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{{Adams
{{Adams
| number = ML13353A119
| number = ML13319B253
| issue date = 12/16/2013
| issue date = 11/15/2013
| title = Lasalle County Station Response to Preliminary White Finding From NRC Integrated Inspection Report 05000373-13-004, 05000374-13-004
| 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 = Karaba P J
| author name = O'Brien K
| author affiliation = Exelon Generation Co, LLC
| author affiliation = NRC/RGN-III/DRP
| addressee name =  
| addressee name = Pacilio M
| addressee affiliation = NRC/Document Control Desk, NRC/RGN-III
| addressee affiliation = Exelon Generation Co, LLC, Exelon Nuclear
| docket = 05000373, 05000374
| docket = 05000373, 05000374
| license number = NPF-011, NPF-018
| license number = NPF-011, NPF-018
| contact person =  
| contact person =  
| case reference number = EA-13-221, IR-13-004, RA-13-072
| case reference number = EA-13-221
| document type = Letter, Licensee Response to Notice of Violation
| document report number = IR-13-004
| page count = 12
| document type = Inspection Report, Letter
| page count = 52
}}
}}


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=Text=
=Text=
{{#Wiki_filter:RA1 3-072December 16, 2013U.S. Nuclear Regulatory CommissionATTN:Document Control DeskWashington, DC 20555-0001LaSalle County Station, Units 1 and 2Facility Operating License Nos. NPF-11 and NPF-18NRC Docket Nos. 50-373 and 50-374Subject:LaSalle County Station Response to Preliminary White Findingfrom NRC Integrated Inspection Report 05000373/2013004; 05000374/2013004References:1)Letter from K. G. O'Brien (U. S. Nuclear Regulatory Commission) to M. J.Pacilio (Exelon Generation Company,LLC), "LaSalleCounty Station, Units 1and 2, NRC Integrated Inspection Report 05000373/2013004;05000374/2013004and Unit 2 Preliminary White Finding," dated November15, 20132)Letter from P. J. Karaba (Exelon Generation Company, LLC) toM. J. Kunowski (U. S. Nuclear Regulatory Commission), "LaSalle CountyStation Response to Preliminary White Finding from NRC IntegratedInspection Report 05000373/2013004; 05000374/20130004," datedNovember 22, 2013In Reference 1, the NRC identified a preliminary White finding for the failure of LaSalle CountyStation personnel to follow procedureLOP-CW-10, "Dewatering the Circulating Water System,"Revision 32, on April 25, 2013. Specifically, operators performed the waterbox dewateringevolution in a manner inconsistent with procedural guidance by manually adjusting thecirculating water isolation valves while the waterbox manways were open. Adjustment of theinlet isolation valve caused a loss of isolation resulting in flooding of the condenser pit and aresultant circulating water pump trip, loss of the normal heat sink, and a manual reactor scram.Reference 1 provided Exelon Generation Company,LLC (EGC)an opportunity to present itsperspective on the facts and assumptions used by the NRC to arrive at the finding and itssignificance at either a Regulatory Conference or in a written response to the NRC. InReference 2, EGC notified the NRC of its intent to provide a written response on thesignificance level of the finding. The Enclosure to this letter provides EGC's perspective on thefacts and assumptions used by the NRC to arrive at the finding significance in a writtenrespons December 16, 2013U. S. Nuclear Regulatory CommissionPage 2EGC agrees that a finding existed for procedural non-compliance leading to a scram withcomplications due to the circulating water trip event that occurred on April 25, 2013. EGC hastaken actions to identify and correct the causes of the issue. EGC is requesting that thesignificance determination be re-evaluated based on the additional information enclosed in thisletter.EGC concludes that the subject finding is of very low safety significance (i.e., Green).There are no regulatory commitments contained within this letter. Should you have any questionsconcerning this letter, please contact Mr. Guy V. Ford, Jr., Regulatory Assurance Manager, at(815) 415-2800.Respectfully,Peter J. KarabaSite Vice PresidentLaSalle County Station
{{#Wiki_filter: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
 
==Dear Mr. Pacilio:==
On September 30, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your LaSalle County Station, Units 1 and 2. The enclosed report documents the inspection results which were discussed on Wednesday, October 2, 2013, with the Site Vice President, Mr. P. Karaba, and other members of your staff.
 
The enclosed inspection report discusses a finding on Unit 2 that has preliminarily been determined to be White, a finding with low-to-moderate safety significance, that may result in additional NRC inspection. As described in Section 4OA3 of this report, a self-revealed finding was identified for the failure of station personnel to follow procedure LOP-CW-10, Dewatering the Circulating Water System, Revision 32, on April 25, 2013. Specifically, operators performed the waterbox dewatering evolution in a manner inconsistent with procedural guidance by manually adjusting the circulating water isolation valves while the waterbox manways were open. Adjustment of the inlet isolation valve caused a loss of isolation resulting in flooding of the condenser pit and a resultant circulating water pump trip, loss of the normal heat sink, and a manual reactor scram. This finding was assessed based on the best available information, using the applicable Significance Determination Process (SDP).
 
The inspectors used Inspection Manual Chapter (IMC) 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1, dated June 19, 2012, for the Initiating Events cornerstone. Because the finding caused a reactor trip AND the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition, a detailed risk evaluation was required. The Senior Reactor Analysts (SRAs) used the LaSalle Standardized Plant Analysis Risk (SPAR) model to perform the detailed risk evaluation. In accordance with Risk Assessment of Operational Events Handbook guidance, the initiating event Loss of Condenser Heat Sink was set to 1.0 using the events and condition assessment module of the Systems Analysis Program for Hands-On Integrated Reliability Evaluations (SAPHIRE), Version 8. The calculated conditional core damage probability for the event was 1.6E-6, which represents a finding of low to moderate safety significance (White).
 
As described in NRC Inspection Manual Chapter 0612, Power Reactor Inspection Reports, dated January 24, 2013, a finding may or may not be associated with regulatory non-compliance and, therefore, may or may not result in a violation. Based on the review of this issue and in accordance with NRC Inspection Manual Chapter 0612, the NRC determined that no violation of a regulatory requirement occurred.
 
In accordance with NRC Inspection Manual Chapter 0609, we intend to complete our evaluation using the best available information and issue our final determination of safety significance within 90 days of the date of this letter. The significance determination process encourages an open dialogue between the NRC staff and the licensee; however, the dialogue should not impact the timeliness of the staffs final determination.
 
Before we make a final decision on this matter, we are providing you with an opportunity to (1) attend a Regulatory Conference where you can present to the NRC your perspective on the facts and assumptions the NRC used to arrive at the finding and assess its significance, or (2) submit your position on the finding to the NRC in writing. If you request a Regulatory Conference, it should be held within 30 days of the receipt of this letter and we encourage you to submit supporting documentation at least one week prior to the conference in an effort to make the conference more efficient and effective. The focus of the Regulatory Conference is to discuss the significance of the finding and not necessarily the root cause(s) or corrective action(s) associated with the finding. If a Regulatory Conference is held, it will be open for public observation. If you decide to submit only a written response, such submittal should be sent to the NRC within 30 days of your receipt of this letter. If you decline to request a Regulatory Conference or to submit a written response, you relinquish your right to appeal the final SDP determination, in that by not doing either, you fail to meet the appeal requirements stated in the Prerequisite and Limitation sections of Attachment 2 of NRC Inspection Manual Chapter 0609.
 
Please contact Michael Kunowski at (630) 829-9618 and in writing within 10 days from the issue date of this letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we will continue with our significance determination and enforcement decision.
 
The final resolution of this matter will be conveyed in a separate correspondence.
 
In addition to the finding discussed above, one self-identified violation of very low safety significance (Green) was identified during this inspection. This finding was determined to involve a violation of NRC requirements and the NRC is treating it as a non-cited violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy.
 
If you contest the violation or significance of the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U. S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, U. S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the LaSalle County Station. If you disagree with the cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at LaSalle County Station.
 
In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholdings, of the NRC's "Rules of Practice," a copy of this letter and its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records System (PARS)
component of NRC's Agencywide Documents Access and Management System (ADAMS).
 
ADAMS is accessible from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic Reading Room).
 
Sincerely,
/RA by Julio Lara for/
Kenneth G. OBrien, Acting Director Division of Reactor Projects Docket Nos. 50-373 and 50-374 License Nos. NPF-11 and NPF-18


