NRC 2013-0021, Request for Approval of Risk-Informed/Safety Based Inservice Inspection Alternative for Class 1 and 2 Piping in Accordance with 10 CFR 50.55a(a)(3)(i)

Request for Approval of Risk-Informed/Safety Based Inservice Inspection Alternative for Class 1 and 2 Piping in Accordance with 10 CFR 50.55a(a)(3)(i)

ML13079A092
Person / Time
Site:	Point Beach
Issue date:	03/19/2013
From:	Meyer L Point Beach
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
NRC 2013-0021
Download: ML13079A092 (103)

Text

7 POINT BEACH March 19, 2013 NRC 2013-0021 10 CFR 50.55a U. S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Nuclear Plant Units 1 and 2 Dockets 50-266 and 50-301 Renewed License Nos. DPR-24 and DPR-27 Request for Approval of Risk-InformedISafetv Based lnservice lnspection Alternative for Class 1 And 2 Pipinq In Accordance With 10 CFR 50.55a(a)(3)(i)

In accordance with 10 CFR 50.55a, "Codes and Standards," Paragraph (a)(3)(i), NextEra Energy Point Beach, LLC (NextEra) requests that the Nuclear Regulatory Commission (NRC) grant relief from the requirements of the American Society of Mechanical Engineers (ASME)

Boiler and Pressure Vessel Code (B&PV Code),Section XI, 2007 Edition with Addenda through 2008 from the requirements of IWB-2200 IWB-2420, IWB-2430, and IWB-2500, which provide the examination requirements for Category B-F and Category B-J welds. Similarly, relief is requested from the requirements IWC-2200, IWC-2420, IWC-2430, and IWC-2500, which provide the examination requirements for Category C-F-1 and C-F-2 welds. Relief is requested on the basis that alternative methods will provide an acceptable level of quality and safety.

Specifically, NextEra proposes to use a risk-informedlsafety-based inservice inspection (RIS-B) process as an alternate to the current IS1 program for Class 1 and 2 piping. The RIS-B process used in this submittal is based upon ASME Code Case N-716, Alternative Piping Classification and Examination Requirements,Section XI, Division 1.

Code Case N-716 is founded, in large part, on the risk-informed inservice inspection (RI-ISI) process described in Electric Power Research Institute (EPRI) Topical Report (TR) 112657 Rev. B-A, Revised Risk-Informed lnservice lnspection Evaluation Procedure, December 1999 (ML013470102) which was previously reviewed and approved by the NRC.

In general, a risk-informed program replaces the number and locations of nondestructive examination (NDE) inspections based on ASME Code,Section XI requirements with the number and locations of these inspections based on the risk-informed guidelines. These processes result in a program consistent with the concept that, by focusing inspections on the most safety-significant welds, the number of inspections can be reduced while at the same time maintaining protection of public health and safety.

NextEra Energy, LLC, 6610 Nuclear Road, Two Rivers, WI 54241

Document Control Desk Page 2 NextEra requests approval of this request prior to January 31, 2014.

Summaw of Commitments This submittal contains no new commitments or revisions to existing commitments.

Very truly yours, NextEra Energy Point Beach, LLC Site Vice President Enclosure cc: Regional Administrator, Region Ill, USNRC Project Manager, Point Beach Nuclear Plant, USNRC Resident Inspector, Point Beach Nuclear Plant, USNRC PSCW Mr. Mike Verhagan, Department of Commerce, State of Wisconsin

ENCLOSURE NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS 1 AND 2 REQUEST FOR APPROVAL OF RISK-INFORMEDISAFETY BASED INSERVICE INSPECTION ALTERNATIVE FOR CLASS 1 AND 2 PIPING IN ACCORDANCE WITH 10 CFR 50.55a(a)(3)(i)

Table of Contents

1. Introduction 1.I Relation to NRC Regulatory Guides 1.I74 and 1.I 78 1.2 Probabilistic Risk Assessment (PRA) Quality

2. Proposed Alternative to Current Inservice Inspection Programs 2.1 ASME Section XI 2.2 Augmented Programs

3. Risk-lnformedlsafety-Based IS1 Process 3.1 Safety Significance Determination 3.2 Failure Potential Assessment 3.3 Element and NDE Selection 3.3.1 Current Examinations 3.3.2 Successive Examinations 3.3.3 Scope Expansion 3.3.4 Program Relief Requests 3.4 Risk Impact Assessment 3.4.1 Quantitative Analysis 3.4.2 Defense-in-Depth 3.5 Implementation 3.6 Feedback (Monitoring)

4. Proposed IS1 Plan Change

5. Precedents

6. ReferenceslDocumentation Attachment A - Probabilistic Risk Assessment Quality Review Page 1 of 28

1. INTRODUCTION Point Beach Nuclear Plant (PBNP) Units 1 and 2 have entered the Fifth inservice inspection (ISI) Interval as defined by the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Section XI Code. PBNP plans to implement a risk-informedlsafety-basedinservice inspection (RIS-B) program in the Fifth IS1 Interval. The Fifth IS1 Interval began in August 2012.

The ASME Section XI Code of record for the Fifth IS1 Interval is the 2007 Edition through the 2008 Addenda for Examination Category B-F, B-J, C-F-1, and C-F-2 Class 1 and 2 piping components.

The RIS-B process used in this submittal is based upon ASME Code Case N-716, Alternative Piping Classification and Examination Requirements,Section XI, Division 1, which is founded in large part on the risk-informed inservice inspection (RI-ISI) process as described in Electric Power Research Institute (EPRI)

Topical Report (TR) 112657 Rev. B-A, Revised Risk-Informed lnsewice lnspection Evaluation Procedure.

1.1 Relation to NRC Regulatory Guides 1.174 and 1.178 As a risk-informed application, this submittal meets the intent and principles of Regulatory Guide 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions On Plant-Specific Changes to the Licensing Basis, and Regulatory Guide 1.178, An Approach for Plant-Specific Risk-Informed Decisionmaking for lnsewice lnspection of Piping. Add itional information is provided in Section 3.4.2 relative to defense-in-depth.

1.2 Probabilistic Risk Assessment (PRA) Quality NextEra Energy Point Beach, LLC (NextEra) employs a multi-faceted approach to establishing and maintaining the technical adequacy and plant fidelity of the probabilistic risk assessment (PRA) models for all operating NextEra Energy nuclear generation sites. This approach includes both a proceduralized PRA maintenance and update process, and the use of self-assessments and independent peer reviews. The following information describes this approach as it applies to the PBNP PRA.

PRA Maintenance and Update The NextEra risk management process ensures that the applicable PRA model remains an accurate reflection of the as-built and as-operated plant. This process is defined in the PBNP PRA Guideline for Model Maintenance and Update. This procedure also delineates the responsibilities and guidelines for updating the full power internal events PRA models at PBNP. This procedure also defines the process for implementing regularly scheduled and interim PRA model updates, for tracking issues identified as potentially affecting the PRA models (e.g., due to changes in the plant, errors or limitations identified in the model, industry operational experience), and for controlling the model and associated computer files. To ensure that the current PRA model remains an accurate reflection of the as-built, as-operated plant, the following activities are routinely performed:

Design changes and procedure changes are reviewed for their impact on the PRA model.

Existing calculations, as credited in the Model, are reviewed for their impact.

Plant specific initiating event frequencies, failure rates, and maintenance unavailabilities are updated approximately every three to four years.

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In addition to these activities, NextEra risk management procedures provide the guidance for particular risk management and PRA quality and maintenance activities. This guidance includes:

Documentation of the PRA model, PRA products, and bases documents.

The approach for controlling electronic storage of Risk Management (RM) products including PRA update information, PRA models, and PRA applications.

Guidelines for updating the full power, internal events PRA models for NextEra Energy nuclear generation sites.

Guidance for use of quantitative and qualitative risk models in support of the On-Line Work Control Process Program for risk evaluations for maintenance tasks (corrective maintenance, preventive maintenance, minor maintenance, surveillance tests and modifications) on systems, structures, and components (SSCs) within the scope of the Maintenance Rule (10 CFR 50.65(a)(4)).

In accordance with this guidance, regularly scheduled PRA model updates nominally occur on an approximately four-year cycle; longer intervals may be justified if it can be shown that the PRA continues to adequately represent the as-built, as-operated plant. NextEra performed a regularly scheduled update to the Unit 1 and Unit 2 PRA model in December 201 1 and March 2013.

PRA Self Assessment and Peer Review Several assessments of technical capability have been made, and continue to be planned, for the PBNP PRA models. These assessments are as follows:

In November 2010, a full scope Peer Review was performed by the PWROG against the available versions of the ASME PRA Standard and Regulatory Guide 1.200, Revision 2, An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities.

In August 201 1, a focused scope Peer Review of the lnternal Flooding Supporting Requirements by independent contractors was reviewed against the available versions of the ASME PRA Standard and Regulatory Guide 1.200, Revision 2.

In October, 201 1, a Peer Review of the findings and suggestions from the November 2010 full scope peer review, except Internal Flooding SRs, by independent contractors, was reviewed against the available versions of the ASME PRA Standard and Regulatory Guide 1.200, Revision 2.

A Full Scope PRA Peer Review for the PBNP PRA model was completed in November 2010. This peer review was performed against the available version of the ASME PRA Standard and Regulatory Guide 1.ZOO, Revision 2 and followed the Follow-On PRA Peer Review process. This peer review included an assessment of the PRA model maintenance and update process. This peer review defined a list of 71 findings for which potential gaps to Capability Category II of the Standard were identified.

A focused peer review of the updated internal flooding study (IF) was conducted in August 201 1.

This peer review was performed against the available version of the ASME PRA Standard and Regulatory Guide 1.200, Revision 2 and followed the Follow-On PRA Peer Review process. Six of the original 13 findings were not resolved and two new ones were identified during the focused peer Page 3 of 28

review. Attachment A contains a summary of these eight findings, including the status of the resolution for each finding and the potential impact of each finding on this application.

Another peer review of the updated PRA excluding IF was conducted in October 201 1. This peer review was performed against the available version of the ASME PRA Standard and Regulatory Guide 1.200, Revision 2 and followed the Follow-On PRA Peer Review process.

Twenty-Seven of the original findings were not resolved and 4 new ones were identified during the focused peer review. Attachment A contains a summary of these 31 findings, including the status of the resolution for each finding and the potential impact of each finding on this application.

The PRA model was further updated resulting in the PBNP PRA model (Revision 5.01, March 2013) that was used in this submittal. In updating the PRA, changes were made to the PRA to address most of the remaining findings. Following the update, an assessment concluded that 36 of the findings were fully resolved (i.e., are no longer gaps), and another 3 were not resolved. No additional gaps were identified during the performance of the review relative to the updated requirements in Addendum B of the ASME PRA Standard and criteria in RG 1.200, Revision 2, including the NRC position stating Appendix A and other NRC-issued clarifications after the 201 1 gap analysis had been performed. A summary of the current open items including the partially resolved items is provided in .

The remaining gaps will be reviewed for consideration during the future model updates, but are judged to have low impact on the PRA model or its ability to support a full range of PRA applications.

The remaining gaps are documented in a database so that they can be tracked and their potential impacts accounted for in applications where appropriate.

General Conclusion Reaardinn PRA Capabilitv Based on the full scope Peer Review and the subsequent two peer reviews, the PBNP PRA is considered RG 1.200, Revision 2, compliant for Internal Events. In addition, the PBNP PRA maintenance and update processes and technical capability evaluations described above provide a robust basis for concluding that the PRA is suitable for use in risk-informed licensing actions. As specific risk-informed PRA applications are performed, remaining gaps to specific requirements in the PRA standard will be reviewed to determine which, if any, would merit application-specific sensitivity studies in the presentation of the application results.

Assessment of PRA Capabilitv Needed for Risk-Informed lnservice Inspection In the risk-informed inservice inspection (RI-ISI) program at PBNP, the EPRl RI-IS1 methodology is used to define alternative inservice inspection requirements. Plant-specific PRA-derived risk significance information is used during the RI-IS1 plan development to support the consequence assessment, risk ranking and delta risk evaluation steps. The importance of PRA consequence results, and therefore the necessary scope of PRA technical capability, is tempered by two processes in the EPRl methodology.

First, PRA consequence results are binned into one of three conditional core damage probability (CCDP) and conditional large early release probability (CLERP) ranges before any welds are chosen for RI-IS1 inspection. Table 2 illustrates the binning process.

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Table 2 - Consequence Results Binning Groups Consequence CCDP Range CLERP Range Category High CCDP > 1E-04 CLERP > 1E-05 Medium 1E-06 < CCDP < 1E-04 1E-07 < CLERP < 1E-05 LOW CCDP < 1E-06 CLERP < 1E-07 The risk importance of a weld is therefore not tied directly to a specific PRA result. Instead, it depends only on the range in which the PRA result falls. The wide binning provided in the methodology generally reduces the significance of specific PRA results.

Secondly, the influence of specific PRA consequence results is further reduced by the joint consideration of the weld failure potential via a non-PRA-dependent damage mechanism assessment. The results of the consequence assessment and the damage mechanism assessment are combined to determine the risk ranking of each pipe segment (and ultimately each element) according to the EPRl Risk Matrix. The Risk Matrix, which equally takes both assessments into consideration, is reproduced below.

POTENTIAL FOR CONSEQUENCES OF PIPE RUPTURE PIPE RUPTURE IMPACTS ON CONDITIONAL CORE DAMAGE PROBABILITY PER DEGRADATION AND LARGE EARLY RELEASE PROBABILITY MECHANISM SCREENING CRITERIA HIGH FLOW ACCELERATED CORROSION MEDIUM OTHER DEGRADATION These facets of the methodology reduce the influence of specific PRA results on the final list of candidate welds.

The limited use of specific PRA results in the RI-IS1 process is also reflected in the risk-informed license application guidance provided in Regulatory Guide 1.I 74. Section 2.2.6 of Page 5 of 28

Regulatory Guide 1.I74 provides the following insight into PRA capability requirements for this type of application:

There are, however, some applications that, because of the nature of the proposed change, have a limited impact on risk, and this is reflected in the impact on the elements of the risk model.

An example is risk-informed inservice inspection (RI-ISI). In this application, risk significance was used as one criterion for selecting pipe segments to be periodically examined for cracking. During the staff review it became clear that a high level of emphasis on PRA technical acceptability was not necessary. Therefore, the staff review of plant-specific RI-IS1 typically will include only a limited scope review of PRA technical acceptability.

Further, Table 1.3-1 of the ASME PRA Standard 1 identifies the bases for PRA capability categories. The bases for Capability Category I for scope and level of detail attributes of the PRA states:

Resolution and specificity sufficient to identify the relative importance of the contributors at the system or train level including associated human actions.

Based on the above, in general, Capability Category I should be sufficient for PRA quality for a RI-IS1 application.

The EPRl methodology further provides an alternate means to estimate the pipe rupture consequence, namely lookup tables. By using lookup tables, PRA analysis is not involved, and the impact of the loss of systems or trains is done in a generic (not plant-specific) fashion. This allowable alternative underscores the relatively low dependence of the process on specific PRA capabilities.

In addition to the above, it is noted that welds are not eliminated from the IS1 program on the basis of risk information. The risk significance of a weld may fall from Medium Risk Ranking to Low Risk Ranking, resulting in it not being a candidate for inspection. However, it remains in the program, and if, in the future, the assessment of its ranking changes (either by damage mechanism or PRA risk) then it can again become a candidate for inspection. If a weld is determined, outside the PRA evaluation, to be susceptible to either flow-accelerated corrosion (FAC), inter-granular stress corrosion cracking (IGSCC) or microbiological induced cracking (MIC) in the absence of any other damage mechanism, then it moves into an "augmented" program where it is monitored for those special damage mechanisms. That occurs no matter what the Risk Ranking of the weld is determined to be.

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Conclusion Regarding PRA Capability for Risk-Informed IS1 The PBNP Unit 1 and Unit 2 PRA models continue to be suitable for use in the RI-IS1 application.

This conclusion is based on:

the PRA maintenance and update processes in place, the PRA technical capability evaluations that have been performed and are being planned, and the RI-IS1 process considerations, as noted above, that demonstrate the relatively limited reliance of the process on PRA capability.

1 Table A-I of Regulatory Guide 1.200 identifies the NRC staff position as "No objection" to Section 1.3 of the ASME PRA Standard, which contains Table 1.3-1.

2. PROPOSED ALTERNATIVE TO CURRENT IS1 PROGRAMS 2.1 ASME Section XI ASME Section XI Examination Categories B-F, B-J, C-F-1, and C-F-2 currently contain requirements for the nondestructive examination (NDE) of Class 1 and 2 piping components.

The alternative RIS-B Program for piping is described in Code Case N-716. The RIS-B Program will be substituted for the current program for Class 1 and 2 piping (Examination Categories B-F, B-J, C-F-1 and C-F-2) in accordance with 10 CFR 50.55a(a)(3)(i) by alternatively providing an acceptable level of quality and safety. Other non-related portions of the ASME Section XI Code will be unaffected.

2.2 Augmented Programs The impact of the RIS-B application on the various plant augmented inspection programs listed below were considered. This section documents only those plant augmented inspection programs that address common piping with the RIS-B application scope (e.g., Class 1 and 2 piping).

A plant augmented inspection program has been implemented in response to NRC Bulletin 88-08, Thermal Stresses in Piping Connected to Reactor Coolant Systems. This program was updated in response to MRP-146, Materials Reliability Program: Management of Thermal Fatigue in Normally Stagnant Non-lsolable Reactor Coolant System Branch Lines. The thermal fatigue concern addressed was explicitly considered in the application of the RIS-B process and is subsumed by the RIS-B Program.

The plant augmented inspection program for flow accelerated corrosion (FAC) per GL 89-08, Erosion/Corrosion-Induced Pipe Wall Thinning, is relied upon to manage this damage mechanism but is not otherwise affected or changed by the RIS-B Program.

Since the issuance of the NRC safety evaluation for EPRl TR 112657, Rev. B-A, several instances of primary water stress corrosion cracking (PWSCC) of unmitigated Alloy 821182 welds has occurred at pressurized water reactors. For PBNP, the only Alloy 821182 Category B-F dissimilar metal welds (greater than NPS 1) are the four Unit 2 steam generator hot leg and cold leg primary nozzle to safe-end welds. However, these welds were factory clad with 521152 material which is considered to be resistant to PWSCC.

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PBNP intends to manage these welds per the requirements of Code Case N-770-1 as outlined in 10 CFR 50.55a. The examination frequency for these four welds is currently based on the frequencies established by these requirements. The RIS-B Program will not be used to eliminate any MRP-139 or Regulatory requirements.

RISK-INFORMEDISAFETY-BASED IS1 PROCESS The process used to develop the RIS-B Program conformed to the methodology described in Code Case N-716 and consisted of the following steps:

Safety Significance Determination (see Section 3.1)

Failure Potential Assessment (see Section 3.2)

Element and NDE Selection (see Section 3.3)

Risk Impact Assessment (see Section 3.4)

Implementation Program (see Section 3.5)

Feedback Loop (see Section 3.6)

Each of these six steps is discussed below.

3.1 Safety Significance Determination The systems assessed in the RIS-B Program are provided in Table 3.1. The piping and instrumentation diagrams and additional plant information, including the existing plant IS1 Program were used to define the piping system boundaries. Per Code Case N-716 requirements, piping welds are assigned safety-significance categories, which are then used to determine the examination treatment requirements. High safety-significant (HSS) welds are determined in accordance with the requirements below. Low safety-significant (LSS) welds include all other Class 2, 3, or Non-Class welds.

(1) Class 1 portions of the reactor coolant pressure boundary (RCPB), except as provided in 10 CFR 50.55a(c)(2)(i) and (c)(2)(ii);

(2) Applicable portions of the shutdown cooling pressure boundary function. That is, Class 1 and 2 welds of systems or portions of systems needed to utilize the normal shutdown cooling flow path either:

(a) As part of the RCPB from the reactor pressure vessel (RPV) to the second isolation valve (i.e., farthest from the RPV) capable of remote closure or to the containment penetration, whichever encompasses the larger number of welds; or (b) Other systems or portions of systems from the RPV to the second isolation valve (i.e.,

farthest from the RPV) capable of remote closure or to the containment penetration, whichever encompasses the larger number of welds; (3) That portion of the Class 2 feedwater system [> 4 inch nominal pipe size (NPS)] of pressurized water reactors (PWRs) from the steam generator to the outer containment isolation valve; (4) Piping within the break exclusion region (BER) greater than 4" NPS for high-energy piping systems as defined by the Owner. Per Code Case N-716, this may include Class 3 or Non-Class piping. There is no BER augmented program at PBNP.

