed are listed in the Attachment to this report.
 
This event follow-up review constituted one sample as defined in IP 71153-05.
{{a|4OA6}}
==4OA6 Management Meetings==
 
===.1 Exit Meeting Summary On October 2, 2013, the inspectors presented the inspection results to Mr. P. Karaba, the Site Vice-President, and other members of the licensee staff.===
The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.
 
===.2 Interim Exit Meetings Interim exits were conducted for the inspection results for the areas of radioactive solid waste processing and radioactive material handling, storage, and transportation; and occupational exposure control effectiveness performance indicator verification with Mr. P. Karaba, Site Vice-President, on August 16, 2013. 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: 
 
=SUPPLEMENTAL INFORMATION=
 
==KEY POINTS OF CONTACT==
Licensee
: [[contact::P. Karaba]], Site Vice President 
: [[contact::H. Vinyard]], Plant Manager 
: [[contact::K. Hedgspeth]], Radiation Protection Manager 
: [[contact::J. Washko]], Engineering Manager 
: [[contact::G. Chavez]], Dry Cask Storage Program Manager 
: [[contact::B. Maze]], Project Management 
: [[contact::M. Sharma]], Engineering Programs 
: [[contact::K. Hall]], Buried Piping Program Owner 
: [[contact::V. Chopra]], Engineering Programs 
: [[contact::J. Vergara]], Regulatory Assurance 
: [[contact::L. Ekern]], Nuclear Oversight 
: [[contact::B. Hilton]], Design Manager 
: [[contact::G. Ford]], Regulatory Affairs Manager 
: [[contact::J. Houston]], Nuclear Oversight Manager 
: [[contact::A. Schierer]], Engineer 
: [[contact::D. Amezaga]], System Engineer 
: [[contact::J. Bendis]], Engineer 
: [[contact::J. Feeney]], LaSalle Nuclear Oversight 
: [[contact::J. Hughes]], Emergency Preparedness Coordinator 
: [[contact::J. Smith]], Operations Training Manager 
: [[contact::L. Blunk]], Regulatory Affairs 
: [[contact::J. Shields]], Invessel Visual Inspection Program Supervisor 
: [[contact::S. Shields]], Regulatory Affairs 
: [[contact::S. Tanton]], Engineer 
: [[contact::T. Hapak]], Chemistry 
: [[contact::C. Howard]], Radiation Protection Operation Manager 
: [[contact::R. Simonsen]], Radiation Protection Operation Manager 
: [[contact::A. Baker]], Dosimetry Specialist 
: [[contact::A. Daniels]], Exelon Emergency Preparedness Manager 
: [[contact::K. Rusley]], Emergency Preparedness Manager 
: [[contact::S. Tutoky]], Senior Chemist 
: [[contact::M. Martin]], Chemistry Developmental Manager 
: [[contact::J. Mosher]], Radiation Protection Manager
: [[contact::S. Koval]], Radwaste Shipping Specialist  Nuclear Regulatory Commission
: [[contact::M. Kunowski]], Chief, Reactor Projects Branch 5
Attachment 
==LIST OF ITEMS==
OPENED, CLOSED AND DISCUSSED
===Opened===
: 05000374/2013-002-00 LER Manual Reactor Scram Following Trip of Circulating Water Pumps (Section 4OA3.1)
: 05000374/2013004-01 FIN Failure to Follow Procedure Led to Manual Scram with Complications (Section 4OA3.1)
: 05000374/2013-001-00 LER Pin Hole Leaks Identified in High Pressure Core Spray Piping (Section 4OA3.2)
: 05000373/2013004-02
: 05000374/2013004-02 NCV Inadequate Procedures Led to Pin Hole Leaks in High Pressure Core Spray Piping (Section 4OA3.2)
: 05000373/2013-003-00 LER Low Pressure Core Spray System Declared Inoperable Due to Faulty Control Switch (Section 4OA3.4)
: 05000373/2013-004-00 LER Reactor Pressure Exceeded 150 psig With Reactor Core Isolation Cooling Inoperable (Section 4OA3.7) 
===Closed===
: [[Closes LER::05000374/LER-2013-002]]-00 LER Manual Reactor Scram Following Trip of Circulating Water Pumps (Section 4OA3.1)
: [[Closes LER::05000374/LER-2013-001]]-00 LER Pin Hole Leaks Identified in High Pressure Core Spray Piping (Section 4OA3.2)
: 05000373/2013004-02
: [[Closes finding::05000374/FIN-2013004-02]] NCV Inadequate Procedures Led to Pin Hole Leaks in High Pressure Core Spray Piping (Section 4OA3.2)
: [[Closes LER::05000374/LER-2012-001]]-00 LER 2B DG Declared Inoperable Due to Excessive Air Start Receiver Blowdown Caused by a Degraded Drain Valve
(Section 4OA3.3)
: [[Closes LER::05000373/LER-2013-003]]-00 LER Low Pressure Core Spray System Declared Inoperable Due to Faulty Control Switch (Section 4OA3.4)
: [[Closes LER::05000373/LER-2013-004]]-00 LER Reactor Pressure Exceeded 150 psig With Reactor Core Isolation Cooling Inoperable (Section 4OA3.7) 
===Discussed===
: 05000373/2012-001-00
: 05000374/2012-001-00 LER Secondary Containment Inoperable Due to Interlock Doors Open (Section 4OA2.5)
: 05000373/2013-001-00
: 05000374/2013-001-00 LER Secondary Containment Inoperable Due to Interlock Doors Open (Section 4OA2.6)
Attachment 
==LIST OF DOCUMENTS REVIEWED==
The following is a partial list of documents reviewed during the inspection.
: Inclusion on this list does not imply that the NRC inspector reviewed the documents in their entirety, but rather that selected sections or portions of the documents were evaluated as part of the overall inspection effort.
: Inclusion of a document on this list does not imply NRC acceptance of the document or any part of it, unless this is stated in the body of the inspection report.