===Enclosure:===
===Enclosure:===
Exelon Risk Assessment of LaSalle Unit 2 April 25, 2013 Scram Eventcc:NRC Document Control DeskNRC Regional Administrator - Region IIINRC Senior Resident Inspector - LaSalle County Station EnclosureEGC RiskAssessmentof LaSalle Unit 2 April 25, 2013 Loss of CW Event1.0Executive SummaryLaSalle County Station received a preliminary WHITE finding for procedural non-compliance leading to a scram with complications due to a loss of circulating water(CW) event that occurred on April 25, 2013. At the time of LaSalle's loss of CW event,both trains of residual heat removal were available to support the function of decay heatremoval. Both of these residual heat removal trains were available and providedadequate defense-in-depth, mitigating the event and protecting the health and safety ofthe public. In addition to the two preferred methods of decay heat removal, theemergency containment venting system, structure, or components (SSCs) wereavailable at the time of the event. There was no degradation of support systems forfrontline defenses, including essential service water, room cooling, instrument air andelectrical power. In accordance with plant processes, just prior to the conduct of theevolution, the operators obtained refresher training in the simulator on response actionsshould a loss of CW occur and were assigned detailed actions including the starting ofsuppression pool cooling for heat removal should it be necessary. The time available toperform the actions was substantial. The quantitative PRA analysis developed insupport of this event does not fully account for the specific plant configuration, thebriefings of all involved in the evolution, and time available to perform the actions.Clearly these qualitative attributes reduce the calculated risk for this event. Additionally,EGC's perspective is that the NRC methodology delineated in the Risk AssessmentStandardization Project (RASP) Handbook is overly conservative and may not provide arealistic evaluation of the event.Given the conservative use of PRA in assessing this event, EGC suggests use of ablended approach in line with the 1995 Policy Statement and Regulatory Guide (RG)1.174,AnApproach for Using Probabilistic Risk Assessment in Risk-Informed Decisionson Plant-Specific Changes to the Licensing Basis,to augment probabilistic results.When the qualitative aspects of the event are considered with the quantitative result,EGC concludes the subject performance deficiency is of very low safety significance(GREEN).1 2.0BackgroundOn April 25, 2013, a self-revealing event occurred and resulted in a loss of CW andmanual reactor scram. An NRC finding was identified with respect to the failure ofstation personnel to follow the procedure LOP-CW-1 0,Dewatering the Circulating WaterSystem,revision 32. This finding was assessed by the NRC using Inspection ManualChapter (IMC) 0609 Appendix A,The Significance Determination Process (SDP) forFindings At-Power forthe initiating events cornerstone. The NRC Senior ReactorAnalyst (SRA) used the LaSalle-specific Standardized Plant Analysis Risk (SPAR)model to perform a risk evaluation. In accordance with the RASP Handbook guidance,the initiating event "Loss of Condenser Heat Sink" was set to 1.0 in the SPAR model torepresent the event. The NRC SPAR model calculated a conditional core damageprobability (CCDP) of 1.6E-6, which represents a finding of low-to-moderate safetysignificance (WHITE) [1]. Using the same methodology, EGC calculated the CCDP as9.7E-7 using its site-specific PRA model [2].Since both calculated risk values (1.6E-6 and 9.7E-7) are close to the GREEN toWHITE threshold (1.OE-6), a close examination of the qualitative factors associated withrisk assessment is critical.3.0MethodologyThis EGC risk analysis used the initial risk assessment performed in accordance withthe RASP Handbook as a starting point. The risk results were reviewed in detail toensure an accurate representation of the risk significance of the event. This reviewrevealed that the PRA results were dominated by PRA model events that havesignificant uncertainty. Additionally, this review revealed that the calculationmethodology outlined in the RASP Handbook for event SDP analysis may produceoverly conservative results.Based on these two issues, it was concluded that a blended approach, using bothquantitative and qualitative insights, was the most appropriate method to determine thesignificance of the loss of CW event. The blended approach also examines the PRAmodel results, defense in depth, safety margin, event duration, and recovery capabilityto provide a balanced assessment of the actual risk of the event. Consideration ofthese inputs provides a balanced assessment that is risk-informed, rather than solelynumerically risk-base .0NRC Policy for PRA UsageThe NRC Policy Statement [3] on the expanded use of PRA advocates expansion ofprobabilistic methods in a manner that complements the NRC's deterministicapproaches and traditional defense-in-depth philosophy. Probabilistic risk assessmentis to be used where practical within the bounds of state-of-the-art PRA technology, andevaluations are to be as realistic as practicable.The concept of a blended approach is consistent with ideas stated in RG 1.174 [4],which, consistent with the integrated approaches laid out in the Policy Statement,stresses a decision-making process which evaluates defense-in-depth philosophy andmaintenance of sufficient safety margins alongside probabilistic methods. Furthermore,RG 1.174 prescribed quantitative risk metrics to be used as core damage frequency(CDF) and large early release frequency (LERF), and noted that risk impacts that arenot reflected (or inadequately reflected) by changes to CDF and LERF, should beaddressed [4]. The regulatory guide states that characterizing uncertainty is a strengthof probabilistic methods, and these uncertainties should be addressed in the decision-making process.RG 1.174 [4] states that the more emphasis that is put on risk insights and PRA resultsin the decision-making process, the more requirements have to be placed on the PRA interms of both scope and how well the risk and change in risk is assessed. Thus, it isrecognized that there are situations where probabilistic frameworks may not ideallycharacterize risk and should be augmented, as necessary, with qualitative informationto make a more complete decision.5.0PRA Model UncertaintyOf the sources of uncertainty identified in RG 1.174, only parameter and modeluncertainty are relevant to the evaluation of this event. Parameter uncertainty relates tothe variation in PRA input values, such as equipment failure rates, initiating eventfrequencies and human error probabilities. Model uncertainty is due to the industry'sincomplete state of knowledge and differing opinions on how models should beformulated. For the loss of CW event, the dominant PRA cutset results contain PRAbasic events with significant uncertainty. These events include: 1) human errorprobabilities related to operator actions and 2) phenomenological impact on emergencycore cooling system (ECCS) pumps following containment leak, rupture or venting.Phenomenological impacts are defined in the ANS/ASME PRA Standard [19] andinclude generation of harsh environments affecting temperature, pressure, debris, waterlevel, humidity, etc. that could impact the success of the system or function underconsideratio Both types of events in the dominant PRA cutset results have significant model andparameter uncertainty; and are applicable to the EGC and NRC SPAR models as theLaSalle model was used as the basis for the NRCSPARmodel. LaSalle PRA modeluncertainty was investigated for the 2011A PRAmodel in accordance with theASME/ANSPRA Standard and documentedin LS-PSA-013 [5],LaSalle PRA SummaryNotebook. Appendix B of that document highlights not only the uncertainty sourcesidentified in NUREG-1855 [6] such as operator actions, it also notes LaSalle-specificsources of uncertainty, and includes the use of the soft vent and loss of RPV makeupsources as a model uncertainty. Because both PRA models are built from similarassumptions, the uncertainties are similar.Therefore,consideration of qualitativeinsights should be applied to both EGC and NRC PRA model results.5.1Operator Action UncertaintyBoth NRC and EGC PRA model cutset results for this event indicate that operatoractions, including failures to initiate suppression pool cooling (SPC) or to vent primarycontainment, have a dominant impact on quantitative results for the loss of condenserscenarios. The RASP Handbook states that in the interest of consistency, a singlehuman failure event (HFE) probability of 1.0E-5 should be used. The RASP Handbookallows using a probability of 1.0E-6 with proper justification. Such justification mayinclude: 1) illustration that the action is well-practiced, 2) familiar with expansive time torespond, 3) has numerous indications of the need for action, 4) procedural guidanceand training that leads to monitoring of plant status to assess the efficacy of response,thus allowing opportunity for self-correction, and 5) low workload [7]. These factorswere satisfied relative to the key operator actions important to a loss of condenserevent.Further, other human reliability analysis (HRA) literature; specifically EPRI report, TR-1021081,Establishing Minimum Acceptable Values for Probabilities of Human FailureEvents,[8] provides justification for using lower probabilities for human failure events.The initiation of suppression pool cooling is an example used in the EPRI report wherea human error probability could even be considered negligible.The task to establish decay heat removal is well-established in procedural guidance,training, and experience of operating staff. Just prior to the event: 1) operators obtainedrefresher training in the simulator on scram response actions due to a loss of CW, 2)had pre-job briefs on scram response actions just prior to the evolution, and 3) haddetailed job assignments just prior to the scram including starting suppression poolcooling. These activities essentially made the potential failure to initiate SPC whenrequired a negligible contributor to the ris These event specific mitigating factors are not accounted for in the HRA methods;therefore, these factors have not been incorporated into the PRA numerical results.Given the uncertainty in base human error probability (HEP) values, EGC concludes it isappropriate to consider the qualitative mitigating factors that were applicable to thisevent; and overall these factors would lower the likelihood of operator failures and lowerthe actual risk significance of the event.5.2ECCS Pump Responses to Containment ConditionsThe PRA model includes the potential failure of ECCS pumps due to containmentconditions following a containment leak, rupture or venting [9, 10]. The probabilitiesassigned to this failure mode are considered a key source of uncertainty in the LaSallePRA model. In the base PRA model, the assumptions related to this failure mode arenot significant as the PRA results are not dominated by this failure mode. However, forthe loss of CW SDP evaluation, this failure mode is a key part of the accidentsequences. Failure probabilities were assigned based on the current state of PRAknowledge; however, significant uncertainty remains surrounding the probability ofECCS pump motor failure due to steam environment, ECCS pump suction binding dueto steam environment in the suppression pool, containment failure locations and reactorbuilding response to containment venting. Given the dominant nature of theseuncertain events, it is necessary to use qualitative insights regarding defense in depth toaugment the PRA model results.6.0RASP Handbook LimitationsThere is process uncertainty with respect to the RASP Handbook's basis for event SDPevaluations. A revision to the RASP Handbook was issued in early 2013 that modifiedthe process for event SDP evaluations. The industry is currently in discussions with theNRC to identify and resolve concerns with the new methodology presented in the RASPHandbook. These process concerns were discussed at a public meeting on November4, 2013 pertaining to potential non-realistic methods to calculate risk and for potentialmisalignment of the risk metrics [18]. Several of the key issues are outlined below.A significant issue identified is that the event SDP's methodology uses CCDP as themetrics as opposed to delta CDF.This isproblematic from both a programmaticstandpoint and a technical standpoint.From a NRC policy perspective, the use of CCDP appears to be in conflict with thebasis of the Reactor Oversight Process (ROP) in terms of the risk metrics used toassess event significance as delta CDF. There currently is no justification of the use ofCCDP in the SDP Basis documentation. The basis states that "there are currently noacceptance guidelines for CCDF or CCDP" [12]. Additionally, the use of CCDP isinconsistent with the risk metrics used in RG 1.17 From an ROP programmatic perspective, the use of CCDP for event based SDPscauses an inconsistency with all of the other PRA based ROP indicators. With thisinconsistency, the performance indicators (PI) results are no longer comparable to SDPevent analysis results. In other words, a WHITE PI finding is no longer equivalent to awhite event SDP in terms of risk significance.From a technical standpoint, the use of CCDP, given the RASP Handbookmethodology, does not provide for a realistic assessment of the risk of the actual event.The RASPHandbook methodology requires that the average maintenance PRA beused and the initiating event of interest be set to 1.0. This methodology accounts onlyfor the event that occurred and does not take into account any plant specificconfigurations, status of mitigating equipment, or other mitigating factors. Under thisapproach, all loss of condenser events would be assessed the same color regardless ofthe plant configuration, operator response and equipment failures.One option identified during the NRC public meeting on November 4, 2013 was to applyqualitative insights to event SDPs to ensure an accurate risk assessment. This is theapproach taken in this risk assessment. It is concluded that probabilistic methodologyalone should not be the only tool used to assess event related SDPs until the identifiedissues are resolved.7.0Integrated Decision-making AnalysisIn the interest of performing an integrated approach which utilizes qualitative as well asquantitative input, the attributes of defense-in-depth, safety margin, extent of condition,degree of degraded program, exposure time, recovery actions and other factors areconsidered below.7.1Defense-in-DepthAt the time of LaSalle's loss of CW event, both trains of residual heat removal wereavailable to support the function of decay heat removal. Both of these residual heatremoval trains were available and provided adequate defense-in-depth, mitigating theevent and protecting the health and safety of the public. In addition to the two preferredmethods of decay heat removal, the emergency containment venting system, structure,or components (SSCs) were available at the time of the event. There was nodegradation of support systems for frontline defenses, including essential service water,room cooling, instrument air and electrical power. Each defensive layer functionedproperly when exercised during the event. In addition, the reactor core isolation cooling(RCIC) system was "protected equipment" per the requirements of LOP-CW-1 0, whichmeant that no maintenance or work was allowed on RCIC during this evolution. RCICwas available to support transient response immediately following the even The only decay heat removal function impacted during this event was the availability ofthe main condenser, a non-safety related SSC. All safety related equipment remainedavailable. There remained redundant and diverse strategies to remove decay heatfollowing a loss of the main condenser. A loss of CW event is within the station's designbasis. It is specifically addressed as an event of moderate frequency within LaSalle'sUpdated Final Safety Analysis Report (UFSAR) [15].There is limited dependence on operator actions outside of expected activities such asmonitoring normal reactor shutdown, verifying incoming transfer to the power bus,monitoring water level in the vessel, observing coastdown, initiating essential cooling,and monitoring vessel pressure. The intent of the station's design and system responsewas maintained.7.2Safety MarginSafety margin was not impacted by the event. All safety-related equipment remainedavailable.Codes and standards were unaffected by the performance deficiency; so,safety margin was not impacted. Entry into operating procedureLOP-CW-10requiredpower level restrictions, which provided further safety margin to the applicable decayheat removal systems. Additional margin is provided in the procedure by ensuring nohalf-scram testing or containment isolation testing is performed. The procedure alsoensures no other activities, which has a risk of causing a scram, are performedconcurrentwith LOP-CW-10.7.3Extent of ConditionA causal investigation was performed that determined the root cause of the event wasunverified assumptions used in lieu of strict procedural adherence [16]. The unverifiedassumption involved the mind-set of the operators that manual seating of the condenserwater box isolation valves to obtain a better seal was not considered troubleshooting.The troubleshooting section of LOP-CW-1 0 required the manways to be closed to makemanual valve adjustments. The extent of condition review conducted in theinvestigation did not reveal procedural non-compliance to be a pervasive problem.Corrective actions were targeted at reinforcing expectations for strict procedurecompliance with operators, along with coaching to the specific individuals involved in theevent. The root cause did not identify any issues that would indicate an overall increasein risk exposure due to the causes identifie .4Degree of Degraded ProgramThe event occurrence was due to human error, reflecting procedural non-compliance onan infrequently performed evolution. This was a random error rather than systemicdegradation or programmatic weaknesses. The root cause investigation did not revealany specific programmatic breakdowns that required corrective actions. Correctiveactions focused on improved awareness and use of human performance tools andfundamentals. No issues were identified that would indicate an overall increase in riskexposure due to degraded programs.7.5Exposure TimeThe operator performance deficiency regarding strict procedure compliance was anisolated event that cannot easily be assigned an exposure time. This performancedeficiency occurred during an infrequently performed evolution. This evolution hadbeen performed two times in the last five years.7.6Recovery ActionsSubstantial time was available in a loss of CW event for recovery of systems orimplementation of corrective operator actions, in the event of additional failures. PRAthermal hydraulic calculations demonstrated that core damage is precluded as long asdecay heat is recovered within approximately 15 hours [17].In addition, more time was actually available due to the power level being limited for theonline dewatering evolution. The evolution was performed at approximately 640 MWe(56% rated thermal power). Having substantial response time meant that the MainControl Room would have significant personnel support outside of the control room,more time to properly diagnose the problem, and significant time to implement anyneeded repairs to decay heat removal systems or restart the circulating water systemand recover the main condenser.8.0Qualitative Risk Assessment ConclusionThis risk assessment examined the loss of CW event in detail including the numericalresults obtained using the current RASP Handbook methodology. The numericalresults from the NRC's SPAR model were 1.6E-06 slightly over the SDP green-whitethreshold of 1.0E-06, while the EGC model results were 9.7E-07 and slightly under theSPD green-white threshol Given the natureof PRAnumerical analysis and the principles outlinedin RG 1.174, theresults frombothmodels(EGC and NRC)were reviewed to assess the following:PRA model uncertainty as it relates to key model results, andRASP Handbook methodology for event SDP.The goal of this review was to ensure the model results when compared to the actualevent, represented an accurate representation of the risk.In summary, the review identified that the PRA results were dominated by events withsignificant uncertainty.Given the PRA model uncertainty, it was concluded that theprinciples in RG 1.174 for an integrated approach should be applied to determine therisk significance of the event. Additionally, the new revision of the RASP Handbookintroduced a new PRA calculation methodology for event based SDPs resulting inindustry concerns and questions. A method of resolving the concerns for this particularSDP is to consider qualitative insights in addition to the quantitative results.The qualitative insights demonstrate that this particular loss of CW event involved lowerhuman error probabilities than standard HRA calculations would indicate, due to thepreparation, training, and execution of response actions by Operations. Also,preparations for the CW evolution ensured availability of risk-significant equipmentwhich preserved defense-in-depth and safety margins. A loss of condenser event,similar to the event that occurred, is an event in the UFSAR that is documented to occurwith a moderate frequency. This event had no extenuating circumstances that wouldcause result in an increase in risk. All safety related equipment remained operable tomitigate and respond to the event. This event impacted only non-safety relatedequipment.For the above reasons, using a blended approach of risk insights supplemented byqualitative insights, EGC asserts that the safety significance of this performancedeficiency is of very low risk significance (GREEN).9.0References1.O'Brien, K.G., LaSalle County Station, Units 1 and 2 NRC Integrated InspectionReport 05000373/2013004; 05000374/2013004 and Unit 2 Preliminary WhiteFinding, November 2013.2.Mearhoff, D. and Addis, H., LS-SDP-03,Risk Significance of Procedural Non-Compliance Leading to a SCRAM with Complications,Revision 1, 2013.3.60 FR 42622,Use of Probabilistic Risk Assessment Methods in NuclearActivities: Final Policy Statement,Federal Register, Volume 60, Number 158, p.42622, August 1995.4.Regulatory Guide 1.174,An Approach for Using Probabilistic Risk Assessment inRisk-Informed Decisions on Plant-Specific Changes to the Licensing Basis,Revision 2, Office of Nuclear Regulatory Research, May 200 .Addis, H.J. and Burns, E.T., LS-PSA-013,LaSalle PSA Summary Notebook,Revision 7,March 2013.6.Guidance on the Treatment of Uncertainties Associated with PRAs in Risk-Informed Decision Making,NUREG-1 855, Volume 1, March 2009.7.Risk Assessment of Operational Events,Volume 1 - Internal Events, Revision 2,January 2013.8.Parry, G.,Establishing Minimum Acceptable Values for Probabilities of HumanFailure Events,1021081, EPRI, October 2010.9.NUREG/CR-4832 Volume 3 Pt.1,Analysis of the LaSalle Unit 2 Nuclear PowerPlant - Internal Events Accident Sequence Quantification,Sandia NationalLaboratories, August 1992.10.Addis, H.J. and Burns, E.T., LS-PSA-002,LaSalle PSA Event Tree Notebook,Revision 7, February 2013.11.Reactor Oversight Process (ROP) Basis Document,NRC Inspection Manual,IMC 0308, November 2007.12.Significance Determination Process Basis Document,NRC Inspection Manual,IMC 0308 Att. 3, October 2006.13.Technical Basis for Performance Indicators,NRC Inspection Manual, IMC 0308Att. 1, November 2007.14.Travers, W. D.,Recommendations for Reactor Oversight Process Improvements,SECY-99-007, January 1999.15.Decrease in Heat Removal by the Secondary System, LSCS UFSAR Section15.2.5, Revision 19, April 2012.16.Myers et al.,Trip of Running CW Pumps and Unit 2 Manual SCRAM due toProcedure Adherence when Isolating a Main Water Condenser Waterbox,RootCause Investigation, July 2013.17.Addis, H.J., and Andersen, V.M,LaSalle PSA Human Reliability AnalysisNotebook,Revision 7, January 2013.18.Summary of the Public Meeting to Discuss Staff Guidance Used to Estimate theSafety Significance of Inspection Findings that Cause Initiating EventOccurrences, dated December 2, 201319.ASME/American Nuclear Society,Standard for Level 1/Large Early ReleaseFrequency Probabilistic Risk Assessment for Nuclear Power Plant Applications,ASME/ANS RA-Sa-2009, March 2009.10
Inspection Report 05000373/2013004; 05000374/2013004 w/Attachment: Supplemental Information
 
REGION III==
Docket Nos: 05000373; 05000374 License Nos: NPF-11; NPF-18 Report No: 05000373/2013004; 05000374/2013004 Licensee: Exelon Generation Company, LLC Facility: LaSalle County Station, Units 1 and 2 Location: Marseilles, IL Dates: July 1, 2013 - September 30, 2013 Inspectors: R. Ruiz, Senior Resident Inspector M. Ziolkowski, Acting Resident Inspector K. Carrington, Acting Resident Inspector G. Roach, Senior Resident Inspector, Dresden D. Chyu, Region III Reactor Engineer I. Hafeez, Region III Reactor Inspector C. Phillips, Project Engineer T. Go, Health Physicist Approved by: M. Kunowski, Chief Branch 5 Division of Reactor Projects Enclosure
 
=SUMMARY OF FINDINGS=
Inspection Report (IR) 05000373/2013004, 05000374/2013004; 07/01/2013-09/30/2013;
 
LaSalle County Station, Units 1 & 2; Followup of Events and Notices of Enforcement Discretion.
 
This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Two findings were identified during the inspection.
 
One finding was preliminarily determined to be White and one finding was determined to be a Green non-cited violation (NCV). The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using IMC 0609,
Significance Determination Process dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within the Cross Cutting Areas dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs 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.
 
===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 licensees 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 licensees failure to follow the prescribed steps of procedure LOP-CW-10 was a performance deficiency warranting a significance determination. The inspectors used Inspection Manual Chapter (IMC) 0609,
Appendix A, The Significance Determination Process (SDP) for Findings At-Power,
Exhibit 1, dated June 19, 2012, for the Initiating Events cornerstone. Because the finding caused a reactor trip AND the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition, a detailed risk evaluation was required. The Senior Reactor Analysts (SRAs) used the LaSalle Standardized Plant Analysis Risk (SPAR) model to perform the detailed risk evaluation.
 