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(5) Any piping segment whose contribution to Core Damage Frequency (CDF) is greater than 1E-6

[and per NRC feedback on the Grand Gulf and D. C. Cook RIS-B applications 1E-07 for Large Early Release Frequency (LERF)] based upon a plant-specific PSA of pressure boundary failures (e.g., pipe whip, jet impingement, spray, inventory losses). This may include Class 3 or Non-Class piping. Service water piping in the cable spreading room was identified as HSS due to CDF and LERF exceeding the above criteria. This piping is shared between both PBNP units.

Failure Potential Assessment Failure potential estimates were generated utilizing industry failure history, plant-specificfailure history, and other relevant information. These failure estimates were determined using the guidance provided in NRC approved EPRl TR-112657 (i.e., the EPRl RI-IS1 methodology), with the exception of the deviation discussed below.

Table 3.2 summarizes the failure potential assessment by system for each degradation mechanism that was identified as potentially operative.

As previously approved for PBNP during last interval, a deviation to the EPRl RIS-B methodology has been implemented in the failure potential assessment. Table 3-16 of EPRl TR-112657 contains the following criteria for assessing the potential for Thermal Stratification, Cycling, and Striping (TASCS). Key attributes for horizontal or slightly sloped piping greater than NPS 1 include:

1. The potential exists for low flow in a pipe section connected to a component allowing mixing of hot and cold fluids; or

2. The potential exists for leakage flow past a valve, including in-leakage, out-leakage and cross-leakage allowing mixing of hot and cold fluids; or

3. The potential exists for convective heating in dead-ended pipe sections connected to a source of hot fluid; or

4. The potential exists for two phase (steamlwater) flow; or

5. The potential exists for turbulent penetration into a relatively colder branch pipe connected to header piping containing hot fluid with turbulent flow; AND AND P Richardson Number > 4 (this value predicts the potential buoyancy of a stratified flow)

These criteria, based on meeting a high cycle fatigue endurance limit with the actual AT assumed equal to the greatest potential AT for the transient, will identify locations where stratification is likely to occur, but allows for no assessment of severity. As such, many locations will be identified as subject to TASCS, where no significant potential for thermal fatigue exists. The critical attribute missing from the existing methodology, that would allow consideration of fatigue severity, is a criterion that Page 9 of 28

addresses the potential for fluid cycling. The impact of this additional consideration on the existing TASCS susceptibility criteria is presented below.

P Turbulent Penetration TASCS Turbulent penetration is a swirling vertical flow structure in a branch line induced by high velocity flow in the connected piping. It typically occurs in lines connected to piping containing hot flowing fluid. In the case of downward sloping lines that then turn horizontal, significant top-to-bottom cyclic ATs can develop in the horizontal sections if the horizontal section is less than about 25 pipe diameters from the reactor coolant piping. Therefore, TASCS is considered for this configuration.

For upward sloping branch lines connected to the hot fluid source that turn horizontal or in horizontal branch lines, natural convective effects combined with effects of turbulence penetration will tend to keep the line filled with hot water. If there is in-leakage of cold water, a cold stratified layer of water may be formed and significant top-to-bottom ATs may occur in the horizontal portion of the branch line. Interaction with the swirling motion from turbulent penetration may cause a periodic axial motion of the cold layer. Therefore, TASCS is considered for these configurations.

For similar upward sloping branch lines, if there is no potential for in-leakage, this will result in a well-mixed fluid condition where significant top-to-bottom ATs will not occur. Therefore, TASCS is not considered for these no in-leakage configurations. Even in fairly long lines, where some heat loss from the outside of the piping will tend to occur and some fluid stratification may be present, there is no significant potential for cycling as has been observed for the in-leakage case. The effect of TASCS will not be significant under these conditions and can be neglected.

k Low flow TASCS In some situations, the transient startup of a system (e.g., shutdown cooling suction piping) creates the potential for fluid stratification as flow is established. In cases where no cold fluid source exists, the hot flowing fluid will fairly rapidly displace the cold fluid in stagnant lines, while fluid mixing will occur in the piping further removed from the hot source and stratified conditions will exist only briefly as the line fills with hot fluid. As such, since the situation is transient in nature, it can be assumed that the criteria for thermal transients (TT) will govern.

9 Valve leakage TASCS Sometimes a very small leakage flow of hot water can occur outward past a valve into a line that is relatively colder, creating a significant temperature difference. However, since this is generally a "steady-state" phenomenon with no potential for cyclic temperature changes, the effect of TASCS is not significant and can be neglected.

P Convection Heating TASCS Similarly, there sometimes exists the potential for heat transfer across a valve to an isolated section beyond the valve, resulting in fluid stratification due to natural convection. However, since there is no potential for cyclic temperature changes in this case, the effect of TASCS is not significant and can be neglected.

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In summary, these additional considerations for determining the potential for thermal fatigue as a result of the effects of TASCS provide an allowance for considering cycle severity. Consideration of cycle severity was used in previous NRC approved RIS-B program submittals for D. C. Cook, Grand Gulf Nuclear Station, Waterford-3, and the Vogtle Electric Generating Plant as well as PBNP during the past interval. The methodology used in the PBNP RIS-B application for assessing TASCS potential conforms to these updated criteria. Additionally, materials reliability program (MRP)

MRP-146 guidance on the subject of TASCS was also incorporated into the PBNP RIS-B application.

3.3 Element and NDE Selection Code Case N-716 and lessons learned from the Grand Gulf and DC Cook RIS-B applications provided criteria for identifying the number and location of required examinations. Ten percent of the high safety significance (HSS) welds shall be selected for examination as follows:

(1) Examinations shall be prorated equally among systems to the extent practical, and each system shall individually meet the following requirements (for PBNP, because there are limited inside first isolation valve (IFIV) welds present in the RH and SI systems due to the fact that most branch lines are classified as RC out to the first isolation valve, the overall lFlV two-thirds requirement must be satisfied by selecting RC system welds in lieu of normal system-specific selections.):

(a) A minimum of 25% of the population identified as susceptible to each degradation mechanism and degradation mechanism combination shall be selected.

(b) If the examinations selected above exceed 10% of the total number of HSS welds, the examinations may be reduced by prorating among each degradation mechanism and degradation mechanism combination, to the extent practical, such that at least 10% of the HSS population is inspected.

(c) If the examinations selected above are not at least 10% of the HSS weld population, additional welds shall be selected so that the total number selected for examination is at least 10%.

(2) At least 10% of the RCPB welds shall be selected.

(3) For the RCPB, at least two-thirds of the examinations shall be located between the lFlV (i.e., isolation valve closest to the RPV) and the RPV (for PBNP, because there are limited lFlV welds present in the RH and SI systems due to the fact that most branch lines are classified as RC out to the first isolation valve, the overall lFlV two-thirds requirement must be satisfied by selecting RC system welds in lieu of normal system-specific selections.).

(4) A minimum of 10% of the welds in that portion of the RCPB that lies outside containment (not applicable for PBNP) shall be selected.

(5) A minimum of 10% of the welds within the break exclusion region (BER) shall be selected (not applicable to PBNP).

In contrast to a number of traditional RI-IS1 program applications, where the percentage of Class 1 piping locations selected for examination has fallen substantially below lo%, Code Case N-716 mandates that 10% of the HSS welds be chosen. A brief summary of the number of welds and the number selected is provided below, and the results of the selections are presented in Table 3.3.

Section 4 of EPRl TR-112657 was used as guidance in determining the examination requirements for Page 11 of 28

these locations. Only those RIS-B inspection locations that receive a volumetric examination are included.

~lasI s ~eldii(') - ~lass2 -- - @lPiping weldd3)

T unit - - -

Tot31 SElecte_d Total ~el&te=d

~Gta/ Selected I 754 77 1143 8 1897(4) 8 5(4) 2 618 63 1246 10 1864 73 Notes:

(1) Includes all Category B-F and B-J locations. All Class Ipiping weld locations are HSS.

(2) Includes all Category C-F-I and C-F-2 locations. Of the Class 2 piping weld locations, 79 are HSS at Unit 1 and 86 are HSS at Unit 2; the remaining are LSS.

(3) Regardless of safety significance, Class 1, 2, and 3 ASME Section XI in-scope piping components will continue to be pressure tested as required by the ASME Section XI Program. VT-2 visual examinations are scheduled in accordance with the pressure test program that remains unaffected by the RIS-B Program.

(4) Two Class 3 service water piping welds in the cable spreading room are defined as HSS and are included in the RIS-B Program. Of these 2 welds, Iwas selected for inspection. This piping is shared between both PBNP units.

3.3.1 Current Examinations For the fourth interval PBNP was using the NRC approved application using EPRI-TR I12657B-A.

3.3.2 Successive Examinations If indications are detected during RIS-B ultrasonic examinations, they will be evaluated per IWB-3514 (Class I ) or IWC-3514 (Class 2) to determine their acceptability. Any unacceptable flaw will be evaluated per the requirements of ASME Code Section XI, IWB-3600 or IWC-3600, as appropriate. As part of this evaluation, the degradation mechanism that is responsible for the flaw will be determined and accounted for in the evaluation. If the flaw is acceptable for continued service, successive examinations will be scheduled per Section 6 of Code Case N-716. If the flaw is found unacceptable for continued operation, it will be repaired in accordance with IWA-4000, applicable ASME Section XI Code Cases, or NRC approved alternatives. The IWB-3600 analytical evaluation will be submitted to the NRC. Finally, the evaluation will be documented in the corrective action program and the Owner submittals required by Section XI. Evaluation of indications attributed to PWSCC and successive examinations of PWSCC indications will be performed in accordance with MRP-I 39 or a subsequent NRC rule making.

3.3.3 Scope Expansion If the nature and type of the flaw is service-induced, then welds subject to the same type of postulated degradation mechanism will be selected and examined per Section 6 of Code Case N-716. The evaluation will include whether other elements in the segment or additional segments are subject to the same root cause conditions. Additional examinations will be performed on those elements with the same root cause conditions or degradation Page 12 of 28

mechanisms. The additional examinations will include HSS elements up to a number equivalent to the number of elements required to be inspected during the current outage. If unacceptable flaws or relevant conditions are again found similar to the initial problem, the remaining elements identified as susceptible will be examined during the current outage. No additional examinations need be performed if there are no additional elements identified as being susceptible to the same root cause conditions. The need for extensive root cause analysis beyond that required for the IWB-3600 analytical evaluation will be dependent on practical considerations (i.e., the practicality of performing additional NDE or removing the flaw for further evaluation during the outage).

Scope expansion for flaws characterized as PWSCC will be conducted in accordance with MRP-139 or subsequent NRC rule makings.

3.3.4 Program Relief Requests Consistent with previously approved RIS-B submittals, PBNP will calculate coverage and use additional examinations or techniques in the same manner it has for traditional Section XI examinations. Experience has shown this process to be weld-specific (e.g., joint configuration). As such, the effect on risk, if any, will not be known until the examinations are performed. Relief requests for those cases where greater than 90% coverage is not obtained, will be submitted per the requirements of 10 CFR 50.55a(g)(5)(iv).

No PBNP relief requests are being withdrawn due to the RIS-B application.

3.4 Risk Impact Assessment The RIS-B Program development has been conducted in accordance with Regulatory Guide 1.I 74 and the requirements of Code Case N-716, and the risk from implementation of this program is expected to remain neutral or decrease when compared to that estimated from current requirements.

This evaluation categorized segments as high safety significant or low safety significant in accordance with Code Case N-716, and then determined what inspection changes were proposed for each system. The changes included changing the number and location of inspections, and in many cases improving the effectiveness of the inspection to account for the findings of the RIS-B degradation mechanism assessment. For example, examinations of locations subject to thermal fatigue will be conducted on an expanded volume and will be focused to enhance the probability of detection (POD) during the inspection process.

3.4.1 Quantitative Analysis Code Case N-716 has adopted the NRC approved EPRl TR-112657 process for risk impact analyses, whereby limits are imposed to ensure that the change-in-risk of implementing the RIS-B Program meets the requirements of Regulatory Guides 1.I74 and 1.178. Section 3.7.2 of EPRl TR-112657 requires that the cumulative change in CDF and LERF be less than 1E-07 and 1E-08 per year per system, respectively.

For LSS welds, Conditional Core Damage Probability (CCDP)lConditional Large Early Release Probability (CLERP) values of 1E-0411E-05 were conservatively used. The rationale for using these values is that the change-in-risk evaluation process of Code Case N-716 is similar to that of the EPRl risk-informed IS1 (RI-ISI) methodology. As such, the goal is to determine CCDPsICLERPs threshold values. For example, the threshold values between High and Medium consequence categories is 1E-4 (CCDP)Il E-5 (CLERP) and between Page 13 of 28

Medium and Low consequence categories are 1E-6 (CCDP)/l E-7 (CLERP) from the EPRl RI-IS1 Risk Matrix. Using these threshold values streamlines the change-in-risk evaluation as well as stabilizes the update process. For example, if a CCDP changes from 1E-5 to 3E-5 due to an update, it will remain below the 1E-4 threshold value; the change-in-risk evaluation would not require updating.

The updated internal flooding PRA was also reviewed to ensure that there is no LSS Class 2 piping with a CCDPICLERP greater than 1E-411E-5. Based on this review there is no Class 2 piping with a CCDPICLERP that exceeds these values.

With respect to assigning failure potentials for LSS piping, the criteria are defined in Table 3 of Code Case N-716. That is, those locations identified as susceptible to FAC are assigned a high failure potential. Those locations susceptible to thermal fatigue, erosion-cavitation, corrosion, or stress corrosion cracking are assigned a medium failure potential, unless they have an identified potential for water hammer loads. In such cases, they will be assigned a high failure potential. Finally, those locations that are identified as not susceptible to degradation are assigned a low failure potential.

In order to streamline the risk impact assessment, a review was conducted that verified that the LSS piping was not susceptible to water hammer. LSS piping may be susceptible to FAC; however, the examination for FAC is performed per the FAC program. This review was conducted similar to that done for a traditional RI-IS1 application. Thus, the high failure potential category is not applicable to LSS piping. In lieu of conducting a formal degradation mechanism evaluation for all LSS piping (e.g. to determine if thermal fatigue is applicable),

these locations were conservatively assigned to the Medium failure potential ("Assume Medium" in Table 3.4) for use in the change-in-risk assessment. Experience with previous industry RIS-B applications shows this to be conservative.

PBNP has conducted a risk impact analysis per the requirements of Section 5 of Code Case N-716 that is consistent with the "Simplified Risk Quantification Method" described in Section 3.7 of EPRl TR-112657. The analysis estimates the net change-in-risk due to the positive and negative influences of adding and removing locations from the inspection program.

The CCDP and CLERP values used to assess risk impact were estimated based on pipe break location. Based on these estimated values, a corresponding consequence rank was assigned per the requirements of EPRl TR-112657 and upper bound threshold values were used as provided in the table below. Consistent with the EPRl methodology, the upper bound for all break locations that fall within the high consequence rank range was based on the highest CCDP value obtained (e.g., Large LOCA CCDP bounds the medium and small LOCA CCDPs).

Page 14 of 28

CCDP and CLERP Values Based on Break Location Break Location Estimated Consequence Upper Bound Designation CCDP CLERP Rank CCDP CLERP LOCA 2.5E-02 2.50E-03 HIGH 2.5E-02 2.5E-03 RCPB pipe breaks that result in a loss of coolant accident - The highest CCDP for Large LOCA, INIT-A, was used (0.1 margin used for CLERP). Unisolable RCPB piping of all sizes.

PLOCA""~' 1 9.OE-05 I 9.OE-06 I MEDIUM I 1.OE-04 I 1.OE-05 lsolable or Potential LOCA (1 open valve or Iclosed valve) inside containment - RCPB pipe breaks that result in an isolable or potential LOCA - Calculated based on Large LOCA CCDP of 3E-2 and valve fail to close probability of -3E-3 (0.1 margin used for CLERP). Between 1st and 2nd isolation valve inside containment.

PPLOCA(" I <1E-5 I <1E-06 I MEDIUM I 1.OE-04 I 1.OE-05 Potential LOCA (2 closed valves) inside containment - Based on failure of two normally closed valves in series from the ISLOCA analysis. Applies to RHR shutdown cooling suction and discharge paths.

Although the CCDP is less than 1E-6, 1E-5 is used as a bounding value in consideration of RHR operation during shutdown.

FB I 1.OE-05 I 1.OE-06 1 MEDIUM I 1.OE-04 I 1.OE-05 Feedwater breaks based on bounding valve for INIT-FBIC and INIT-FBOC (0.1 margin used for CLERP)

Class 2 LSS I 1.OE-04 I 1.OE-05 ( MEDIUM I 1.OE-04 I 1.OE-05 Class 2 pipe breaks that occur in the remaining system piping designated as low safety significant.

Estimated based on upper bound for Medium Consequence.

1. The PRA does not explicitly model potential and isolable LOCA events, because such events are subsumed by the LOCA initiators in the PRA. That is, the frequency of a LOCA in this limited piping downstream of the first RCPB isolation valve times the probability that the valve fails is a small contributor to the total LOCA frequency. The N-716 methodology must evaluate these segments individually; thus, it is necessary to estimate their contribution. This is estimated by taking the LOCA CCDP and multiplying it by the valve failure probability.

2. PLOCA is identified and used in the quantification of both ILOCA and PLOCA.

The likelihood of pressure boundary failure (PBF) is determined by the presence of different degradation mechanisms and the rank is based on the relative failure probability. The basic likelihood of PBF for a piping location with no degradation mechanism present is given as x, and is expected to have a value less than 1E-08. Piping locations identified as medium failure potential have a likelihood of 20xo. These PBF likelihoods are consistent with References 9 and 14 of EPRl TR-112657. In addition, the analysis was performed both with and without taking credit for enhanced inspection effectiveness due to an increased POD from application of the RIS-B approach.

Table 3.4 presents a summary of the RIS-B Program versus the third IS1 interval (1986 Edition of ASME Section XI) program requirements on a "per system" basis. The presence of FAC was adjusted for in the quantitative analysis by excluding its impact on the failure potential rank. The exclusion of the impact of FAC on the failure potential rank and therefore in the determination of the change-in-risk, was performed because FAC is a damage mechanism managed by a separate, independent plant augmented inspection program. The RIS-B Program credits and relies upon this plant augmented inspection program to manage this damage mechanism. The plant FAC program will continue to determine where and when examinations shall be performed. Hence, since the number of FAC examination locations Page 15 of 28

remains the same "before" and "after" (the implementation of the RIS-B program) and no delta exists, there is no need to include the impact of FAC in the performance of the risk impact analysis.

As indicated in the following tables, this evaluation has demonstrated that unacceptable risk impacts will not occur from implementation of the RIS-B Program, and that the acceptance criteria of Regulatory Guide 1.I 74 and Code Case N-716 are satisfied.

PBNP Unit I With POD Credit Without POD Credit System Delta Delta CDF Delta CDF Delta LERF LERF CV - Chemical Volume & Control -1.12E-10 -1.12E-I1 -6.17E-11 -6.17E-12 FW - Feedwater -2.60E-12 -2.60E-13 1.40E-I 2 1.40E-13 RC - Reactor Coolant -6.61 E-08 -6.61E-09 -8.13E-09 -8.13E-I 0 RH - Residual Heat Removal 6.74E-10 6.74E-11 6.74E-10 6.74E-I 1 SI - Safety Injection 3.19E-I0 3.19E-11 3.19E-I0 3.19E-11 AF - Auxiliary Feedwater 0.00E+00 0.00E+00 0.00E+00 0.00E+00 MS - Main Steam 1.40E-10 I.40E-11 1.40E-10 1.40E-I 1 Total -6.51E-08 -6.51E-09 -7.05E-09 -7.05E-I 0 PBNP Unit 2 With POD Credit Without POD Credit System Delta CDF Delta CDF Delta LERF LERF Delta CV - Chemical Volume & Control -8.10E-I I -8.lOE-12 -4.50E-11 -4.50E-12 FW - Feedwater -7.00E-13 -7.00E-14 2.50E-12 2.50E-13 RC - Reactor Coolant -4.81E-08 -4.81E-09 1.88E-09 1.88E-10 RH - Residual Heat Removal 7.24E-10 7.24E-11 7.24E-10 7.24E-11 SI - Safety Injection 3.28E-10 3.28E-11 3.28E-10 3.28E-I 1 AF - Auxiliary Feedwater 0.00E+00 0.00E+00 0.00E+00 0.00E+00 MS - Main Steam 1.30E-10 1.30E-11 1.30E-10 1.30E-I I Total -4.70E-08 -4.70E-09 3.01E-09 3.01 E-10 As shown in Table 3.4, new RIS-B locations were selected such that the RIS-B selections exceed the Section XI selections for certain categories (Delta column has a positive number).