: 1R01 Adverse Weather Protection Action Requests: - 99968; 2A CW Pump Clean Motor
: 1R04 Equipment Alignment Procedures: -
: LOS-DG-M2; 1A(2A) Diesel Generator Operability Test; Rev. 89 -
: LOS-DG-Q2; 1A(2A) Diesel Generator Auxiliaries Inservice Test; Rev. 55 -
: OP-AA-108-101; Control of Equipment and System Status; Rev. 10
-
: OP-AA-108-103; Locked Equipment Program; Rev. 2 -
: OP-AA-109-101; Clearance and Tagging; Rev. 9
: Action Requests: -
: 1501313; NRC Question on Emergency Fuel Cutoff Valves
-
: 1550074; NRC Walk Down Observation for CSCS Pump Mounting Bolt 
-
: 1555903; Extent of Condition Walk Down for CSCS Pump Mounting Bolt Working Documents: -
: LOP-DG-01E; Unit 1 A DG Electrical Checklist; 8/21/2013 -
: LOP-DG-01M; Unit 1 A DG Mechanical Checklist; 8/21/2013
-
: LOP-DG-04E; Unit 2 A DG Electrical Checklist; 8/21/2013
-
: LOP-DG-04M; Unit 2 A DG Mechanical Checklist; 8/21/2013
-
: LOP-DG-06E; Unit 1 A DG Cooling System Electrical Checklist; 8/21/2013 -
: LOP-DG-06M; Unit 1 A DG Cooling System Mechanical Checklist; 8/22/2013 -
: LOP-DG-09E; Unit 2 A DG Cooling System Electrical Checklist; 8/21/2013 -
: LOP-DG-09M; Unit 2 A DG Cooling System Mechanical Checklist; 8/21/2013
-
: OP-LA-101-111-1002; Protected Equipment Log, U2 Standby Gas Treatment Train Unavailable; 7/27/2013  -
: LOP-SC-01E; Unit 1 Standby Liquid Control System Electrical Checklist; Rev. 9 -
: LOP-SC-01M; Unit 1 Standby Liquid Control System Mechanical Checklist; Rev. 10
: Miscellaneous: - 3.7.2; Diesel Generator Cooling Water (DGCW) System; Amendment 200/187  - 3.8.1; AC Sources - Operating; Amendment 172/158
- 3.8.3; Diesel Fuel Oil and Starting Air; Amendment 191/178
- 9.5-26;
: LSCS-UFSAR Emergency Battery-Operated Lighting; Rev. 13
- B 3.7.2; Diesel Generator Cooling Water (DGCW) System; Rev. 0 - B 3.8.3; Diesel Fuel Oil and Starting Air; Rev. 33 - Check List Search; 8/7/2013   
: Attachment
: 1R05 Fire Protection
: Calculations: - L-000776, Appendix A; Summary of Combustible Loading; Rev. 7 
- L-000776, Appendix B; Combustible Load, FZ 7B3, Unit 0 Div. 1 Standby DG Room; Rev. 7 - L-000776, Appendix B; Combustible Load, FZ 8B2, Unit 2 Div. 2 Standby DG Room; Rev. 7 Figures and Drawings: - A-172; Turbine Building Sections & Details Sheet - S; Rev. J - A-275; Diesel Generator Room Ground Floor Plan West Area; Rev. AA -
: FZ-7B2; Pre-Fire Plan, DG Bldg. 710'0" Elev.; Rev. 1
-
: FZ-8B2; Pre-Fire Plan, DG Bldg. 710'0", U2 Div. 2, Standby DG Room;
: Rev. 1
- FZ 8C-4; LaSalle Pre-Fire Plan Layout, Unit 2 Elevation 674'0" Div. 2 RHR Service Water Pump Room; Rev. 0
: Miscellaneous: - 2I4; LaSalle Pre-Fire Plan Layout; Unit 1 Elevation 673'4", LPCS/RCIC Pump Cubicle; Rev. 1 -
: FZ-2I4; Pre-Fire Plan; RX Bldg. 674'4" Elev. U1 LPCS / RCIC Pump Cubicle; Rev. 1 -
: FZ-4F1; Pre-Fire Plan Layout, Unit 1 Elevation 710' 0", Div. 1 Essential Switchgear Room
-
: FZ-8C4; Pre-Fire Plan DG Bldg. 674'0" Elev. U2 Division 2 RHR Service Water Pump Room; Rev. 0 - H.3;
: LSCS-FPR; Rev. 5 - H.3-30;
: LSCS-FPR; Unit 1 LPCS/RCIC Pump Cubicle - Fire Zone 2I4 - H.3-162;
: LSCS-FPR, Standby Diesel Generator Room; Rev. 5 
- H.3-199;
: LSCS-FPR, Design-Basis Fire; Rev. 5
- Table H.3-1;
: LSCS-FPR, Safety-Related Equipment and Radioactive Equipment by Fire Area/Zone; Rev. 5 - Table H.3-2;
: LSCS-FPR, Combustible Loading and Extinguishing Capability; Rev. 5 - Table H.4-44;
: LSCS-FPR, Safe Shutdown Equipment Located in Fire Zone 2I4; Rev. 5 - Table H.4-99;
: LSCS-FPR, Safe Shutdown Equipment Located in Fire Zone 8C4; Rev. 5 1R06 Flooding
: Procedures: -
: ER-AA-3003; Cable Condition Monitoring Program; Rev. 3 -
: LOA-FLD-001; Flooding; Rev. 16
: Action Requests: -
: 1513902; Incorporation of PRA Insights 
-
: 1514239; Engineering Cable Program Walkdown Results - 1A TDRFP
-
: 1514253; Engineering Cable Program Walkdown Results -
: TB 710'
-
: 1514258; Engineering Cable Program Walkdown Results - 1B TDRFP -
: 1514261; Engineering Cable Program Walkdown Results - 1B TDRFP -
: 1514267; Engineering Cable Program Walkdown Results - 1A TDRFP -
: 1514274; Engineering Cable Program Walkdown Results - 2A TDRFP Working Documents: -
: LMS-ZZ-04; Units 1 & 2 Water Tight Door Surveillance Logs; Rev. 6 
-
: LS-PSA-012; LaSalle PRA (2011 PRA Update) Internal Flood Analysis, Vol. 1 of 2:
: Summary and Notebook; Rev. 1 
: Attachment  -
: LS-PSA-012; LaSalle PRA (2011 PRA Update) Internal Flood Analysis, Vol. 2 of 2:
: Flood Walkdown Notebook; Rev. 1  -