In accordance with Risk Assessment of Operational Events Handbook guidance, the initiating event Loss of Condenser Heat Sink was set to 1.0 using the events and condition assessment module of the Systems Analysis Program for Hands-On Integrated Reliability Evaluations (SAPHIRE), Version 8. The calculated conditional core damage probability for the event was 1.6E-6, which represents a finding of low-to-moderate safety significance (White). The finding had a cross-cutting aspect in the area of human performance, decision-making, because the licensee failed to use conservative assumptions when planning and executing the dewatering evolution. Specifically, the incorrect assumption that this evolution performed at-power could be treated the same as when performed during a shutdown condition enabled operators to stray from strict procedure adherence and into knowledge space (H.1(b)). (Section 4OA3)
 
===Cornerstone: Mitigating Systems and Barrier Integrity===
* Green: A self-revealed finding of very low safety significance and associated non-cited violation of Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the failure to have procedures adequate for the circumstances during long-term operation of the high pressure core spray (HPCS)system on minimum flow. Specifically, three small holes developed in the Unit 2 HPCS minimum flow line elbow due to cavitation and other flow-related wear caused by inconsistent procedural guidance regarding operation in the minimum-flow mode.
 
The licensee promptly repaired the system leak and entered the issue into its CAP as ARs 1503825 and 1530682, which included the performance of an apparent cause evaluation. Further corrective actions included the revision of the affected procedures.
 
The finding was determined to be more than minor because it was associated with the Mitigating Systems and Barrier Integrity cornerstone attributes of Procedure Quality and adversely affected the cornerstone objectives of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the procedural guidance given to operate the HPCS system was inadequate to prevent long-term operation of the system in the minimum flow mode of operation, which led to cavitation and flow-induced wear, causing the failure of the Unit 2 HPCS minimum flow line and inoperability of the HPCS system as well as the primary containment boundary.
 
The inspectors determined that the finding could be evaluated in accordance with IMC 0609, Appendix A, The Significance Determination for Findings At-Power, and Appendix H, Containment Integrity Significance Determination Process. Further, it was determined that a phase two risk assessment was necessary because the finding impacted suppression pool integrity, and through that process, this issue screened as
: '''Green.'''
The inspectors did not identify a cross-cutting aspect associated with this finding. (Section 4OA3)
 
=REPORT DETAILS=
 
===Summary of Plant Status===
 
Unit 1 The unit began the inspection period operating at full power. On September 7, 2013, power was reduced to approximately 65 percent for a control rod sequence exchange and scram time testing. Unit 1 was restored to full power on September 8.
 
Unit 2 The unit began the inspection period operating at full power. On August 31, 2013, power was reduced to approximately 65 percent for a control rod sequence exchange and scram time testing. Unit 2 was restored to full power on September 1. Additionally, on September 27, power was reduced to approximately 60 percent for power suppression testing to identify a leaking fuel element. Upon the successful completion of that evolution, Unit 2 was restored to approximately full power on September
 
==REACTOR SAFETY==
Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity {{a|1R01}}
==1R01 Adverse Weather Protection==
{{IP sample|IP=IP 71111.01}}
===.1 Summer Seasonal Readiness Preparations===
 
====a. Inspection Scope====
The inspectors reviewed the licensees preparations for summer weather for selected systems, including conditions that could lead to an extended drought.
 
During the inspection, the inspectors focused on plant specific design features and the licensees procedures used to mitigate or respond to adverse weather conditions.
 
Additionally, the inspectors reviewed the UFSAR and performance requirements for systems selected for inspection, and verified that operator actions were appropriate as specified by plant specific procedures. The inspectors also reviewed CAP items to verify that the licensee was identifying adverse weather issues at an appropriate threshold and entering them into its CAP in accordance with station CAP procedures. The inspectors reviews focused specifically on the ultimate heat sink and core standby cooling system (CSCS). Documents reviewed are listed in the Attachment to this report.
 
This inspection constituted one seasonal adverse weather sample as defined in Inspection Procedure (IP) 71111.01-05.
 
====b. Findings====
No findings were identified. {{a|1R04}}
==1R04 Equipment Alignment==
{{IP sample|IP=IP 71111.04}}
===.1 Quarterly Partial System Walkdowns===
 
====a. Inspection Scope====
The inspectors performed partial system walkdowns of the following risk-significant systems:
* Unit 1 'A' diesel generator (DG) walkdown following 1 'B' DG idle start;
* Unit 1 standby gas treatment system;
* Unit 1 'A' standby liquid control system; and
* Unit 1 reactor core isolation cooling (RCIC).
 
The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, UFSAR, Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the 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 licensees probabilistic risk assessment.
 
The inspectors walked down the system to review mechanical and electrical equipment lineups; electrical power availability; system pressure and temperature indications, as appropriate; component labeling; component lubrication; component and equipment cooling; hangers and supports; operability of support systems; and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the to this report.
 
These activities constituted one complete system walkdown sample as defined in IP 71111.04-05.
 
====b. Findings====
No findings were identified. {{a|1R05}}
==1R05 Fire Protection==
{{IP sample|IP=IP 71111.05}}
===.1 Routine Resident Inspector Tours===
{{IP sample|IP=IP 71111.05Q}}
 
====a. Inspection Scope====
The inspectors conducted fire protection walkdowns which were focused on availability, accessibility, and the condition of firefighting equipment in the following risk-significant plant areas:
* fire zone 2I4 U1 low pressure core spray (LPCS)/RCIC room;
* fire zone 8C4 Unit 2 Division II residual heat removal system southwest corner room;
* Unit 1 Division 1 essential switchgear room 4F1;
* Unit 1 Division II DG room 7B2; and
* Unit 2 Division II DG room 8B2.
 
The inspectors reviewed areas to assess if the licensee had implemented a fire protection program that adequately controlled combustibles and ignition sources within the plant, effectively maintained fire detection and suppression capability, maintained passive fire protection features in good material condition, and implemented adequate compensatory measures for out-of-service, degraded, or inoperable fire protection equipment, systems, or features in accordance with the licensees fire plan.
 
The inspectors selected fire areas based on their overall contribution to internal fire risk as documented in the plants Individual Plant Examination of External Events with later additional insights, their potential to impact equipment which could initiate or mitigate a plant transient, or their impact on the plants ability to respond to a security event.
 
Using the documents listed in the Attachment to this report, the inspectors verified that fire hoses and extinguishers were in their designated locations and available for immediate use; that fire detectors and sprinklers were unobstructed; that transient material loading was within the analyzed limits; and fire doors, dampers, and penetration seals appeared to be in satisfactory condition. The inspectors also verified that minor issues identified during the inspection were entered into the licensees CAP.
 
Documents reviewed are listed in the Attachment to this report.
 
These activities constituted five quarterly fire protection inspection samples as defined in IP 71111.05-05.
 
====b. Findings====
No findings were identified. {{a|1R06}}
==1R06 Flooding==
{{IP sample|IP=IP 71111.06}}
===.1 Internal Flooding===
 
====a. Inspection Scope====
The inspectors reviewed selected risk-important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the UFSAR, engineering calculations, and abnormal operating procedures, to identify licensee commitments. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the fire suppression or the circulating water systems. The inspectors also reviewed the licensees CAP documents with respect to past flood-related items identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the 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 licensees CAP documents with respect to past submerged cable issues identified in the CAP program to verify the adequacy of the corrective actions. The inspectors performed a walkdown of manholes 1 through 6, which are subject to flooding.
 
Documents reviewed are listed in the Attachment to this report.
 
This inspection activity constituted one underground vaults sample as defined in IP 71111.06-05.
 
====b. Findings====
No findings were identified. {{a|1R11}}
==1R11 Licensed Operator Requalification Program==
{{IP sample|IP=IP 71111.11}}
===.1 Resident Inspector Quarterly Review of Licensed Operator Requalification===
{{IP sample|IP=IP 71111.11Q}}
 
====a. Inspection Scope====
On August 8, 2013, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:
* licensed operator performance;
* crews clarity and formality of communications;
* ability to take timely actions in the conservative direction;
* prioritization, interpretation, and verification of annunciator alarms;
* correct use and implementation of abnormal and emergency procedures;
* control board manipulations;
* oversight and direction from supervisors; and
* ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.
 
The crews performance in these areas was compared to pre-established operator action expectations and successful critical task completion requirements. Documents reviewed are listed in the Attachment to this report.
 
This inspection constituted one quarterly licensed operator requalification program simulator sample as defined in IP 71111.11.
 
====b. Findings====
No findings were identified.
 
===.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk===
{{IP sample|IP=IP 71111.11Q}}
 
====a. Inspection Scope====
On September 4, 2013, the inspectors observed control room operators during the performance of the secondary containment leak rate test. This was an activity that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas:
* licensed operator performance;
* crews clarity and formality of communications;
* ability to take timely actions in the conservative direction;
* prioritization, interpretation, and verification of annunciator alarms (if applicable);
* correct use and implementation of procedures;
* control board (or equipment) manipulations;
* oversight and direction from supervisors; and
* ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications (if applicable).
 
The performance in these areas was compared to pre-established operator action expectations, procedural compliance and task completion requirements. Documents reviewed are listed in the Attachment to this report.
 
This inspection constituted one quarterly licensed operator heightened activity/risk sample as defined in IP 71111.11.
 
====b. Findings====
No findings were identified. {{a|1R12}}
==1R12 Maintenance Effectiveness==
{{IP sample|IP=IP 71111.12}}
===.1 Routine Quarterly Evaluations===
 
====a. Inspection Scope====
The inspectors evaluated degraded performance issues involving the following risk-significant systems:
* Unit Common B diesel fire pump following a failure to start;
* Unit 1 circulating water system; and
* Unit 2 circulating water system.
 
The inspectors reviewed events, such as where ineffective equipment maintenance had resulted in valid or invalid automatic actuations of engineered safeguards systems, and independently verified the licensee's actions to address system performance or condition problems in terms of the following:
* implementing appropriate work practices;
* identifying and addressing common cause failures;
* scoping of systems in accordance with 10 CFR 50.65(b) of the maintenance rule;
* characterizing system reliability issues for performance;
* charging unavailability for performance;
* trending key parameters for condition monitoring;
* ensuring 10 CFR 50.65(a)(1) or (a)(2) classification or re-classification; and
* verifying appropriate performance criteria for systems, structures, and components /functions classified as (a)(2), or appropriate and adequate goals and corrective actions for systems classified as (a)(1).
 
The inspectors assessed performance issues with respect to the reliability, availability, and condition monitoring of the system. In addition, the inspectors verified maintenance effectiveness issues were entered into the CAP with the appropriate significance characterization. Documents reviewed are listed in the Attachment to this report.
 
This inspection constituted three quarterly maintenance effectiveness samples as defined in IP 71111.12-05.
 
====b. Findings====
No findings were identified. {{a|1R13}}
==1R13 Maintenance Risk Assessments and Emergent Work Control==
{{IP sample|IP=IP 71111.13}}
===.1 Maintenance Risk Assessments and Emergent Work Control===
 
====a. Inspection Scope====
The inspectors reviewed the licensee's evaluation and management of plant risk for the maintenance and emergent work activities affecting risk-significant and safety-related equipment listed below to verify that the appropriate risk assessments were performed prior to removing equipment for work:
* failed fuel inspection;
* 345-kiloVolt (kV) lightning strike on line 0104;
* automatic start of 1 'A' DG cooling water pump results in extended yellow risk condition;
* yellow risk condition for Unit 1 standby gas treatment work; and
* Unit 2 downpower for power suppression testing.
 
These activities were selected based on their potential risk significance relative to the Reactor Safety Cornerstones. As applicable for each activity, the inspectors verified that risk assessments were performed as required by 10 CFR 50.65(a)(4) and were accurate and complete. When emergent work was performed, the inspectors verified that the plant risk was promptly reassessed and managed. The inspectors reviewed the scope of maintenance work, discussed the results of the assessment with the licensee's probabilistic risk analyst or shift technical advisor, and verified plant conditions were consistent with the risk assessment. The inspectors also reviewed TS requirements and walked down portions of redundant safety systems, when applicable, to verify risk analysis assumptions were valid and applicable requirements were met. Documents reviewed are listed in the Attachment to this report.
 
These maintenance risk assessments and emergent work control activities constituted five samples as defined in IP 71111.13-05.
 
====b. Findings====
No findings were identified. {{a|1R15}}
==1R15 Operability Determinations and Functional Assessments==
{{IP sample|IP=IP 71111.15}}
===.1 Operability Evaluations===
 
====a. Inspection Scope====
The inspectors reviewed the following issues:
* Unit Common 'B' control room ventilation charcoal filters potentially impacted by Freon leak;
* Unit 2 high drywell temperatures;
* AR 01476770 Operability Evaluation (Op Eval) 04-006 may be non-conservative;
* General Electric-Hitachi Part 21 issued for reactor protection system electrically monitored protective assemblies in molded case circuit breakers; and
* Unit 1 #1 turbine stop valve.
 
The inspectors selected these potential operability issues based on the risk significance of the associated components and systems. The inspectors evaluated the technical adequacy of the evaluations to ensure that TS operability was properly justified and the subject component or system remained available such that no unrecognized increase in risk occurred. The inspectors compared the operability and design criteria in the appropriate sections of the TS and UFSAR to the licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of CAP documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the Attachment to this report.
 
This operability inspection constituted five samples as defined in IP 71111.15-05.
 
====b. Findings====
No findings were identified. {{a|1R19}}
==1R19 Post-Maintenance Testing==
{{IP sample|IP=IP 71111.19}}
===.1 Post-Maintenance Testing===
 
====a. Inspection Scope====
The inspectors reviewed the following post-maintenance testing (PMT) activities to verify that procedures and test activities were adequate to ensure system operability and functional capability:
* Unit Common 'A' auxiliary electrical equipment room ventilation train following compressor replacement;
* Unit 2 standby gas treatment;
* Unit 1 1B standby liquid control;
* Unit 1 'C' residual heat removal (RHR) breaker preventive maintenance;
* Unit 1 RCIC high steam line flow instrumentation replacement;
* Unit 2 hydraulic control unit 38-43; and
* Unit 1 'A' DG following preventive and corrective maintenance.
 
These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):
the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed CAP documents associated with PMT to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.
 
This inspection constituted seven PMT samples as defined in IP 71111.19-05.
 
====b. Findings====
No findings were identified. {{a|1R22}}
==1R22 Surveillance Testing==
{{IP sample|IP=IP 71111.22}}
===.1 Surveillance Testing===
 
====a. Inspection Scope====
The inspectors reviewed the test results for the following activities to determine whether risk-significant systems and equipment were capable of performing their intended safety function and to verify testing was conducted in accordance with applicable procedural and TS requirements:
* LIS-NR-303A/B average power range monitor (APRM) functional surveillance (Routine);
* Unit 1 Division II 125-Vdc (Volts direct current) battery surveillance (Routine);
* Unit 2 RHR quarterly surveillance (LOS-RH-Q1) (Routine); and
* Unit 2 'B' DG cooling water pump (Inservice Testing--IST).
 