To show that the use of a conservative upper bound CCDPICLERP does not result in an optimistic calculation with regard to meeting the acceptance criteria, a conservative sensitivity was conducted where the RIS-B selections were set equal to the Section XI selections (Delta changed from positive number to zero). The acceptance criteria are met when the number of RIS-B selections is not allowed to exceed Section XI.

Page 16 of 28

The intent of the inspections mandated by 10 CFR 50.55a for piping welds is to identify conditions such as flaws or indications that may be precursors to leaks or ruptures in a system's pressure boundary. Currently, the process for selecting inspection locations is based upon terminal end locations, structural discontinuities, and stress analysis results. As depicted in ASME White Paper 92-01-01 Rev. 1, Evaluation of Insen~iceInspection Requirements for Class I, Category B-J Pressure Retaining Welds in Piping, this methodology has been ineffective in identifying leaks or failures. EPRl TR-112657 and Code Case N-716 provide a more robust selection process founded on actual service experience with nuclear plant piping failure data.

This process has two key independent ingredients; that is, a determination of each location's susceptibility to degradation and secondly, an independent assessment of the consequence of the piping failure. These two ingredients assure defense-in-depth is maintained. First, by evaluating a location's susceptibility to degradation, the likelihood of finding flaws or indications that may be precursors to leak or ruptures is increased. Secondly, a generic assessment of high-consequence sites has been determined by Code Case N-716, supplemented by plant-specific evaluations, thereby requiring a minimum threshold of inspection for important piping whose failure would result in a LOCA or BER break. Finally, Code Case N-716 requires that any piping on a plant-specific basis that has a contribution to CDF of greater than 1E-06 (or 1E-07 for LERF) be included in the scope of the application.

PBNP identified Class 3 service water piping in the cable spreading room as HSS. This piping is shared between both PBNP units.

All locations within the Class 1, 2, and 3 pressure boundaries will continue to be pressure tested in accordance with the Code, regardless of its safety significance.

Implementation Upon approval of the RIS-B Program, procedures that comply with the guidelines described in Code Case N-716 will be prepared to implement and monitor the program. The new program will be implemented during the fifth IS1 interval. No changes to the Technical Specifications or Updated Final Safety Analysis Report are necessary for program implementation.

The applicable aspects of the ASME Code not affected by this change will be retained, such as inspection methods, acceptance guidelines, pressure testing, corrective measures, documentation requirements, and quality control requirements. Existing ASME Section XI program implementing procedures will be retained and modified to address the RIS-B process, as appropriate.

Feedback (Monitoring)

The RIS-B Program is a living program that is required to be monitored continuously for changes that could impact the basis for which welds are selected for examination. Monitoring encompasses numerous facets, including the review of changes to the plant configuration, changes to operations that could affect the degradation assessment, a review of NDE results, a review of site failure information from the corrective action program, and a review of industry failure information from industry operating experience (OE). Also included is a review of PRA changes for their impact on the RIS-B program. These reviews provide a feedback loop such that new relevant information is obtained that will ensure that the appropriate identification of HSS piping locations selected for examination is maintained. As a minimum, this review will be conducted on an ASME period basis.

Page 17 of 28

In addition, more frequent adjustment may be required as directed by NRC Bulletin or Generic Letter requirements, or by industry and plant-specific feedback.

If an adverse condition, such as an unacceptable flaw is detected during examinations, the adverse condition will be addressed by the corrective action program and procedures. The following are appropriate actions to be taken:

A. Identify (Examination results conclude there is an unacceptable flaw).

B. Characterize (Determine if regulatory reporting is required and assess if an immediate safety or operation impact exists).

C. Evaluate (Determine the cause and extent of the condition identified and develop a corrective action plan or plans).

D. Decide (make a decision to implement the corrective action plan).

E. Implement (complete the work necessary to correct the problem and prevent recurrence).

F. Monitor (through the audit process ensure that the RIS-B program has been updated based on the completed corrective action).

G. Trend (Identify conditions that are significant based on accumulation of similar issues).

For preservice examinations, PBNP will follow the rules contained in Section 3.0 of N-716. Welds classified HSS require a preservice inspection. The examination volumes, techniques, and procedures shall be in accordance with Table 1 of N-716. Welds classified as LSS do not require preservice inspection.

4. PROPOSED IS1 PLAN CHANGE PBNP is currently in the First Period of the Fifth IS1 Interval.

In anticipation of the approval of this RIS-B submittal, selected welds that are being examined during the I"' Period, using the traditional ASME Section XI methodology, also meet the examination requirements of Table 1 of Code Case N-716. After approval of the RIS-B submittal, those welds in the RIS-B scope that were examined during the first period that also met Table 1 requirements may be credited toward the RIS-B requirements for the I"' Period.

As discussed in Section 2.2, implementation of the RIS-B program will not alter any PWSCC examination requirements for the Alloy 821182 examinations.

A comparison between the RIS-B Program and the 1989 Edition of Section XI program requirements for in-scope piping is provided in Table 4. In addition, service water piping in the cable spreading room was identified as high safety significant and is included in the RIS-B Program. Ten percent of the welds will be inspected during the interval. No degradation mechanism was identified for this piping, but a wall thickness type of volumetric exam will be conducted since this is considered most relevant to service water systems.

5. PRECEDENTS

1. NRC letter to Southern Nuclear Operating Company, Inc, dated January 18, 2012, Joseph M. Farley Nuclear Plant, Units 1 and 2 - Risk-Informed Safety-Based lnservice lnspection Alternative for Class I and Class 2 Piping Welds (TAC Nos. ME5273 and ME5274), (ML12012A135)

2. NRC letter to Southern Nuclear Operating Company, Inc, dated March 3, 2010, Vogtle Electric Generating Plant, Units 1 and 2 - Risk-Informed Safety-Based lnservice lnspection Alternative for Class 1 and Class 2 Piping Welds (TAC Nos. ME1097 and ME1098), (ML100610470)

Page 18 of 28

3. NRC letter to Indiana Michigan Power Company, dated September 28, 2007, Donald C. Cook Nuclear Plant, Units 1 and 2 - Risk-Informed Safety-Based lnservice lnspection Alternative for Class 1 and Class 2 Piping Welds (TAC Nos. MD3137 and MD3138), (ML072620553)

4. NRC letter to Entergy Operations, Inc, dated September 21, 2007, Grand Gulf Nuclear Station Unit 1 -

Request for Alternative GG-ISI-002 - Implement Risk-Informed lnservice lnspection Program Based on American Society of Mechanical Engineers Boiler and Pressure Vessel Code, Code Case N-716 (TAC No. MD3044), (ML072430005)

5. NRC letter to Entergy Operations, Inc, dated April 28, 2008, Waterford Steam Electric, Unit 3 - Request for Alternative W3-ISI-005, Request to Use ASME Code Case N-716 (TAC No. MD7061),

(ML080980120)

6. NRC letter to Dominion Nuclear Connecticut, Inc, dated March 27, 2012, Millstone Power Station, Unit No. 2 - Issuance of Relief Request RR-04-11 Regarding Risk-Informed lnservice lnspection Program (TAC No. ME5962), (MLI 20800433)

6. REFERENCESIDOCUMENTATION

1. EPRl Report 1006937, Extension of EPRl Risk Informed IS1Methodology to Break Exclusion Region Programs.

2. EPRl TR-112657, Revised Risk-Informed lnsewice lnspection Evaluation Procedure, Rev. B-A.

3. ASME Code Case N-716, Alternative Piping Classification and Examination Requirements,Section XI Division I.

4. Regulatory Guide 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions On Plant-Specific Changes to the Licensing Basis.

5. Regulatory Guide 1.I 78, An Approach for Plant-Specific Risk-Informed Decisionmaking lnsewice lnspection of Piping.

6. Regulatory Guide 1.200, Rev 2 An Approach For Determining The Technical Adequacy Of Probabilistic Risk Assessment Results For Risk-Informed Activities.

7. USNRC Safety Evaluation for Grand Gulf Nuclear Station Unit 1, Request for Alternative GG-ISI-002-Implement Risk-Informed IS1 based on ASME Code Case N-716, dated September 21, 2007.

8. USNRC Safety Evaluation for DC Cook Nuclear Plant, Units 1 and 2, Risk-Informed Safety-Based IS1 program for Class Iand 2 Piping Welds, dated September 28, 2007.

9. EPRl Report 1021467 Nondestructive Evaluation: Probabilistic Risk Assessment Technical Adequacy Guidance for Risk-Informed In-Sewice lnspection Programs.

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Table 3.la Unit I Code Case N-716 Safety Significance Determination Notes:

I. System Scope:

AF = Auxiliary Feedwater CV = Chemical Volume and Control System FW = Main Feedwater MS = Main Steam RC = Reactor Coolant RH = Residual Heat Removal SI = Safety Injection

2. Two service water piping welds in the cable spreading room are included in the HSS scope due to exceeding the CDF > 1E-6 threshold. This piping is shared between both PBNP units.

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Table 3.1 b Unit 2 Code Case N-716 Safety Significance Determination Safety Weld N-716 Safety Significance Determination Significance System 'I' Count RCPB SDC PWR: FW BER CDF z 1E-6 (I' High Low cv 154 J 4 FW 54 J J 314 J J RC 14 4 J J 9 J 4 4 RH 32 J J 315 J 89 J J SI 38 J J 4 485 J AF 264 J MS 96 J 557 J J Summary 61 4 J J Results for all 32 J J Systems 54 J 4 1160 4 TOTAL 1864 Notes:

1. System Scope:

AF = Auxiliary Feedwater CV = Chemical Volume and Control System FW = Main Feedwater MS = Main Steam RC = Reactor Coolant RH = Residual Heat Removal SI = Safety Injection

2. Two service water piping welds in the cable spreading room are included in the HSS scope due to exceeding the CDF > IE-6 threshold. This piping is shared between both PBNP units.

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Table 3.2 Failure Potential Assessment Summary Notes:

1. Systems are described in Table 3.1.

2. A degradation mechanism assessment was not performed on low safety significant piping segments. This includes the AF and MS in its entirety, as well as portions of the RH and SI systems. A degradation mechanism assessment was also performed of the high safety significant service water piping welds in the cable spreading room; no mechanisms were identified.

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Table 3.3a: Unit 1 Code Case N716 Selections otes:

1. Systems are described in Table 3.1.

2. Two service water piping welds in the cable spreading room are included in the HSS scope due to exceeding the CDF > 1E-6threshold. One weld will be selected for inspection. This piping is shared between both PBNP units Page 23 of 28

Table 3.3b: Unit 2 Code Case N716 Selections Notes:

1. Systems are described in Table 3.1.

2. Two service water piping welds in the cable spreading room are included in the HSS scope due to exceeding the CDF > 1E-6 threshold. One weld will be selected for inspection. This piping is shared between both PBNP units.

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SI Total 3.22E-10 3.22E-10 3.22E-11 3.22E-11 AF Total Low Class 2 LSS Assume Medium 0 0 0 0.00E+00 0.00E+00 0.00E+00 0.00E+00 MS Total Low Class 2 LSS Assume Medium 14 0 -14 1.40E-10 1.40E-10 I.40E-11 I.40E-I 1 Grand Total 261 72 -189 -6.51E-08 -7.04E-09 -6.51 E-09 -7.04E-10 Notes:

1. Systems are described in Table 3.1.

2. Only those ASME Section XI Code inspection locations that received a volumetric examination are included in the count. Inspection locations previously subjected to a surface examination only were not considered in accordance with Section 3.7.1 of EPRl TR-112657.

3. Only those R l S B inspection locations that receive a volumetric examination are included in the count. Locations subjected to VT2 only are not credited in the count for risk impact assessment.

4. The failure potential rank for high safety significant (HSS) locations is assigned as "Highn, "Mediumn,or "Low" depending upon potential susceptibly to the various types of degradation. [Note: Low Safety Significant (LSS) locations were conservatively assumed to be a rank of Medium (i.e., "Assume Medium")

5. The "LSS designation is used to identify those Code Class 2 locations that are not HSS because they do not meet any of the five HSS criteria of Section 2(a) of N-716 (e.g., not part of the BER scope).

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Table 3.4b Unit 2 Risk I m ~ a cAnalvsis t Results I System I ~%

i nce 1 Break

~ocation I DMs Failure Potential I Rank I SXI Inspections I RIS B I Delta I wlPOD CDF impact I wlo POD I LERF Impact wIPOD I wlo POD I FW Total I I I I I I I I -7.00E-12 I 2.50E-11 I -7.00E-13 1 2.50E-12 1 RC High LOCA TT Medium 6 12 6 -4.50E-08 -1.50E-08 -4.50E-09 -1.50E-09 RC High LOCA TT,TASCS Medium 6 3 -3 -4.50E-09 7.50E-09 -4.50E-10 7.50E-10 RC High LOCA TASCS Medium 4 2 -2 -3.00E-09 5.00E-09 -3.00E-10 5.00E-10 RC High LOCA None Low 64 29 -35 4.38E-09 4.38E-09 4.38E-10 4.38E-10 RC High PLOCA None Low 0 0 0 0.00E+00 0.00E+00 0.00E+00 0.00E+00 I RC Total I I I I I I I 1 -4.81E-08 1 1.88E-09 1 -4.81E-09 1 1.88E-10 I RH High PLOCA I None I Low 1 8 1 0 1 -8 ( 4.00E-12 ( 4.00E-12 ( 4.00E-13 I 4.00E-13 1 RH High I PPLOCA I None I Low 1 13 1 4 1 -9 1 4.50E-12 1 4.50E-12 1 4.50E-13 1 4.50E-13 1 RH Low Class 2 LSS Assume Medium 72 0 -72 7.20E-10 7.20E-10 7.20E-11 7.20E-11 RH Total 7.29E-10 7.29E-10 7.29E-11 7.29E-11

--F SI High 1 1 7 Medium 1 1 0 0.00E+00 0.00E+00 0.00E+00 0.00E+00 PLOCA IGSCC SI High PLOCA IGSCC Medium 2 2 0 0.00E+00 0.00E+00 0.00Et00 0.00E+00 S1 High PLOCA 1 None 1 Low 1 39 1 0 1 -39 1 1.95E-11 1 1.95E-11 1 1.95E-12 1 1.95E-12 1 SI Low I class 2 LSS I I Assume Medium 1 31 1 0 1 -31 1 3.10E-10 I 3.10E-10 I 3.10E-11 I 3.10E-11 I 1 SI Total I I I I I I I I 3.30E-10 I 3.30E-10 I 3.30E-11 I 3.30E-11 I AF Total Low Class 2 LSS Assume Medium 0 0 0 0.00E+00 0.00E+00 0.00E+00 0.00E+00 MS Total Low Class 2 LSS Assume Medium 13 0 -13 1.30E-10 1.30E-10 1.30E-11 1.30E-11 Grand Total 277 64 -213 -4.70E-08 3.04E-09 -4.70E-09 3.04E-I 0 Notes:

1. Systems are described in Table 3.1.

2. Only those ASME Section XI Code inspection locations that received a volumetric examination are included in the count. Inspection locations previously subjected to a surface examination only were not considered in accordance with Section 3.7.1 of EPRl TR-112657.

3. Only those RIS-B inspection locations that receive a volumetric examination are included in the count. Locations subjected to VT2 only are not credited in the count for risk impact assessment.

4. The failure potential rank for high safety significant (HSS) locations is assigned as "High", "Medium", or "Low" depending upon potential susceptibly to the various types of degradation. [Note: Low Safety Significant (LSS) locations were conservatively assumed to be a rank of Medium (i.e., "Assume Medium*)

5. The "LSS" designation is used to identify those Code Class 2 locations that are not HSS because they do not meet any of the five HSS criteria of Section 2(a) of N-716 (e.g., not part of the BER scope).

Page 26 of 28

Total 1897 261 430 72 13 Notes:

1. Systems are described in Table 3.1.

2. The column labeled "Other" is generally used to identify plant augmented inspection program locations credited per Section 4 of Code Case N-716. Code Case N-716 allows the existing plant augmented inspection program for IGSCC (Categories B through G) in a BWR to be credited toward the 10%

requirement. This option is not applicable for the PBNP RIS-B application. The "Other" column has been retained in this table solely for uniformity purposes with other RIS-B application template submittals and to indicate when RIS-B selections will receive a VT-2 examination (these are not credited in risk impact assessment).

3. The failure potential rank for high safety significant (HSS) locations is assigned as "High", "Medium", or "Low" depending upon potential susceptibly to the various types of degradation. [Note: Low safety significant (LSS) locations were conservatively assumed to be a rank of Medium (i.e., "Assume Medium").

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SI J PLOCA None Low B-J 121 39 43 0 1 J Assume SI C-F-1 485 31 19 0 NA Class 2 LSS Medium 4 Assume AF 264 0 0 0 NA Class 2 LSS Medium N/A J Assume MS C-F-2 96 13 2 0 NA Class 2 LSS Medium Total 1864 277 283 64 9 Notes:

1. Systems are described in Table 3.1.

2. The column labeled "Other" is generally used to identify plant augmented inspection program locations credited per Section 4 of Code Case N-716. Code Case N-716 allows the existing plant augmented inspection program for IGSCC (Categories B through G) in a BWR to be credited toward the 10%

requirement. This option is not applicable for the PBNP RIS-B application. The "Other" column has been retained in this table solely for uniformity purposes with other RIS-B application template submittals and to indicate when RIS-B selections will receive a VT-2 examination (these are not credited in risk impact assessment).

3. The failure potential rank for high safety significant (HSS) locations is assigned as "High", "Medium", or "Low" depending upon potential susceptibly to the various types of degradation. [Note: Low safety significant (LSS) locations were conservatively assumed to be a rank of Medium (i.e., "Assume Medium").

Page 28 of 28

ATTACHMENT A TO ENCLOSURE NEXTERA ENERGY POINT BEACH, LLC POINT BEACH NUCLEAR PLANT, UNITS I AND 2 PROBABILISTIC RISK ASSESSMENT QUALITY REVIEW

Attachment 1: Point Beach PRA Peer Review Findings Other Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution t- Findin Not Met Finding IE-A1-01 SRs IE-A5 (CC-I)

IE-B2 ( ~ o .t Met)

IE-D2 (Not 2010 Peer Review Finding:

A systematic process for identifying initiating events was not performed. Table 4 (Plant System Review to Determine Special Initiators) in the No - The 2011 Peer Review Finding was resolved in the PRA Model. See resolution below.

2011 Peer Review Plant Response:

Met) initiating events report provides an identification of Table 4, Special initiator column was expanded to include System IE that impact mitigation equipment but tech spec shutdowns and improved to include explanation does not fully address the impact of loss any of why special initiator is not required and 1 or how the normally operating system that could results in an system is subsumed by another initiating event.

IE. For example loss of the 4.1 6 kV AC would lead to an IE due to the loss of component cooling The following text was added to Initiating Events water, loss of instrument air, and loss of CVCS; Notebook, PRA 2.0, Section 1.3.5, "Special Initiators for however, there is no quantitative estimate as a PBNP":

basis for screening out this initiating event. Loss of HVAC in the Electrical Equipment Room HVAC "A review of Table 2-1 in DBD-27, "ACCIDENT ANALYSIS could result in a reactor trip but no documentation REACTOR TRIP VARIABLES, LIMITS, and RESPONSE or room heat up calculations are provided to TIMES" was performed if required to determine if the event support that loss of the system would not generate described in Table 4, column 3, "Description of Event",

a trip. would cause a direct or indirect reactor trip. The results of this review are captured in "Special lnitiating Event?"

Without a systematic review that accounts for column of Table 4."

plant-specific features an initiating event can be missed. New special initiators were identified as part of this review.

4160 VAC Safeguards buses 1A05 and 1A06 on Unit 1, A systematic review should be performed and 2A05 and 2A06 on Unit 2. The Unit is required to shut documented on all normally operating systems. down if one of the safeguards buses cannot be restored Provide a quantitative basis for screening out the within 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br />. CAFTA runs were performed to determine loss of 4.16kV AC bus as an initiator. A the impact of these initiators.

recommendation would be that this review would include documentation of possible failure modes A flag file was used to set all initiators to false except and effect on safety system(s) for each system. lnitiating Event Transient with PCS which had the This is also an ideal location to document possible probability set to the 1 year failure probability of a dual unit impacts. 4160 VAC Vital Switchgear Bus. The flag file also set the 4160 VAC Vital Switchgear bus to failed. The results were the CDF due to a failed 4160 VAC Vital Switchgear bus I

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Attachment I:Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs 2010 Peer Review Finding Response: initiator was between 1.9E-7 and 1.2E-9. LERF was The systematic process was described in between 3.9E-10 and 9.4E-12. These are not significant Section 1.2 which has been revised to also provide contributions.

a list of steps in addition to the descriptive text.