: WO 1346416-01; Perform Motor Winding Test per
: MA-AA-723-330 & SWGR 242X CUB -
: WO 1567941-01;
: MH-1/2/3/4/5/6 Manhole Inspection and Pumping if Required; 10/5/2012 -
: WO 1603786-01;
: MH-1/2/3/4/5/6 Manhole Inspection and Pumping if Required; 3/4/2013 Figures and Drawings: - 1E-1-3685; Cable Routing Outdoor Area; Rev. X
- 3.4-1; Flood Control - Basement Floor Plan; Updated Final Safety Analysis Report; Rev. 16 
- M-91; P & ID Reactor Building Equipment Drains System; Rev. AL
- M-106; P & ID Diesel Auxiliary Turbine & Service Building Floor Drains; Rev. M - M-137; P & ID Reactor Building Equipment Drains System; Rev. AF - M-151; P & ID Diesel Auxiliary and Turbine Building Floor Drains System; Rev. K Miscellaneous: - 1E-3685; Underground Cables List; undated, superseded copy
- A/R
: 100321-01; Update of
: IEN 2002-12, "Submerged Safety-Related Electrical Cables" Impact at LaSalle; 7/11/2002 -
: AT 760587-06,
: SEN 272; Assessment of Point Beach's Medium Voltage Cables Failure Applicability to LaSalle; 4/8/2008 -
: ER-AA-3003; Cable Tests Due Report; 9/6/2013 -
: IN 2002-12; OPEX Action Plan for NRC Information Notice:
: Submerged Safety-Related Electrical Cables (A/T# 100321); 3/21/2002 - Photos, Manholes 3,4,5; 10/12/2010
- PMRQ
: 187009-01; Predefined Look Ahead:
: MH-1/2/3/4/5/6 Manhole Inspection and Pumping if Required; 9/22/2013 - Underground Cables -LaSalle Cable Condition Monitoring Program (MV (4.16 KV) Motor/Cable Megger Trending / Results; 2005 - 2012  - WEC Guide:
: Plant Parameter List of Temp Procedures, T-mods, Daily orders;
: 9/6/2013 - 9/9/2013 1R11 Licensed Operator Requalification Program
: Procedures: -
: LOS-CS-Q1; Secondary Containment Damper Operability Test; Rev. 33
-
: LOS-CS-SR1; Secondary Containment Leak Rate Test; Rev. 5 -
: OP-AA-101-111; Roles and Responsibilities of On-Shift Personnel; Rev. 5  -
: OP-AA-101-111-1001; Operations Standards and Expectations; Rev. 13 -
: OP-AA-101-113; Operator Fundamentals; Rev. 7 Action Requests: -
: 1460607; Operations Crew Clock Reset
-
: 1464147; Crew 6 Lessons Learned
-
: 1483443; Crew Clock Reset:
: Time Delay -
: 1549737; Exam Quality Issue Identified During 71111.11 FASA  -
: 1550215; OPS Crew 3 Clock Reset -
: 1554666; Improper Prep Task & Procedure Change Needed for
: LOS-CS-SR1   
: Attachment
: 1R12 Maintenance Effectiveness
: Procedures: -
: ER-AA-310; Implementation of the Maintenance Rule; Rev. 9
-
: ER-AA-310-1002; Maintenance Rule Functions - Safety Significance Classification; Rev. 3 -
: ER-AA-310-1004; Maintenance Rule - Performance Monitoring -
: ER-AA-310-1006; Maintenance Rule - Expert Panel Roles and Responsibilities; Rev. 4 -
: LMS-FP-12C; Diesel Fire Pump Engine Two Year Surveillance; Rev. 17
-
: LOP-CW-09; Circulating Water System Ice Melting (CW); Rev. 16 
-
: LOP-FP-02; Fire Pump Diesel Startup and Shutdown; Rev. 21 -
: WC-AA-101; On-Line Work Control Process; Rev. 20 Action Requests: -
: 1361639; 1CW006B Failed to Open on Pump Start -
: 1366828; 2C CW Pump Did Not Open on Start -
: 1503439; 2C Circ Water Pump Failed to Start
-
: 1504132; 1A CW Pump Trip
-
: 1506809; Leakage Past CW Inlet Valve Results in Reactor Trip
-
: 1510920; 2C CW Pump Tripped
-
: 1511136; 1A Circ. Water PP. Failed to Start -
: 1514097; CW System Exceeded Maintenance Rule Performance Criteria -
: 1530325; A DFP Discharge Check Valve Not Holding Pressure -
: 1558916; Lessons Learned from
: LOS-CS-SR1 (4.0 Critique)
: Clearance Orders: - 91451; Replace 1CW01FFC Spray Nozzles
- 95713; Inspect/Clean CW Bay Per
: LTS-600-23
- 96569; 1CW006A Inspection (Electrical) - 97853; 1C CW Pump Motor Winding Test & BRK Cub Relay Cals - 98743; Troubleshooting and Repair of 1A CW Pump
- 99242; 1CW01PB Motor Winding Test
- 99968; 2A CW Pump Clean Motor Screens (Summer Readiness)
-
: 103654; 2CW006A/B/C Upper Coupling Work -
: 104757; 2CW01PB Various Work/Motor Winding Test -
: 104969; Inspect 2CW082 Actuator and Slave
-
: 105023; Inspect and Clean Forebay & Install UPS Mod
-
: 105557; 2A CW Pump Motor Inspection
-
: 107781; 2CW01PB Clean Motor Intake Screens
-
: 107805; 1A Circ Water Pump Bay Cleaning -
: 107912;
: LOP-ZZ-07 Att. UU and VV -
: 107983; 1CW01PB Clean Air Intake Screens
-
: 109783; 1A CW Pump Troubleshoot
- M60891; 2C CW Pump Trip - M60892; 1A CW Pump Failure to Start Figures and Drawings: -
: CW-1; Training Document:
: Circulating Water System; Rev. 5 
- M-63; P & ID Circulating Water System; Rev. K   