The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:
* did preconditioning occur;
* the effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing;
* acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis;
* plant equipment calibration was correct, accurate, and properly documented;
* as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the UFSAR, procedures, and applicable commitments;
* measuring and test equipment calibration was current;
* test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied;
* test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;
* test data and results were accurate, complete, within limits, and valid;
* test equipment was removed after testing;
* where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers code, and reference values were consistent with the system design basis;
* where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;
* where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure;
* where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;
* prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;
* equipment was returned to a position or status required to support the performance of its safety functions; and
* all problems identified during the testing were appropriately documented and dispositioned in the CAP.
 
Documents reviewed are listed in the Attachment to this report.
 
This inspection constituted three routine surveillance testing samples and one inservice testing sample as defined in IP 71111.22, Sections -02 and -05.
 
====b. Findings====
No findings were identified.
 
===Cornerstone: Emergency Preparedness===
{{a|1EP6}}
==1EP6 Drill Evaluation==
{{IP sample|IP=IP 71114.06}}
===.1 Emergency Preparedness Drill Observation===
 
====a. Inspection Scope====
The inspectors evaluated the conduct of a routine licensee emergency drill on July 16, 2013, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator, technical support center and operational support center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures.
 
The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the CAP. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report.
 
This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-05.
 
====b. Findings====
No findings were identified.
 
===.2 Training Observation===
 
====a. Inspection Scope====
The inspector observed simulator training evolutions for licensed operators on August 6 and September 17, 2013, which required emergency plan implementations by a licensee operations crew. These evolutions were planned to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post-evolution critiques for the scenarios. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews 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 licensees training evolutions with emergency preparedness drill aspects constituted two samples as defined in IP 71114.06-06.
 
====b. Findings====
No findings were identified.
 
==RADIATION SAFETY==
Cornerstones: Public Radiation Safety and Occupational Radiation Safety {{a|2RS8}}
==2RS8 Radioactive Solid Waste Processing and Radioactive Material Handling, Storage, and==
 
Transportation (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 licensees performance and inform the smart sampling inspection planning.
 
====b. Findings====
No findings were identified.
 
===.2 Radioactive Material Storage (02.02)===
 
====a. Inspection Scope====
The inspectors selected areas where containers of radioactive waste are stored and evaluated whether the containers were labeled in accordance with 10 CFR 20.1904, Labeling Containers, or controlled in accordance with 10 CFR 20.1905, Exemptions to Labeling Requirements, as appropriate.
 
The inspectors assessed whether the radioactive material storage areas were controlled and posted in accordance with the requirements of 10 CFR Part 20, Standards for Protection Against Radiation. For materials stored or used in the controlled or unrestricted areas, the inspectors evaluated whether they were secured against unauthorized removal and controlled in accordance with 10 CFR 20.1801, Security of Stored Material, and 10 CFR 20.1802, Control of Material Not in Storage, as appropriate.
 
The inspectors assessed whether the licensee established a process for monitoring the impact of long-term storage (e.g., buildup of any gases produced by waste decomposition, chemical reactions, container deformation, loss of container integrity, or re-release of free-flowing water) that was sufficient to identify potential unmonitored, unplanned releases or non-conformance with waste disposal requirements.
 
The inspectors selected containers of stored radioactive material, and assessed for signs of swelling, leakage, and deformation.
 
====b. Findings====
No findings were identified.
 
===.3 Radioactive Waste System Walkdown (02.03)===
 
====a. Inspection Scope====
The inspectors walked down accessible portions of select radioactive waste processing systems to assess whether the current system configuration and operation agreed with the descriptions in the UFSARt, Offsite Dose Calculation Manual, and Process Control Program.
 
The inspectors reviewed administrative and/or physical controls (i.e., drainage and isolation of the system from other systems) to assess whether the equipment that was not in service or was abandoned in place would not contribute to an unmonitored release path and/or affect operating systems or be a source of unnecessary personnel exposure.
 
The inspectors assessed whether the licensee reviewed the safety significance of systems and equipment abandoned in place in accordance with 10 CFR 50.59, Changes, Tests, and Experiments.
 
The inspectors reviewed the adequacy of changes made to the radioactive waste processing systems since the last inspection. The inspectors evaluated whether changes from what is described in the UFSAR were reviewed and documented in accordance with 10 CFR 50.59, as appropriate, and to assess the impact on radiation doses to members of the public.
 
The inspectors selected processes for transferring radioactive waste resin and/or sludge discharges into shipping/disposal containers and assessed whether the waste stream mixing, sampling procedures, and methodology for waste concentration averaging were consistent with the Process Control Program, and provided representative samples of the waste product for the purposes of waste classification as described in 10 CFR 61.55, Waste Classification.
 
For those systems that provide tank recirculation, the inspectors evaluated whether the tank recirculation procedures provided sufficient mixing.
 
The inspectors assessed whether the licensees 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 licensees 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 licensees use of scaling factors and calculations to account for difficult-to-measure radionuclides was technically sound and based on current 10 CFR Part 61 analyses for the selected radioactive waste streams.
 
The inspectors evaluated whether changes to plant operational parameters were taken into account to:
: (1) maintain the validity of the waste stream composition data between the annual or biennial sample analysis update; and
: (2) assure that waste shipments continued to meet the requirements of 10 CFR Part 61 for the waste streams selected above.
 
The inspectors evaluated whether the licensee had established and maintained an adequate Quality Assurance Program to ensure compliance with the waste classification and characterization requirements of 10 CFR 61.55, Waste Classification, and 10 CFR 61.56, Waste Characteristics.
 
====b. Findings====
No findings were identified.
 
===.5 Shipment Preparation (02.05)===
 
====a. Inspection Scope====
The inspectors observed shipment packaging, surveying, labeling, marking, placarding, vehicle checks, emergency instructions, disposal manifest, shipping papers provided to the driver, and licensee verification of shipment readiness. The inspectors assessed whether the requirements of applicable transport cask certificate of compliance had been met. The inspectors evaluated whether the receiving licensee was authorized to receive the shipment packages. The inspectors evaluated whether the licensees procedures for cask loading and closure procedures were consistent with the vendors 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 licensees response to NRC Bulletin 79-19, Packaging of Low-Level Radioactive Waste for Transport and Burial, dated August 10, 1979; and
* Title 49 CFR Part 172, Hazardous Materials Table, Special Provisions, Hazardous Materials Communication, Emergency Response Information, Training Requirements, and Security Plans, Subpart H, Training.
 
Due to limited opportunities for direct observation, the inspectors reviewed the technical instructions presented to workers during routine training. The inspectors assessed whether the licensees training program provided training to personnel responsible for the conduct of radioactive waste processing and radioactive material shipment preparation activities.
 
====b. Findings====
No findings were identified.
 
===.6 Shipping Records (02.06)===
 
====a. Inspection Scope====
The inspectors evaluated whether the shipping documents indicated the proper shipper name; emergency response information and a 24-hour contact telephone number; accurate curie content and volume of material; and appropriate waste classification, transport index, and UN number for the following radioactive shipments:
* LW12-006; Radioactive Material, LSA-I, 7, UN 2912, 40-Foot Seavan Containing Dry Active Waste To Be Processed at Energy Solutions Bear Creek Facility, Oak Ridge Tennessee; February 15, 2012;
* LW13-024; Radioactive Material, LSA-II, 7, UN 3321; Condensate Pre-Filter Septa Liner to Energy Solutions Bear Creek Facility, Oak Ridge Tennessee; July 25, 2013;
* LW12-037; Radioactive Material, LSA-II, 7, UN 3321; 21-300FR Liner of Dewatered Bead Resin in 14-215H-26 Cask; to Clive Disposal Facility, Utah; October 12, 2012; and
* LW12-002; Radioactive Material, LSA-II, 7, UN 3321; Fissile Excepted; Dewatered Bead Resin; Clive Disposal Facility, Clive, Utah; January 10, 2012.
 
Additionally, the inspectors assessed whether the shipment placarding was consistent with the information in the shipping documentation.
 
====b. Findings====
No findings were identified.
 
===.7 Identification and Resolution of Problems (02.07)===
 
====a. Inspection Scope====
The inspectors assessed whether problems associated with radioactive waste processing, handling, storage, and transportation were being identified by the licensee at an appropriate threshold, were properly characterized, and were properly addressed for resolution in the licensees 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 licensees corrective actions for issues identified during those audits.
 
====b. Findings====
No findings were identified.
 
==OTHER ACTIVITIES==
Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency Preparedness, Public Radiation Safety, Occupational Radiation Safety, and Physical Protection
{{a|4OA1}}
==4OA1 Performance Indicator Verification==
{{IP sample|IP=IP 71151}}
===.1 Mitigating Systems Performance Index - Emergency AC Power System===
 
====a. Inspection Scope====
The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Emergency AC Power System performance indicator for Units 1 and 2 for the third quarter 2012 through the second quarter 2013. To determine the accuracy of the performance indicator (PI) data reported, PI definitions and guidance in Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, were used. The inspectors reviewed the licensees 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 licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified.
 
Documents reviewed are listed in the Attachment to this report.
 
This inspection constituted two MSPI emergency AC power system samples as defined in IP 71151-05.
 
====b. Findings====
No findings were identified.
 
===.2 Mitigating Systems Performance 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 licensees operator narrative logs, issue reports, MSPI derivation reports, event reports, and NRC Integrated Inspection Reports for July 2012 through June 2013 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.
 
The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.
 
This inspection constituted two MSPI high pressure injection system samples as defined in IP 71151-05.
 
====b. Findings====
No findings were identified.
 
===.3 Mitigating Systems Performance 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 licensees operator narrative logs, issue reports, MSPI derivation reports, event reports, and NRC Integrated Inspection Reports for July 2012 through June 2013 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.
 
The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.
 
This inspection constituted two MSPI residual heat removal system samples as defined in IP 71151-05.
 
====b. Findings====
No findings were identified.
 
===.4 Mitigating Systems Performance Index - Cooling Water Systems===
 
====a. Inspection Scope====
The inspectors sampled licensee submittals for the Mitigating Systems Performance Index - Cooling Water Systems PI for Units 1 and 2 for the fourth quarter 2012 through the second quarter 2013. To determine the accuracy of the PI data reported, PI definitions and guidance in NEI 99-02 were used. The inspectors reviewed the licensees 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 licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.
 
This inspection constituted two MSPI cooling water system samples as defined in IP 71151-05.
 
====b. Findings====
No findings were identified.
 
===.5 Occupational Exposure Control Effectiveness===
 
====a. Inspection Scope====
The inspectors sampled licensee submittals for the occupational radiological occurrences PI for the first quarter 2012 through the second quarter 2013. The inspectors used PI definitions and guidance in NEI 99-02 to determine the accuracy of the PI data reported. The inspectors reviewed the licensees 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 licensees PI data collection and analyses, the inspectors discussed with radiation protection staff the scope and breadth of their data review and the results of those reviews. The inspectors independently reviewed electronic personal dosimetry dose rate and accumulated dose alarms, dose reports, and the dose assignments for any intakes that occurred during the time period reviewed to determine if there were potentially unrecognized PI occurrences.
 
The inspectors also conducted walkdowns of numerous locked high and very high radiation area entrances to determine the adequacy of the controls in place for these areas. Documents reviewed are listed in the Attachment to this report.
 
This inspection constituted one occupational exposure control effectiveness sample as defined in IP 71151-05.
 
====b. Findings====
No findings were identified. {{a|4OA2}}
==4OA2 Identification and Resolution of Problems==
{{IP sample|IP=IP 71152}}
===.1 Routine Review of Items Entered into the Corrective Action Program===
 
====a. Inspection Scope====
As part of the various baseline inspection procedures discussed in previous sections of this report, the inspectors routinely reviewed issues during baseline inspection activities and plant status reviews to verify they were being entered into the licensees CAP at an appropriate threshold, that adequate attention was being given to timely corrective actions, and that adverse trends were identified and addressed. Attributes reviewed included: identification of the problem was complete and accurate; timeliness was commensurate with the safety significance; evaluation and disposition of performance issues, generic implications, common causes, contributing factors, root causes, extent-of-condition reviews, and previous occurrences reviews were proper and adequate; and that the classification, prioritization, focus, and timeliness of corrective actions were commensurate with safety and sufficient to prevent recurrence of the issue.
 
Minor issues entered into the licensees CAP as a result of the inspectors observations are included in the Attachment to this report.
 
These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in 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 licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.
 
These daily reviews were performed by procedure as part of the inspectors daily plant status monitoring activities and, as such, did not constitute any separate inspection samples.
 
====b. Findings====
No findings were identified. {{a|4OA3}}
==4OA3 Follow-Up of Events and Notices of Enforcement Discretion==
{{IP sample|IP=IP 71153}}
===.1 (Closed) Licensee Event Report (LER) 05000374/2013-002-00: Manual Reactor Scram===
 
Following Trip of Circulating Water Pumps
 
====a. Inspection Scope====
This event, which occurred on April 25, 2013, involved an evolution designed to enable the licensee to access and repair a condenser tube leak identified on the Unit 2 main condenser east waterbox. An existing procedure was utilized to allow the unit to stay at power while the affected half of the waterbox was isolated and drained. However, during the execution of this evolution, the circulating water (CW) system had its isolation boundary challenged by operators while the waterbox manway covers were still open, which resulted in the flooding of the condenser pit, a CW pump trip, and manual scram.
 
Documents reviewed are listed in the Attachment to this report. This LER is closed.
 
This event follow-up review constituted one sample as defined in IP 71153-05.
 
====b. Findings====
Failure to Follow Procedure Led to Manual Scram with Complications     
 
=====Introduction:=====
A self-revealed finding preliminarily determined to be of low-to-moderate safety significance (White) was identified for the licensees failure to follow procedure LOP-CW-10, Dewatering the Circulating Water System, Revision 32, on Unit 2.
 
Specifically, operators executed the condenser waterbox dewatering evolution in a manner inconsistent with procedural guidance, resulting in a circulating water pump trip, loss of the normal heat sink, and reactor scram.
 
=====Description:=====
On April 25, 2013, during Unit 2s 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.
 
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 licensees failure to follow the prescribed steps of procedure LOP-CW-10 was reasonably within the licensees ability to foresee and correct and should have been prevented, and is therefore considered a performance deficiency warranting a significance determination. The inspectors used Inspection Manual Chapter (IMC) 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power Exhibit 1, dated June 19, 2012, for the Initiating Events cornerstone. The inspectors answered yes to the screening question, Did the finding cause a reactor trip AND the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown conditions? The loss of a condenser is cited as an example of such an event. A detailed risk evaluation was required.
 
The Senior Reactor Analysts (SRAs) used the LaSalle Unit 1 SPAR model as a surrogate for the Unit 2 performance deficiency to perform the detailed risk evaluation.
 
The SPAR model revision was 8.21. Several modifications were performed by Idaho National Laboratory to appropriately model plant response to a loss of condenser heat sink event.
 
In accordance with Risk Assessment of Operational Events Handbook guidance, for findings that cause initiating events to occur, the initiating event that was observed is set to 1.0 or True and the conditional core damage probability is calculated. The conditional core damage probability is multiplied by one inverse year (yr-1) to equate this to a change in core damage frequency for the performance deficiency. For this finding, the initiating event Loss of Condenser Heat Sink was set to 1.0 using the events and condition assessment module of the Systems Analysis Program for Hands-On Integrated Reliability Evaluations (SAPHIRE), Version 8.
 
The calculated conditional core damage probability for a loss of condenser heat sink event was 1.6E-6, which represents a finding of low to moderate safety significance (White). The dominant sequence is a loss of condenser heat sink event with loss of all decay heat removal due to failure of suppression pool cooling and failure of containment venting. Late injection after containment failure is also failed.
 