The loss of a single 4.16 kV AC bus does not result in a unit trip. This has happened at Point Beach and the unit did not trip. This is not an initiating event. Since this is based on actual plant historical events no quantitative estimate is needed.

Loss of HVAC was evaluated in PRA Notebook 05.25. The evaluation for some critical areas was revised and for some areas fault tree models were developed to evaluate the impact of the loss of HVAC. These calculations provide a quantitative basis that these HVAC systems do not contribute and need not be modeled.

A systematic review of the plant-specific features was performed in lnitiating Events Notebook 2.00, Section 1.3.4, "Review of PBNP Design."

A systematic review of all normally operating systems was performed. This is documented in Sections 1.3.4, 1.3.5, and Table 4. Additional documentation is provided in each system notebook in Section 05.xx.4, "Initiating Events Review" and Section 05.xx.8, "Failure Modes and Effects Analysis." A quantitative basis for the loss of a 4.16kV AC bus is not needed. The plant has lost a 4.16 kV AC bus and the unit did not trip.

Therefore this is not a potential initiating event.

Dual unit impacts are discussed in the Success Criteria Notebook, Section 4.1, "Dual Unit Success Criteria."

Page 2 of 71 I

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs 2011 Peer Review Finding:

Section 1.2, 1.3.4, 1.3.5 and Table 4 provide evidence of a systematic review and addresses loss of 4kv and HVAC. Also, the system notebooks address the potential for initiating event (e.g., 05.25 HVAC). However, based on this review, weaknesses still remain and this finding could not be completed closed. The documentation suggests that an immediate plant trip is required for an equipment failure to be considered an initiating event. However, tech spec shutdowns should also be considered (e.g., <24 hr LC0 unlikely equipment failure could be fixed within tech spec). The evaluation must be expanded to include this. For example the plant experienced a 4KV failure that did not cause a trip but resulted in plant shutdown due to tech specs.

Was there a tech spec requirement to shutdown.

Table 4 should be improved to explain why a special initiator is not required and or how the system is subsumed in another initiating event (Section 1 should have most of the basis along with SY?)

Not Met IE-A1-0I 2010 Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the (Not Met) The requirement for this element is to use a PRA Model. See resolution below.

Finding structured, systematic process for grouping IE-B2-01 initiating events. For example, such a systematic 201 1 Peer Review Plant Response:

approach may employ master logic diagrams, heat Column 5, "Special lnitiating Event", of Table 4 in the balance fault trees, or failure modes and effects lnitiating Event Notebook, 2.0 has been expanded to analysis (FMEA). document the review of the systems and the basis for Special IE exclusion.

There is no discussion of the use of a structured, systematic process for grouping initiating events.

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Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs Ensure a structured, systematic process for grouping initiating events was used, and document the process.

2010 Peer Review Finding Response:

Several F&Os have resulted in changes in the IE Notebook.

Section 1.2 now explicitly presents the structured, systematic methodology used in the development of the initiating events. Step 3 of this process it the grouping of identified initiating events.

Section 2.2 has been revised to better document the systematic process as per the below.

Section 2.3 has been added to present the plant operator interview comments.

2011 Peer Review Finding:

Sections 1.2 and 2.2 were revised to better explain the structured approach; however, as described for IE-A1-01 the documentation of the review of all systems in Table 4 and basis for IE exclusion is required.

IE-D3 Not Met 2010 Peer Review Finding: No - The 2011 Peer Review Finding was resolved in the No documentation of sources of uncertainty for PRA Model. See resolution below.

Finding initiating events could be found in the IE document.

IE-D3-01 2011 Peer Review Plant Response:

The Standard requires this documentation. Section 5.0 of the PRA Notebook 11.O, Quantification Notebook contains a discussion on the sources of Add section discussing sources of uncertainty in uncertainty and their impact to the PRA.

the Initiating Events calculation.

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Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs 2010 Peer Review Finding Response:

Sources of Uncertainty for this and all other PBNP PRA Notebooks are evaluated in PBNP PRA 11.OO Quantification Notebook. A new Section 5 was added to the IE Notebook to state that Sources of Uncertainty are evaluated in PRA 11.00, the Quantification Notebook.

2011 Peer Review Finding:

Section 1.3.6 of IE Notebook identifies assumptions, which are a key source of uncertainty and Section 5 of IE Notebook references QU for uncertainty, but there is no updated QU Notebook AS- Not Met 2010 Peer Review Finding: No - The 2011 Peer Review Finding was resolved in the BI This element states that for each modeled initiating PRA Model. See resolution below.

Finding event, identify mitigating systems impacted by the AS-BI - occurrence of the initiator and the extent of the 2011 Peer Review Plant Response:

01 impact. Include the impact of initiating events on There are no longer any front line systems shared mitigating systems in the accident progression between units. Auxiliary feedwater is now unit specific.

either in the accident sequence models or in the Startup Steam Generator pumps which were the motor system models. driven AFW pumps are shared between units. CSTs are shared but levels are maintained to accommodate an Currently two separate models are being accident on one unit and hot shutdown on the other unit.

maintained for PBNP - One for Unit and One for 13.8 KV - Designed for normal loads on one unit which are Unit 2. By maintaining two separate models, the g,ater than accident loads on both units.

full impact of dual unit initiating events, and the 4160 VAC - Designed for normal loads on one unit which importance of failures of shared equipment is not are greater than accident loads on both units.

adequately addressed. The dual unit impact of 480 VAC - Unit specific shared systems, especially under dual unit EDG - Can supply both units with a single diesel initiating events, is very important from a risk 120 VAC - Unit Specific perspective, and will become even more important 125 VDC - The batteries are designed for accident on one when the PRA is converted to a Fire PRA model. unit and hot standby on other unitm A single top PRA model that reflects both Units Accumulators - Unit Specific would explicitly address the dual unit impacts and SI RHR - Unit Specific the importance of systemlequipment failures. AFW - Unit Specific (See note above)

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Attachment I: Point Beach PRA Peer Review Findings 1 Category I Other I Issue and Proposed Resolution I Impact to Applications and Peer Review Resolution 1 Challenqe: The two separate top models being Containment Spray - Unit Specific maintained for PBNP address the full impact of Fan Coolers - Unit Specific dual unit initiators. Containment Isolation - Unit Specific Service Water System - Success criteria of two pumps can Response: From the team review during the week, support accident on one unit and hot shutdown on other and our discussions with the PRA people, it did not unit.

appear that dual unit initiators were being Component Cooling Water - Unit Specific addressed appropriately. Given the events at Actuation Systems - Unit Specific Fukashima, this is now of particular concern. In Main Feedwater - Unit Specific particular, in a dual Unit initiating event -the Main Steam - Unit Specific equipment on the opposite Unit will most likely Reactor Coolant System - Unit Specific NOT be available to respond to the initiating event CVCS - Unit Specific

- it will be dedicated to its Unit until its Unit is Fire Protection - Accident loads on both units are less than placed in a safe, stable state, or until it is shown fire protection loads. Used to make up CSTs and cool that it is not needed for its Unit. There was no TDAFWP bearings.

evidence that this was taken into consideration at Instrument/ServiceAir - Accident loads on both units are all in the individual models. Depending upon the less than normal operating loads.

Dual Unit Initiating Event, cross-tiedlshared Fuel Oil - Designed to support EDG with accident on one systems will most likely have their cross-connect unit and hot shutdown on other unit.

valves closed to isolate the two Units from each This should clarify that dependencies between unit shared other - and will require an operator action to re- systems have the capability as required to cope with dual open the valves if the system is allowed to be re- unit shutdowns.

cross connected - this consideration was not seen in the individual models. There is also no evidence that the HFEs associated with an event are modified for a dual-unit initiator when Operators will be at a premium, and their availability to respond to outside the control room actions will be impacted.

2010 Peer Review Plant Response:

The two separate top models being maintained for PBNP address the full impact of dual unit initiating events. The PBNP PRA currently uses 2 separate top gates, one for Unit 1 and one for Unit 2. This has been the case historically and the 2 models Page 6 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs are maintained in parallel. The standard does not require a single top model for a multiple unit site.

While there are some shared systems between the 2 PBNP units (electrical, service water) and some additional systems that have limited cross-connect capabilities (auxiliary feedwater, component cooling water, instrument air, station air), identical fault tree logic is used in both models for these systems and the commonalities and impacts are properly accounted for in the logic models. For example, the AFW system model considers the availability of AFW flow to the opposite unit to determine what pumps can be considered for the unit in question. Some additional gates were added to the model to better reflect dual unit impacts.

The following changes were made to the model in response to F&O AS-B1-01 , the F&O related to a single model for both units:

- Under existing gate GAFM2500, add new AND gate GAFM2501 with two new inputs. One input is new OR gate GAFM2502 and the other input is new OR gate GAFM2503. New OR gate GAFM2503 has as inputs existing initiating events INIT-TIG, INIT-TIGB, INIT-TIP, INIT-TIW, INIT-TDI, INIT-TD2, INIT-TIA, INIT-TSW.

- Under gate GAFW1800, add new AND gate GAFW1801. Under new AND gate 1801, add OR gate GAFM2503.

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Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs

- Under gate GAFM2900, add new AND gate GAFM2901. Under new AND gate add OR gate GAFM2503.

The Technical Specifications were reviewed to assure that the impact of the status of the opposite unit is correctly modeled and it was determined that there is no impact from unit status. The modeling of the common systems and systems with cross-tie capability described above was reviewed and the modeling correctly captures the dependencies.

There is no requirement for a single top event for a multiple unit site. Additionally, none of the duel unit site models that the PRA team is familiar with have a single top model for multiple units.

If a single top model were produced it would still be solved at the individual unit level. It is not clear what the meaning would be of solving for simultaneous core damage.

2011 Peer Review Finding:

It does not appear that the Standard requires a single top and the models for each unit appears correct for quantifying risk of each unit with shared equipment. Also, Point Beach can supply both units with a single diesel. What is not clear is whether all dependencies between unit shared systems have this capability and the importance of any that cannot supply both units. Given recent events and the potential importance of dual unit events, this finding will have to remain open.

Page 8 of 71

Attachment I : Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs AS- Not Met SY-B6 2010 Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the B3 (Met) This element is associated identifying and PRA Model. See resolution below.

Finding SY-B14 modeling the effects of the phenomenological AS-B3- (Not Met) conditions created by the accident progression. 2011 Peer Review Plant Response:

01 Phenomenological impacts include: generation of Accident Sequence Notebook 3.2, Section 6.5.1 was harsh environments affecting temperature, revised to include discussion of HELB and the impacts on pressure, debris, water levels, humidity, etc. that the Aux Bldg and Turbine Bldg.

could impact the success of the system or function under consideration.

The effects of phenomenological conditions created by the accident progression of Main Steam Line Breaks or Feed Line Breaks outside containment are not adequately addressed. In particular, the analysis states that MSBL's outside containment "result in no adverse Containment atmosphere" or "there are no adverse environmental conditions" from the event.

Because of the accident sequence itself - there will be a steam environment in the vicinity of the break, but this adverse environment is not addressed.

Because of the potential impact on non-qualified equipment and Operator actions in areas outside of containment that can be subject to the effects of MSLBs outside containment, the potential adverse conditions need to be identified and their impact of equipment and actions in the areas need to be addressed. Additionally, no discussion on debris generated in Containment due to LOCAs or MSLBs inside containment can be found.

Evaluate the phenomenological conditions created by the accident progression and include the impacts of any adverse conditions in the fault tree Page 9 of 71

Attachment I:Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs model and documentation. Need to evaluate potential steam environments outside containment, Main Feed breaks outside Containment, HELB issues, debris generation inside containment, potential NPSH impacts, etc.

2010 Peer Review Plant Response:

Section 5.4.6 and Table 5.4.5 of the AS Notebook were enhanced with the following:

"Large LOCAs may also create an environment (i.e., pressure, temperature, humidity, debris generation) that could impact equipment. This is addressed in the Success Criteria Notebook (Reference 8.1)."

Section 5.5.6 and Table 5.5.4 of the AS Notebook were enhanced with the following:

"Events inside containment may create an environment (i.e., pressure, temperature, humidity, debris generation) that could impact equipment.

This is addressed in the Success Criteria Notebook (Reference 8.1).

For events outside containment, collateral damage is explicitly included in the model. For secondary line break events in the turbine building, a loss of all MFW and Instrument Air is assumed. Breaks in the Aux building also impact equipment. For these cases, only qualified equipment or equipment not directly."

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Attachment 1: Point Beach PRA Peer Review Findings I Catenorv I Other SR a& - Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs Section 3.4 of the SC Notebook was enhanced (and Reference 4 was added in Section 9) with the following:

"In addition, Section 1.4 and Section 9 (assumption 6) of the SIIRHR System Notebook (Reference 4) address the issue of debris in containment, concluding that debris has no impact on containment sump recirculation."

The above enhancements address the concerns of the F&O regarding the environmental impacts of Large LOCAs (Small and Medium LOCAs produce much less force; see responses to GSI-191) and Secondary Line Breaks.

2011 Peer Review Finding:

Sections 5.4.6, 5.5.6 and tables 5.4.5, 5.5.4 of AS Notebook were revised to address this F&O, but there was insufficient information to address HELB outside containment. Plant response refers to SC Notebook Section 3.4 which does not contain anything relevant. The details of HELB (e.g., FW and MS) and the impacts in the Aux Bldg and Turbine Bldg are not described. The RHR system notebook was revised to address issue of containment sump debris and plugging of SI injection path flow orifices.

AS- Not Met SY-A5 2010 Peer Review Finding: No - The 2011 Peer Review Finding - was resolved in the B6 (Met) This element is associated with ensuring that plant PRA Model. See resolution below.

Finding SY-A21 configurations and maintenance practices which AS (Not Met) create dependencies among various system 2011 Focused Peer Review Plant Response:

01 SY-B6 alignments are defined and modeled in a manner The HFE of failure of the operators to properly manage (Met) that reflects these dependencies, either in the EDG loads was not modeled due to the extremely low SY-Bl5 accident sequence models or in the system probability of the opportunity for this error to result in a loss (Met) models. of the EDG ever occurring. In order for this HFE to be Page 11 of 71

Attachment I : Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs Because of electrical bus limitations, Point Beach viable, there must be a loss of offsite power, a demand for has some unique system alignment restrictions. the safety injection pumps (i.e., a LOCA), and a random Currently these system alignment restrictions are failure of one of the EDGs. Furthermore, the probability of not reflected in the PRA model. In particular, there this HFE is expected to be low due to the clarity of the are system alignment restrictions associated with procedural guidance and the frequent training given to the the System Air and CVCS systems such that operators on proper EDG load management.

specific System Air Compressors cannot be in operation if specific CVCS pumps are in operation. Within AOP-22, a note specifically states that EDG Loading is critical when the site is reduced to a single EDG A review of the Normal System Operating and the EDG is required to support the equipment required Procedures should be performed to identify the for Safety Injection.

unique PBNP system alignments and restrictions.

Once the unique system alignments and A calculation is presented below, which calculates the restrictions are identified, the limitations should be probability of using this procedure:

reflected in the PRA fault tree models.

SI = 1E-2 Includes LOCAs and SteamIFeed line breaks 2010 Peer Review Plant Response: since excessive cooldown will generate an SI The following text sections were added to the AS LOOP = 3 ~ Sum ~ 2of all LOOPS Notebook, Section 5.6.3, and the EDG and Gas Turbine = 1E-I Out for Maintenance 4160 VAC Notebooks. As01-35C will not be 3 EDGs = 7E-6 Common Cause Failure to Run 1st hour applicable after the March 2001 Unit 2 outage it is or CCF run 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />.

felt that this need not be added to the 480 VAC Notebook. Probability of using this procedure with only 1 EDG = 1E-2

• 3E-2

• 1E-I

• 7E-6 = 2.1 E-10.

Point Beach Electrical Loads Limitations Per Tim Lensmire, the Point Beach electrical engineer knowledgeable on electrical loads, was interviewed on 2-17-2011 by Stanley Goukas to address load management for normal alignments at Point Beach. The first is01-35C which Tim says in theory should go away after the upcoming Unit 2 outage once the EPU modifications have been implemented. The second and third are AOP-22 for Unit 1 and Unit 2. These AOP's provide for Page 12 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs load management on the diesel generators following a loss of offsite power.

Additionally, it was noted that additional loading restrictions may be placed in effect when maintenance is performed on electrical equipment:

13.8KV or 4160 Volt Electrical Load Management When maintenance is performed on some 4160 volt transformers bus load restrictions are placed in effect:

3.5 When removing 1X-03, Unit 1 High Voltage Station Auxiliary Transformer, or 1X-04, Unit 1 Low Voltage Station Auxiliary Transformer, from service, the following additional measures will ensure operability of offsite power from a potential degraded voltage condition during a unit trip:

(Ref 6.6.8 & Attachment F)

For any unit in Mode 1 - defeat one of that units 4160V fast bus transfer, typically the A-03 to A-01 Bus Tie due to the turbine auxiliaries powered from A-02. For any unit in Modes 5, 6 or defueled -

maintain that units A01 and A02 4160V motors OFF.

3.6 When re-energizing the 1X-04 transformer the 13.8KV bus should be aligned to the 1X-03 transformer to reduce possible perturbations to opposite units online equipment.

These transformers are the normal supply to the class 1E buses. As such, these transformers Page 13 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs would not be taken out of service while the plant is operating. The model assumes that no routine maintenance would be performed on these transformers during unit operation. Therefore, this load restriction has no impact on the model.01-35C - 480 Volt Electrical Load Conservation The loads considered as discretionary are charging pumps 1P-2A and 1P-2B and instrument air compressor K-2A. To meet the loading requirement, first one of these loads is secured off (no auto-start). If this configuration does not meet the loading requirement, then 2 of these loads are secured off (no auto-start). However, these load management measures are not utilized when an AOPlEOP is in effect.

The load management issues addressed in 01-35C will be resolved by modifications being made during the upcoming (March 2011) Unit 2 refueling outage. Therefore, the electrical load considerations contained in 01-35C need not be considered in the model.

AOP-22 Unit 1 - EDG Load Management This procedure is applicable when the EDGs are running, loaded, and the bus being supplied is isolated. If the load on a EDG exceeds the 200 hour0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> limit the operators isolate unnecessary plant equipment per Attachment A, Unit 1 Electrical Loads (for EDGs G-01 and G-02) or isolate non-safeguards bus 1B-40 (for EDGs G-03 and G-04) as per Step 1, Response Not Obtained.

Page 14 of 71 G

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs If the load on a EDG exceeds the 2,000 hour0 days <br />0 hours <br />0 weeks <br />0 months <br /> limit the operators isolate additional unnecessary plant equipment per Attachment A. It should be noted that Attachment A simply defines all of the potential loads by bus and does not prioritize these loads or indicate what loads should be shed first.

Since Attachment A does not prescribe what loads should be retained or shed, it is not possible to determine directly what impact this restriction has on the model. Since the PRA models the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following a Unit trip the applicable loading limits for the PRA are the 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> ratings, or 2,850 kW for G-01 and G-02 and 2,848 kW for G-03 and G-04. An analysis of the loads necessary to safely shutdown both units with a single diesel generator has been performed and it is possible with any single diesel, subject to equipment failure. These facts, and the statement that loads are started and stopped "as directed by the plant procedures" (Step 2), indicate that the necessary equipment to safely shutdown the unit(s) would be identified by the operating procedures in effect at time and operated at direction of the operators. Therefore, no additional modeling is necessary to capture any potential limitations.

To ensure that excessive loads are not credited in the PRA, the minimal set of equipment necessary to safely shutdown the unit(s) for the Loss of Offsite Power and Station Blackout accident sequences were reviewed and compared against the analysis of the loads necessary to safely shutdown both units with a single diesel generator Page 15 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs mentioned above. This demonstrated that there are no additional impacts of electrical load limitations on the PRA models.

AOP-22 Unit 2 - EDG Load Management This procedure is applicable when the EDGs are running, loaded, and the bus being supplied is isolated. If the load on a EDG exceeds the 200 hour0.00231 days <br />0.0556 hours <br />3.306878e-4 weeks <br />7.61e-5 months <br /> limit the operators isolate unnecessary plant equipment per Attachment A (for EDGs G-01 and G-02) or isolate non-safeguards bus 18-40 (for EDGs G-03 and G-04) as per Step 1, Response Not Obtained. If the load on a EDG exceeds the 2,000 hour0 days <br />0 hours <br />0 weeks <br />0 months <br /> limit the operators isolate additional unnecessary plant equipment per Attachment A, Unit 2 Electrical Loads. It should be noted that Attachment A simply defines all of the potential loads by bus and does not prioritize these loads or indicate what loads should be shed first.