: Attachment
: Miscellaneous: - 3.7; TRM Fire Suppression Water System; Rev. 2
-
: AR 1514097; (a)(1) Determination; MRFFs in April of Circulation Water Pumps Exceeded Reliability Criterion for the CW System; 6/14/2013 -
: AR 1514097; (a)(1) Action Plan Development and Action Plan (Monitoring) Goal Setting;
: CW-01:
: Provide Main Condenser with Continuous Supply of Cooling Water; 7/11/2013 - B 3.7; Fire Suppression Water System; Rev. 2
- CW Evaluation for MR; 7/2011 - 6/2013
- CW; System Health Reports Common Unit and Units 1 & 2, Circulating Water;
: 4/2013 - 6/2013 -
: CW-01; Performance Monitoring - Reliability, Unit 1; 9/12/2013
-
: CW-01; Performance Monitoring - Reliability, Unit 2; 9/12/2013
-
: CW-01; Performance Monitoring - Unavailability, Unit 1; 9/12/2013
-
: CW-01; Performance Monitoring - Unavailability, Unit 2; 9/12/2013 -
: CW-01; Scoping and Risk Significance - Scoping; 8/28/2013 -
: CW-01; Scoping/Risk Significance Detailed Report, Circulating Water; 4/28/2005
-
: CW-01; Unavailability and Reliability Monitoring Evaluation; July 2011 - June 2013
-
: CW-03; Scoping/Risk Significance Detailed Report; 4/28/2005
-
: CW-06; Maintenance Rule Scoping Document; 8/28/2013 -
: ER-AA-310-1009; Program Health Report:
: Maintenance Rule; 2nd Quarter 2013 - Evaluation Status List; 3/2006 - 6/2013 and 2/2012 - 8/2013
- FP/FP-07; Scoping/Risk Significance - Summary Report; 8/19/2013
-
: FP-07; Performance Monitoring - Reliability; 8/2011 - 8/2013
-
: FP-07; Performance Monitoring - Unavailability; 8/2011 - 8/2013
-
: LAS-1-CW; Maintenance Rule System Basis Documents, Units 1 and 2; 9/8/2013 -
: LAS-1-CW-01; MR Function Snapshot, Unit 1; 9/4/2013 -
: LAS-1-CW-01; MR Function Snapshots, Units 1 and 2; 9/8/2013
- LaSalle Events Listing, Title and Days Since Last Event, as of 4/25/2013; 9/5/2013
- LaSalle Failure Report; 8/2011 - 8/2013
-
: LSCS-UFSAR 10.4; Other Features of Steam and Power Conversion System; Rev. 19 - MR "Report" Search; 3/2013 - 5/2013 - NUMARC 93-01; NEI Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants; Rev. 4A - Operations Log; Search "cw005", "cw006"; 9/1/2013
- Operations Log; Search "pump", "CW"; 9/5/2013
- Performance Criteria; CW; 8/28/2013 - Performance Details, FP:
: Fire Protection; 8/19/2013, 8/27/2013 - Performance Monitoring - Condition Monitoring; 8/2011 - 8/2013
- Train Unavailability Evaluation; 7/1/2011 - 7/31/2013 - Unavailability Details;
: FP-07 Diesel Fire Pumps; 11/20122 - 5/2013 1R13
: Maintenance Risk Assessments and Emergent Work Control Procedures: -
: ER-AA-600-1011; Risk Management Program; Rev. 11
-
: ER-AA-600-1021; Risk Management Application Methodologies; Rev. 4
-
: ER-AA-1100; Implementing and Managing Engineering Programs; Rev. 10 -
: PC-AA-1014; Risk Management; Rev. 3 -
: PC-AA-1014-F-1; Project Risk Management Plan; Rev 2   
: Attachment
: Action Requests: -
: 1498450; Line 0101 Trip
-
: 1503723; Unit 1 LPCS Injection Valve 1E21-F005 Will Not Open -
: 1519061; Entered
: LOA-TORN-001 and Online Risk Yellow for Both Units -
: 1519957; OLR Color Change Due to RCIC Switch Failure
-
: 1544262; OCBS 11-13 & 10-11 Opened and Reclosed
-
: 1544276; 2FP04JA Has No Power
-
: 1544383; Building 30 ETLS Blown
-
: 1546110; 1A DG CWPP Auto Started During 1C RHR BKR Maintenance 
-
: 1566951; OPS 4.0 Critique of Unit 2 Downpower and PST Working Documents: -
: AR 1546110; Event / Issues Report of 1A DG CWP Auto Started During 1C RHR BKR Maintenance -
: AR 1546110; Apparent Cause Evaluation:
: During
: LES-GM-103 on 1C RHR Switch Gear, the 1A DG Cooling Water Pump Auto Started; 8/13/2013 -
: PC-AA-1014-F-2; Project Risk Impact Matrix, Risk Analysis Legend; Rev. 2, 9/6/2013
-
: WO 1656244-01;
: LOS-RH-M1 U1 RHR "C" Att 1C; 8/9/2013 Miscellaneous: - Operator Log Entries; 8/7/2013 -8/8/2013
: 1R15 Operability Determinations and Functional Assessments
: Procedures: -
: LOS-RP-Q2; Turbine Stop Valve Scram and
: EOC-RPT Functional Test; Rev. 21
: Action Requests: -
: 1261854; 2C71A-K010C Possible Relay Failure or Wire Issue w/Limits -
: 1297044; TSV #3 RPS Relay 1C71A-K10C Did Not De-Energize as Requested
-
: 1476770; Op Eval 04-006 Non Conservative?
-
: 1510719; Elevated Drywell Temperature 
-
: 1532590; Evaluate 0B VC Charcoal Trains Due to Freon Leak -
: 1533947; Control Room Condenser Coil 0VC03AB D/P Alarm -
: 1554858; 1C71A-K010B #1 TSV Relay Chatter Figures and Drawings: - 1E-1-4089AB; For Record Per
: DCR 970285.
: As-Built; Rev H.