LaSalle Unit 2 has a Mark II containment. The SRAs used IMC 0609 Appendix H, Containment Integrity Significance Determination Process dated May 6, 2004, to evaluate the potential risk contribution due to large early release frequency. The finding was a Type A finding in which the finding has an impact on core damage frequency.
 
The dominant sequences involved long-term accident sequences that involve failure of containment heat removal that eventually progresses to containment failure. These sequences do not contribute to large early release frequency because it is assumed that effective emergency response actions can be taken within the long time frame of the accident sequences.
 
The licensee also performed an analysis of the performance deficiency using the LaSalle probabilistic risk assessment (PRA) model and provided it to the NRC for information.
 
The analysis used several different methodologies which produced slightly different results. The SRAs determined that the licensee analysis was consistent with the NRC analysis if similar assumptions were applied. However, the overall conclusion of the licensee analysis was that this performance deficiency was best represented by a finding of very low safety significance (Green). The NRC determined that the NRC evaluation using standard SDP and Risk Assessment of Operational Events Handbook guidance and the modified SPAR model were appropriate tools for the SDP evaluation and the finding was best characterized as a finding of low to moderate safety significance (White).
 
The finding had a cross-cutting aspect in the area of human performance, decision-making, because the licensee failed to use conservative assumptions when planning and executing the dewatering evolution. Specifically, the incorrect assumption that this evolution performed at-power could be treated the same as when performed during a shutdown condition enabled operators to stray from strict procedure adherence and into knowledge space (H.1(b)).
 
=====Enforcement:=====
This finding preliminarily determined to be of low-to-moderate safety significance (White) did not involve a violation of regulatory requirements because the systems involved were not safety-related and the evolution was not considered an activity affecting quality. The event was captured in the licensees CAP as AR 01506809 and is being documented as FIN 05000374/2013004-01, Failure to Follow Procedure Led to Manual Scram with Complications. Corrective actions included various training activities for operators, procedure revisions, and potential physical enhancements to the CW isolation valves.
 
===.2 (Closed) LER 050002013-001-00: Pin Hole Leaks Identified in High Pressure Core===
 
Spray Piping On April 18, 2013, Unit 2 was in Mode 3 following a scram and a loss of offsite power that had occurred on both units the previous day. Three pin-hole through-wall leaks in the U2 HPCS minimum flow line piping were discovered. The leaks were on the outside bend of the first elbow downstream of the minimum flow restricting orifice, and appeared to be leaking a total of approximately 0.5 gallons per minute (gpm) with the HPCS pump not running.
 
Unit 2 HPCS was declared inoperable and, because the HPCS minimum flow line is in direct communication with the suppression pool, primary containment was also declared inoperable. The direct cause of the event was a combination of cavitation and mechanical wear/erosion of the piping wall. Corrective actions included replacing the leaking pipe elbow, and performing ultrasonic inspections of susceptible piping on both Units. Also, HPCS operating procedures were reviewed and revised. Documents reviewed are listed in the Attachment to this report. This LER is closed.
 
This event follow-up review constituted one sample as defined in IP 71153-05.
 
Findings Inadequate Procedures Led to Pin Hole Leaks in High Pressure Core Spray Piping
 
=====Introduction:=====
A finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed for the failure to have procedures adequate for the circumstances during long-term operation of the HPCS system on minimum flow.
 
=====Description:=====
On April 17, 2013, following a station dual-unit loss of offsite power, the HPCS system started on both units. Unit 2 HPCS system ran in minimum flow mode for about 17 hours and Unit 1 HPCS system ran in minimum flow mode for about 15 hours before they were secured. On April 18, 2013, three small holes developed in the Unit 2 HPCS minimum flow line elbow. Total leakage was about 0.5 gpm.
 
The licensee determined in the Apparent Cause Evaluation (AR 1503825-08) that these holes were caused by cavitation and other flow related wear. The licensees 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 licensees assessment. In response to NRC Bulletin 88-04, Potential Safety Related Pump Loss, the licensee stated that they would put precautions in operating procedures not to run the pump in min-flow mode for extended periods. The vendor information available at that time stated that extended operation was anything over 3 hours.
 
Licensee procedure LOP-HP-04, Shutdown of High Pressure Core Spray System After An Automatic Initiation, Revision 11, had a precaution statement that, In order to minimize pump degradation, consideration should be made to secure the HPCS pump when extended periods of operation on minimum flow is expected. In addition, there was a note in the body of the procedure that says that if the pump is to be run in the min-flow mode for longer than 30 minutes then an additional flow path should be provided by running in the full flow test mode. However, these warnings do not specify that the pump cannot be run in min-flow for long periods of time; instead, the procedure only specifies that the pump should not be operated in min-flow for long periods of time. Finally, LOP-HP-04 neither had any procedural guidance on how to operate in the full flow test mode with a high drywell pressure signal present nor did it reference any other procedure on how to operate the system in this manner.
 
=====Analysis:=====
The inspectors determined that having HPCS operating procedures that were inadequate for the circumstances of running HPCS in the minimum flow mode for extended periods was contrary to 10 CFR 50, Appendix B, Criterion V, and was a performance deficiency.
 
The finding was determined to be more than minor because the finding was associated with the Mitigating Systems cornerstone attribute of Procedure Quality and adversely affected the cornerstone objective of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences.
 
Specifically, the procedural guidance given to operate the HPCS system was inadequate to prevent long-term operation of the system in the minimum flow mode of operation that led to cavitation and flow-induced wear which resulted in 3 pin hole leaks in the Unit 2 HPCS min-flow line.
 
The inspectors determined that the finding could be evaluated in accordance with IMC 0609, Appendix A, The Significance Determination for Findings At-Power, dated June 19, 2012, and Appendix H, Containment Integrity Significance Determination Process, dated May 6, 2004. The inspectors used Section A of Exhibit 2 of Appendix A, Mitigating Systems Screening Questions. The inspectors answered all four questions No because even with the holes in the minimum flow line the HPCS could still inject and therefore did not lose its safety function.
 
The inspectors also reviewed IMC 0609, Appendix H, Section 6.0, Procedure For Type B Findings. A Type B finding is one that has no effect on delta-core damage frequency. The inspectors entered Table 6.1 and determined that a phase two review was necessary because LaSalle has a Mark II containment and the finding impacted suppression pool integrity. The inspectors then entered Table 6.2 which stated that if the leakage from the drywell was less than 100 percent of the drywell volume per day then the issue screened as Green. The inspectors determined that leakage from the drywell to the environment was less than 100 percent per day based on information from IMC 0308, Appendix H, Technical Basis, Containment Integrity Significance Determination Process (IMC 0609, App H) For Type A and Type B Findings Full Power and Shutdown Operations, dated May 6, 2004. Inspection Manual Chapter 0308, Section 2.2, stated that the hole size that would result in leakage equivalent to greater than 100 percent of the containment volume per day would have a diameter of greater that one inch. A circle around all the holes combined found in the HPCS piping was less than 0.5 inches in diameter. Therefore, this issue screens as Green.
 
The inspectors did not identify a cross-cutting aspect associated with this finding.
 
=====Enforcement:=====
Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and be accomplished in accordance with these instructions, procedures, or drawings. Procedure LOP-HP-04, Shutdown of High Pressure Core Spray System After an Automatic Initiation, Revision 11, is considered an activity affecting quality by the licensee as well as by the NRC.
 
Contrary to the above, on April 17, 2013, the licensee failed to have procedures of a type appropriate to the circumstances needed to operate and shut down the HPCS system.
 
Specifically, the procedural guidance available to the operators allowed them to operate the HPCS system in the min-flow mode for 17 hours on Unit 2 and 15 hours on Unit 1, which resulted in an unisolable leak hole in the Unit 2 HPCS min-flow line (and ultimately in the suppression chamber) and degraded the Unit 1 HPCS min-flow piping.
 
Because this violation was of very low safety significance and it was entered into the licensees CAP (as ARs 1503825 and 1530682), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000373/2013004-02; 05000374/2013004-02, Inadequate Procedures Led to Pin Hole Leaks in High Pressure Core Spray Piping).
 
As corrective actions, the licensee immediately declared the HPCS system and the primary containment inoperable and entered the applicable TS actions. The affected pipe elbow was then promptly replaced and the systems returned to service.
 
Additionally, an extent of condition examination was performed on other potentially effected sections of piping. Finally, to prevent recurrence, the licensee revised the effected procedures.
 
===.3 (Closed) LER 050002012-001-00: 2B DG Declared Inoperable Due to Excessive Air===
 
Start Receiver Blowdown Caused by a Degraded Drain Valve This event, which occurred on August 31, 2012, involved preventive maintenance that was being performed on the 2B DG A train starting air receiver, which was not intended to cause the system to be inoperable. While operators were blowing down the air receiver, the pressure decreased below the minimum allowable 165 pounds per square inch (psig) required for DG operability per TS 3.8.3 Condition D. The licensee declared the system out of service and entered the appropriate TS action statement. Shortly thereafter, system pressure was restored and the 2B DG was declared operable. The cause of the event was determined to be a degraded drain valve on the receiver. The licensee replaced the valve at a later date to prevent recurrence. No findings were identified. This LER is closed.
 
This event follow-up review constituted one sample as defined in IP 71153-05
 
===.4 (Closed) LER 050002013-003-00: Low Pressure Core Spray System Declared===
 
Inoperable Due to Faulty Control Switch This event occurred on April 18, 2013, while Unit 1 was in Mode 3 following a loss of offsite power event and dual unit scram the previous day. While attempting to raise Unit 1 reactor water level using the Low Pressure Core Spray (LPCS) system, LPCS injection motor-operated valve 1 E21-F005 failed to open when its control switch was held in the "OPEN" position. The LPCS system was declared inoperable but available, and the appropriate TS action statement was entered, requiring that LPCS be restored to operable status within seven days.
 
The cause of the event was determined to be the failure of the control switch due to the buildup of oxidation on the contact surfaces. All other contacts in the switch were found to be working normally. The corrective action was to replace the control switch.
 
A sample of similar switches has been scheduled to be tested to determine if electrical contact erosion is starting to occur on other switches with similar in-service life installed in similar electrical circuits.
 
This event was also discussed in greater detail and was associated with a non-cited violation previously documented in NRC Special Inspection Report 05000373/2013009; 05000374/2013009. No additional findings were identified during this LER review. This LER is closed.
 
This event follow-up review constituted one sample as defined in IP 71153-05.
 
===.5 (Discussed) LER 05000373/2012-001-00, 374/2012-001-00: Secondary Containment===
 
Inoperable Due to Interlock Doors Open As previously described in NRC inspection report 05000373/2013003; 05000374/2013003 02, the inspectors are in the process of reviewing the adequacy of the licensees 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 licensees implemented and planned corrective actions in response to the events described in the subject LER. Since resolution of the associated URI is necessary to determine if there are any violations of NRC requirements, this LER review will not be closed at this time.
 
Documents reviewed are listed in the Attachment to this report. This LER is not closed.
 
This continuation of an event follow-up review did not constitute a completed sample as defined in IP 71153-05.
 
===.7 (Closed) LER 050002013-004-00: Reactor Pressure Exceeded 150 psig With Reactor===
 
Core Isolation Cooling Inoperable This event occurred on April 22, 2013, while Unit 1 was in Mode 2, Startup. Reactor pressure was increased to above 150 psig with the RCIC system isolated and inoperable. This was an action prohibited by TS and was previously discussed and documented as a Licensee-Identified Green NCV in NRC Inspection Report 05000373/2013002; 05000374/2013002, Section 4OA7. No additional findings were identified. Documents reviewed are listed in the Attachment to this report. This LER is closed.
 
This event follow-up review constituted one sample as defined in IP 71153-05.
 
===.8 Review of Event Notification EN 49167 Retraction===
 
On July 1, 2013, the licensee made a 10 CFR 50.72 event notification (EN 49167) for the Unit 2 HPCS minimum flow valve pressure switch setpoint found outside of tolerance. The setpoint was found at 112.6 psig instead of greater than or equal to 113.2 psig. At the time of notification, the licensee determined that this was a condition that could have prevented fulfillment of a safety function needed to mitigate the consequences of an accident. On August 5, 2013, the licensee determined that premature opening of the HPCS minimum flow valve would not have prevented the HPCS from fulfilling its safety function since the licensees 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 licensees retraction.
 
Documents reviewed are listed in the Attachment to this report.
 
This event follow-up review constituted one sample as defined in IP 71153-05.
 
{{a|4OA6}}
==4OA6 Management Meetings==
 
===.1 Exit Meeting Summary===
 
On October 2, 2013, the inspectors presented the inspection results to Mr. P. Karaba, the Site Vice-President, and other members of the licensee staff. The licensee acknowledged the issues presented. The inspectors confirmed that none of the potential report input discussed was considered proprietary.
 
===.2 Interim Exit Meetings===
 
Interim exits were conducted for the inspection results for the areas of radioactive solid waste processing and radioactive material handling, storage, and transportation; and occupational exposure control effectiveness performance indicator verification with Mr. P. Karaba, Site Vice-President, on August 16, 2013.
 
The inspectors confirmed that none of the potential report input discussed was considered proprietary. Proprietary material received during the inspection was returned to the licensee.
 
ATTACHMENT:
 
=SUPPLEMENTAL INFORMATION=
 
==KEY POINTS OF CONTACT==
 
Licensee
: [[contact::P. Karaba]], Site Vice President
: [[contact::H. Vinyard]], Plant Manager
: [[contact::K. Hedgspeth]], Radiation Protection Manager
: [[contact::J. Washko]], Engineering Manager
: [[contact::G. Chavez]], Dry Cask Storage Program Manager
: [[contact::B. Maze]], Project Management
: [[contact::M. Sharma]], Engineering Programs
: [[contact::K. Hall]], Buried Piping Program Owner
: [[contact::V. Chopra]], Engineering Programs
: [[contact::J. Vergara]], Regulatory Assurance
: [[contact::L. Ekern]], Nuclear Oversight
: [[contact::B. Hilton]], Design Manager
: [[contact::G. Ford]], Regulatory Affairs Manager
: [[contact::J. Houston]], Nuclear Oversight Manager
: [[contact::A. Schierer]], Engineer
: [[contact::D. Amezaga]], System Engineer
: [[contact::J. Bendis]], Engineer
: [[contact::J. Feeney]], LaSalle Nuclear Oversight
: [[contact::J. Hughes]], Emergency Preparedness Coordinator
: [[contact::J. Smith]], Operations Training Manager
: [[contact::L. Blunk]], Regulatory Affairs
: [[contact::J. Shields]], Invessel Visual Inspection Program Supervisor
: [[contact::S. Shields]], Regulatory Affairs
: [[contact::S. Tanton]], Engineer
: [[contact::T. Hapak]], Chemistry
: [[contact::C. Howard]], Radiation Protection Operation Manager
: [[contact::R. Simonsen]], Radiation Protection Operation Manager
: [[contact::A. Baker]], Dosimetry Specialist
: [[contact::A. Daniels]], Exelon Emergency Preparedness Manager
: [[contact::K. Rusley]], Emergency Preparedness Manager
: [[contact::S. Tutoky]], Senior Chemist
: [[contact::M. Martin]], Chemistry Developmental Manager
: [[contact::J. Mosher]], Radiation Protection Manager
: [[contact::S. Koval]], Radwaste Shipping Specialist
Nuclear Regulatory Commission
: [[contact::M. Kunowski]], Chief, Reactor Projects Branch 5
Attachment
 
==LIST OF ITEMS==
 
===OPENED, CLOSED AND DISCUSSED===
 
===Opened===
: 05000374/2013-002-00  LER    Manual Reactor Scram Following Trip of Circulating Water Pumps (Section 4OA3.1)
: 05000374/2013004-01    FIN    Failure to Follow Procedure Led to Manual Scram with Complications (Section 4OA3.1)
: 05000374/2013-001-00  LER    Pin Hole Leaks Identified in High Pressure Core Spray Piping (Section 4OA3.2)
: 05000373/2013004-02    NCV    Inadequate Procedures Led to Pin Hole Leaks in High
: 05000374/2013004-02          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    NCV    Inadequate Procedures Led to Pin Hole Leaks in High
: 05000374/2013004-02          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  LER  Secondary Containment Inoperable Due to Interlock
: 05000374/2012-001-00        Doors Open (Section 4OA2.5)
: 05000373/2013-001-00  LER  Secondary Containment Inoperable Due to Interlock
: 05000374/2013-001-00        Doors Open (Section 4OA2.6)
Attachment
 
==LIST OF DOCUMENTS REVIEWED==
 
}}
}}

Latest revision as of 12:58, 20 December 2019

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
ML13319B253
Person / Time
Site: LaSalle  Constellation icon.png
Issue date: 11/15/2013
From: O'Brien K
Division Reactor Projects III
To: Pacilio M
Exelon Generation Co, Exelon Nuclear
References
EA-13-221 IR-13-004
Download: ML13319B253 (52)
v • d • e


Text

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

Dear Mr. Pacilio:

On September 30, 2013, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at your LaSalle County Station, Units 1 and 2. The enclosed report documents the inspection results which were discussed on Wednesday, October 2, 2013, with the Site Vice President, Mr. P. Karaba, and other members of your staff.

