L-PI-04-133, Relief Request to Implement Risk-Informed Inservice Inspection (ISI) Scheduling for the Fourth 10-Year Inspection Interval

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Relief Request to Implement Risk-Informed Inservice Inspection (ISI) Scheduling for the Fourth 10-Year Inspection Interval
ML043650201
Person / Time
Site: Prairie Island  Xcel Energy icon.png
Issue date: 12/29/2004
From: Solymossy J
Nuclear Management Co
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
L-PI-04-133
Download: ML043650201 (41)
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Text

Prairie Island Nuclear Generating Plant Committed to Operated by Nuclear Management Company, LLC DEC t 9 2004 L-PI-04-133 10CFR50.55a(a)(3)(i)

U S Nuclear Regulatory Commission ATTN: Document Control Desk Washington, DC 20555-0001 Prairie Island Nuclear Generating Plant Units 1 and 2 Dockets 50-282 and 50-306 License Nos. DPR-42 and DPR-60 Relief Request to Implement Risk-Informed lnservice Inspection (1st) Scheduling for the Fourth 10-Year InsDection Interval for Prairie Island Units 1 and 2 Prairie Island submitted its lnservice Inspection Plan for the Fourth 10-Year Interval on June 21,2004. The interval runs from December 21,2004 through December 20,2014, for both Unit 1 and Unit 2.

Enclosed is a relief request to allow a risk-informed weld selection and examination volumes as an alternative to the requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code,Section XI. The alternative follows ASME Code Case N-578, Risk-Informed Requirements for Class 1, 2, and 3 Piping, Method B and Electric Power Research Institute Topical Report TR-112657 Rev. B-A, Revised Risk-Informed lnservice Inspection Evaluation Procedure.

We are requesting relief pursuant to 10 CFR Part 50, Section 50.55a(a)(3)(i) because the proposed alternative would provide an acceptable level of quality and safety.

Nuclear Management Company requests approval by December 31,2005. A similar alternative was approved for the Point Beach Nuclear Plant, Units 1 and 2, by NRC letter dated July 2, 2003.

1717 Wakonade Drive East Welch, Minnesota 55089-9642 Telephone: 651.388.1121

Document Control Desk Page 2 Summary of Commitments This letter contains no new commitments and no revisions to existing commitments.

Generating Plant Enclosures(2) cc: Administrator, Region Ill, USNRC Project Manager, Prairie Island, USNRC Resident Inspector, Prairie Island, USNRC

ENCLOSURE 1 Prairie Island Unit 1 - RELIEF REQUEST NUMBER 1-RR-4-5: (Rev. 0)

Prairie Island Unit 2 - RELIEF REQUEST NUMBER 2-RR-4-5: (Rev. 0) 2 pages follow

Nuclear Management Company Inservice Inspection Prairie Island Unit 1 and Unit 2 4h Interval Examination Plan Prairie Island Unit 1 - RELIEF REQUEST NUMBER 1-RR-4-5: (Rev. 0)

Prairie Island Unit 2 - RELIEF REQUEST NUMBER 2-RR-4-5: (Rev. 0)

Risk Informed Examination of Class 1 and 2 Piping Welds (Code Case N-578 and EPRI TR-112657)

SYSTEM/COMPONENT (S) FOR WHICH RELIEF REQUEST WILL BE USED Code Class: Class 1 and 2

Reference:

ASME,Section XI, 1998 Edition with Addenda through 2000, Tables IWB-2500-1 and IWC-2500-1 ASME Section XI Code Case N-578 Examination Categories: B-F, B-J, C-F-1, C-F-2 Item Number: B5.10, B5.20, B5.40, B5.50, B5.70, B9.11, B9.21, B9.31, B9.32, B9.40, C5.11, C5.21, C5.30, C5.41, C5.51, C5.61, C5.70, C5.81

==

Description:==

All pressure retaining piping welds Component Numbers: See attached Risk-Informed Inservice Inspection Plan, Prairie Island Nuclear Generating Plant, Units 1 and 2, Revision 0 CODE REQUIREMENTS:

The 1998 Edition of Section XI with Addenda through 2000, IWB-2500(a) states, components shall be examined and tested as specified in Table IWB-2500-1. The method of examination for the components and parts of the pressure retaining boundaries shall comply with those tabulated in Table IWB-2500-1 except where alternate examination methods are used that meet the requirements of IWA-2240.

