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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
| author affiliation = NRC/RGN-III/DRP
| addressee name = Pacilio M
| 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: [[see also::IR 05000373/2013004]]
 
=Text=
{{#Wiki_filter:UNITED STATES NUCLEAR REGULATORY COMMISSION REGION III 2443 WARRENVILLE ROAD, SUITE 210 LISLE, IL 60532-4352
  November 15, 2013
EA-13-221
Mr. Michael J. Pacilio
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
  M. Pacilio -2- 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 lic
ensee; 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. 
  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 th
e Publicly Available Records System (PARS) component of NRC's Agencywide Documents Access and Management Sy
stem (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 ListServ
TM 
  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
TABLE OF CONTENTS SUMMARY OF FINDINGS ...........................................................................................................
1 REPORT DETAILS ................................................................................................................
....... 3 Summary of Plant Status .......................................................................................................
.... 3 1. REACTOR SAFETY ....................................................................................................... 3
1R01 Adverse Weather Protection (71111.01) ............................................................ 3
1R04 Equipment Alignment (71111.04) ....................................................................... 4
1R05 Fire Protection (71111.05) .................................................................................. 5
1R06 Flooding (71111.06) ........................................................................................... 6
1R11 Licensed Operator Requalification Program (71111.11) .................................... 7
1R12 Maintenance Effectiveness (71111.12) .............................................................. 8
1R13  Maintenance Risk Assessments and Emergent Work Control (71111.13) ......... 9
1R15 Operability Determinations and Functional Assessments (71111.15) ................ 9
1R19 Post-Maintenance Testing (71111.19) ............................................................. 10
1R22 Surveillance Testing (71111.22) ....................................................................... 11
1EP6 Drill Evaluation (71114.06) ............................................................................... 12
2. RADIATION SAFETY ................................................................................................... 13
2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and Transportation (71124.08) .......................................................... 13
4. OTHER ACTIVITIES .................................................................................................... 18
4OA1 Performance Indicator Verification (71151) ...................................................... 18
4OA2 Identification and Resolution of Problems (71152) ........................................... 20
4OA3  Follow-Up of Events and Notices of Enforcement Discretion (71153) .............. 21
4OA6  Management Meetings ..................................................................................... 28
SUPPLEMENTAL INFORMATION ............................................................................................... 1
KEY POINTS OF CONTACT..................................................................................................... 1
LIST OF ITEMS OPENED, CLOSED AND DISCUSSED ......................................................... 2
LIST OF DOCUMENTS REVIEWED
......................................................................................... 3
LIST OF ACRONYMS USED .................................................................................................. 16
 
1 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 
2 Enclosure
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)
 
3 Enclosure
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 30. 1. REACTOR SAFETY Cornerstones:  Initiating Events, Mitigating Systems, and Barrier Integrity 1R01 Adverse Weather Protection (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. 
4 Enclosure
1R04 Equipment Alignment (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 parameter
s 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 
5 Enclosure
deficiencies significantly affected the system
function.  In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved.  Documents reviewed are listed in the
Attachment to this report. These activities constituted one complete system walkdown sample as defined in
IP 71111.04-05. b. Findings
No findings were identified. 1R05 Fire Protection (71111.05) .1 Routine Resident Inspector Tours (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. 
6 Enclosure
b. Findings
No findings were identified.
1R06 Flooding (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.   
7 Enclosure
This inspection activity constituted one underground vaults sample as defined in
IP 71111.06-05. b. Findings
No findings were identified. 1R11 Licensed Operator Requalification Program (71111.11) .1 Resident Inspector Quarterly Review of Licensed Operator Requalification (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 (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; 
8 Enclosure
* 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. 1R12 Maintenance Effectiveness (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. 
9 Enclosure
This inspection constituted three quarterly maintenance effectiveness samples as defined in IP 71111.12-05. b. Findings
No findings were identified. 1R13  Maintenance Risk Assessments and Emergent Work Control (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. 1R15 Operability Determinations and Functional Assessments (71111.15) .1 Operability Evaluations
a. Inspection Scope
The inspectors reviewed the following issues: 
10 Enclosure
* 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. 1R19 Post-Maintenance Testing (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 
11 Enclosure
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. 1R22 Surveillance Testing (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; 
12 Enclosure
* 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  1EP6 Drill Evaluation (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 
13 Enclosure
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. 2. RADIATION SAFETY Cornerstones:  Public Radiation Safety and Occupational Radiation Safety 2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and
Transportation (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. 
14 Enclosure
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." 
15 Enclosure
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.
 
16 Enclosure
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 Bulleti
n 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. 
17 Enclosure
.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.
 