Since Attachment A does not prescribe what loads should be retained or shed, it is not possible to determine directly what impact this restriction has on the model. Since the PRA models the first 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> following a Unit trip the applicable loading limits for the PRA are the 2000 hour0.0231 days <br />0.556 hours <br />0.00331 weeks <br />7.61e-4 months <br /> ratings, or 2,850 kW for G-01 and G-02 and 2,848 kW for G-03 and G-04. An analysis of the loads necessary to safely shutdown both units with a single diesel generator has been performed and it is possible with any single diesel, subject to equipment failure. These facts, and the statement that loads are started and stopped "as directed by the plant procedures" (Step 2), indicate that the Page 16 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs necessary equipment to safely shutdown the unit(s) would be identified by the operating procedures in effect at time and operated at direction of the operators. Therefore, no additional modeling is necessary to capture any potential limitations.

To ensure that excessive loads are not credited in the PRA, the minimal set of equipment necessary to safely shutdown the unit(s) for the Loss of Offsite Power and Station Blackout accident sequences were reviewed and compared against the analysis of the loads necessary to safely shutdown both units with a single diesel generator mentioned above. This demonstrated that there are no additional impacts of electrical load limitations on the PRA models.

2011 Peer Review Finding:

Section 5.6.3 of AS Notebook and EDG & 4Kv system notebooks were revised.01-35c will not be applicable after upcoming Unit 2 outage (480 V).

AOP-22 addressed load management on EDGs.

Additional restrictions on 13.8 and 4 Kv, but these maintenance alignments are not conducted at power.

Appears that load management failure is a possible failure mode for EDGs that is not modeled.

AOP-22 indicates load management is critical however could not find basis concluding it could be neglected as an EDG failure. Plant response indicated that HEP "HEP-416-U1-A-3-4" included Load Management within a cross-tie action. This was reviewed in HRA Calculator (HRAC) and no Page 17 of 71

Attachment I:Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs tasks for load management were identified and no mention of load management was visible in the HRA entry. Similar AC cross-tie actions were also reviewed in HRAC and likewise no load management information was in identified. Also, the Load list in AOP-22 was summed to yield over 7000kW. Further, Calculation 2004-002 "Emergency Diesel Loading" appears to credit operator actions for various situations. For example, Page 215 has negative loads (i.e., loads that are secured) for "SW Reduction", "Turn off MDAFP", and "Turn Off SI Pump (P-15)". Thus, in theory it seems possible to overload an EDG (Load limit -3000kW). No Modeling of Operator to manage EDG Loads found. (See SY-21-01).

AS- Not Met 2010 Peer Review Finding: Yes - The 201 1 Peer Review Finding was NOT resolved in B7 This element is associated with modeling time- the PRA Model. As stated in the finding, only recovering Finding phased dependencies (i.e., those that change as SBO sequences and not considering battery depletion AS-B7- the accident progresses, due to such factors as time will conservatively affect the results.

01 depletion of resources, recovery of resources, and changes in loads) in the accident sequences. 2011 Peer Review Plant Response:

In the current convolution calculation for LOSP, LOOP Examples are: recovery is applied to only SBO sequences and DC (a) For SBOILOOP sequences, key battery life is not considered (i.e. Fails at 0 hours0 days <br />0 hours <br />0 weeks <br />0 months <br />). This is time-phased events, such as: conservative since recoveries which could be applied to

( I ) AC power recovery reduce CDF and LERF are not applied. The resolution to (2) DC battery adequacy (time- this F&O will possibly be addressed in the next PRA Model dependent discharge) revision (5.02).

(3) Environmental conditions (e.g., room cooling) for operating equipment and the control room Although time-phased recoveries appear to be considered at PBNP, it is not clear that they are addressed appropriately and completely. For Page 18 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs example, in the HVAC notebook, there are several rooms that are expected to exceed the design limits for the equipment in them, but failure of HVAC to the rooms are not modeled. Additional justification for why HVAC to those rooms is not required needs to be addressed.

2010 Peer Review Plant Response:

The PRA model reasonably accounts for the impacts of time phased dependencies.

The model has been improved in 3 areas to better reflect the impact of time phased events.

First, the Power Recovery Convolution has been revised. This calculation determines the likelihood of the recovery of offsite power at the specific times that the MAAP and the RCP Seal LOCA analyses identified as being critical to the development of accident sequences. The current Convolution analyses were developed specifically for SBO (no power available from any source) and are therefore not applicable to a partial power situation such as LOOP. Additionally, the modifications to the DC modeling resolve the bulk of the cutsets in LOOP that give the appearance of being long term SBO sequences.

Second, the HVAC Notebook analyses have been revised. Additional consideration was given to the available information and additional analyses were performed to quantitatively support the conclusions presented in the notebook.

Page 19 of 71

Attachment I:Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs Third, the modeling and tagging of battery depletion and the recovery rules for restoration of power to a DC bus have been revised. The previous model had a single tag to identify a depleted bus and the HEP dependencies are cued off of this tag. This resulted in the failure of a single DC bus effectively failing all DC power (a modeling error). This has been revised such that there is a unique tag for each DC bus and the cutsets in LOOP that looked like they should be in SBO (erroneous cutsets) have been modified to correctly reflect the loss of DC at a specific bus and not the loss of all DC power.

2011 Peer Review Finding:

The model was improved in 3 areas to better reflect the impact of time phased dependencies as described above. HVAC notebook was updated and model includes HVAC as appropriate.

However, the Model is still conservative because LOOP recovery for non-SBO scenarios is still neglected and the basis for this is inadequate.

Also, DC life is still assumed to be 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> when realistic battery life is much greater (DC notebook does not mention true battery life other than full load test takes 2 '/2 days). In the convolution analysis, credit is not even taken for the one battery hour. As a minimum greater detail is required to document these assumptions and their impact on the results (QU). Since the 5.00 model is being reviewed the QU results will not address additional model changes being incorporated NEXTERA.

Page 20 of 71

Attachment I:Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs SC- Not Met AS-C3 (Not 2010 Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the A6 Met) This SR requires that success criteria be confirmed PRA Model. See resolution below.

Finding to be consistent with features procedures and SC-A6- operating philosophy of the plant. 2011 Peer Review Plant Response:

02 The response to F&O SC-A6-02 was added to PRA 3.2, Doc Point Beach set the upper end of their small break Success Criteria Notebook, Section 6.2.3.

Only LOCA event to 2 inches based on generic information from NUREGs. However, in the accident sequence notebook, Point Beach made a statement to the effect that over much of the range of their small break LOCA spectrum, secondary side heat removal side was not needed (see small LOCA assumptions section). However, in Section 6.2.3 of PRA 3.2, it is stated "The small LOCA event tree (Event Tree Notebook, Figure S2) applies to breaches in the RCS which are large enough that the break flow exceeds the capacity of the normal reactor makeup system. The break size, however, is not large enough to provide core decay heat removal." These two statements are inconsistent. A review of the success criteria calculations did not reveal any calculations to determine the upper end of the small LOCA spectrum based on the need for secondary side heat removal.

Run a set of MAAP calculations to determine the break size that is just sufficient to remove decay heat and depressurize the primary side. Use the break size thus determined as the lower bound for the medium LOCA and upper bound for the small LOCA. Use the results to also clarify the small LOCA definition in the SC notebook, the AS notebook and the IE notebook and make them all consistent.

Page 21 of 71

Attachment I : Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs 2010 Peer Review Plant Response:

The Westinghouse Design Basis Analysis divides LOCAs into two sizes, large and small. The small LOCA upper end break size is 6 inches diameter.

The basis for this division is that large LOCAs exhibit high break exit velocities such that mitigation flows (low pressure injection, accumulators, etc.) bypass the core and exit the break without providing core cooling. This occurs until the end of the "blowdown phase", when the break exit velocities drop such that mitigation flows reach the core to provide core cooling. As such, different design basis codes (SATANJWREFLOOD for large LOCAs and NOTRUMP for small LOCAs) must be used for the different size LOCAs.

The MAAP code cannot be used to analyze the short term timeframes of large LOCAs that produce the conditions that result in core bypass (see Section 3.4 of PRA 3.2). However, MAAP is reasonable for analyzing the longer term time frames of all LOCA sizes. The results of MAAP run PBI ML-25 (4" LOCA without AFW or cooldown and depressurization) indicate that RHR injection only just barely averts core damage. This would indicate that the large LOCA success criteria could be used down to approximately 4 inches.

However, the 6 break size is a reasonable point at which to differentiate between PRA-defined large and medium LOCAs based on the core bypass characteristics described above.

The differentiation point between PRA-defined medium and small LOCAs is 2 inches diameter.

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Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs MAAP run PBI ML-06 shows that sufficient energy is removed via the break that secondary cooling is not required as long as high head SI is successful.

However, unlike the 6" and 4" medium LOCAs, a 2" LOCA does require AFW and operator-initiated cooldown and depressurization to use RHR if high head fails (MAAP run PB1SL-17 for failure of high head recirculation, PB1SL-14 for failure of high head injection).

As one can see, the requirements for AFW and cooldown and depressurization that exist for medium LOCA successful sequence 3 are set by the lower bound of the medium LOCA (2 inch diameter).

One could move more of the break spectrum in the 2" to 4" range into the small LOCA realm such that there was no requirement for AFW and cooldown and depressurization for the medium LOCA.

However, there would be more break spectrum in the small LOCA that would not require secondary heat removal if high head injection was available.

Conversely, one could move more of the break spectrum in the 2" to 1" range into the medium LOCA realm such that there was always a requirement for secondary heat removal if high head injection was available for the small LOCA.

However, there would be more break spectrum in the medium LOCA that would require AFW and cooldown and depressurization, and possibly feed and bleed for failure of AFW. In other words, there are competing conditions such that a "perfect" break point" may not be attainable.

Page 23 of 71

Attachment I:Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs reasonable break size for the differentiation point between PRA-defined medium and small LOCAs.

Therefore, no changes were made to the Point Beach break size spectrum.

2011 Peer Review Finding:

Plant response to peer review seems reasonable but has to be included in the SC (and or IE and AS) notebook to resolve this finding (important documentation based on previous peer review).

SY- Not Met 2010 Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the A21 This element states that system conditions that PRA Model. See resolution below.

Finding cause a loss of desired system function, (e.g.,

SY-A21- excessive heat loads, excessive electrical loads, 2011 Peer Review Plant Response:

01 excessive humidity, etc.) should be identified. The HFE of failure of the operators to properly manage EDG loads was not modeled due to the extremely low A review of various electrical.systemnotebooks probability of the opportunity for this error to result in a loss and the EDG system notebook did not identify any of the EDG ever occurring. In order for this HFE to be consideration of excessive electrical loads on the viable, there must be a loss of offsite power, a demand for busses or the EDG. With the electrical margin for the safety injection pumps (i.e., a LOCA), and a random some of the busses and the EDGs at Point Beach failure of one of the EDGs. Furthermore, the probability of being minimal to non-existent, a review for this HFE is expected to be low due to the clarity of the potential excessive loading conditions needs to be procedural guidance and the frequent training given to the performed and documented. In particular, a look at operators on proper EDG load management.

Operators starting equipment in response to redundant equipment failures, and failures of Within AOP-22, a note specifically states that EDG equipment to fully load shed should be considered, Loading is critical when the site is reduced to a single EDG documented, and explicitly included in the model and the EDG is required to support the equipment required as appropriate. Currently, with the exception of the for Safety Injection.

EDG start logic, load shed and UV detection is embedded in the bus failure rates, and needs to be A calculation is presented below, which calculates the explicitly modeled because of the excessive probability of using this procedure:

loading concern.

I I I I I I Page 24 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs With the electrical margin for some of the busses SI = 1E-2 Includes LOCAs and SteamIFeed line breaks and the EDGs at Point Beach being minimal to since excessive cooldown will generate an SI non-existent, a review for potential excessive LOOP = 3E-2 Sum of all LOOPS loading conditions needs to be performed and Gas Turbine = 1E-I Out for Maintenance documented. In particular, a look at Operators 3 EDGs = 7E-6 Common Cause Failure to Run 1st hour starting equipment in response to redundant or CCF run 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />.

equipment failures, and failures of equipment to fully load shed should be considered, documented, Probability of using this procedure with and explicitly included in the model as appropriate. only 1 EDG = 1E-2

• 3E-2

• 1E-1

• 7E-6 = 2.1 E-10.

Currently, with the exception of the EDG start logic, load shed and UV detection is embedded in the bus failure rates, and needs to be explicitly modeled because of the excessive loading concern.

2010 Peer Review Plant Response:

Plant Response: Excessive Electrical Loads are addressed in the response to F&O AS-B6-1.

The PRA model requires ALL of the circuit breakers associated with a bus that are required to be shed (be opened) prior to closing a circuit breaker for a new power source to be aligned to the bus. This is explicitly modeled and is not imbedded in the bus failure rates as was thought by the reviewers. No model change is required to address this comment.

The limitations associated with the 4.16 KV transformers are related to maintenance that would not be performed during operation, so there is not impact on modeling.

Page 25 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs 2011 Peer Review Finding:

AOP-22 for Unit Iand Unit 2 provide for load management on the diesel generators following a loss of offsite power. Procedure direct operators to isolatelstrip unnecessary loads if the EDG load exceeds the 20012000 hour limit. To ensure that excessive loads are not credited in the PRA, the minimal set of equipment necessary to safely shutdown the unit(s) for the Loss of Offsite Power and Station Blackout accident sequences were reviewed and compared against the analysis of the loads necessary to safely shutdown both units with a single diesel generator mentioned above. This demonstrated that there are no additional impacts of electrical load limitations on the PRA models.

See also discussion in AS-B6-01 .

SY- Not Met 2010 Peer Review Finding: No - The 2011 Peer Review Finding was resolved in the B3 ESTABLISH common cause failure groups by PRA Model. See resolution below.

Finding using a logical, systematic process that considers SY-B3- similarity in: 2011 Peer Review Response:

0I Common Cause Failure of Component Cooling Water

a. Service conditions Pumps to start and run has been added to the model.

b. Environment

c. Design or manufacturer The delta CDF due to this change was

d. Maintenance 4.25E-8 on Unit 1 and 4.28E-8 on Unit 2.

JUSTIFY the basis for selecting common cause There was no delta LERF on either Unit.

component groups.

Candidates for common cause failures include, for example: Sensitivity of common cause failures for component cooling water pumps in mitigation section of model.

a. Motor-operated valves

b. Pumps CC--MDP-FS-1-11A = 1.51E-O3ldemand

c. Safety-relief valves Beta = 2.31 E-02 NRC Common Cause Database MDP FS

d. Air-operated valves Page 26 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs

e. Solenoid-operated valves Common cause failure to start = failure rate

• Beta

f. Check valves

g. Diesel generators Common cause failure to start = 1.51E-03

• 2.31 E-02 =

h. Batteries 3.49E-05ldemand

i. Inverters and battery charger Type Code CC- MDP CM 11S = 3.49E-051demand

j. Circuit breakers CC--MDP-FR-1-11A = 5.86E-061hour For initiating events, common cause failure groups Beta = 5.86E-02 NRC Common Cause Database CC MDP for the "failure to run" or "failure to operate" modes FR that involve a normally operating component failing followed by the failure of the standby failure group Common cause failure to run = failure rate

• Beta use an exposure time of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />. Because the exposure in which the normally operating Common cause failure to run = 5.86E-06

• 5.86E-02 =

component can fail is one year, and because CCF 3.43E-07Ihour parameters are dimensionless, the use of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> Type Code CC- MDP CM 11R = 3.43E-o7/hour is incorrect. It should be one year.

The times can be changed and then the initiating Results:

event requantified.

U1 CDF U2 CDF 2010 Peer Review Plant Response:

No CCW U1 CDF No CCW U2 CDF Plant Response: Because the exposure in which CCF CCW CCF CCF CCW CCF the normally operating component can fail is one year, and because CCF parameters are 5.34E-06 5.39E-06 5.34E-06 5.38E-06 dimensionless, the use of 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> is incorrect." DELTA 4.25E-08 DELTA 4.28E-08 This statement is incorrect. In all of the analyses of common cause data events to date, the definition U1 LERF U2 LERF of the parameter is "failure of identical components No CCW U1 LERF No CCW U2 LERF due to the same cause within a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period." CCF CCW CCF CCF CCW CCF Thus, CCF parameters are NOT dimensionless; 7.83E-08 7.83E-08 8.1 3E-08 8.13E-08 they are a fraction of failures that occur in a DELTA 0.00E+00 DELTA 0.00E+00 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> period. CCF parameters not dimensionless.

The change in CDF for both units was an increase of 4E-8 and there was no change in calculated LERF. Therefore, Page 27 of 71

Attachment I : Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs 2011 Peer Review Finding: the change has an insignificant impact on CDF and LERF Plant response could be improved as it is common for both Unit 1 and Unit 2.

practice in most PRAs to decouple standby pump failures from CCF of running pumps over 8760 The changes to the fault trees are documented in the hours. Although it is slightly optimistic there is no appropriate System Notebook.

data for failure of one pump over 8760 and then common cause failure of the second (given start success) to fail before repair of the first pump. This modeling approach needs to be clearly described in the system notebooks. SW modeling was improved using this approach. Note that CCW has one operating pump and one standby pump thus there is no CCF to run for an initiating event using this approach. However, there is no CCF to run or start in the CCW mitigation model, which is required.

HR- Not Met 2011 Peer Review Finding: No - The 2011 Peer Review Finding was resolved in the A3 Pre-Initiator dependency is based on an incorrect PRA Model. See resolution below.

Finding interpretation of SY-B2 "No requirement to model HR-A3- intra-system common-cause" and includes 2011 Peer Review Plant Response:

0I judgments that are not adequately defended. The RPS system was reviewed. Two groups of sensors, low following excerpts from the HRA Notebook pressurizer pressure and low low steam generator level demonstrate this misinterpretation and do not were identified as not having diversity. As such, common present any compelling justification for the cause mis-calibration errors were calculated and added to judgments: the Unit 1 and Unit 2 models for these groups of sensors.

No other signals were identified which did not have Per ASME SR SY-B2, there is no diversity.

requirement to model intersystem common cause failure. As Calculation MSE-EJJ-05-10, "Point Beach Nuclear Power miscalibration of redundant channels is Plant Mis-calibration Human Reliability Analysis", dated a common cause failure, miscalibration December 19, 2005 identified low pressurizer pressure, between different systems need not be VCT Level and AFW pressure as common cause modeled. By considering diverse input mis-calibration failures. The low pressurizer pressure was signals to an actuation signal as added above. The VCT Level and AFW pressure were "different systems", screening of signals added to the model as a result of this calculation. The Page 28 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs can be accomplished based on values used for the common cause of these sensor groups diversity. were obtained from Calculation MSE-EJJ-05-10. The calculation has been included in Appendix A -

A signal channel typically consists of a Mis-calibration.

transducer, transmitter, power supply and an analog-to-digital converter that converts the input from the transmitter to an on-off signal using a bistable.

Calibrations are performed on the transducerltransmitter and on the bistable. Miscalibration of either the transmitter or bistable setpoints can defeat the automatic actuation signal.

For redundant channels, calibration of the transmitter can be screened out from further consideration, if signals provided by the transmitters are also used for indications in the control room.

For example, steam generator level has redundant channels that are monitored closely by control room personnel during normal operation. If one or more redundant channels deviate from the rest, the operators would take notice.

However, the calibration of the bistables cannot be screened out as a miscalibration may only become evident when the signal is required.

For signals that are simply generated by relay contacts due to loss of voltage across the relay coil, miscalibration is deemed not to be a significant contributor to signal failure.

Miscalibration is therefore not to be Page 29 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs modeled for the signals such as loss of offsite power 1 4 kV bus undervoltage.

RPS should be considered a single system and screening based solely on intra-system common-cause considerations should not apply. The model includes no common-cause miscalibration or misalignment and the basis for this treatment is not adequately defended.

Screening of pre-initiators also includes a notion of diversity. The concept of diversity is not adequately developed:

The automatic actuation signals are screened on diversity. Two groups of signals which produce automatic actuation were identified. Those related to reactor protection system and those related to ESFAS.

Tables A-I and A-2 in Appendix A show the ESFAS signals as described in the ESFAS system notebook. The reactor protection system signals are outlined in Table 7.2-1 of the FSAR and all signals have been screened from further consideration based on redundancy and diversity. As described in Chapter 14 of the FSAR all events accidents analyzed require at least two diverse parameters.