Table IWB-2500-1, Categories B-F and B-J requires 100% and 25% respectively of the total number of non-exempt welds.

The 1998 Edition of Section XI with Addenda through 2000, IWC-2500(a) states, components shall be examined and pressure tested as specified in Table IWC-2500-1.

The method of examination for the components and parts of the pressure retaining boundaries shall comply with those tabulated in Table IWC-2500-1 except where alternate examination methods are used that meet the requirements of IWA-2240.

Table IWC-2500-1, Categories C-F-1 and C-F-2 requires 7.5% of the total number of-non-exempt and exempt welds, but not less than 28 welds.

In addition, Tables IWB-2500-1 and IWC-2500-1 reference figures that convey the examination volume for each configuration that could be encountered.

Nuclear Management Company Inservice Inspection Prairie Island Unit 1 and Unit 2 4th,Interval Examination Plan PROPOSED ALTERNATIVE:

As an alternative to existing ASME Section XI requirements for piping weld selection and examination volumes, Prairie Island Nuclear Generating Plant (PINGP) will implement the alternative methods as specified in Code Case N-578 and EPRI TR-112657B-A. Risk-Informed Inservice Inspection Program Plan, Prairie Island Nuclear Generating Plant, Units 1 and 2, Revision 0 details the methodology for application of this alternative.

BASIS FOR RELIEF:

The scope for the ASME Section XI IS1 Programs is largely based on deterministic results contained in design stress reports. These reports are normally very conservative and may not be an accurate representation of failure potential. Since the stress reports for PINGP do not contain all the information required to select welds in accordance with the later editions of ASME Section XI, PINGP has been utilizing the alternative selection methodology of the 1974 Edition of Section XI with addenda through summer 1975 for Category B-J welds as allowed by 10CFR50.55a(b>(2)(ii). Industry service experience has shown that piping weld failures are due to either corrosion or fatigue and typically occur in areas not included in the plants IS1 program. Consequently, nuclear plants are devoting significant resources to inspection programs that provide minimum benefit.

As an alternative, significant industry attention has been devoted to the risk-informed selection criteria in order to determine a more appropriate scope for IS1 Programs at nuclear power plants. EPRI studies indicate that the application of Risk Informed techniques will allow operating plants to reduce the examination scope of current IS1 Programs by as much as 60% to 80%, significantly reduce costs and radiation exposure, and continue to maintain an equivalent or better safety level as current ASME Section XI selection criteria.

PINGP has reviewed the EPRI Methodology as documented in the NRC approved Topical Report TR-112657B-A and referenced in Code Case N-578. Utilizing this methodology for the selection and subsequent examination of PINGP Class 1 and 2 piping welds will provide an acceptable level of quality and safety.

IMPLEMENTATION SCHEDULE:

Relief is requested for the 4h 10 year interval of the Inservice Inspection Program for Prairie Island Units 1 and 2.

REFERENCE:

By letter dated July 2,2003, the NRC Staff authorized similar relief to Point Beach Nuclear Plant Units 1 and 2 (TAC Nos. MB5553 and MB5554).