The enclosed inspection report discusses a finding on Unit 2 that has preliminarily been determined to be White, a finding with low-to-moderate safety significance, that may result in additional NRC inspection. As described in Section 4OA3 of this report, a self-revealed finding was identified for the failure of station personnel to follow procedure LOP-CW-10, Dewatering the Circulating Water System, Revision 32, on April 25, 2013. Specifically, operators performed the waterbox dewatering evolution in a manner inconsistent with procedural guidance by manually adjusting the circulating water isolation valves while the waterbox manways were open. Adjustment of the inlet isolation valve caused a loss of isolation resulting in flooding of the condenser pit and a resultant circulating water pump trip, loss of the normal heat sink, and a manual reactor scram. This finding was assessed based on the best available information, using the applicable Significance Determination Process (SDP).

The inspectors used Inspection Manual Chapter (IMC) 0609, Appendix A, The Significance Determination Process (SDP) for Findings At-Power, Exhibit 1, dated June 19, 2012, for the Initiating Events cornerstone. Because the finding caused a reactor trip AND the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition, a detailed risk evaluation was required. The Senior Reactor Analysts (SRAs) used the LaSalle Standardized Plant Analysis Risk (SPAR) model to perform the detailed risk evaluation. In accordance with Risk Assessment of Operational Events Handbook guidance, the initiating event Loss of Condenser Heat Sink was set to 1.0 using the events and condition assessment module of the Systems Analysis Program for Hands-On Integrated Reliability Evaluations (SAPHIRE), Version 8. The calculated conditional core damage probability for the event was 1.6E-6, which represents a finding of low to moderate safety significance (White).

As described in NRC Inspection Manual Chapter 0612, Power Reactor Inspection Reports, dated January 24, 2013, a finding may or may not be associated with regulatory non-compliance and, therefore, may or may not result in a violation. Based on the review of this issue and in accordance with NRC Inspection Manual Chapter 0612, the NRC determined that no violation of a regulatory requirement occurred.

In accordance with NRC Inspection Manual Chapter 0609, we intend to complete our evaluation using the best available information and issue our final determination of safety significance within 90 days of the date of this letter. The significance determination process encourages an open dialogue between the NRC staff and the licensee; however, the dialogue should not impact the timeliness of the staffs final determination.

Before we make a final decision on this matter, we are providing you with an opportunity to (1) attend a Regulatory Conference where you can present to the NRC your perspective on the facts and assumptions the NRC used to arrive at the finding and assess its significance, or (2) submit your position on the finding to the NRC in writing. If you request a Regulatory Conference, it should be held within 30 days of the receipt of this letter and we encourage you to submit supporting documentation at least one week prior to the conference in an effort to make the conference more efficient and effective. The focus of the Regulatory Conference is to discuss the significance of the finding and not necessarily the root cause(s) or corrective action(s) associated with the finding. If a Regulatory Conference is held, it will be open for public observation. If you decide to submit only a written response, such submittal should be sent to the NRC within 30 days of your receipt of this letter. If you decline to request a Regulatory Conference or to submit a written response, you relinquish your right to appeal the final SDP determination, in that by not doing either, you fail to meet the appeal requirements stated in the Prerequisite and Limitation sections of Attachment 2 of NRC Inspection Manual Chapter 0609.

Please contact Michael Kunowski at (630) 829-9618 and in writing within 10 days from the issue date of this letter to notify the NRC of your intentions. If we have not heard from you within 10 days, we will continue with our significance determination and enforcement decision.

The final resolution of this matter will be conveyed in a separate correspondence.

In addition to the finding discussed above, one self-identified violation of very low safety significance (Green) was identified during this inspection. This finding was determined to involve a violation of NRC requirements and the NRC is treating it as a non-cited violation (NCV), consistent with Section 2.3.2 of the Enforcement Policy.

If you contest the violation or significance of the NCV, you should provide a response within 30 days of the date of this inspection report, with the basis for your denial, to the U. S. Nuclear Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001, with copies to the Regional Administrator, Region III; the Director, Office of Enforcement, U. S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC Resident Inspector at the LaSalle County Station. If you disagree with the cross-cutting aspect assignment in this report, you should provide a response within 30 days of the date of this inspection report, with the basis for your disagreement, to the Regional Administrator, Region III, and the NRC Resident Inspector at LaSalle County Station.

In accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholdings, of the NRC's "Rules of Practice," a copy of this letter and its enclosure, and your response (if any) will be available electronically for public inspection in the NRCs Public Document Room or from the Publicly Available Records System (PARS)

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

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

Sincerely,

/RA by Julio Lara for/

Kenneth G. OBrien, 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

REGION III==

Docket Nos: 05000373; 05000374 License Nos: NPF-11; NPF-18 Report No: 05000373/2013004; 05000374/2013004 Licensee: Exelon Generation Company, LLC Facility: LaSalle County Station, Units 1 and 2 Location: Marseilles, IL Dates: July 1, 2013 - September 30, 2013 Inspectors: R. Ruiz, Senior Resident Inspector M. Ziolkowski, Acting Resident Inspector K. Carrington, Acting Resident Inspector G. Roach, Senior Resident Inspector, Dresden D. Chyu, Region III Reactor Engineer I. Hafeez, Region III Reactor Inspector C. Phillips, Project Engineer T. Go, Health Physicist Approved by: M. Kunowski, Chief Branch 5 Division of Reactor Projects Enclosure

SUMMARY OF FINDINGS

Inspection Report (IR) 05000373/2013004, 05000374/2013004; 07/01/2013-09/30/2013;

LaSalle County Station, Units 1 & 2; Followup of Events and Notices of Enforcement Discretion.

This report covers a 3-month period of inspection by resident inspectors and announced baseline inspections by regional inspectors. Two findings were identified during the inspection.

One finding was preliminarily determined to be White and one finding was determined to be a Green non-cited violation (NCV). The significance of inspection findings is indicated by their color (i.e., greater than Green, or Green, White, Yellow, Red) and determined using IMC 0609,

Significance Determination Process dated June 2, 2011. Cross-cutting aspects are determined using IMC 0310, Components Within the Cross Cutting Areas dated October 28, 2011. All violations of NRC requirements are dispositioned in accordance with the NRCs 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.

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 licensees 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 licensees failure to follow the prescribed steps of procedure LOP-CW-10 was a performance deficiency warranting a significance determination. The inspectors used Inspection Manual Chapter (IMC) 0609,

Appendix A, The Significance Determination Process (SDP) for Findings At-Power,

Exhibit 1, dated June 19, 2012, for the Initiating Events cornerstone. Because the finding caused a reactor trip AND the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown condition, a detailed risk evaluation was required. The Senior Reactor Analysts (SRAs) used the LaSalle Standardized Plant Analysis Risk (SPAR) model to perform the detailed risk evaluation.

In accordance with Risk Assessment of Operational Events Handbook guidance, the initiating event Loss of Condenser Heat Sink was set to 1.0 using the events and condition assessment module of the Systems Analysis Program for Hands-On Integrated Reliability Evaluations (SAPHIRE), Version 8. The calculated conditional core damage probability for the event was 1.6E-6, which represents a finding of low-to-moderate safety significance (White). The finding had a cross-cutting aspect in the area of human performance, decision-making, because the licensee failed to use conservative assumptions when planning and executing the dewatering evolution. Specifically, the incorrect assumption that this evolution performed at-power could be treated the same as when performed during a shutdown condition enabled operators to stray from strict procedure adherence and into knowledge space (H.1(b)). (Section 4OA3)

Cornerstone: Mitigating Systems and Barrier Integrity

  • Green: A self-revealed finding of very low safety significance and associated non-cited violation of Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was identified for the failure to have procedures adequate for the circumstances during long-term operation of the high pressure core spray (HPCS)system on minimum flow. Specifically, three small holes developed in the Unit 2 HPCS minimum flow line elbow due to cavitation and other flow-related wear caused by inconsistent procedural guidance regarding operation in the minimum-flow mode.

The licensee promptly repaired the system leak and entered the issue into its CAP as ARs 1503825 and 1530682, which included the performance of an apparent cause evaluation. Further corrective actions included the revision of the affected procedures.

The finding was determined to be more than minor because it was associated with the Mitigating Systems and Barrier Integrity cornerstone attributes of Procedure Quality and adversely affected the cornerstone objectives of ensuring the availability, reliability, and capability of systems that respond to initiating events to prevent undesirable consequences and providing reasonable assurance that physical design barriers protect the public from radionuclide releases caused by accidents or events. Specifically, the procedural guidance given to operate the HPCS system was inadequate to prevent long-term operation of the system in the minimum flow mode of operation, which led to cavitation and flow-induced wear, causing the failure of the Unit 2 HPCS minimum flow line and inoperability of the HPCS system as well as the primary containment boundary.

The inspectors determined that the finding could be evaluated in accordance with IMC 0609, Appendix A, The Significance Determination for Findings At-Power, and Appendix H, Containment Integrity Significance Determination Process. Further, it was determined that a phase two risk assessment was necessary because the finding impacted suppression pool integrity, and through that process, this issue screened as

Green.

The inspectors did not identify a cross-cutting aspect associated with this finding. (Section 4OA3)

REPORT DETAILS

Summary of Plant Status

Unit 1 The unit began the inspection period operating at full power. On September 7, 2013, power was reduced to approximately 65 percent for a control rod sequence exchange and scram time testing. Unit 1 was restored to full power on September 8.

Unit 2 The unit began the inspection period operating at full power. On August 31, 2013, power was reduced to approximately 65 percent for a control rod sequence exchange and scram time testing. Unit 2 was restored to full power on September 1. Additionally, on September 27, power was reduced to approximately 60 percent for power suppression testing to identify a leaking fuel element. Upon the successful completion of that evolution, Unit 2 was restored to approximately full power on September

REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, and Barrier Integrity

1R01 Adverse Weather Protection

Main article: IP 71111.01

.1 Summer Seasonal Readiness Preparations

a. Inspection Scope

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

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

Additionally, the inspectors reviewed the 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.

1R04 Equipment Alignment

Main article: IP 71111.04

.1 Quarterly Partial System Walkdowns

a. Inspection Scope

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

  • Unit 1 'A' diesel generator (DG) walkdown following 1 'B' DG idle start;

The inspectors selected these systems based on their risk significance relative to the Reactor Safety Cornerstones at the time they were inspected. The inspectors attempted to identify any discrepancies that could impact the function of the system and, therefore, potentially increase risk. The inspectors reviewed applicable operating procedures, system diagrams, UFSAR, Technical Specification (TS) requirements, outstanding work orders (WOs), condition reports, and the impact of ongoing work activities on redundant trains of equipment in order to identify conditions that could have rendered the systems incapable of performing their intended functions. The inspectors also walked down accessible portions of the systems to verify system components and support equipment were aligned correctly and operable. The inspectors examined the material condition of the components and observed operating parameters of equipment to verify that there were no obvious deficiencies. The inspectors also verified that the licensee had properly identified and resolved equipment alignment problems that could cause initiating events or impact the capability of mitigating systems or barriers and entered them into the CAP with the appropriate significance characterization. Documents reviewed are listed in the to this report.

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

b. Findings

No findings were identified.

.2 Semi-Annual Complete System Walkdown

a. Inspection Scope

On 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 licensees probabilistic risk assessment.

The inspectors walked down the system to review mechanical and electrical equipment lineups; electrical power availability; system pressure and temperature indications, as appropriate; component labeling; component lubrication; component and equipment cooling; hangers and supports; operability of support systems; and to ensure that ancillary equipment or debris did not interfere with equipment operation. A review of a sample of past and outstanding WOs was performed to determine whether any deficiencies significantly affected the system function. In addition, the inspectors reviewed the CAP database to ensure that system equipment alignment problems were being identified and appropriately resolved. Documents reviewed are listed in the to this report.

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

b. Findings

No findings were identified.

1R05 Fire Protection

Main article: IP 71111.05

.1 Routine Resident Inspector Tours

Main article: IP 71111.05Q

a. Inspection Scope

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

  • 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 licensees fire plan.

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

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

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R06 Flooding

Main article: IP 71111.06

.1 Internal Flooding

a. Inspection Scope

The inspectors reviewed selected risk-important plant design features and licensee procedures intended to protect the plant and its safety-related equipment from internal flooding events. The inspectors reviewed flood analyses and design documents, including the UFSAR, engineering calculations, and abnormal operating procedures, to identify licensee commitments. In addition, the inspectors reviewed licensee drawings to identify areas and equipment that may be affected by internal flooding caused by the failure or misalignment of nearby sources of water, such as the fire suppression or the circulating water systems. The inspectors also reviewed the licensees CAP documents with respect to past flood-related items identified in the CAP to verify the adequacy of the corrective actions. The inspectors performed a walkdown of the 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 licensees CAP documents with respect to past submerged cable issues identified in the CAP program to verify the adequacy of the corrective actions. The inspectors performed a walkdown of manholes 1 through 6, which are subject to flooding.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program

Main article: IP 71111.11

.1 Resident Inspector Quarterly Review of Licensed Operator Requalification

Main article: IP 71111.11Q

a. Inspection Scope

On August 8, 2013, the inspectors observed a crew of licensed operators in the plants simulator during licensed operator requalification training to verify that operator performance was adequate, evaluators were identifying and documenting crew performance problems, and training was being conducted in accordance with licensee procedures. The inspectors evaluated the following areas:

  • licensed operator performance;
  • crews clarity and formality of communications;
  • ability to take timely actions in the conservative direction;
  • prioritization, interpretation, and verification of annunciator alarms;
  • correct use and implementation of abnormal and emergency procedures;
  • control board manipulations;
  • oversight and direction from supervisors; and
  • ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications.