18 Enclosure
4. OTHER ACTIVITIES Cornerstones:  Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection 4OA1 Performance Indicator Verification (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 Ju
ly 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. 
19 Enclosure
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 Ju
ly 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 Performanc
e 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. 
20 Enclosure
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. 4OA2 Identification and Resolution of Problems (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 
21 Enclosure
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. 4OA3  Follow-Up of Events and Notices of Enforcement Discretion (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. 
22 Enclosure
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 
23 Enclosure
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 probabili
ty 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. 
24 Enclosure
.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 
25 Enclosure
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 
26 Enclosure
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.
 
27 Enclosure
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 
28 Enclosure
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. 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 
 
1 Attachment
SUPPLEMENTAL INFORMATION KEY POINTS OF CONTACT
Licensee P. Karaba, Site Vice President  H. Vinyard, Plant Manager 
K. Hedgspeth, Radiation Protection Manager 
J. Washko, Engineering Manager 
G. Chavez, Dry Cask Storage Program Manager 
 
B. Maze, Project Management  M. Sharma, Engineering Programs  K. Hall, Buried Piping Program Owner 
V. Chopra, Engineering Programs 
J. Vergara, Regulatory Assurance 
 
L. Ekern, Nuclear Oversight 
B. Hilton, Design Manager  G. Ford, Regulatory Affairs Manager 
J. Houston, Nuclear Oversight Manager 
A. Schierer, Engineer 
D. Amezaga, System Engineer  J. Bendis, Engineer  J. Feeney, LaSalle Nuclear Oversight 
J. Hughes, Emergency Preparedness Coordinator 
J. Smith, Operations Training Manager 
L. Blunk, Regulatory Affairs 
J. Shields, Invessel Visual Inspection Program Supervisor  S. Shields, Regulatory Affairs  S. Tanton, Engineer 
T. Hapak, Chemistry 
C. Howard, Radiation Protection Operation Manager 
R. Simonsen, Radiation Protection Operation Manager  A. Baker, Dosimetry Specialist  A. Daniels, Exelon Emergency Preparedness Manager 
K. Rusley, Emergency Preparedness Manager 
S. Tutoky, Senior Chemist 
M. Martin, Chemistry Developmental Manager 
J. Mosher, Radiation Protection Manager S. Koval, Radwaste Shipping Specialist
Nuclear Regulatory Commission
M. Kunowski, Chief, Reactor Projects Branch 5 
2 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 05000374/2013-002-00 LER Manual Reactor Scram Following Trip of Circulating Water Pumps (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) 05000374/2012-001-00 LER 2B DG Declared Inoperable Due to Excessive Air Start Receiver Blowdown Caused by a Degraded Drain Valve
(Section 4OA3.3) 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)
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) 
3 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 Contro
l 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
 
4 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 Equi
pment 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 
5 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
 
6 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
 
7 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; 2
nd 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
 
8 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 
9 Attachment
Miscellaneous: - 3.3.1.1; RPS Instrumentation, Reactor Protection System Instrumentation; Amendment
147/133 - 3.3.4.1; EOC- RPT Instrumentation, End of Cy
cle 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 
10 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 Li
st, 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 
11 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
 
12 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:  2
nd Qtr PI Drills Facilities/Equipment Issues - 1554421; EP:  Facility & Equipment Issues 3
rd 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; 3
rd Qtr 2011 - 2
nd 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 
13 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 (M
SPI) 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 
14 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
 
15 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
 
16 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
 
17 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 th
e Publicly Available Records System (PARS) component of NRC's Agencywide Documents Access and Management Sy
stem (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 ListServ
TM  DISTRIBUTION
: See next page
 
 
See previous concurrence
DOCUMENT NAME:  LaSalle IR 2013004  Publicly Available  Non-Publicly Available 
Sensitive  Non-Sensitive To receive a copy of this document, indicate in the concurrence box "C" = Copy without attach/encl "E" = Copy with attach/encl "N" = No copy
  OFFICE  RIII    RIII  RIII 
RIII  NAME  MKunowski:rj JJandovitz for
  SOrth 1 PLougheed for
    DATE  11/15/13  11/15/13 
  1OE concurred on 11/7/13; NRR concurred on 11/12/13 OFFICIAL RECORD COPY
 
  Letter to Michael J. Pacilio from Kenneth G. O'Brien dated November 15, 2013
SUBJECT: LASALLE COUNTY STATION, UNITS 1 AND 2 NRC INTEGRATED INSPECTION REPORT 05000373/2013004; 05000374/2013004 AND UNIT 2 PRELIMINARY WHITE FINDING DISTRIBUTION
: Brett Rini
 
RidsNrrDorlLpl3-2 Resource 
RidsNrrPMLaSalle
 
RidsNrrDirsIrib Resource Cynthia Pederson
Anne Boland
Steven Orth
 
Allan Barker
 
Carole Ariano
Linda Linn DRPIII DRSIII
Patricia Buckley
Tammy Tomczak
ROPreports.Resource@nrc.gov
}}

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