ENCLOSURE 2 Risk-Informed lnservice Inspection Program Plan Prairie Island Nuclear Generating Plant Units 1 and 2 - Revision 0 35 pages follow

RISK-INFORMED INSERVICE INSPECTION PROGRAM PLAN PRAIRIE ISLAND NUCLEAR GENERATING PLANT UNITS IAND 2 REVISION 0 Table of Contents

1. Introduction 1.I Relation to NRC Regulatory Guides 1.I74 and 1.I78 1.2 PSA Quality
2. Proposed Alternative to Current Inservice Inspection Programs 2.1 ASME Section XI 2.2 Augmented Programs
3. Risk-Informed IS1 Process 3.1 Scope of Program 3.2 Consequence Evaluation 3.3 Failure Potential Assessment 3.4 Risk Characterization 3.5 Element and NDE Selection 3.5.1 Additional Examinations 3.5.2 Program Relief Requests 3.6 Risk Impact Assessment 3.6.1 Quantitative Analysis 3.6.2 Defense-in-Depth
4. Implementation and Monitoring Program
5. Proposed IS1 Program Plan Change
6. References/Documentation
1. INTRODUCTlON The Prairie Island Nuclear Generating Plant (PINGP) is currently nearing the end of its third inservice inspection (ISI) interval as defined by the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Section XI Code for Inspection Program B. PINGP plans to implement a risk-informed inservice inspection (RI-ISI) program during the fourth inservice inspection interval, which begins December 21, 2004 for both units. The ASME Section XI Code used during the third interval was the 1989 Edition. PINGP is using the 1998 Edition of Section XI with addenda through 2000 for the fourth inservice inspection interval.

The objective of this submittal is to request the use of a risk-informed process for the inservice inspection of Class 1 and 2 piping. The RI-IS1 process used in this submittal is described in Electric Power Research Institute (EPRI) Topical Report (TR) 112657 Rev. B-A Revised Risk-Informed lnservice Inspection Evaluation Procedure. The RI-IS1 application was also conducted in a manner consistent with ASME Code Case N-578Risk-Informed Requirements for Class 1, 2, and 3 Piping, Method B.

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 .I 74,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 lnservice Inspection of Piping. Further information is provided in Section 3.6.2 relative to defense-in-depth.

1.2 PSA Quality The Prairie Island Level 1 and Level 2 Probabilistic Risk Assessment (PRA) results based on the Revision 1.2 update were used to evaluate the consequences of pipe ruptures for the RI-IS1 assessment during power operation. A summary of the Level 1 and Level 2 results (in terms of dominant contributors to Core Damage Frequency and Large Early Release Frequency) are discussed below.

Summary of the PRA Level 1 Results: The Prairie Island Level 1 PRA model calculated a Core Damage Frequency (CDF) for internal events of 2.20E-5/year for each PINGP unit. The dominant accident sequences by initiating events are:

0 Loss of Offsite Power (LOOP) including station blackout (SBO) (23.9%)

0 Loss of Coolant Accidents (LOCA) (23.8%)

Internal Flooding (22.5%)

0 Steam Generator Tube Rupture (SGTR) (14.8%)

0 Transients excluding LOOP (15.0%)

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Summary of the PRA Level 2 Results: The Prairie Island Level 2 calculated a Large Early Release Frequency (LERF) of 6.9E-7/year for each PINGP unit, resulting in a LERF/CDF ratio of 0.031. The dominant contributors to LERF are:

SGTR(87%)

Intersystem LOCA (13%)

0 Core damage sequence followed by failure of containment isolation (0.2%)

PRA MODEL HISTORY:

IPE Results (Level Iand Level 2, Revision 0)

The first full-scope PRA analysis done for the Prairie Island Nuclear Generating Plant was performed to satisfy the Individual Plant Examination (IPE) requirements, and was completed in February 1994. This was a study to determine vulnerabilities to severe accidents from at-power operation. It was based on a Level 1 and Level 2 PRA model performed for Unit 1. Unit 2 vulnerabilities were qualitatively evaluated based on the Unit 1 results and consideration of asymmetries in plant design and operation that exist between the units. The study found no vulnerabilities to severe accidents at the PINGP.

This PRA study is now considered to be Revision 0 of the Level 1 and 2 PRA models.