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

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

b. Findings

No findings were identified.

.2 Resident Inspector Quarterly Observation of Heightened Activity or Risk

Main article: IP 71111.11Q

a. Inspection Scope

On September 4, 2013, the inspectors observed control room operators during the performance of the secondary containment leak rate test. This was an activity that required heightened awareness or was related to increased risk. The inspectors evaluated the following areas:

  • licensed operator performance;
  • crews clarity and formality of communications;
  • ability to take timely actions in the conservative direction;
  • prioritization, interpretation, and verification of annunciator alarms (if applicable);
  • correct use and implementation of procedures;
  • control board (or equipment) manipulations;
  • oversight and direction from supervisors; and
  • ability to identify and implement appropriate TS actions and Emergency Plan actions and notifications (if applicable).

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

Main article: IP 71111.12

.1 Routine Quarterly Evaluations

a. Inspection Scope

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

  • Unit Common B diesel fire pump following a failure to start;

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

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

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

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control

Main article: IP 71111.13

.1 Maintenance Risk Assessments and Emergent Work Control

a. Inspection Scope

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

  • 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

Main article: IP 71111.15

.1 Operability Evaluations

a. Inspection Scope

The inspectors reviewed the following issues:

  • Unit Common 'B' control room ventilation charcoal filters potentially impacted by Freon leak;
  • Unit 2 high drywell temperatures;
  • 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 licensees evaluations to determine whether the components or systems were operable. Where compensatory measures were required to maintain operability, the inspectors determined whether the measures in place would function as intended and were properly controlled. The inspectors determined, where appropriate, compliance with bounding limitations associated with the evaluations. Additionally, the inspectors reviewed a sampling of CAP documents to verify that the licensee was identifying and correcting any deficiencies associated with operability evaluations. Documents reviewed are listed in the Attachment to this report.

This operability inspection constituted five samples as defined in IP 71111.15-05.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing

Main article: IP 71111.19

.1 Post-Maintenance Testing

a. Inspection Scope

The inspectors reviewed the following post-maintenance testing (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 RCIC high steam line flow instrumentation replacement;
  • Unit 2 hydraulic control unit 38-43; and
  • Unit 1 'A' DG following preventive and corrective maintenance.

These activities were selected based upon the structure, system, or component's ability to impact risk. The inspectors evaluated these activities for the following (as applicable):

the effect of testing on the plant had been adequately addressed; testing was adequate for the maintenance performed; acceptance criteria were clear and demonstrated operational readiness; test instrumentation was appropriate; tests were performed as written in accordance with properly reviewed and approved procedures; equipment was returned to its operational status following testing (temporary modifications or jumpers required for test performance were properly removed after test completion); and test documentation was properly evaluated. The inspectors evaluated the activities against TSs, the UFSAR, 10 CFR Part 50 requirements, licensee procedures, and various NRC generic communications to ensure that the test results adequately ensured that the equipment met the licensing basis and design requirements. In addition, the inspectors reviewed CAP documents associated with PMT to determine whether the licensee was identifying problems and entering them in the CAP and that the problems were being corrected commensurate with their importance to safety. Documents reviewed are listed in the Attachment to this report.

This inspection constituted seven PMT samples as defined in IP 71111.19-05.

b. Findings

No findings were identified.

1R22 Surveillance Testing

Main article: IP 71111.22

.1 Surveillance Testing

a. Inspection Scope

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

  • LIS-NR-303A/B average power range monitor (APRM) functional surveillance (Routine);
  • Unit 1 Division II 125-Vdc (Volts direct current) battery surveillance (Routine);
  • Unit 2 RHR quarterly surveillance (LOS-RH-Q1) (Routine); and
  • Unit 2 'B' DG cooling water pump (Inservice Testing--IST).

The inspectors observed in-plant activities and reviewed procedures and associated records to determine the following:

  • did preconditioning occur;
  • the effects of the testing were adequately addressed by control room personnel or engineers prior to the commencement of the testing;
  • acceptance criteria were clearly stated, demonstrated operational readiness, and were consistent with the system design basis;
  • plant equipment calibration was correct, accurate, and properly documented;
  • as-left setpoints were within required ranges; and the calibration frequency was in accordance with TSs, the UFSAR, procedures, and applicable commitments;
  • measuring and test equipment calibration was current;
  • test equipment was used within the required range and accuracy; applicable prerequisites described in the test procedures were satisfied;
  • test frequencies met TS requirements to demonstrate operability and reliability; tests were performed in accordance with the test procedures and other applicable procedures; jumpers and lifted leads were controlled and restored where used;
  • test data and results were accurate, complete, within limits, and valid;
  • test equipment was removed after testing;
  • where applicable for inservice testing activities, testing was performed in accordance with the applicable version of Section XI, American Society of Mechanical Engineers code, and reference values were consistent with the system design basis;
  • where applicable, test results not meeting acceptance criteria were addressed with an adequate operability evaluation or the system or component was declared inoperable;
  • where applicable for safety-related instrument control surveillance tests, reference setting data were accurately incorporated in the test procedure;
  • where applicable, actual conditions encountering high resistance electrical contacts were such that the intended safety function could still be accomplished;
  • prior procedure changes had not provided an opportunity to identify problems encountered during the performance of the surveillance or calibration test;
  • equipment was returned to a position or status required to support the performance of its safety functions; and
  • all problems identified during the testing were appropriately documented and dispositioned in the CAP.

Documents reviewed are listed in the Attachment to this report.

This inspection constituted three routine surveillance testing samples and one inservice testing sample as defined in IP 71111.22, Sections -02 and -05.

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation

Main article: IP 71114.06

.1 Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors evaluated the conduct of a routine licensee emergency drill on July 16, 2013, to identify any weaknesses and deficiencies in classification, notification, and protective action recommendation development activities. The inspectors observed emergency response operations in the simulator, technical support center and operational support center to determine whether the event classification, notifications, and protective action recommendations were performed in accordance with procedures.

The inspectors also attended the licensee drill critique to compare any inspector-observed weakness with those identified by the licensee staff in order to evaluate the critique and to verify whether the licensee staff was properly identifying weaknesses and entering them into the CAP. As part of the inspection, the inspectors reviewed the drill package and other documents listed in the Attachment to this report.

This emergency preparedness drill inspection constituted one sample as defined in IP 71114.06-05.

b. Findings

No findings were identified.

.2 Training Observation

a. Inspection Scope

The inspector observed simulator training evolutions for licensed operators on August 6 and September 17, 2013, which required emergency plan implementations by a licensee operations crew. These evolutions were planned to be evaluated and included in performance indicator data regarding drill and exercise performance. The inspectors observed event classification and notification activities performed by the crew. The inspectors also attended the post-evolution critiques for the scenarios. The focus of the inspectors activities was to note any weaknesses and deficiencies in the crews 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 licensees training evolutions with emergency preparedness drill aspects constituted two samples as defined in IP 71114.06-06.

b. Findings

No findings were identified.

RADIATION SAFETY

Cornerstones: Public Radiation Safety and Occupational Radiation Safety

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 licensees performance and inform the smart sampling inspection planning.

b. Findings

No findings were identified.

.2 Radioactive Material Storage (02.02)

a. Inspection Scope

The inspectors selected areas where containers of radioactive waste are stored and evaluated whether the containers were labeled in accordance with 10 CFR 20.1904, Labeling Containers, or controlled in accordance with 10 CFR 20.1905, Exemptions to Labeling Requirements, as appropriate.

The inspectors assessed whether the radioactive material storage areas were controlled and posted in accordance with the requirements of 10 CFR Part 20, Standards for Protection Against Radiation. For materials stored or used in the controlled or unrestricted areas, the inspectors evaluated whether they were secured against unauthorized removal and controlled in accordance with 10 CFR 20.1801, Security of Stored Material, and 10 CFR 20.1802, Control of Material Not in Storage, as appropriate.

The inspectors assessed whether the licensee established a process for monitoring the impact of long-term storage (e.g., buildup of any gases produced by waste decomposition, chemical reactions, container deformation, loss of container integrity, or re-release of free-flowing water) that was sufficient to identify potential unmonitored, unplanned releases or non-conformance with waste disposal requirements.

The inspectors selected containers of stored radioactive material, and assessed for signs of swelling, leakage, and deformation.

b. Findings

No findings were identified.

.3 Radioactive Waste System Walkdown (02.03)

a. Inspection Scope

The inspectors walked down accessible portions of select radioactive waste processing systems to assess whether the current system configuration and operation agreed with the descriptions in the UFSARt, Offsite Dose Calculation Manual, and Process Control Program.

The inspectors reviewed administrative and/or physical controls (i.e., drainage and isolation of the system from other systems) to assess whether the equipment that was not in service or was abandoned in place would not contribute to an unmonitored release path and/or affect operating systems or be a source of unnecessary personnel exposure.

The inspectors assessed whether the licensee reviewed the safety significance of systems and equipment abandoned in place in accordance with 10 CFR 50.59, Changes, Tests, and Experiments.

The inspectors reviewed the adequacy of changes made to the radioactive waste processing systems since the last inspection. The inspectors evaluated whether changes from what is described in the UFSAR were reviewed and documented in accordance with 10 CFR 50.59, as appropriate, and to assess the impact on radiation doses to members of the public.

The inspectors selected processes for transferring radioactive waste resin and/or sludge discharges into shipping/disposal containers and assessed whether the waste stream mixing, sampling procedures, and methodology for waste concentration averaging were consistent with the Process Control Program, and provided representative samples of the waste product for the purposes of waste classification as described in 10 CFR 61.55, Waste Classification.

For those systems that provide tank recirculation, the inspectors evaluated whether the tank recirculation procedures provided sufficient mixing.

The inspectors assessed whether the licensees 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 licensees 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 licensees use of scaling factors and calculations to account for difficult-to-measure radionuclides was technically sound and based on current 10 CFR Part 61 analyses for the selected radioactive waste streams.

The inspectors evaluated whether changes to plant operational parameters were taken into account to:

(1) maintain the validity of the waste stream composition data between the annual or biennial sample analysis update; and
(2) assure that waste shipments continued to meet the requirements of 10 CFR Part 61 for the waste streams selected above.

The inspectors evaluated whether the licensee had established and maintained an adequate Quality Assurance Program to ensure compliance with the waste classification and characterization requirements of 10 CFR 61.55, Waste Classification, and 10 CFR 61.56, Waste Characteristics.

b. Findings

No findings were identified.

.5 Shipment Preparation (02.05)

a. Inspection Scope

The inspectors observed shipment packaging, surveying, labeling, marking, placarding, vehicle checks, emergency instructions, disposal manifest, shipping papers provided to the driver, and licensee verification of shipment readiness. The inspectors assessed whether the requirements of applicable transport cask certificate of compliance had been met. The inspectors evaluated whether the receiving licensee was authorized to receive the shipment packages. The inspectors evaluated whether the licensees procedures for cask loading and closure procedures were consistent with the vendors 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 licensees response to NRC Bulletin 79-19, Packaging of Low-Level Radioactive Waste for Transport and Burial, dated August 10, 1979; and
  • Title 49 CFR Part 172, Hazardous Materials Table, Special Provisions, Hazardous Materials Communication, Emergency Response Information, Training Requirements, and Security Plans, Subpart H, Training.

Due to limited opportunities for direct observation, the inspectors reviewed the technical instructions presented to workers during routine training. The inspectors assessed whether the licensees training program provided training to personnel responsible for the conduct of radioactive waste processing and radioactive material shipment preparation activities.

b. Findings

No findings were identified.

.6 Shipping Records (02.06)

a. Inspection Scope

The inspectors evaluated whether the shipping documents indicated the proper shipper name; emergency response information and a 24-hour contact telephone number; accurate curie content and volume of material; and appropriate waste classification, transport index, and UN number for the following radioactive shipments:

  • LW12-006; Radioactive Material, LSA-I, 7, UN 2912, 40-Foot Seavan Containing Dry Active Waste To Be Processed at Energy Solutions Bear Creek Facility, Oak Ridge Tennessee; February 15, 2012;
  • LW13-024; Radioactive Material, LSA-II, 7, UN 3321; Condensate Pre-Filter Septa Liner to Energy Solutions Bear Creek Facility, Oak Ridge Tennessee; July 25, 2013;
  • LW12-037; Radioactive Material, LSA-II, 7, UN 3321; 21-300FR Liner of Dewatered Bead Resin in 14-215H-26 Cask; to Clive Disposal Facility, Utah; October 12, 2012; and
  • LW12-002; Radioactive Material, LSA-II, 7, UN 3321; Fissile Excepted; Dewatered Bead Resin; Clive Disposal Facility, Clive, Utah; January 10, 2012.

Additionally, the inspectors assessed whether the shipment placarding was consistent with the information in the shipping documentation.

b. Findings

No findings were identified.

.7 Identification and Resolution of Problems (02.07)

a. Inspection Scope

The inspectors assessed whether problems associated with radioactive waste processing, handling, storage, and transportation were being identified by the licensee at an appropriate threshold, were properly characterized, and were properly addressed for resolution in the licensees 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 licensees corrective actions for issues identified during those audits.

b. Findings

No findings were identified.

OTHER ACTIVITIES

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

4OA1 Performance Indicator Verification

Main article: IP 71151

.1 Mitigating Systems Performance Index - Emergency AC Power System

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index (MSPI) - Emergency AC Power System performance indicator for Units 1 and 2 for the third quarter 2012 through the second quarter 2013. To determine the accuracy of the performance indicator (PI) data reported, PI definitions and guidance in Nuclear Energy Institute (NEI) Document 99-02, Regulatory Assessment Performance Indicator Guideline, Revision 6, were used. The inspectors reviewed the licensees 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 licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified.

Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

.2 Mitigating Systems Performance 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 licensees operator narrative logs, issue reports, MSPI derivation reports, event reports, and NRC Integrated Inspection Reports for July 2012 through June 2013 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

.3 Mitigating Systems Performance 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 licensees operator narrative logs, issue reports, MSPI derivation reports, event reports, and NRC Integrated Inspection Reports for July 2012 through June 2013 to validate the accuracy of the submittals. The inspectors reviewed the MSPI component risk coefficient to determine if it had changed by more than 25 percent since the previous inspection, and if so, that the change was in accordance with applicable NEI guidance.

The inspectors also reviewed the licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

This inspection constituted two MSPI residual heat removal system samples as defined in IP 71151-05.

b. Findings

No findings were identified.

.4 Mitigating Systems Performance Index - Cooling Water Systems

a. Inspection Scope

The inspectors sampled licensee submittals for the Mitigating Systems Performance Index - Cooling Water Systems PI for Units 1 and 2 for the fourth quarter 2012 through the second quarter 2013. To determine the accuracy of the PI data reported, PI definitions and guidance in NEI 99-02 were used. The inspectors reviewed the licensees 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 licensees issue report database to determine if any problems had been identified with the PI data collected or transmitted for this indicator and none were identified. Documents reviewed are listed in the Attachment to this report.

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

b. Findings

No findings were identified.