Page 30 of 71

Attachment I : Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs Screening based on diversity such as signals that are actuated based on two separate parameters (e.g., Level OR Pressure) seems reasonable but not all signals have such diversity.

HR- Not Met HR-D2 (CC- 2010 Peer Review Suggestion: No - The 2011 Peer Review Finding was resolved in the DI 1) This element requires an estimation of the PRA Model. See resolution below.

Finding HR-D3 (CC- probabilities of human failure events using a HR-DI- 1) systematic process. Acceptable methods include 201 1 Peer Review Plant Response:

01 THERP 12-51and ASEP 12-61. Screening values were reset from 1E-4 to 5E-4. The model was rerun and a list of BEs showing up in the CDF Point Beach uses screening values for all of their cutsets at a truncation of 1E-11 was generated.

pre-initiator human actions. In the report, the The mis-positioning BEs in the list were then reviewed to HEPs are givens as the screening value with an see which if any were important. A mis-positioning BE error factor. The screening values tend to be was considered important if the F-V was greater than medians. Therefore, the values in the model, 0.005 or the RAW was greater than 2. There was one which are means, are higher than the screening mis-positioning BE on Unit 1 which had a RAW that was values in the report because of the conversion from slightly less than 2 and one mis-positioning BE on Unit 2 medians to means. However, this is not described which had a RAW greater than 2. These events had a in the report. detailed ASEP analysis performed to generate a specific value for them. The value obtained was then inserted into Provide a discussion of the conversion from the model and used for the quantification. Note that the medians to means in the report so that the report mi,-position event was for valve IAF-109 on Unit 1 and values can be traced back to the values used in the ~ A F - I09 on Unit 2, the same mis-positioning event.

model.

2010 Peer Review Plant Response:

This is an incorrect "Suggestion." The Peer Reviewer chose to explain the difference between the documentation and the model provided for the Peer Review as being a problem in the conversion of the value from medians to means. This is an incorrect explanation for the differences. The HRA Calculator TM does this conversion and exports mean values to the CAFTA .rr database file.

The actual cause of the differences is that the HEP Page 31 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs data was changed after the QU Notebook had been completed, thus there was a discrepancy between the HR, QU, and CAFTA documentation.

To incorporate these data changes into the model would have required a complete revision of the QU Notebook and there was insufficient time to do this prior to the Peer Review.

The pre-initiator values listed in the HR documentation will be implemented into the CAFTA .rr database file prior to the final quantification and development of the QU Notebook. Thus, this issue is resolved.

2011 Peer Review Finding:

The use of screening values does not meet HR-D2.

The values appear arbitrarily low, for screening values, and are not based on actual procedure-based assessment (i.e., a systematic process).

While THERP data may have been used in creating the screening values, neither the THERP or ASEP methods are used. For example, no consideration of independent verification is presented in the analysis approach. SR HR-D2 allows screening (using the ASEP approach) for non-significant HEP. As a test, the BE importance was looked at and the very first pre-initiator randomly selected (HEP-AF--TY-1P29) has a RAW of 2.06.

HR- CC-II HR-E3 (CC- 2010 Peer Review Finding: No - The 2011 Peer Review Finding was resolved in the G5 1) Talk throughs were performed for E-0, ECA 0.1, PRA Model. See resolution below.

Finding HR-E4 (CC- E-1.3 and E-1.4 and for risk significant operator HR-G5- I) actions (Section E.2). Simulator observation was 2011 Peer Review Plant Response:

01 provided for SGTR event that address timing for Screening values were reset from 1E-4 to 5E-4. The actions. Appendix E.4 provides simulator model was rerun and a list of BEs showing up in the CDF Page 32 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs observations to several procedures but only cutsets at a truncation of 1E-I Iwas generated. The provides timing information. But after a review of mis-positioning BEs in the list were then reviewed to see the risk significant operator action in the which if any were important. A mis-positioning BE was quantification notebook and Appendix E there was considered important if the F-V was greater than 0.005 or limited or no information on (HEP-SW--START-IE, the RAW was greater than 2. There was one HEP-AF--CST-FW, HEP-AF--CST-LOW). In mis-positioning BE on Unit 1 which had a RAW that was general the only insights documented from these slightly less than 2 and one mis-positioning BE on Unit 2 interviews were to support timing. There is little or which had a RAW greater than 2. These events had a no documentation to support the evaluation of the detailed ASEP analysis performed to generate a specific information that impacts the cognitive, stress value for them. The value obtained was then inserted into levels, and information that to support the THERP. the model and used for the quantification. Note that the For example the time window information mis-position event was for valve IAF-109 on Unit 1 and HEP-CCW-STDBY-IE (OPS FAILS TO ALIGN 2AF-109 on Unit 2, the same mis-positioning event.

STANDBY HEAT EXCHANGE (PRE REACTOR TRIP)) is based the High CCW temperature alarm Section 4.2 of the HRA Notebook, 6.0 has been rewritten the limiting time should be based on high RCP to clearly identify simulator observations and operator bearing temp. During an operator interview the interviews conducted to confirm the interpretation of the operators would trip the reactor in a shorter time procedures is consistent with observations and response window than 15 minutes to protect the RCPs. models are correct for scenarios modeled.

Without this level of detail document it is difficult to Appendix E has added Section E.5, "Additional Emails reproduce results. with operations and plant staff to support HRA.

Talk throughs andlor simulator run insights should Documentation has been revised to correctly list cover information requires to support the Appendix E and Appendix F as appropriate.

evaluation of the information that impacts the cognitive, stress levels, and information that to Response to Finding from November 2010 stated that support the THERP. At a minimal this level of "Appendix F, Section F.2, was inadvertently truncated.

detail should be provided for all risk significant This table included additional operator interview insights operator actions- An example of inf~m'~ation that related to execution on additional risk significant HFEs (As would be expected to be documented and asked of 8/4/10)." This should read " Appendix E, Section E.2, during an interview would, for each scenario, was inadvertently truncated. This table included additional confirmation that the action and procedure steps operator interview insights related to execution on are correctly performed. Document the number of additional risk significant HFEs (As of 814.11 O)."

people required to support the actions (impotent for Page 33 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs local actions). Documenting information to support the information necessary to evaluation the cognitive error (clearly of the cue, front panel or back panel, etc). Document the workload during the event (Are you in multipage procedures or one, stress level, etc). Document time window estimates. If time to cue or time to undesirable state is based on T&H ask if these times are consistent with what they have seen on the simulator.

2010 Peer Review Plant Response:

The reviewer and analyst clearly agree that time required to complete actions were based on operator talk-throughs of the procedures or simulator observations. HR-G5 does not require documentation of operator interviews to support the evaluation of the information that impacts the cognitive, stress, levels, and information that to support execution analysis. However, review of Appendix F by the HRA analysts showed that Appendix F, Section F.2, was inadvertently truncated. This table included additional operator interview insights related to execution on additional risk significant HFEs (As of 814110).

Not included in Section F.2 were 3 risk significant HFEs related to aligning the battery charger and these HFEs were re-interviewed with operations and the insights are included in the HFE analysis.

The overall HEP values were not impacted by I additional operator insights.

Page 34 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs HEP-125-BAT-CHG OPS FAILS TO ALIGN PWRJRELOAD TO BATT CHARGER FROM CONTROL ROOM HEP-125-COG OPS FAILS TO RECOGNIZE NEED TO PWR BATT CHARGER (COMMON COG)

HEP-125-COG-REC OPS FAILS TO RECOVERY BATTERY CHARGER AFTER BATTERIES DEPLETE 2011 Peer Review Finding:

Note that this original finding is related to SRs HR-E3, HR-E4, and HR-G5 (HR-E3 and HR-E4 listed as CC: I by original peer review team).

HR-E3 requires interviews to confirm procedure interpretation and HR-E4 requires confirmation of response models. Plant response to this F&O does not address HR-E3 and HR-E4. More complete operators interviews appear required.

Also, the documentation appears to alternately list the Interview Appendix as Appendix E and Appendix F. This editorial issue should be corrected when additional operator interview information is added.

DA- CC-I 2010 Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the C7 For the Level 2 requirements, this SR states PRA Model. See resolution below.

Finding "BASE number of surveillance tests on plant DA-C7- surveillance requirements and actual practice. 2011 Peer Review Plant Response:

01 BASE number of planned maintenance activities MSPl surveillance data was not used. The MSPl Basis on plant maintenance plans and actual practice. Document for Point Beach was used. From Section 1.1.6 BASE number of unplanned maintenance acts on of the MSPl Basis Document "For Point Beach, the actual plant experience." numbers of demands for Emergency AC System are based on the actual number of demands and estimated Page 35 of 71

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Attachment I: Point Beach PRA Peer Review Findings v

I Category 1 Other Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs Plant surveillance data of 3 years was obtained from MSPl basis doc, Revision 14, September 30, 2009.

This data was annualized for computing the test and maintenance unavailability due to surveillance procedural tests, actual planned maintenance activities and unplanned maintenance acts on actual plant experience at Point Beach. In cases where MSPl basis document demand data was not available, actual demands were determined from data logging devices installed on the equipment or from Safety Monitor. The DA- 2010 Peer Review Finding: No - The 2011 Peer Review Finding was resolved in the C8 Plant-specific operational records were not used PRA Model. See resolution below.

Finding for components such as SW pumps -these were DA-C8- lumped together. 2011 Peer Review Plant Response:

0I The purpose of collecting data is to try to estimate future Doc Assumed symmetry across the similar components performance. It is a better estimate of future unavailability Only - this meets the CC I in the Standard for DA-C8. by polling the data for identical components in the same system. The data should be long term averages, so the Apply component specific data to each individual occurrence of unavailability due to failure should average component for unavailability. out over the long term. Therefore, long term averages will continue to be used. Component specific unavailability 2010 Peer Review Plant Response: data will not be used.

Plant Response: In 6 years of the data period following are the actual observations about service water pumps:

1. There were no failures to run incidents for any of the service water pumps.

2. All the pumps were evenly swapped for running and no preferential treatment was given to any of the pumps.

3. There was only one failure to start out of the system engineer estimated 2592 starts.

Page 37 of 71

Attachment I:Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs

4. All the Plant operators logs were studied to look for coherence and absolutely no specific operational preference were given to any pump.

The plant specific operational and standby status timing of each SW pump was obtained from the system engineer.

Additionally, the time that components in normally operating systems was not imbedded in the PRA.

Rather, the PRA was set up to be imported into the Safety Monitor and thus house events had been used to set the status running and standby equipment. In response to F&Os IE-C10-01 and SC-A6-03 specific configurations with the duration for each configuration have been added to the PRA. This incorporates the plant-specific operational records.

2011 Peer Review Finding:

Information could not be found in DA or SW System Notebooks (Doc only).

DA- 1 CC-I 2010 Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the CIO This SR states "when using surveillance test data, PRA Model. See resolution below.

Finding REVIEW the test procedure to determine whether DA-Cl 0- a test should be credited for each possible failure 2011 Peer Review Plant Response:

0I mode. COUNT only completed tests or unplanned Per Scientech e-mail from Lincoln Sarmanian dated operational demands as success for component 10/31/2011 @ 3:29 PM the procedures were evaluated to operation." For Level 2 - it also requires "If the determine that the appropriate failure modes depending on component failure mode is decomposed into sub-the type of component were accounted for.

elements (or causes) that are fully tested, then USE tests that exercise specific in The first paragraph of Section 2.3.3 was revised to read as their evaluation." follows (underlined text was added): Data for the number Page 38 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs of demands based on surveillance testing was This is met at CCI since the first part of generated through the demands stated in procedures requirement appears to be done appropriately, but and requirements (performance per demand) during it does not appear that the component failure various plant states is tabulated in Appendix A. The modes are decomposed into sub-elements that are number of times a test procedure was required was fully tested. recorded for the key components. The procedure was then reviewed to determine the number of demands Review the procedures down to the sub-element on the component for each test run. The appropriate level and use the information to credit tests that failure modes for the type of component were exercise specific sub-elements. accounted for in the procedure review. In addition, key components which were not being tested but did 2010 Peer Review Plant Response: receive demands were also recorded.

Plant Response: The Summary Assessment is not true. The review of test procedures was performed. The results of this review are shown in Appendix A of the Data Notebook.

As per Capability Category Ill, Table-7 of the data notebook lists the actual hours of unavailability for the components as per the decomposition of the component failure mode into sub-elements that are fully tested and use tests that exercise specific sub-elements in their evaluation.

In the calculation of unavailability hours for the data period it was ensured that double counting of unavailability is avoided.

2011 Peer Review Finding:

Section 2.3,3describes the process for evaluating test data obtained via surveillance procedures. It does not state that it evaluates procedure to determine if test can be credited for all possible failure modes of the component.

Page 39 of 71

Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs DA- Not Met 2010 Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the C14 The System Notebook Guidance notebook states PRA Model. See resolution below.

Finding that a specific review for possible activities which DA-Cl4- can cause the simultaneous unavailability of 2011 Peer Review Plant Response:

01 redundant equipment is documented in the Data Reviewed Real Time Safety Monitor from Notebook. No discussion of such a review was December 11,2009 through December 11,2010 for Unit 1 found in the Data Notebook. and Unit 2. Only concurrent maintenance found on a regular basis was battery and associated battery charger.

Although the team confirmed that concurrent Whenever battery DO5 was OOS, the associated battery planned maintenance on redundant equipment is charger DO7 was also 00s. When battery DO6 was OOS, not allowed per plant philosophy, this is not battery charger DO8 was also 00s. When battery Dl05 addressed anywhere in the PRA. Because of this, was OOS, battery charger Dl07 was also 00s. When T&M event combinations are showing up in battery D l 06 was OOS, battery charger D l 08 was also dominant cutsets that are in reality not allowed, 00s.

and should have been eliminated as mutually exclusive events. The converse is not true. When a battery charger was out of service, the associated battery was aligned to the spare Add in a discussion of the plant philosophy that battery charger.

does not allow concurrent planned maintenance on redundant equipment - including redundant Since the maintenance for the battery and associated equipment in the opposite unit. Once this is battery charger is concurrent, they are not independent complete, a review of ALL T&M events in the PRA events, but the same event. To account for this the same should be performed to determine which ones are T&M event was used for the battery and associated precluded from being planned concurrently, and battery charger. This change did not affect the CDF or these combinations should be added into the LERF on either unit.

system notebooks and the fault tree model as mutually exclusive events. Section 3.3 of the Data Analysis Notebook was updated to describe the review that was performed, the findings and 2010 Peer Review Plant Response: the effect on the model.

Plant Response: All T&M events contained in the models were reviewed, along with the plant Technical Specifications. Additional combinations of T&M events were added to the MEX portion of the CAFTA fault tree.

I I I I I Page 40 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs 2011 Peer Review Finding:

Finding was that a discussion of concurrent maintenance was not found in the DA Notebook.

DA- CC-II DA-D3 2010 Peer Review Finding: No - The 2011 Peer Review Finding was resolved in the DI CHOOSE prior distributions as either non PRA Model. See resolution below.

Finding informative, or representative of variability in DA-DI- industry data. CALCULATE parameter estimates 2011 Peer Review Plant Response:

01 for the remaining events by using generic industry Table 5 and Table 6 were reviewed against data. NUREGICR-6928 with changes made as appropriate.

The issue is how the posterior distribution is Were also checked against .rr files for Unit 1 and Unit 2.

calculated. The data notebook states that the .rr files were updated to be consistent with revised Table 5 generic priors are taken from NUREGICR-6928. and Table 6.

Those distributions are either beta distributions or gamma distributions depending on whether the FW normal operating pump revised in Table 5 and .rr files failure mode is demands or time related. The for both units.

parameters of the distributions are real numbers.

The means for the posterior distribution are calculated in a manner consistent with the expressions presented on pages 14 and 15 of the PBNB notebook. Several cases were tested (AF-MDP, FR.>=I Hour and FS) and using the expressions on pages 14 and 15. The means calculated were higher than that presented in Table 5. Hence the updated distributions may be optimistic.

NUREGICR-6823 Handbook of Parameter Estimation for Probabilistic Risk Assessment discusses Bayesian updating of beta and gamma functions. Recalculate the posteriors using the information from that NUREG as guidance. Note the posterior parameters are easily calculated as is the mean. The percentile can be calculated from EXCEL or equivalent.

Page 41 of 71

/ I I Attachment I:Point Beach PRA Peer Review Findings I 1 SR Category and Finding Other Affected SRs Issue and Proposed Resolution / Impact to Applications and Peer Review Resolution 1 2010 Peer Review Plant Response:

Plant Response: This F&O is incorrect and should NOT be a Finding or a Suggestion. As guided by the Cap Cat Ill realistic parameter estimates based on relevant generic and plant-specific evidence was calculated.

The issue is the use of generic data parameters taken from NUREGICR-6928. The NUREG presents the resulting generic data as both gamma distributions and Mean and ER and does not provide guidance as to how to use these or which set to use. The principal author stated that he had not considered using the results as we did that this is not incorrect.

After several lengthy discussions both in-house and with the principal Author of NUREGICR-6928, the consensus was that using the mean and error factor to generate the parameters for the prior distribution was correct and that using the provided gamma functions would yield incorrect results.

This is artifact of the limits imposed in developing the gamma distributions presented in the NUREG.

Thus, the approach used at Point Beach is correct.

After discussions and review with FPL staff and performing the Bayesian updates in the CAFTA software package and obtaining the same results, it was decided to continue with the first approach, which is correct.

That said, the differences between the 2 methods were evaluated. A new Table-5 was developed on Page 42 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs the basis of the reviewer's recommendation and new insights observed for certain components like fire water pump.

Bayesian update was used for specific characterization of the uncertainty.

Prior distribution (characteristic parameters: alpha and beta) was obtained from NUREGICR-6928 and posterior was calculated. The process has been stated in detail in section 3.1.1 Hardware Failure Rates.

The parameter estimates for the remaining events were calculated by using generic industry data from Table-5 of NUREGICR-6928.

The results of the 2 methods were compared. The gamma approach essentially has smaller tails in the prior distribution and as such, the mean value of an update can be influenced to be higher with less uncertainty than the correct approach.

2011 Peer Review Finding:

Based on PBUI .rr dated October 2010, it appears that priors taken from NUREGICR-6928 (MDP STBY FTS) incorrectly assigned to FW normal operating pump (MDP RNNING FTS). Also, value in Table 5 for FW-MDP FS is inconsistent with PBUI .rr. Agree that using NUREGICR data distribution (e.g., beta) mean and EF as input to a lognormal for Bayesian updating has a minor effect. Suggestion, ensure that the 5.01 model, including Table 5 are reviewed for consistency and the correct prior.

Page 43 of 71

Attachment I:Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs DA- CC-1 2010 Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the D4 When the Bayesian approach is used to derive a PRA Model. See resolution below.

Finding distribution and mean value of a parameter, DA-D4- CHECK that the posterior distribution is reasonable 2011 Peer Review Plant Response:

01 given the relative weight of evidence provided by Additional text added to Appendix C, Section 1.O. New the prior and the plant-specific data. text states:

The team did not find evidence that the posterior "Table 5 provides inputs where the prior was updated with distribution was checked to determine if it is plant specific data for the posterior. Upon completion of reasonable given the relative weight of evidence the update process a reasonableness check is performed.

provided by the prior and the plant-specific data. Each posterior distribution is reviewed against the prior For a discussion of what is intended in the distribution and the weight of the plant specific evidence to standard refer to NUREGICR-6823 Handbook of ensure that the result of the update is reasonable. The Parameter Estimation for Probabilistic Risk generic value, plant specific value and updated value were Assessment. considered on a case by case basis. For those cases where the generic and plant specific data were close, the From the ASME Standard: ExamplesOf tests posterior was reviewed to ensure it was close. Where the ensure that the is generic and plant specific were different, the posterior was and that the generic parameter estimates are reviewed to ensure this was reflected.

consistent with the plant-specific application includethe following: The balance of the data applied the generic prior as the posterior. Since the generic was applied, the posterior is (a) Confirmation that the Bayesian updating reasonable and appropriate relative to the generic prior."

does not produce a posterior distribution with a single bin histogram (b) Examination of the cause of any unusual (e.g., multimodal) posterior distribution shapes (c) Examination of inconsistencies between the prior distribution and the plant-specific evidence to confirm that they are appropriate (d) Confirmation that the Bayesian updating algorithm provides meaningful results over the range of values being considered Page 44 of 71 I

Attachment I:Point Beach PRA Peer Review Findings I Category I Other I SR I and - I Affected I Issue and Proposed Resolution I Impact to Applications and Peer Review Resolution /

Finding SRs (e) Confirmation of the reasonableness of the posterior distribution mean value 2010 Peer Review Plant Response:

Plant Response: Additional text added to Appendix C, Section 1.O. New text states:

"Upon completion of the update process a reasonableness check is performed. Each posterior distribution is reviewed against the prior distribution and the weight of the plant specific evidence to ensure that the result of the update is reasonable."