Level 1 and Level 2, Revision 1.0 Revision 1.O of the Unit 1, Level 1 PRA model was completed in 1996. In addition to incorporating fault tree models for a few more balance-of-plant systems (for example, the non-safeguards station air system and the steam dump and circulating water systems), this update included modeling for a number of significant changes to the plant safeguards electrical systems that were not yet installed at the time of the IPE submittal.

Examples include elimination of sub-fed 480V MCCs, division of the two Unit 1 safeguards 480 V AC buses into four buses and relocation of those buses within the plant, and significant reliability upgrades for the DC power system. Component failure and unavailability data for six key systems were updated for the period 1986 through 1995, as were the initiating event frequencies. LOCA frequencies were reanalyzed to make them more plant-specific, using a pipe failure study technique developed by EPRI.

Revision 1.O of the Unit 1, Level 2 PRA model was completed in 1999, and was built upon the Level 1 Revision 1.0 model. In addition to the changes incorporated in the revision to the Level 1 model, this update reflected credit for the potential for hot leg creep rupture phenomenon to facilitate vessel failure at low pressure for early core damage sequences, and credit for a change to the emergency procedures that greatly reduced the risk from induced steam generator tube creep rupture events (these events were not modeled in the 1.0 analysis). Also, credit for containment spray recirculation was removed from the model, because of a change in emergency operating procedures.

Level 1 and Level 2, Revision 1.1 Revision 1. I of the Unit 1, Level 1 model was completed in 1999. This was essentially the same model as Rev. 1.0; however, a single top fault tree approach to the quantification of overall CDF was used, as was a standard truncation level of 1E-10.

Previously, the PRA models were quantified using SETS, which allowed different truncation levels for each individual core damage sequence.

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No Level 2 or LERF model was updated with this designation (no revision to the Level 2 models or to LERF was performed which used the Level 1, Revision 1.Imodel as input).

The basis for this was the nearly identical nature of the Revision 1.O and Revision 1. I Level 1 models - no significant difference in the Level 2 results could exist based solely on the move to the Revision 1. I model.

Level 1 and Level 2, Revision 1.2 Revision 1.2 of the Unit 1, Level 1 model was completed in 2001. Significant changes were incorporated during this revision. Many of these changes were based on comments received by the Westinghouse Owners Group (WOG) PRA Certification Team Review that took place in September 2000. Changes include:

New LOCA break size groupings for small, medium and large LOCAs (SLOCA, MLOCA, LLOCA)

New LOCA break size frequencies based on generic data from NUREG/CR-5750 Update to several initiating event frequencies (LOOP, LODC)

Inclusion of Offsite Power recovery actions for non-SBO events Creation of initiating event trees for the cooling water, component cooling, and instrument air systems PORV LOCA events have been added Changes to SBO success criteria (removal of diesel generator recovery)

Random reactor coolant pump Seal Failure initiating event was added Updates to several system fault trees Credit for the Pressurizer PORV accumulator Upgrade to the Human Reliability Analysis (key operator actions)

The mission time for the emergency diesel generators and cooling water pumps were changed from 6 hours6.944444e-5 days <br />0.00167 hours <br />9.920635e-6 weeks <br />2.283e-6 months <br /> to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> since offsite power recovery is credited.

A full Level 2 revision to correspond with the Level 1, Revision 1.2 model has not been completed at this time. However, an update to the LERF results based on the Level 1, Revision 1.2 model has been performed.

Other than the changes to the underlying Level 1 model, the following changes were made to the LERF calculation itself:

Failure of containment isolation was modeled using a fault tree model for each unscreened containment penetration from the previous analysis. The previous LERF analysis used a point value estimate for the failure of containment isolation.