- PC,
: CS-1; Primary Containment Training Figure; Rev. 0 - PC,
: CS-2:
: Secondary Containment Training Figure; Rev. 1 Working Documents: -
: AR 1261854; Equipment Apparent Cause Evaluation 2C71A-K010C Possible Relay Failure or Associated Limit Switch -
: EC 345926; Establish Threshold of VOC Exposure to Charcoal Filters; undated  -
: EC 393644; Evaluation of Elevated Ambient Temperature on the Qualified Service Life of Environmentally Qualified (EQ) Equipment Located Inside Containment; Rev. 000 -
: OE 12-003; Operability Evaluation Potential to Increase Pool Swell Loads,
: AR 1430378; Rev. 0 - OE -4-006;
: AR 236085; CSCS Pump Room Ventilation, Revision of Completion Dates for Corrective Actions Due to Higher Priority Emergent Work; Rev. 4 
: Attachment
: Miscellaneous: - 3.3.1.1; RPS Instrumentation, Reactor Protection System Instrumentation; Amendment 147/133 - 3.3.4.1; EOC- RPT Instrumentation, End of Cycle Recirculation Pump Trip Instrumentation; Amendment 147/133 - B 3.3.1.1; RPS Instrumentation, Reactor Protection System Instrumentation; Rev. 0
- B 3.3.4.1;
: EOC-PRT Instrumentation, End of Cycle Recirculation Pump Trip Instrumentation; Rev. 0 - B 3.7.5; Control Room Area Ventilation AC System; Rev. 0 -
: EC 349032; Evaluation of
: ECR 97901, Anticipated CSCS Pump Room Temperatures; Rev. 0 -
: EC 350250; Thermal Capability Assessment of Safety-Related Electrical Equipment Located in the CSCS Rooms, Units 1 and 2; 7/14/2004 - IEEE Std 383-2003; IEEE Standard for Qualifying Class 1E Electric Cables and Field Splices for Nuclear Power Generating Stations; 2004 -
: LSCS-UFSAR 3.8-1; Design of Category I Structures; Rev. 13 - NREG 487; MARK II Containment Lead Plant Program Load Evaluation and Acceptance Criteria; Supplement No. 1 - Operator Log Entries Report; 9/6/2013
- Specification Sheet for Firewall III Instrumentation Cable, Multi-Conductor Unshielded (XLPE/CSPE) from Rockbestos-Suprenant Cable Corp.; 2003 - VC/VE Recirc. Charcoal Efficiency per ASTM D3808-1989; 1998 - 2013 1R19 Post-Maintenance Testing
: Procedures: -
: LIP-GM-946; Installation Procedure for S-O-R Series 102/131/103/141 Environmentally Qualified Differential Pressure Switches; Rev. 15 -
: LIS-RI-101; Unit 1 RCIC Steam Line High Flow Isolation Calibration; Rev. 27
-
: LOP-RD-09; Return of CRD System HCU to Service; Rev. 17 -
: MA-AA-716-012; Post Maintenance Testing; Rev. 19
: Action Requests: -
: 1112278; Spurious Unit 1 RCIC Inboard (Div. II) Steam Isolation -
: 1435575; Spurious Isolation of RCIC On High Steam Flow  -
: 1546110; 1A DG CWPP Auto Started During 1C RHR BKR Maintenance
-
: 1553341; RM - Unit 2
: HCU 34-03 DCV Failure
-
: 1557013;
: RM-Unit 1 SSPV Removal At 42-51 for Powerlabs Analysis
-
: 1557020;
: RM-Unit 2 SSPV Removal at 14-11 for Powerlabs Analysis -
: 1557101; Oil Leak, One Drop per 5 Minutes Working Documents: -
: AR 1546110; Event / Issues Report of 1A DG CWP Auto Started During 1C RHR BKR Maintenance - Clearance Order 110749-000; 1C41-F0001B SBLC Storage Tank Outlet Valve; 7/31/2013
-
: EC 374750;
: IT-7000 Drawing for CSCS Cooler Outlet Throttle Valve Replacement - Replace Globe Valves with Valves with Throttle Trim; Rev. 000 -
: LOS-RD-SR12; TBT2 Connector Removal/Re-install Check Sheet; 8/31/2013 -
: LOS-SC-Q1, Att. 1B; Tech Spec Surveillance; SBLC Pump Quarterly; 8/1/2013 -
: LOS-SC-Q1; Document Approval for SBLC Pump Operability/Inservice Test and Explosive Valve Continuity Check; Rev. 40 -
: LOS-VG-M1, Att. 2A; Tech Spec Surveillance; U2 SBGT; 7/29/2013 
: Attachment  -
: OP-AA-108-106; Equipment Return to Service Checklist; 1B SBLC Pump and Suction Valve, 1C41-C001B1/1C41-F001B -
: WC-AA-111; Surveillance WO Disposition Sheet for
: LOS-AA-W1 Att. 2C, Technical Specification Weekly CRD Accumulator Pressure Check; Rev. 4 -
: WO 1278800-03; 1DG01K-C:
: Replace AC Circ Oil Pump & Motor Assembly; 9/9/2013
-
: WO 1328700-02; Replace Lithium Battery; 9/9/2013
-
: WO 1329042-02; Inspection of 480KV Klockner-Moeller Motor Control; 7/31/2013 
-
: WO 1329042-02; OP PMT:
: Breaker Closes and Carries a Load, Perform
: LES-GIM-109; 8/1/2013 -
: WO 1329043-02; OP PMT:
: 1C41C001B SBLC B Pump Breaker Closes, Perform
: LES-GIM-109; 7/29/2013 -
: WO 1397170-02; Perform
: LES-GM-109 for 1A DG Space HTR @
: MCC 136X-2/A3 (1AP8) 9/9/2013 -
: WO 1397171-02; Perform
: LES-GM-109 for 1VD03C @
: MCC 136X-3/B2 (1AP81E); 9/9/2013 -
: WO 1467397-01; 1E31-N007AA Replace SOR D/P Switch Per
: IT-7000 This Time; 8/29/2013 -
: WO 1467397-01; Att 3B1, Work Package Planning, Briefing and Transition Form:
: Planner Initial Determination of FME Zone Check Appropriate Block; 8/28/2013 -
: WO 1498167-02; OP PMT New A VE Compressor Operates Properly; 7/14/2013
-
: WO 1579132-02; 1A DG AC Soakback Pump Leak; 9/10/2013 -
: WO 1607300-02; 1DGK018A Move Banana Jacks to Terminal Strip; 9/10/2013 -