2011 Peer Review Finding:

This information is not contained in Appendix C or Section 1.O. Also there has to be a discussion about the comparison not just a statement that you t-Not Met Finding QU-DI-Met) did one.

QU-D2 (Not 2010 Peer Review Finding:

This SR requires a review of a sample of the QU-D3 (Not significant accident sequences/cutsets sufficient to Met) determine that the logic of the cutset or sequence No - The 2011 Peer Review Finding was resolved in the PRA Model. See resolution below.

2011 Peer Review Plant Response:

01 QU-D5 (Not is correct. At the time of the Peer Review for the Internal Events Met) PRA, the Quantification Notebook was in Draft. Based on The cutset review presented in the Quantification the final version of the Quantification Notebook, the tables, notebook is not adequate. Reviews describe the cutset descriptions, and cutsets were updated.

sequence that the cutset represents or list the failed equipment, but do not describe how the specific component failures in the cutset lead to the end state defined by the sequence. Since the equipment failures were not analyzed, significant cutsets exist that do not appear to make physical sense and do not reflect the as built, as operated plant.

Page 45 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs A specific example of a suspect cutset is cutset #4.

The cutset is either invalid or represents a design deficiency of the plant. The cutset indicates failure of a single air handling unit while the non-safety related gas turbine generator is in maintenance leads directly to core damage.

Review indicates that the cutset may be invalid or overly conservative due to a convolution of items:

HRA recovery rules are assuming a HRA failure since the power supplies for the cues to the event are not explicitly modeled. This is likely over conservative and skewing the results of the quantification.

The cutset may be due to the assumed alignment of the service water pumps, which are assumed to be in the most restrictive alignment for this type of event. This alignment assumption is most likely over conservative and skewing the model quantification results.

A further example of a suspect cutset is cutset

1. I 2501, which includes simultaneous planned maintenance on both turbine driven AFW pumps.

This condition would not be entered during plant operation, making the cutset invalid.

Both of these cutsets were reviewed and determined valid in the quantification notebook.

Cutsets need to be reviewed to ensure the results make sense and reflect the as built, as operated plant. Cutsets need to be adequately described to facilitate understanding of the PRA.

Page 46 of 71

Attachment I:Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs 2010 Peer Review Plant Response:

No response provided.

201 1 Peer Review Finding:

No Plant Response.

The QU notebook is set up properly to address SR-Dl, D2, D3 and D5, however, this notebook including critical tables are not update and competed yet.

Based on review of new cutsets, old cutest #4 now requires failure of 2 AHUs versus 1, however, description of this cutset in Table 3.3-1 in previous QU Notebooks appears erroneous and inconsistent with actual cutset.

Old cutset 12501 (TIA-005-SEQ) is lower in frequency, but procedurally the plant is currently allowed to have both TDPs unavailable for maintenance. Thus, this modeling is appropriate and the frequency of this cutset is less than 1E-7.

Table 3.2-1 provides as discussion of significant event tree sequences and a discussion of the underlying logic (QU-D2 and D3). Table 3.3-5 provides a review of non significant cutsets (QU-D5 and D3) 2010 Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the This SR requires the PRA to compare its results to PRA Model. See resolution below.

Finding those from similar plants and IDENTIFY causes for QU-D4- significant differences. For example: Why is LOCA 201 1 Peer Review Plant Response:

01 a large contributor for one plant and not another? On January 10, 2012 PRA analysts from Point Beach, Prairie Island, Kewaunee and Ginna participated in a While the CDF results and initiating event conference calllmeeting to discuss the differences in the contributions from several plants are compared to PRA results. The insights provided by this discussion the results from the Point Beach PRA, there is no have been added to Section 5.4 of the Quantification discussion of the causes for significant differences Notebook, 11.O. Differences now included are batteries, in those results. A discussion of the reasons for service water header arrangement, safety injection pumps Page 47 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs the differences is necessary to meet Category IIIIII. and power uprate.

Provide a discussion of the reasons for significant differences in plant results.

2010 Peer Review Plant Response:

No response provided.

2011 Peer Review Finding:

No Plant response.

Section 5.4 and Tables 5.4-1 and 2 provides a high level comparison, however the description of differences in results should be enhanced (the only difference cited is the 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> battery life assumed for Point Beach). This is a limited description that requires more detail. For example, an explanation of why loss of 4Kv is 0.0 at Point Beach and not so at other plants.

2010 Peer Review Finding: No - The 2011 Peer Review Finding was resolved in the This SR requires a review of the importance of PRA Model. See resolution below.

components and basic events to determine that they make logical sense. 2011 Peer Review Plant Response:

At the time of the Peer Review for the Internal Events No review of components or basic event PRA, the Quantification Notebook was in Draft. Based on importances was documented in the PRA the final version of the Quantification Notebook, the documentation. importance measures were updated and reviewed. See resolution below.

Perform and document a review of the significant components/basic events.

Reviews of risk significant basic events are discussed in 2010 Peer Review Plant Response: section 4.2 of PRA 11.O, Quantification Notebook.

No response provided.

Page 48 of 71

Attachment I: Point Beach PRA Peer Review Findinas Category Other and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs configurations) were updated and therefore do not need to be added, however, characterization of assumptions are all minimal or no impact is questionable and still needs improvement. For example, battery life of 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> is characterized as "no impact" yet in comparison with other plants (Section 5.4) this is characterized as a significant difference with other plants. --

QU- Not Met 2010 Peer Review Finding: No - The 2011 Peer Review Finding was resolved in the F5 This SR requires documentation of limitations in PRA Model. See resolution below.

Finding the quantification process that would impact QU-F5- applications. 2011 Peer Review Plant Response:

01 The following text was added to Section 2.4.4, "Logic The discussion of limitations in the quantification Flags" in the PRA 11.0 Quantification Notebook.

process does not appear to be adequate. There is a discussion in the quantification notebook that is Flags were used in the Point Beach model to indicate a limited to quantifying sequences with failure particular condition (ie. " A Steam Generator Intact) and to probabilities greater than 0.1. There is no establish normal alignments (ie. D-49 supplying D-53). In discussion of quantification process items which most cases, the flags were either set to 0.0 or 1.O. When could impact applications. For example, the model a flag setting is set to a value between 0.0 and 1.0, the assumes certain equipment alignments in the flag is being used to establish a split fraction. For master flag file. The assumed alignments could example, 1 of 2 component cooling water pumps is impact applications, and the assumed alignments typically running on each unit. To account for this in the should be noted in the limitations discussion so model, the flag for CCW pump running is set to 0.5 and that the impact on applications can be addressed the flag for CCW pump in standby is set to 0.5. This is the when the model is used in support of applications. way that flags are used to provide a model which represents the as-built, as-operated plant.

Review the model and quantification process and identify process and modeling items that are The potential impact on the results if the flags are not set unique to the Point Beach PRA quantification that properly is to create a model which does not accurately an analyst needs to be aware of when supporting reflect the plant. Depending on the flag settings this can applications. have a large or small impact on the results. For example, if the flags were set to have both component cooling water pumps running, the core damage frequency would increase.

Page 50 of 71

Attachment I: Point Beach PRA Peer Review Findings 1 Category I Other Issue and Proposed Resolution Impact to Applications and Peer Review Resolution 2010 Peer Review Plant Response: The importance of the flags is that they enable the model The model was changed to address all possible to be changed to reflect changes in operating philosophy.

configurations of the normally operating systems. If instead of normally operating 3 of 6 service water pumps, the plant went to normally operating 2 of 6 service The change added alignments so all pumps have water pumps the value of the flags for the service water T&M, are standby or running, etc. Changes were pumps running and standby would change. No changes made to the service water system, the component to the model would be required. The other importance of cooling water system, and the instrument air flag settings is that risk can easily be evaluated when system. equipment is set up to an alternate alignment by changing the value of the flag, rather than changing the model.

As a result of these changes there is no need to discuss the impact of the assumed alignments as The internal events PRA can be used for applications by these are no longer used in the model. resetting basic events values to the desired values through the use of a flag file. To find out the impact of flooding out 2011 Peer Review Finding: a room, all the equipment and operator actions failed by Finding LE-G5-01 is not addressed above. Also, a the flooding in the room would be reset using a flag file to discussion of flag file setting and their potential failed (TRUE). The impact of the applications on the impact on results, importance and applications has model is application specific.

not been presented as requested by the original peer review.

LE- CC-II 2010 Peer Review Finding: No - The 201 1 Peer Review Finding - was resolved in the BI No credit was taken for manual actions to vent the PRA Model. See resolution below.

Finding reactor pressure vessel (post core damage) to LE-B1-01 reduce vessel pressure. 201 1 Peer Review Plant Response:

Doc The technical basis explaining how the operator action Only Venting is ultimately credited for venting through a was subsumed was added to Section 4.0 of the Large stuck open pressurizer PORV or safety valve when Early Release Frequency Notebook, 12.0.

addressing an induced SGTR. However, if the severe accident management guidelines call for depressurization, additionally fidelity and use of the low RCS pressure branch in the event tree.

Include the action (with hardware properly accounted for) or justify not including it.

Page 51 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs 2010 Peer Review Plant Response:

Credit for manual action to vent the reactor vessel was taken. Although not applied as a functional heading in the Containment Event Tree (Figure 4-1 of PRA 12.0), a 50% probability of early RCS depressurization, which represents manual opening of a PORV or a stuck-open PORV, was used when calculating the probabilities of PI-SGTRs and TI-SGTRs in Appendix C of PRA 12.0 (see Appendix C item # 6, listed as "APET Heading F").

This treatment is very similar to the treatment provided for early RCS depressurization in WCAP-16341-P (for which, unfortunately, Point Beach was not a participant). Generally, this WCAP is considered to represent a Category II model.

However, there are three differences between the WCAP modeling and the NUREG modeling:

The WCAP used a success probability of 0.9 for early RCS depressuization, based upon Engineering Judgment. A value of 0.5 is used based upon NUREG-1570 (which also used Engineering Judgment).

The WCAP assumes successful early RCS depressurization prevents TI-SGTR. The NUREG-1570 model assumes that if the SIGs are depressurized, there is still a probability of TI-SGTR even with early RCS depressurization.

In the WCAP, successful early RCS depressurization potentially yields a different early containment failure probability (although both Page 52 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs failure probabilities are approximately equal). The PB CET containment failure probabilities (i.e.,

CF-LOW and CF-HIGH) are assumed equal.

Thus, an early RCS depressurization would not yield different containment failure results.

One final comment. The NUREG-1570 Induced SGTR model contains three main branches or pathways: I ) the RCS is initially intact and may become depressurized via a number of ways, including manual depressurization (path A); 2) the RCS has a seal LOCA (path B); and 3) the RCS has a very early stuck open PORV (path C). Given the PB tube integrity, the only possibility of a TI-SGTR is for the path that contains a seal LOCA (path B). Because the RCS has a depressurization pathway, intentional depressurization is not questioned for this pathway in the NUREG-1570 model. Thus, only a PI-SGTR may be impacted by intentional depressurization (thus addressing the second bulleted modeling difference from above).

A sensitivity was performed in which the successful depressurization probability was changed from 0.5 to 0.9. The PI-SGTR probability had an insignificant change (thus addressing the first bulleted modeling difference from above).

Given the above discussion, the following conclusions are provided:

Credit for manual action to vent the reactor vessel was taken.

A sensitivity on the probability of successful early RCS depressurization was performed and the PI-SGTR probability had an insignificant change.

Successful early RCS depressurization would have Page 53 of 71

Attachment 1: Point Beach PRA Peer Review Findings 1 Category I Other I SR 1 and - I Affected 1 Issue and Proposed Resolution 1 Impact to Applications and Peer Review Resolution Finding SRs

( no impact to the TI-SGTR probability.

~uccessfulearly RCS depressurization would have no impact on the early containment failure probability.

Therefore, no changes were made to the Point Beach LERF Notebook.

2011 Peer Review Finding:

The technical basis described above explaining how the operator action is subsumed needs to be added to the LE Notebook to close this Finding.

LE- CC-I 2010 Peer Review Finding: No - The 2011 Peer Review Finding was resolved in the C2 One action, HEP-CI--EOP-0-~2,which is to close PRA Model. See resolution below.

Finding the containment isolation valves given a LOCA, LE-C2-02 was included in the model. As stated in Section 2011 Peer Review Plant Response:

5.2.2 of PRA 11.O, " MAAP analyses for break Changed gate GC11444 from an "AND" gate to an "OR sizes larger than 6" had insufficient time available gate.

to perform the action. Therefore, this HEP is "0R"ed in the model with the Large LOCA initiating The change does not affect CDF since it is in the LERF event. However, a review of the model revealed fault tree, containment isolation.

that this operator action was "ANDnedwith the large LOCA initiator. The delta Unit 1 LERF due to this change was 2E-12.

Change the Gate from "AND" to " O R and verify There was no delta Unit 2 LERF due to this change.

that the rest of the logic remains valid.

2010 Peer Review Plant Response:

This action was reviewed in the CAFTA fault tree logic. Agree with the suggested gate change.

Change gate GC11444 from an "AND" gate to an

" O R gate. The remainder of the logic is valid.

2011 Peer Review Finding:

Gate GC11444 has not been changed.

Page 54 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs LE- CC-I 201 1 Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the C3 CC-II requires review of significant accident PRA Model. See resolution below.

Finding sequences and justification for any repairs LE-C3-01 credited. There is no evidence that this has been 2011 Peer Review Plant Response:

New considered. A review of significant accident sequences was performed.

No repairs were identified which could be credited. This was documented in PRA notebook 12.0, LE notebook, Section 1.6.2 by adding the following paragraph.

The Point Beach PRA models limited credit for systems or functional recovery, this applies to both the Level 1 PRA and the Level 2 PRA. NRC and industry PRA expectations regarding modeling of recovery of failed equipment or functions during accident progression is that any such credited recovery in the PRA is scrutinized. As such, typical of most industry PRAs, the Point Beach PRA does not model significant credit in the Level 2 PRA for recovering failed equipment functions (other than offsite AC power).

LE- CC-I LE-C10 2010 Peer Review Suggestion: No - The 201 1 Peer Review Finding was NOT resolved in C9 (CC-I) Point Beach uses a unit-specific NUREGICR-6595 the PRA Model. See resolution below. The Finding LE-Cl I CAFTA one-top model covering both CDF and documentation should be updated at the next PRA Model LE-C9-01 (CC-I) LERF. The model should be expanded to address revision to document the plant specific differences from LE-C12 the dual unit impacts but no additional level of the model in NUREGICR-6595 (CC-I) detail would be required. The NRC has indicated LE-D3 (CC- that for most applications, they are only interested 2011 Peer Review Plant Response:

1) in LERF. Furthermore, they have indicated that the use of a simplified NUREGICR-6595 LERF model The LERF Analysis does meet CC-I requirements. Use of was acceptable as long as it addressed the PRA which meets CC-1 requirements is conservative.

plant-specific differences from the model in NUREGJCR-6595. However, for any application that directly addresses containment performance or the actual source terms and timing, a more detailed analysis approximating a Level 2 PRA would likely be required.

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Attachment I : Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs 2010 Peer Review Plant Response:

First, this is a suggestion only and there is no requirement to address this issue.

Second, the Peer Review was of the Level 1 CDF and LERF Model. The issue raised suggests that A Level 2 PRA would likely be required to evaluate some issues of containment performance. This is outside the bounds of the areas to be evaluated in a Level 1 Peer Review.

Additionally, it should be noted that Point Beach has a complete Level 2 PRA model, which is in the process of being updated, that is available to be used for any evaluation of containment performance for which the Level 1 LERF model is deemed insufficient.

2011 Peer Review Finding:

Original suggestion is limited in scope and since CC-II is not obtained for SR-C9 through C12, this should have been a finding. Above response does not address CC-II requirements (e.g., need to explain that containment analysis went beyond NUREG and is CC-I1 and add it to the notebook if this is true). Also, the present LERF Notebook is not a complete Level 2 model. If it exists it is not available.

LE- CC-I1 2010 Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the D5 The secondary side isolation analysis was PRA Model. See resolution below.

Finding performed in a conservative manner without a LE-D5-01 detailed analysis of isolation capability. For 2011 Peer Review Plant Response:

Doc example, all steam generator tube rupture core The technical explanation was added to the end of Only in damage sequences are conservatively assumed to Section 5.8.4 of the Accident Sequence Notebook.

AS lead to LERF. The analysis meets Capability Page 56 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs Category I, but a more detailed, realistic analysis is necessary to meet Capability Category II or higher.

Perform a more detailed realistic secondary side isolation analysis to meet Capability Category II or higher.

2010 Peer Review Plant Response:

The end states of the SGTR event are GLH (SGTR, Late core damage, High pressure) and GEH (SGTR, Early core damage, High pressure),

and only GEH is considered LERF (PRA 12.0, Section 3.2.3). The following SGTR GEH sequences either do not question isolation or isolation was successful, yet are considered LERF for PB:

R-022: Isolation not questioned, AFW to ruptured SIG used, thus ruptured SIG not isolated.

Therefore isolation is not successful. A more detailed isolation analysis not required for this sequence.

R-023: Isolation not questioned, all AFW fails. A Level 2 MAAP analysis shows that this sequence results in RCS and SIG pressures rising to the point of SIG ASD andlor MSSV actuation.

Therefore isolation is not successful. A more detailed isolation analysis not required for this sequence.

R-026: Isolation successful, cooldown and depressurization fails. Because of the failure of cooldown and depressurization, the ruptured SIG continues to fill due to primary to secondary flow resulting in opening of the SIG ASD and/or MSSV.

Therefore isolation is not successful.

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Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs A more detailed isolation analysis not required for this sequence.

R-031: Isolation successful, cooldown and depressurization fails. Because of the failure of cooldown and depressurization, the ruptured SIG continues to fill due to primary to secondary flow resulting in opening of the SIG ASD andlor MSSV.

Therefore isolation is not successful. A more detailed isolation analysis not required for this sequence.

Note that the PB SGTR emergency procedure (EOP-3) cannot prevent the MSSVs from opening, and the ruptured SIG ASD controller is set to 1050 psig. This setting does not preclude the ASD from opening under the sequence conditions described above. Thus, successful isolation does not preclude the possibility of a release from the ruptured SIG.

Therefore, no changes were made to the Point Beach LERF Notebook.

2011 Peer Review Finding:

Agree with technical explanation, but this explanation must be added to the AS Notebook for SGTR to close this Finding.

LE-FI Not Met 2010 Peer Review Finding: No - The 2011 Peer Review Finding was resolved in the There were some discrepancies between Unit 1 PRA Model. See resolution below.

Finding and Unit 2 LERF results for loss of offsite power.

LE-FI -01 Point Beach did identify the error but has not 2011 Peer Review Plant Response:

corrected as yet. Point Beach did provide the Model was revised such that GINIT-S2 is "ORed with LERF results for both units in tables and pie charts. GSC1120 when input to gate CET-013F.

The pie chart for Unit 2 did not agree with the tables for ISLOCA results or SGTR results.

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Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs Specifically, the table shows a LERF contribution of 9.3 % for ISLOCA but ISLOCA does not show up in the pie chart for unit 2. Also, the table shows a LERF contribution of 16.4% for Unit 2 but the pie chart for Unit 2 shows 1%.

Correct the known error with respect to the Loss of Offsite Power Contributions. Review the LERF results and adjust the tables and pie charts so that they are consistent with each other.

2010 Peer Review Plant Response:

Some of the issues with LERF were related to logic errors that have been identified and corrected in other systems, most notably 125 VDC and AFW, and one pair event tree errors on Unit 2 (TDI and TD2).

All of the Unit 1 and Unit 2 event trees were reviewed against the LERF notebook to verify that the event tree sequences are binned to the correct category.

Following this, the LERF Unit 1 and Unit 2 logics were reviewed against the verified event trees to ensure that the sequences are being properly classified.

Additional differences were due to discrepancies in data between the two Units (calc type, values).

A set of changes to the CAFTA fault tree structures were made. The most notable was adding gate GSCI 120 to AND gate CET-013F. This imposed the missing condition of RCP Seal LOCA.

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Attachment I : Point Beach PRA Peer Review Findings 1 Category 1 Other and - Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs 2011 Peer Review Finding:

Errors corrected. However, it appears that S2 gate GINIT-S2 should be ORed with GSCI 120 when input to Gate CET-013F.