Core damage sequences involving early containment failure but without containment bypass (from the full Level 2 analysis) were excluded from the LERF result. These sequences had been conservatively added to the LERF calculation in the absence of certainty about whether they met an industry standard definition of large, early release that was still in development. The IPE source term analysis showed only the containment bypass events (induced-SGTR, ISLOCA) to result in the highest releases of volatile (non-Page 4 of 35

noble gas) radionuclides. SGTR events also involved large releases of volatiles, but were considered to be a late release. Containment isolation failure sequences involved early releases but the magnitude of the volatiles was categorized as medium. Also, the majority of these sequences were assumed to lead to early containment failure due to very conservative treatment of the hydrogen combustion phenomenon. In this revision only SGTR and containment isolation failures (including intersystem LOCAs), are considered in the evaluation of the LERF results.

Level 1, Revision 2.0 Subsequent to the RI-IS1 assessment being performed, a Level 1, Revision 2.0 PRA model update was performed in order to obtain a working PRA model for Unit 2.

Previously, all probabilistic risk analysis for Unit 2 involved application of the Unit 1 model results, with modifications that attempted to consider the impact of asymmetries between the units. The update was also performed to correct some errors and make some enhancements to the existing Revision 1.2 PRA model. The model update was completed in 2002 and was built upon the Level 1 Revision 1.2 model.

An evaluation was performed to determine the impact of the updated PRA model on the RI-IS1 application, which was performed using Revision 1.2 of the PRA model. Based upon a review of the PRA model update, it was determined that there were no resulting changes to the RI-IS1 consequence evaluation, and therefore no impact on the RI-IS1 risk ranking and element selection activities. Additionally, the highest CCDP and CLERP used in the risk impact analysis did not change. This review is documented in Engineering Information Record No. 51-5053193-00.

MODEL REVIEWS:

NRC Review of IPE: The IPE was submitted to the NRC on March 1, 1994. The NRC review of the Prairie Island IPE was issued in May 1997. The Staff Evaluation Report (SER) concluded the following regarding the Prairie Island IPE:

1) The IPE is complete with regards to the information requested in Generic Letter 88-20 and associated guidance in NUREG-1335;
2) The IPE results are reasonable given the Prairie Island design, operation, and history; and
3) The IPE process is capable of identifying most likely severe accidents and severe accident vulnerabiIit ies.

WOG Peer Review: In September 2000, the Westinghouse Owners Group PRA Peer Certification Review was performed on the 1999 update PRA model (Revision 1.1). In general, the review team concluded that the PINGP PRA could effectively be used to support applications involving risk significance determinations supported by deterministic analysis once the items noted in the report are addressed. A majority of the Facts and Observation (including all of the Level A findings) have been addressed in the Revision 1.2 model. While addressing the remaining Facts and Observations would take time to resolve completely, they are not expected to result in model changes that could significantly affect the overall results or conclusions of the Risk-Informed IS1 consequence evaluation.

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2. PROPOSED ALTERNATIVE TO CURRENT IS1 PROGRAM REQUIREMENTS 2.1 ASME Section XI ASME Section XI Examination Categories B-F, B-J, C-F-1 and C-F-2 currently contain the requirements for the nondestructive examination (NDE) of Class 1 and 2 piping components. The alternative RI-IS1 program for piping is described in EPRl TR-112657.

The RI-IS1 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. EPRl TR-112657 provides the requirements for defining the relationship between the RI-IS1 program and the remaining unaffected portions of ASME Section XI.

2.2 Augmented Programs The following augmented inspection program was considered during the RI-IS1 application:

The augmented inspection program for flow accelerated corrosion (FAC) per Generic Letter 89-08 is relied upon to manage this damage mechanism but is not otherwise affected or changed by the RI-IS1 program.