: WO 1643728; OP
: LOS-RD-SR7 U2 Control Rod Settle Testing; 8/27/2013
-
: WO 1649978-01; LOS_VC_M1 VC EMU "A" Train Att. A; 7/14/2013
-
: WO 1656244-01;
: LOS-RH-M1 U1 RHR "C" Att 1C; 8/9/2013
-
: WO 1663774-01; Replace SSPV on 2C11-D4227; 9/10/2013 
-
: WO 1665175-02; OP PMT:U2 HCU Leak Check
: LOP-RD-09; 9/10/2013 -
: WO 1665175-03; OP PMT:
: U2 SSPV Removal For PowerLabs Analysis; 8/31/2013 -
: WO 1322922-05; Replace 1DG006 Per
: EC 374750; 9/10/2013 Miscellaneous: - 1A DG Maintenance Activities; Ver. 44; 8/30/2013
- 1DG01K; Active Degraded Equipment List, LCOTR # 01-DG-13-06-1A DG OOS - 9.4-1; LSCS_UFSAR Heating, Ventilation and Air Conditioning Systems; Rev. 14 -
: AR 1546110; Apparent Cause Evaluation:
: During
: LES-GM-103 on 1C RHR Switch Gear, the 1A DG Cooling Water Pump Auto Started; 8/13/2013 - B 3.7.5; Control Room Area Ventilation Air Conditioning (AC) System; Rev. 0 - LCOTR 01-SC-13-01-1B SC; Active Degraded Equipment List, 1B
: SBLC-1C41-F001B and 1C41-C001B Breakers; 8/1/2013  -
: WO 1322922-12; Task Completion Processing:
: CMO Vibes Test per
: IT-7000-M-PP-36 Test Reqmt #6 1R22 Surveillance Testing
: Procedures: -
: ER-AA-321-1007; Inservice Testing (IST) Program Corporate Technical Positions; Rev. 1 -
: LIS-NR-303A; Unit 1 Average Power Range Monitor Channels A, C and E Rod Block and Scram Functional Test; Rev. 19 -
: LOP-CX-06; Primary Containment Isolation Status Display; Rev. 8
-
: LOS-RH-Q1; RHR (LPCI) and RHR Service Water Pump and Valve Inservice Test for Modes 1,2,3,4, and 5; Rev. 80 -
: LOS-DG-Q3; 1B(2B) Diesel Generator Auxiliaries Inservice Test; Rev. 63 
: Attachment
: Action Requests: -
: 1543791; IDNS Questions regarding
: LOS-DG-Q3 
-
: 1543795; Procedure Enhancement Opportunity
-
: 1543962; Crew 6 Lessons Learned - Crew Clock Reset Working Documents: -
: WO 1626352-01; APRM Chans A, C, & E Rod Block and Scram; 5/17/2013 -
: WO 1626353-01; APRM Chans B, D, & F Rod Block and Scram; 5/17/2013
: Figures and Drawings: -
: IT-7000-M-PP-14; Generic Locking Device Details for Throttle Valves; Rev. M - M-1465; P&ID CSCS Equipment Cooling System; Rev. E
: Working Documents: -
: EC 360691; CSCS Cooling Water Flow Margins for Operability of the ECCS Cubicle Room Coolers and DG Coolers; Rev. 0  -
: EC 381142; Eliminate the Flow Ranges Listed in IST Acceptance Criteria Manual Sheets and Replace with a Specific Value; Rev. 0 -
: WO 1643237-01; OP
: LOS-RH-Q1 2C RHR Att. 2C; 7/22/2013 Operability Evaluations: -
: EC 340193; Physical Restraint of Diesel Generator Cooler Outlet Throttle Valve Position; Rev. 0 -
: EC 343899; Additional VY Cooler Valves Added to Work Order; Rev. 1
-
: EC 343899; Locking Devices for DG Cooler Outlet Valves to Prevent Drifting; Rev. 1 -
: EC 349192; Design Consideration Summary,
: CC-AA-102, Rev. 10, VY Area Cooler Outlet Throttle Valves Locking Device Equivalent Change; Rev. 1 -
: EC 349192; Work Planning Instructions, VY Area Cooler Outlet Throttle Valves Locking Device Equivalent Change; Rev. 1 Miscellaneous: - 3.3.1.1; RPS Instrumentation; Amendment No. 147/133
- 6.3;
: LSCS-UFSAR; Low-Pressure Coolant Injection (LPCI) Subsytem; Rev. 18 - ASME OM Code ISTB 1995-2012; Inservice Testing of Pumps in Light-Water Reactor Nuclear Power Plants - Pre-2000 Plants - B 3.3.1.1; RPS Instrumentation Bases; Rev. 0 
- B 3.3.1.1; RPS Instrumentation Bases; Rev. 51 
- B 3.5.1;
: ECCS-Operating
-
: IST-LAS-BDOC-V-10; 1E22-C002 IST Bases Document, U1 HPCS DG Cooling Water Pump; 5/25/2011 -
: IST-LAS-BDOC-V-10; 2E22-C002 IST Bases Document, U2 HPCS DG Cooling Water Pump; 5/25/2011 -
: LOS-DG-Q3; Tech. Spec. Surveillance DG Cooling Water Pump Inservice Test ATT. B3; 8/6/2013 -
: LSCS-UFSAR 9.2-1; Water Systems; Rev. 13 - TRM 3.3.c; Control Rod Block Instrumentation; Rev. 4 
- TRM 3.3.c; Control Rod Block Instrumentation; Rev. 6  - TRM Appendix E; Response Times; Rev. 2   
: Attachment
: 1EP6 Drill Evaluation
: Procedures: -
: EP-AA-1005; Radiological Emergency Plan Annex for LaSalle Station; Rev. 36 -
: LS-AA-1020; Reportability Tables and Decision Trees; Rev. 20
: Action Requests: -
: 1360963; EP:
: First/Second Quarter PI Drill Results
-
: 1400931; EP NRC Graded Exercise:
: Sim Unsat Demonstration Criteria -
: 1400953; EP NRC Graded Exercise:
: TSC Unsat Demonstration Criteria -
: 1401029; EP NRC Graded Exercise:
: TSC Performance Issues
-
: 1401051; EP NRC Graded Exercise:
: OSC Unsat Demonstration Criteria
-
: 1457631; EP NRC PI Data Incorrect for November 2012
-
: 1492190; EP:
: Performance Indicator Decline -
: 1511049; EP Unusual Event:
: Failed facility Objective H.3 for OSC -
: 1532676; EP:
: 2nd Qtr PI Drills Facilities/Equipment Issues -
: 1554421; EP:
: Facility & Equipment Issues 3rd Qtr PI Drill Set - 0LLOOO -
: 1559781; Everbridge System Did Not Work As Expected During ERO Drill
-
: 1559989; NOS ID:
: EP 2013 Off Year Exercise Observations -
: 1560005; NOS ID:
: Environs Team Industrial Safety Deficiencies
: Event Notification: - EN (Drill); High Water Level in Unit 1 A RHR Room Reactor Building 673'; 7/16/2013
: Miscellaneous: - Drill/Exercise Performance Graph; 3rd Qtr 2011 - 2nd Qtr 2013 - LaSalle Unit Difference Book; 3/4/2013
-
: LS-AA-2120; Monthly Data Elements for NRC Drill/Exercise Performance; 1/2013, 2/2013, and 3/2013 - NARS
: EP-MW-114-100-F-01; Nuclear Accident Reporting System (NARS) Form (Drill) Utility Message 1; 7/16/2013  - NARS
: EP-MW-114-100-F-01; Nuclear Accident Reporting System (NARS) Form (Drill) Utility Message 2; 7/16/2013  -
: NEI 99-02; Emergency Preparedness Cornerstone; Rev. 6 2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and Transportation
: Procedures: -
: RP-AA-600; Radioactive Material Waste Shipments; Rev. 12
-
: RP-AA-600-1004; Radioactive Waste Shipments to Energy Solutions' Clive Utah Disposal Site Containerized Waste Facility; Rev. 11 -
: RP-AA-600-1005; Radioactive Material and Disposal Site Waste Shipments; Rev. 15 -
: RP-AA-600-1007; Radioactive Waste Shipments to Energy Solutions' Clive Utah Disposal Facility Bulk Waste Facility; Rev. 6 -
: RP-AA-600-1010; Use and Operation of WMG Software for Creating Containers, Samples, Waste Streams and Waste Types; Rev. 0 -
: RP-AA-600-1011; Use and Operation of WMG Software for Gross Gamma Characterization and Generation of Shipping Paperwork; Rev. 2 -
: RP-AA-601; Surveying Radioactive Material Shipments; Rev. 14
-
: RP-AA-602; Packaging of Radioactive Material Shipments; Rev. 18 
: Attachment  -
: RP-AA-603; Inspection and Loading of Radioactive Material Shipments; Rev. 8 -
: RP-AA-605; 10 CFR Part-61 Program; Rev. 5 -
: RPLA-605-1001; Waste Stream Results Review of Trending for Shifts in Scaling Factors Action Requests: -
: 1094844; Nuclear Oversight Identified Radwaste Shipping Documentation Issues -
: 1387239; Waste Shipment Records are Missing Required Documentations -
: 1412089; Radwaste Seavan Housekeeping was Found Below Standard
-
: 1533686; Miscommunication During Receipt of Radioactive Shipment
: Miscellaneous: -
: FO-OP-023-161025; Energy Solutions; Waste Transfer and Bead Resin/Activated Carbon Dewatering Procedure for 14-215 or Smaller Liners at LaSalle Station Utilizing a Standard Dewatering System Fill-head; Rev. 3 - LM13-128; Radioactive Material,
: LSA-II, 7,
: UN 3321; Seven Boxes of Areva Equipment to Areva NP, Lynchburg, VA; 8/15/2013;  - LW12-002; Radioactive Material,
: LSA-II, 7,
: UN 3321; Fissile Excepted; Dewatered Bead Resin; Clive Disposal Facility, Clive, Utah; 1/10/2012 - LW12-006; Radioactive Material,
: LSA-I, 7,
: UN 2912, 40-Foot Seavan Containing Dry Active Waste To Be Processed at Energy Solutions Bear Creek Facility, Oak Ridge Tennessee;
: 2/15/2012 - LW12-032; Radioactive Material,
: LSA-II, 7,
: UN 3321, Pre-filter Septa Liner in 14-215 Cask Containing Dry Active Waste to be Processed at Energy Solutions Bear Creek Facility, Oak Ridge Tennessee; 8/16/2012 - LW12-037; Radioactive Material,
: LSA-II, 7,
: UN 3321; 21-300FR Liner of Dewatered Bead Resin in 14-215H-26 Cask; to Clive Disposal Facility, Utah; 10/12/2012;  - LW13-022; Radioactive Material,
: LSA-II, 7,
: UN 3321; CP Pre-Filtered Septa Liners in 14-215H-25 to Energy Solutions Bear Creek Facility, Oak Ridge Tennessee; 7/25/2013 - LW13-024; Radioactive Material,
: LSA-II, 7,
: UN 3321; Condensate Pre-Filter Septa Liner to Energy Solutions Bear Creek Facility, Oak Ridge Tennessee; 7/25/2013; - Radioactive Waste Shipment Logs, 2012 - 2013
: 4OA1 Performance Indicator Verification
: Procedures: -
: LS-AA-117-1002; Licensing and Regulatory Affairs Correspondence Concurrence Form; Rev. 3; 1/2012 - 4/2013 -
: LS-AA-2140; Monthly Data Elements for NRC Occupational Exposure Control Effectiveness; Rev. 5 - ROP Mitigating System Performance Index (MSPI) Basis Document, LaSalle County Nuclear Generating Station; Rev. 14 Working Documents: -
: EC 368200; Evaluation:
: Provide Scaling to Take Fillup Rate Reading 1(2)PM13J, Terminals TB34-10,11; Rev. 0
: Miscellaneous: - MSPI / WANO Reporting, DG System Units 1 and 2; 7/2012 - 6/2013 - MSPI / WANO Reporting, HPCS System Units 1 and 2; 7/2012 - 6/2013
- MSPI / WANO Reporting, RHR System Units 1 and 2; 7/2012 - 6/2013
- PI Data Elements from 1/2012 - 4/2013 
: Attachment  - Units 1 and 2, Core Standby Cooling Systems MSPI Data; 10/2012 - 6/2013
: 4OA2 Identification and Resolution of Problems
: Procedures: -
: MA-AA-716-010-1103; Fluid Sealing Technology Program; Rev. 2  -
: WC-AA-106; Priority Screening Decision Flow; Rev. 13 Action Requests: -
: 1549534; Drum Evaporator Steam Not Exhausting Properly
: Miscellaneous: - B 3.7j; TRM Fire Suppression Water System; Rev. 2
- Completed Site Template for 30-Day Response to Bulletin 2011-01 LaSalle Station -