Not Met 2010 Peer Review Finding: No - The 2011 Peer Review Finding was NOT resolved in Appendix A of PRA 12.0 contains a list of 25 the PRA Model. See resolution below.

Finding assumptions specific to the LERF analysis but did LE-F3-01 not include a characterization of the potential of the The documentation should be updated at the next PRA assumptions. Section 5.2 for PRA 11.0 discussed Model revision to document the potential impact on the sensitivities and other sources of uncertainties. model for the identified assumptions. Include sensitivities This section did contain one sensitivity analysis in this assessment.

related to LERF but the selected case was not related to any of the assumptions in PSA 12.0. 2011 Peer Review Plant Response:

Appendix C of PRA 11.0 also contains a list of the No response provided.

assumptions with a "characterization". These did match the assumptions listed in PRA 12.0. The characterization was at best terse. The assumptions were characterized as "Realistic" or "Conservative". However, for the "conservative" assumptions, there was no discussion of the potential impact on the model or the results. Also, the one issue for which a sensitivity analysis was performed was not on the list. This is a good indication that the list is incomplete.

a) Provide an assessment of potential impact on the model for the assumptions characterized as "conservative".

b) Tie the LERF sensitivity case to a LERF assumption by adding a new assumption and review the LERF analyses to determine if there are any other assumptions that might impact the analysis.

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Attachment 1: Point Beach PRA Peer Review Findings

( Category 1 Other SR I and I Affected I Issue and Proposed Resolution ( Impact to Applications and Peer Review Resolution

) Finding 1 SRs I I I

( 2010 Peer Review Plant Response:

No response provided.

I 2011 Peer Review Finding:

No plant response yet.

Met 2011 Flooding Focused Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the This SR states: For each flood area, IDENTIFY the PRA Model. See resolution below.

Finding potential sources of flooding including IFSO-A1 - (a) equipment (e.g., piping, valves, pumps) located 2011 Focused Flooding Peer Review Plant Response:

01 in the area that are connected to fluid systems A review of all systems at Point Beach was performed to (e.g., circulating water system, service water identify which systems were liquid systems. The Table in system, component cooling water system, Section 7.3 was then updated to show the review of all feedwater system, condensate and steam liquid systems including justification for why they are not systems); required to be addressed further or to indicate they were (b) plant internal sources of flooding (e.g., tanks or included.

pools) located in the flood area; (c) plant external sources of flooding (e.g.,

reservoirs or rivers) that are connected to the area through some system or structure; (d) in-leakage from other flood areas (e.g., back flow through drains, doorways, etc.)

Listing of potential flood sources in Section 7.3 appears to be reasonably complete, but a couple of systemsltanks do not appear to be addressed including Reheat Steam, Extraction Steam, Fuel oil tanks, Lube oil reservoirs, Spent Fuel pools, etc.

Since the Extraction Steam and Reheat Steam systems are specifically identified as potential HELB concerns in Section 7.1.2 of the report, they need to be included in the Section 7.3 analysis.

These other fluid sources are not expected to result in new significant floods but are required to be identified for completeness.

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Attachment I : Point Beach PRA Peer Review Findings 1 Category 1 Other Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution To meet the intent of the supporting requirement a review of all fluid systems should be performed and their presence needs to be mentioned, including a justification for why they are not required to be addressed further (e.g. insufficient volume, location of suction/discharge piping, with respect to pool level, presence of pool leak detection systems, etc.).

2011 Focused Flooding Peer Review Finding: No - The 2011 Peer Review Finding was resolved in the For each source and its identified failure PRA Model. See resolution below.

Finding mechanism, IDENTIFY the characteristic of release IFSO-A5- and the capacity of the source. INCLUDE: 201 1 Focused Flooding Peer Review Plant Response:

(a) a characterization of the breach, including The Temperature and Pressure information for each type (e.g., leak, rupture, spray) system modeled in the Flooding PRA was added to (b) flow rate section 7.1.2 of the Flooding Notebook.

(c) capacity of source (e.g., gallons of water)

(d) the pressure and temperature of the source Section 7.3.2 of the Internal Flooding Analysis provides the details of the postulated internal flooding events, although temperature and pressure is not discussed in this section, and is not documented in the WEFLOOD.XLS spreadsheet.

Temperature and pressure information needs to be provided to meet the requirements of the SR.

2011 Focused Flooding Peer Review Finding: No - The 2011 Peer Review Finding was resolved in the (Met) As noted in F&O IFQU-A1-01 of the 2010 Peer PRA Model. See resolution below.

Finding Review, the process used to identify flood-induced IFQU-A1- initiating events is in the documentation, but the initiating events identified in the documentation 2011 Focused Flooding Peer Review Plant Response:

does not always propagate properly into the flag SR IFEV-B2 was not resolved from the 2010 Full Scope files used for the quantification. In particular, the PRA Peer Review (F&O 2010 IFQU-A1-01). This was HEP events listed in Appendix 7.1J, Section 3.0 do Page 62 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs not appear to have been included in the identified in the Draft Internal Flooding Focused Peer appropriate flag files. Review. This F&O stated that there is still an issue with the Flag Files matching the documentation. In this To address this finding, the flag files should be instance, Flag Files U1-AFPN.flg, U1-AFPS.flg, reviewed for completeness and reflect the basis U2-AFPN.flg, U2-AFPS.flg and U2-FOPH.flg did not have information in the documentation so that all results the associated HEP listed in Appendix 7.1J, Section 3.0 are complete and reproducible. set to TRUE. The associated flag files were revised and affected the results as follows:

As a result of this change, Appendix 7.1 K was revised accordingly.

IFQU- Not Met 2011 Focused Flooding Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the A6 F&O IFQU-A6-01 from the 2010 Peer Review PRA Model. See resolution below.

Finding identified that several internal events related HFEs IFQU-A6- were modified to support the quantification. 2011 Focused Flooding Peer Review Plant Response:

01 However, the basis behind the "adjustments" to the ASME-ANS RA-Sa-2009 IFQU-A6 has the following HFEs did not appear to be justified - for example - requirements:

a straight multiplier has been applied to the Internal For all human failure events in the internal flood scenarios, Events HFEs instead of re-evaluating the HFE in INCLUDE the following scenario specific impacts on PSFs detail. This is inappropriate since the conditions for control room and ex-control room actions as associated with the original equipment failures that appropriate to the Page 63 of 71

Attachment 1: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs resulted in the need for the HFE have changed, HRA methodology being used:

and the potential to respond to the failure is (a) additional workload and stress (above that for similar completely different. sequences not caused by internal floods)

(b) cue availability For the HFEs credited in the Internal Flooding (c) effect of flood on mitigation, required response, timing, analysis, a completely "new evaluation" of the and recovery activities (e.g., accessibility restrictions, HFEs need to be performed including an possibility of physical harm) evaluation of the time available, the stress levels, (d) flooding-specific job aids and training (e.g., procedures, and the potential that the equipment is even training exercises) recoverable post flooding. Although additional information has been provided to attempt to justify The Internal Flooding Analysis Notebook addresses each the generic factors applied, this approach does not as follows:

meet the requirements of this SR since it still does not include consideration of the scenario-specific (a) Section 3.3 of Appendix 7.1H. The impacts of stress impacts on the performance shaping factors which on operator reliability are addressed in is required in order to meet this SR. NUREGICR-I278 (Reference H-2) and take the form of multipliers that are applied to the nominal HEPs that are used to evaluate the subtasks of an operator action. These stress multipliers are considered to be applicable to flood-related stress and are used as the basis for quantifying the effects of flood-induced equipment failures and confusion on operator reliability. Table 20-16 of NUREGICR-1278 (Reference H-2) provides a list of stress multipliers for step-by-step and dynamic actions over a range of different stress levels for both experienced and novice crews. These are used as the basis for the flood multipliers. Multiplier values for the Point Beach internal flooding analysis are determined by the following flow charts. The first flowchart is applicable to In-Control Room actions and the second flowchart is for Ex-Control Room actions. All Operator Actions in the internal events PRA model were reviewed and evaluated for the internal flooding analysis. For each PRA model operator action, the HRA Calculator data Page 64 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs associated with the action was reviewed and the appropriate multiplier applied to the HEP per the flow charts above (See Tables 1 and 2). The HRA Calculator provided the internal event HEP value for each event, the location of the action, and the time available to complete the action. Additional workload and stress have been evaluated for workload and stress per NUREGICR-1278 which is appropriate to the HRA methodology used in the Point Beach PRA.

(b) Cue availability has been evaluated and is documented in Table 1 and Table 2 of Section 3.3 in Appendix 7.1 H.

(c) The effect of flooding on mitigation was documented in Section 3.0 of Appendix 7.1J. The table in this section lists the HFEs which were set to guaranteed failure for selected flood initiating events because of the flooding effects in the areas where these actions are performed.

(d) Flooding specific job aids are provided in Attachment 2 to Appendix 7.1 H. Attachment 2 to Appendix 7.1 H are the detailed HEP calculations for the operator actions credited in mitigating the flood. No operator training on mitigating flooding is provided at Point Beach.

IFQU- Not Met 2011 Focused Flooding Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the A10 F&O IFQU-A10-01 of the 2010 Peer Review PRA Model. See resolution below.

Finding identified that although the Internal Flooding IFQU- Analysis documentation contained a couple of 2011 Focused Flooding Peer Review Plant Response:

A1 0-01 tables that had LERF values provided in them, no A discussion has been added to Appendix 7.1 K, discussion could be found that any review of the "Quantification", Section 3.2 which describes the review LERF analysis was performed to confirm the performed to determine if any new LERF sequences applicability of the LERF sequences. The current needed to be considered due to the unique impacts of a Internal Flooding analysis does include a review of flood. No additional sequences were identified.

cut sets to ensure that the cut sets make sense Page 65 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs from a LERF perspective; however, it still does not contain a discussion of the review that was performed to determine if any NEW LERF sequences needed to be considered due to the unique impacts of a flood. Potential NEW LERF impacts could be required if the flood could cause bypass scenarios that were not previously evaluated due to multiple spurious operations, inadvertent openings of Containment purge valves due to flood impacts on control panels, etc.

These types of potential NEW LERF impacts need to be included in the analysis, either by confirming that there are no NEW LERF sequences, or by modifying the LERF analysis as appropriate to address any NEW LERF sequences that are identified.

IFQU- Met IFEV-A5 201 1 Focused Flooding Peer Review Finding: No - The 201 1 Peer Review Finding was resolved in the 62 (Not Met) Although significant work has been done, and PRA Model. See resolution below.

Finding detailed spreadsheets are provided, there is still an IFQU-B2- inconsistency between the write-up in the front of 201 1 Focused Flooding Peer Review Plant Response:

01 the documentation (Section 7.4.4) and the SR IFEV-A5 was not resolved from the 2010 Full Scope information contained in the WEFLOOD PRA Peer Review (F&O 2010 IFQU-B2-01). This was spreadsheet printout in Appendix 7.1 B and the identified in the Draft Internal Flooding Focused Peer WEFLOOD.XLS file provided to the Peer Review Review. This F&O stated that there is still and issue with Team. For example, Section 7.4.4.8 states a the IF Notebook matching the electronic files, and in this frequency of 3.34E-05/yr for the DGI scenario case it was the WEFLOOD.xls matching Section 7.4.4.1 while the WEFLOOD spreadsheet shows a through 7.4.4.35. To resolve this issue in Rev. 2 of the frequency of 3.5E-05/yr, and section 7.4.4.9 states 201 1 IF Notebook, the values referenced from a frequency for the DG2 scenario of 5.97E-05/yr WEFLOOD.xls was removed and added a statement that while the WEFLOOD spreadsheet shows a the flooding frequency can be found in the spreadsheet frequency of 5.01 E-05/yr. Note that the flag files WEFLOOD.xls found in Appendix 7.1 C, WEFLOOD.xls.

appear to match the WEFLOOD.XLS spreadsheet.

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Attachment I : Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs This inconsistency should be eliminated and the analysis results consistent across the applications and documentation to avoid confusion and to support future updates.

IFQU- Not Met IFPP-B3 2011 Focused Flooding Peer Review Finding: No - The 2011 Peer Review Finding was resolved in the B3 (Not Met) In the 2010 Peer Review, F&O IFQU-B3-01 was PRA Model. See resolution below.

Finding IFQU-B3 written to identify that the Internal Flooding analysis IFQU-B3- (Not Met) did not identify some of the major conservatisms 2011 Focused Flooding Peer Review Plant Response:

0I IFSN-B3 and assumptions in the analysis. This appears to 1. Uncertainty has been added to all flooding initiating (Not Met) remain an open item for multiple reasons. Some events. The following text was added to Appendix 7.11, IFSO-B3 specific examples include: "Uncertainty Analysis", Section 2.3, "Flood-Induced (Not Met) lnitiating Events".

Although the methodology selected for estimating "lnitiating event frequencies are assumed to have a initiating event frequencies is valid, it does not lognormal distribution. The error factors associated appear that uncertainty bounds associated with with the initiating event frequencies are determined by the IE frequencies were determined or the order of magnitude associated with the initiating documented. event frequency. If the initiating event frequency is All flood related initiating events are currently E-3, an error factor of 10 is used. For an initiating mapped to the general transient initiating event event frequency of E-4, an error factor of 15 is (INIT-T3), but some of the floods, by definition, assumed. If the initiating event frequency is E-5 or impact entire systems that would result in another lower, an error factor of 20 is applied. The application type of initiating event - e.g. CCW pump room of the lognormal distributions for the data range is flood would really be a "loss of CCW" initiating consistent with how the other initiating events are event, but it is not mapped to INIT-TCC. treated in the PRA."

Mapping the flood-induced initiating events in this manner is considered an assumption and needs 2. The following text was added to Appendix 7.1 1, to be identified as such "Uncertainty Analysis", Section 2.3, "Flood-Induced The analysis specifically assumes the number of lnitiating Events".

pumps running and the flow rate at which they are operating. These types of assumptions can "It is assumed that all flood related initiating events can result in major impacts on the resulting analysis be mapped to the general transient initiating event, and need to be addressed in the Uncertainty INIT-T3. This assumption is valid even though some analysis. floods impact entire systems. This is because in those cases where the entire system is impacted, the entire svstem is failed bv the flaa file. For examole. if the Page 67 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs The number of pumps and therefore flow rates flooding in the PAB reaches the height of the CCW associated with various flood scenarios are pumps, the CCW system would be lost. The loss of assumed, critical heights are assumed, etc. the CCW system is accounted for by setting the flag Because these assumptions have a direct impact files associated with the scenario to fail the CCW on timing for HRA and on determining the pumps. The reactor will trip and the CCW pumps will potential consequences of a flood, they need to be lost."

be captured and sensitivities performed to determine their significance. 3. Section 3.6 was added to 7.11 which looks at the There is an inherent assumption that all flood number of pumps running and the impact on the events will result in a reactor trip with PCS analysis. The conclusion is that this assumption does available. In reality, this is not true since some not have a major impact on the resulting analysis.

floods would result in a loss of CCW, others 3.6 Number of Running Pumps would result in a loss of Instrument Air, etc.

These types of assumptions need to be There are three systems which are involved with identified, and their potential impact on submergence flooding, the only type of flooding quantification and results need to be evaluated, which would be impacted by the number of pumps especially for flood scenarios that have a very running. HELB, spray and jet impingement are large contribution to either CDF or LERF. independent of the number of pumps in service. The The qualitative and quantitative screening three systems are service water, circulating water processes involve several subjective criteria and and fire protection. Of the three systems, only the interpretations of the Standard that are by service water system has an operator action which definition, assumptions and sources of would be affected by the number of pumps going to a uncertainties. Since these subjective criteria runout condition. One fire protection pump at runout impact the entire analysis, they should be is larger than any of the fire protection scenario considered as significant sources of uncertainties flowrates. So, whether one pump is running or two and significant assumptions. the time to submergence is unchanged. The circulating water system floods do not credit operator actions and will not be considered further.

The time to reach critical flood height can be affected by the number of pumps running if the pipe break size is large enough to accommodate all running pumps in a runout condition. For example, the maximum flow out of a service water pipe break in the cable spreading room is about 7,000 gpm which Page 68 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs is less than the runout flow from one operating service water pump. This means the cable spreading room time to reach critical flood height is the same for one service water pump running or six. It does not create any new flooding hazards. So, submergence floods which Four of the submergence flooding areas credit operator action to stop the flood before the critical flood height is reached for service water flooding.

These are AFPN, U2F, DG2 and PAB. U2F does not have any service water piping large enough to cause pump runout flow and will not be considered further.

AFPN does not credit operator actions for floods which would cause runout of three service water pumps and will not be considered further.

The remaining two areas had the operator actions which prevent reaching critical flood height for major flooding. It was assumed that if 4, 5, or 6 pumps were running, the operator would not be able to respond before the critical flood height was reached.

The operator action failure rate was changed from the value with three service water pumps running to 1.O, always failed. The initiating event frequencies calculated from this were then substituted for the existing values in the internal flooding cutset. This changed the core damage frequency on Unit 1 from 1.98190E-6 to 1.98197E-6. The difference is 7E-11 which is not significant and the number of pumps running does not significantly affect the core damage frequency.

IFSO- Finding IFEV-A7 201 1 Focused Flooding Peer Review: No - The 2011 Peer Review Finding was resolved in the A4 IFSO-A4- (Met) F&O IFSO-A4-01 from the 2010 Peer review PRA Model. See resolution below.

01 IFSO-A6 identified that human induced flooding needed to Page 69 of 71

Attachment I: Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs (Met) be added to the Internal Flooding analysis. The IFSO-B2 current analysis has a very detailed evaluation of (Met) industry-related human induced flood events, and 2011 Focused Flooding Peer Review Plant Response:

the potential for Point Beach specific human Section 7.5.3 of PRA 7.1, Internal Flooding Notebook has induced flood events. In the detailed evaluation, it been revised to include human induced inadvertent fire was identified that over the last 8 years, protection system actuation and maintenance induced approximately 20% of the major flood events in flooding. The spreadsheet used to calculate submergence industry that were determined to be applicable to initiating event frequencies (WEFLOOD.xls) has been Point Beach were human-induced flood events. updated to include human induced inadvertent fire However, the conclusion was that the probability of protection system actuations and maintenance induced human-induced significant flooding in power modes flooding. The table was updated to show the results of the was judged to be insignificant. Since major flood events which were applicable to Point Beach.

human-induced significant floods had a 20% All of the major industry flooding events which were contribution to significant flood frequency, this human induced and applicable to Point Beach are in the conclusion appears to be unjustified. inadvertent fire protection actuation category.

Additionally, the IFSO-A4-01 F&O stated that the Section 7.5.4 was added to PRA 7.1 which discusses walkdown sheets should consider and document maintenance-inducedflooding at Point Beach. The the potential for human-induced flooding for each conclusion was that maintenance induced flooding will flood area. Note, there is some discussion in have a negligible impact on flooding because of the low Section 7.3.2 associated with the potential for probability of mechanical failure and the negligible human-inducedfloods in each flood area, but it is probability of human failure to incorrectly position not always easy to find or understand, and it does maintenance isolation boundary valves. However, not provide a systematic evaluation for maintenance induced flooding was included for human-induced flooding potential. 3 submergence flooding zones.

Section 7.5.6 (formerly 7.5.4) provides a detailed review of action requests at Point Beach over the last 10 years looking for cases of maintenance induced flooding. None were identified which confirms the conclusion of Section 7.5.4.

Regarding the second part of the finding, that walkdown sheets should consider and document the potential for human-induced flooding for each flood area, no Page 70 of 71

Attachment I:Point Beach PRA Peer Review Findings Category Other SR and Affected Issue and Proposed Resolution Impact to Applications and Peer Review Resolution Finding SRs requirement to that effect could be identified.

IFSO-A4 is related to identification of flooding mechanisms and does not discuss walkdowns.

IFEV-A7 says to include consideration of human-induced floods during maintenance through application of generic data. It does not discuss walkdowns.

IFSO-A6 says to conduct plant walkdowns to verify the accuracy of information obtained from plant information sources and determine or verify the location of flood sources and in-leakage pathways. This was performed as part of the flooding walkdowns. However, a separate walkdown was performed to confirm the maintenance induced flooding evaluation and is documented in added Section 7.5.5.

2 The gap analysis is conducted independently of RI-IS1 and is based on comparing the PRA model against the supporting requirements of ASME PRA standard at capability category 11. Many of the identified gaps are not applicable to RI-IS1 since in general capability category I is sufficient.

For completeness, all current gaps are identified in Attachment 1.

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