.5 Occupational Exposure Control Effectiveness

a. Inspection Scope

The inspectors sampled licensee submittals for the occupational radiological occurrences PI for the first quarter 2012 through the second quarter 2013. The inspectors used PI definitions and guidance in NEI 99-02 to determine the accuracy of the PI data reported. The inspectors reviewed the licensees 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 licensees 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

Main article: IP 71152

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

a. Inspection Scope

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

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

These routine reviews for the identification and resolution of problems did not constitute any additional inspection samples. Instead, by procedure they were considered an integral part of the inspections performed during the quarter and documented in 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 licensees CAP. This review was accomplished through inspection of the stations daily condition report packages.

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

b. Findings

No findings were identified.

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

Main article: IP 71153

.1 (Closed) Licensee Event Report (LER) 05000374/2013-002-00: Manual Reactor Scram

Following Trip of Circulating Water Pumps

a. Inspection Scope

This event, which occurred on April 25, 2013, involved an evolution designed to enable the licensee to access and repair a condenser tube leak identified on the Unit 2 main condenser east waterbox. An existing procedure was utilized to allow the unit to stay at power while the affected half of the waterbox was isolated and drained. However, during the execution of this evolution, the circulating water (CW) system had its isolation boundary challenged by operators while the waterbox manway covers were still open, which resulted in the flooding of the condenser pit, a CW pump trip, and manual scram.

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

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

b. Findings

Failure to Follow Procedure Led to Manual Scram with Complications

Introduction:

A self-revealed finding preliminarily determined to be of low-to-moderate safety significance (White) was identified for the licensees failure to follow procedure LOP-CW-10, Dewatering the Circulating Water System, Revision 32, on Unit 2.

Specifically, operators executed the condenser waterbox dewatering evolution in a manner inconsistent with procedural guidance, resulting in a circulating water pump trip, loss of the normal heat sink, and reactor scram.

Description:

On April 25, 2013, during Unit 2s 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.

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 licensees failure to follow the prescribed steps of procedure LOP-CW-10 was reasonably within the licensees ability to foresee and correct and should have been prevented, and is therefore considered a performance deficiency warranting a significance determination. The inspectors used Inspection Manual Chapter (IMC) 0609 Appendix A, The Significance Determination Process (SDP) for Findings At-Power Exhibit 1, dated June 19, 2012, for the Initiating Events cornerstone. The inspectors answered yes to the screening question, Did the finding cause a reactor trip AND the loss of mitigation equipment relied upon to transition the plant from the onset of the trip to a stable shutdown conditions? The loss of a condenser is cited as an example of such an event. A detailed risk evaluation was required.

The Senior Reactor Analysts (SRAs) used the LaSalle Unit 1 SPAR model as a surrogate for the Unit 2 performance deficiency to perform the detailed risk evaluation.

The SPAR model revision was 8.21. Several modifications were performed by Idaho National Laboratory to appropriately model plant response to a loss of condenser heat sink event.

In accordance with Risk Assessment of Operational Events Handbook guidance, for findings that cause initiating events to occur, the initiating event that was observed is set to 1.0 or True and the conditional core damage probability is calculated. The conditional core damage probability is multiplied by one inverse year (yr-1) to equate this to a change in core damage frequency for the performance deficiency. For this finding, the initiating event Loss of Condenser Heat Sink was set to 1.0 using the events and condition assessment module of the Systems Analysis Program for Hands-On Integrated Reliability Evaluations (SAPHIRE), Version 8.

The calculated conditional core damage probability for a loss of condenser heat sink event was 1.6E-6, which represents a finding of low to moderate safety significance (White). The dominant sequence is a loss of condenser heat sink event with loss of all decay heat removal due to failure of suppression pool cooling and failure of containment venting. Late injection after containment failure is also failed.

LaSalle Unit 2 has a Mark II containment. The SRAs used IMC 0609 Appendix H, Containment Integrity Significance Determination Process dated May 6, 2004, to evaluate the potential risk contribution due to large early release frequency. The finding was a Type A finding in which the finding has an impact on core damage frequency.

The dominant sequences involved long-term accident sequences that involve failure of containment heat removal that eventually progresses to containment failure. These sequences do not contribute to large early release frequency because it is assumed that effective emergency response actions can be taken within the long time frame of the accident sequences.

The licensee also performed an analysis of the performance deficiency using the LaSalle probabilistic risk assessment (PRA) model and provided it to the NRC for information.

The analysis used several different methodologies which produced slightly different results. The SRAs determined that the licensee analysis was consistent with the NRC analysis if similar assumptions were applied. However, the overall conclusion of the licensee analysis was that this performance deficiency was best represented by a finding of very low safety significance (Green). The NRC determined that the NRC evaluation using standard SDP and Risk Assessment of Operational Events Handbook guidance and the modified SPAR model were appropriate tools for the SDP evaluation and the finding was best characterized as a finding of low to moderate safety significance (White).

The finding had a cross-cutting aspect in the area of human performance, decision-making, because the licensee failed to use conservative assumptions when planning and executing the dewatering evolution. Specifically, the incorrect assumption that this evolution performed at-power could be treated the same as when performed during a shutdown condition enabled operators to stray from strict procedure adherence and into knowledge space (H.1(b)).

Enforcement:

This finding preliminarily determined to be of low-to-moderate safety significance (White) did not involve a violation of regulatory requirements because the systems involved were not safety-related and the evolution was not considered an activity affecting quality. The event was captured in the licensees CAP as AR 01506809 and is being documented as FIN 05000374/2013004-01, Failure to Follow Procedure Led to Manual Scram with Complications. Corrective actions included various training activities for operators, procedure revisions, and potential physical enhancements to the CW isolation valves.

.2 (Closed) LER 050002013-001-00: Pin Hole Leaks Identified in High Pressure Core

Spray Piping On April 18, 2013, Unit 2 was in Mode 3 following a scram and a loss of offsite power that had occurred on both units the previous day. Three pin-hole through-wall leaks in the U2 HPCS minimum flow line piping were discovered. The leaks were on the outside bend of the first elbow downstream of the minimum flow restricting orifice, and appeared to be leaking a total of approximately 0.5 gallons per minute (gpm) with the HPCS pump not running.

Unit 2 HPCS was declared inoperable and, because the HPCS minimum flow line is in direct communication with the suppression pool, primary containment was also declared inoperable. The direct cause of the event was a combination of cavitation and mechanical wear/erosion of the piping wall. Corrective actions included replacing the leaking pipe elbow, and performing ultrasonic inspections of susceptible piping on both Units. Also, HPCS operating procedures were reviewed and revised. Documents reviewed are listed in the Attachment to this report. This LER is closed.

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

Findings Inadequate Procedures Led to Pin Hole Leaks in High Pressure Core Spray Piping

Introduction:

A finding of very low safety significance and associated non-cited violation of 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, was self-revealed for the failure to have procedures adequate for the circumstances during long-term operation of the HPCS system on minimum flow.

Description:

On April 17, 2013, following a station dual-unit loss of offsite power, the HPCS system started on both units. Unit 2 HPCS system ran in minimum flow mode for about 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> and Unit 1 HPCS system ran in minimum flow mode for about 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> 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 licensees 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 licensees 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 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br />.

Licensee procedure LOP-HP-04, Shutdown of High Pressure Core Spray System After An Automatic Initiation, Revision 11, had a precaution statement that, In order to minimize pump degradation, consideration should be made to secure the HPCS pump when extended periods of operation on minimum flow is expected. In addition, there was a note in the body of the procedure that says that if the pump is to be run in the min-flow mode for longer than 30 minutes then an additional flow path should be provided by running in the full flow test mode. However, these warnings do not specify that the pump cannot be run in min-flow for long periods of time; instead, the procedure only specifies that the pump should not be operated in min-flow for long periods of time. Finally, LOP-HP-04 neither had any procedural guidance on how to operate in the full flow test mode with a high drywell pressure signal present nor did it reference any other procedure on how to operate the system in this manner.

Analysis:

The inspectors determined that having HPCS operating procedures that were inadequate for the circumstances of running HPCS in the minimum flow mode for extended periods was contrary to 10 CFR 50, Appendix B, Criterion V, and was a performance deficiency.

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

Specifically, the procedural guidance given to operate the HPCS system was inadequate to prevent long-term operation of the system in the minimum flow mode of operation that led to cavitation and flow-induced wear which resulted in 3 pin hole leaks in the Unit 2 HPCS min-flow line.

The inspectors determined that the finding could be evaluated in accordance with IMC 0609, Appendix A, The Significance Determination for Findings At-Power, dated June 19, 2012, and Appendix H, Containment Integrity Significance Determination Process, dated May 6, 2004. The inspectors used Section A of Exhibit 2 of Appendix A, Mitigating Systems Screening Questions. The inspectors answered all four questions No because even with the holes in the minimum flow line the HPCS could still inject and therefore did not lose its safety function.

The inspectors also reviewed IMC 0609, Appendix H, Section 6.0, Procedure For Type B Findings. A Type B finding is one that has no effect on delta-core damage frequency. The inspectors entered Table 6.1 and determined that a phase two review was necessary because LaSalle has a Mark II containment and the finding impacted suppression pool integrity. The inspectors then entered Table 6.2 which stated that if the leakage from the drywell was less than 100 percent of the drywell volume per day then the issue screened as Green. The inspectors determined that leakage from the drywell to the environment was less than 100 percent per day based on information from IMC 0308, Appendix H, Technical Basis, Containment Integrity Significance Determination Process (IMC 0609, App H) For Type A and Type B Findings Full Power and Shutdown Operations, dated May 6, 2004. Inspection Manual Chapter 0308, Section 2.2, stated that the hole size that would result in leakage equivalent to greater than 100 percent of the containment volume per day would have a diameter of greater that one inch. A circle around all the holes combined found in the HPCS piping was less than 0.5 inches in diameter. Therefore, this issue screens as Green.

The inspectors did not identify a cross-cutting aspect associated with this finding.

Enforcement:

Title 10 CFR Part 50, Appendix B, Criterion V, Instructions, Procedures, and Drawings, requires, in part, that activities affecting quality be prescribed by documented instructions, procedures, or drawings, of a type appropriate to the circumstances and be accomplished in accordance with these instructions, procedures, or drawings. Procedure LOP-HP-04, Shutdown of High Pressure Core Spray System After an Automatic Initiation, Revision 11, is considered an activity affecting quality by the licensee as well as by the NRC.

Contrary to the above, on April 17, 2013, the licensee failed to have procedures of a type appropriate to the circumstances needed to operate and shut down the HPCS system.

Specifically, the procedural guidance available to the operators allowed them to operate the HPCS system in the min-flow mode for 17 hours1.967593e-4 days <br />0.00472 hours <br />2.810847e-5 weeks <br />6.4685e-6 months <br /> on Unit 2 and 15 hours1.736111e-4 days <br />0.00417 hours <br />2.480159e-5 weeks <br />5.7075e-6 months <br /> 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 licensees CAP (as ARs 1503825 and 1530682), this violation is being treated as an NCV, consistent with Section 2.3.2 of the NRC Enforcement Policy (NCV 05000373/2013004-02; 05000374/2013004-02, Inadequate Procedures Led to Pin Hole Leaks in High Pressure Core Spray Piping).

As corrective actions, the licensee immediately declared the HPCS system and the primary containment inoperable and entered the applicable TS actions. The affected pipe elbow was then promptly replaced and the systems returned to service.

Additionally, an extent of condition examination was performed on other potentially effected sections of piping. Finally, to prevent recurrence, the licensee revised the effected procedures.

.3 (Closed) LER 050002012-001-00: 2B DG Declared Inoperable Due to Excessive Air

Start Receiver Blowdown Caused by a Degraded Drain Valve This event, which occurred on August 31, 2012, involved preventive maintenance that was being performed on the 2B DG A train starting air receiver, which was not intended to cause the system to be inoperable. While operators were blowing down the air receiver, the pressure decreased below the minimum allowable 165 pounds per square inch (psig) required for DG operability per TS 3.8.3 Condition D. The licensee declared the system out of service and entered the appropriate TS action statement. Shortly thereafter, system pressure was restored and the 2B DG was declared operable. The cause of the event was determined to be a degraded drain valve on the receiver. The licensee replaced the valve at a later date to prevent recurrence. No findings were identified. This LER is closed.

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

.4 (Closed) LER 050002013-003-00: Low Pressure Core Spray System Declared

Inoperable Due to Faulty Control Switch This event occurred on April 18, 2013, while Unit 1 was in Mode 3 following a loss of offsite power event and dual unit scram the previous day. While attempting to raise Unit 1 reactor water level using the Low Pressure Core Spray (LPCS) system, LPCS injection motor-operated valve 1 E21-F005 failed to open when its control switch was held in the "OPEN" position. The LPCS system was declared inoperable but available, and the appropriate TS action statement was entered, requiring that LPCS be restored to operable status within seven days.

The cause of the event was determined to be the failure of the control switch due to the buildup of oxidation on the contact surfaces. All other contacts in the switch were found to be working normally. The corrective action was to replace the control switch.

A sample of similar switches has been scheduled to be tested to determine if electrical contact erosion is starting to occur on other switches with similar in-service life installed in similar electrical circuits.

This event was also discussed in greater detail and was associated with a non-cited violation previously documented in NRC Special Inspection Report 05000373/2013009; 05000374/2013009. No additional findings were identified during this LER review. This LER is closed.

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

.5 (Discussed) LER 05000373/2012-001-00, 374/2012-001-00: Secondary Containment

Inoperable Due to Interlock Doors Open As previously described in NRC inspection report 05000373/2013003; 05000374/2013003 02, the inspectors are in the process of reviewing the adequacy of the licensees 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 licensees implemented and planned corrective actions in response to the events described in the subject LER. Since resolution of the associated URI is necessary to determine if there are any violations of NRC requirements, this LER review will not be closed at this time.

Documents reviewed are listed in the Attachment to this report. This LER is not closed.

This continuation of an event follow-up review did not constitute a completed sample as defined in IP 71153-05.

.7 (Closed) LER 050002013-004-00: Reactor Pressure Exceeded 150 psig With Reactor

Core Isolation Cooling Inoperable This event occurred on April 22, 2013, while Unit 1 was in Mode 2, Startup. Reactor pressure was increased to above 150 psig with the RCIC system isolated and inoperable. This was an action prohibited by TS and was previously discussed and documented as a Licensee-Identified Green NCV in NRC Inspection Report 05000373/2013002; 05000374/2013002, Section 4OA7. No additional findings were identified. Documents reviewed are listed in the Attachment to this report. This LER is closed.

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

.8 Review of Event Notification EN 49167 Retraction

On July 1, 2013, the licensee made a 10 CFR 50.72 event notification (EN 49167) for the Unit 2 HPCS minimum flow valve pressure switch setpoint found outside of tolerance. The setpoint was found at 112.6 psig instead of greater than or equal to 113.2 psig. At the time of notification, the licensee determined that this was a condition that could have prevented fulfillment of a safety function needed to mitigate the consequences of an accident. On August 5, 2013, the licensee determined that premature opening of the HPCS minimum flow valve would not have prevented the HPCS from fulfilling its safety function since the licensees 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 licensees 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

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

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 NCV Inadequate Procedures Led to Pin Hole Leaks in High
05000374/2013004-02 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 NCV Inadequate Procedures Led to Pin Hole Leaks in High
05000374/2013004-02 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 LER Secondary Containment Inoperable Due to Interlock
05000374/2012-001-00 Doors Open (Section 4OA2.5)
05000373/2013-001-00 LER Secondary Containment Inoperable Due to Interlock
05000374/2013-001-00 Doors Open (Section 4OA2.6)

Attachment

LIST OF DOCUMENTS REVIEWED

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