: Memorandum From David Rhoades to Bryan Hanson; Confirmation of Supporting Material for 30-Day Response to NRC Bulletin 2011-01 "Mitigating Strategies"; 6/3/2011 - ODCM (CY-LA-170-301); PORC Routing Package; Rev. 4
: 4OA3
: Follow-Up of Events and Notices of Enforcement Discretion
: Procedures: -
: LOP-CW-10; Dewatering the Circulating Water System (CW); Rev. 32 - S-13-5-2; LOA / Tech Spec Drill, Dynamic Simulator Scenario Guide; Rev. 0
: Action Requests: -
: 1506809; Leakage Past CW Inlet Valve Results in Reactor Trip
-
: 1531436; Inst OOT, 2E22-N012A, Trend Code B2 
-
: 1535071; Extent of Condition Inspection Required on HP Line Per EACE
-
: 1535075; Extent of Condition Inspection Required on HP Line Per EACE Licensee Event Reports: - 2012-001-00; LER 2B Diesel Generator Declared Inoperable Due to Excessive Air Start Receiver Blowdown Caused by a Degraded Drain Valve (Closed in 2013-003 Inspection Report) - 2013-001-00; LER Pin Hole Leaks Identified in High Pressure Core Spray Piping 
- 2013-002-00; Manual Reactor Scram Following Trip of Circulating Water Pumps; 4/25/2013 - 2013-003-00; LER Low Pressure Core Spray System Declared Inoperable Due to Faulty Control Switch (Closed in 2013-007 Special Inspection Report) - 2013-004-00; LER Reactor Pressure Exceeded 150 psig with Reactor Core Isolation Cooling Inoperable
: Event Notification: - 48969; Unit 2 Manual Scram Due to Loss of Circulating Water; 4/25/2013
- 49167 (Update); Retraction:
: High Pressure Core Spray Minimum Flow Valve Pressure Switch Setpoint Found Outside of Tolerance; 8/5/2013 - 49167; High Pressure Core Spray Minimum Flow Valve Pressure Switch Setpoint Found Outside of Tolerance; 7/1/2013   
: Attachment
: Miscellaneous: -
: AR 1503825; Apparent Cause Evaluation, Through-wall High Pressure Core Spray Pipe Leak; 4/18/2013  -
: AR 1506809; Root Cause Investigation Trip of Running CW Pumps and Unit 2 Manual SCRAM Due to Procedure Adherence When Isolating a Main Condenser Waterbox - EC Eval
: 394548; Evaluation Concerning HPCS Inoperability from
: AR 1531436; Rev. 0 
: Attachment
==LIST OF ACRONYMS==
: [[USED]] [[]]
: [[AC]] [[Alternating Current]]
: [[ADAMS]] [[Agencywide Document Access Management System]]
: [[ALARA]] [[As-Low-As-Is-Reasonably-Achievable]]
: [[APRM]] [[Average Power Range Monitor]]
: [[AR]] [[Action Request (also known as Issue Report)]]
: [[CAP]] [[Corrective Action Program]]
: [[CFR]] [[Code of Federal Regulations]]
: [[CSCS]] [[Core Standby Cooling System]]
: [[CW]] [[Circulating Water]]
: [[DC]] [[Direct Current]]
DG Diesel Generator
d/p Differential Pressure
: [[EN]] [[Event Notification]]
FSAR Final Safety Analysis Report
gpm gallons per minute
: [[HCU]] [[Hydraulic Control Unit]]
: [[HPCS]] [[High Pressure Core Spray]]
: [[IEEE]] [[Institute of Electrical & Electronic Engineers]]
: [[IMC]] [[Inspection Manual Chapter]]
: [[IP]] [[Inspection Procedure]]
IR Inspection Report IV Independent Verification
kV Kilovolt
: [[LER]] [[Licensee Event Report]]
: [[LLC]] [[Limited Liability Corporation]]
: [[LPCS]] [[Low Pressure Core Spray min-flow Minimum Flow]]
: [[MSPI]] [[Mitigating System Performance Index]]
: [[NCV]] [[Non-Cited Violation]]
: [[NEI]] [[Nuclear Energy Institute]]
: [[NRC]] [[U.S. Nuclear Regulatory Commission]]
: [[NRR]] [[]]
: [[U.S.]] [[Nuclear Regulatory Commission Office of Nuclear Reactor Regulation]]
: [[PARS]] [[Publicly Available Records System]]
: [[PI]] [[Performance Indicator]]
: [[PI&R]] [[Problem Identification and Resolution]]
: [[PMT]] [[Post-Maintenance Testing]]
: [[PRA]] [[Probabilistic Risk Assessment psig Pounds Per Square Inch Gauge]]
: [[RCIC]] [[Reactor Core Isolation Cooling]]
: [[RHR]] [[Residual Heat Removal]]
: [[RP]] [[Radiation Protection]]
: [[RPS]] [[Reactor Protection System]]
: [[SBLC]] [[Standby Liquid Control]]
: [[SDP]] [[Significance Determination Process]]
: [[SL]] [[Severity Level]]
SPAR  Standardized Plant Analysis Risk SRA Senior Reactor Analyst
Attachment
: [[TS]] [[Technical Specification]]
: [[UFSAR]] [[Updated Final Safety Analysis Report]]
: [[URI]] [[Unresolved Item]]
WO Work Order
M. Pacilio -3- 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]] [[Resident Inspector at LaSalle County Station. In accordance with Title 10 of the Code of Federal Regulations 2.390, "Public Inspections, Exemptions, Requests for Withholdings," 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's 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 by Julio Lara for/        Kenneth G. O'Brien, Acting Director
Division of Reactor Projects Docket Nos. 50-373 and 50-374
License Nos. NPF-11 and NPF-18
 
Enclosure: Inspection Report 05000373/2013004; 05000374/2013004  w/Attachment:  Supplemental Information cc w/encl: Distribution via ListServTM 
}}

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