3. RISK-INFORMED IS1 PROCESS The process used to develop the RI-IS1 program conformed to the methodology described in EPRl TR-112657 and consisted of the following steps:

0 Scope Definition 0 Consequence Evaluation 0 Failure Potential Assessment 0 Risk Characterization 0 Element and NDE Selection 0 Risk Impact Assessment 0 Implementation Program 0 Feedback Loop A deviation to the EPRl RI-IS1 methodology has been implemented in the failure potential assessment for PINGP. Table 3-16 of EPRl TR-112657 contains criteria for assessing the potential for thermal stratification, cycling and striping (TASCS). Key attributes for horizontal or slightly sloped piping greater than 1 nominal pipe size (NPS) include:

1. Potential exists for low flow in a pipe section connected to a component allowing mixing of hot and cold fluids, or
2. Potential exists for leakage flow past a valve, including in-leakage, out-leakage and cross-leakage allowing mixing of hot and cold fluids, or Page 6 of 35
3. Potential exists for convective heating in dead-ended pipe sections connected to a source of hot fluid, or
4. Potential exists for two phase (steam/water) flow, or
5. Potential exists for turbulent penetration into a relatively colder branch pipe connected to header piping containing hot fluid with turbulent flow, AND AND 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 all 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 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 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 keep the line filled with hot water. If there is no potential for in-leakage towards the hot fluid source from the outboard end of the line, 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 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.

9 Low flow TASCS In some situations, the transient startup of a system 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.

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> 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.

> 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.

In summary, these additional considerations for determining the potential for thermal fatigue as a result of the effects of TASCS provide an allowance for the consideration of cycle severity in assessing the potential for TASCS effects. The above criteria have previously been submitted by EPRl for generic approval (Letters dated February 28, 2001 and March 28, 2001, P.J.

ORegan (EPRI) to Dr. B. Sheron (USNRC), Extension of Risk-Informed lnservice Inspection Methodology).

3.1 Scope of Program The scope of this RI-IS1 program includes all nonexempt Class 1 and 2 piping welds (IWB-1220 and IWC-1220). The systems included in the RI-IS1 program are provided in Tables 3.1-1 and 3.1-2 for Units 1 and 2, respectively.

3.2 Consequence Evaluation The consequence(s) of pressure boundary failures were evaluated and ranked based on their impact on core damage and containment performance (i.e., isolation, bypass and large early release). The consequence evaluation included an assessment of shutdown and external events. The impact on these measures due to both direct and indirect effects was considered using the guidance provided in EPRl TR-112657.

3.3 Failure Potential Assessment Failure potential estimates were generated utilizing industry failure history, plant specific failure history, and other relevant information. These failure estimates were determined using the guidance provided in EPRl TR-112657, with the exception of the previously stated deviation.

Tables 3.3-1 and 3.3-2 summarize the failure potential assessment by system for each degradation mechanism that was identified as potentially operative in Units 1 and 2, respectively.

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3.4 Risk Characterization In the preceding steps, each run of piping within the scope of the program was evaluated to determine its impact on core damage and containment performance (i.e., isolation, bypass and large, early release) as well as its potential for failure. Given the results of these steps, piping segments are then defined as continuous runs of piping potentially susceptible to the same type(s) of degradation and whose failure will result in similar consequence(s). Segments are then ranked based upon their risk significance as defined in EPRl TR-112657.

The results of these calculations are presented in Tables 3.4-1 and 3.4-2 for Units 1 and 2, respectively.

3.5 Element and NDE Selection In general, EPRl TR-112657 requires that 25% of the locations in the high risk region and 10% of the locations in the medium risk region be selected for inspection using appropriate NDE methods tailored to the applicable degradation mechanism. In addition, per Section 3.6.4.2 of EPRl TR-112657, if the percentage of Class 1 piping locations selected for examination falls substantially below 1O%, then the basis for selection needs to be investigated.

For PINGP Unit 1, the percentage of Class 1 welds selected for examination per the RI-IS1 process was 10.0% (69 of 690 welds).

For PINGP Unit 2, the percentage of Class 1 welds selected for examination per the RI-IS1 process was 10.4% (73 of 705 welds).

As stated in TR-112657, the existing FAC augmented inspection program provides the means to effectively manage this mechanism. No additional credit was taken for any FAC augmented inspection program locations beyond those selected by the RI-IS1 process to meet the sampling percentage requirements.

Class 1 Piping Welds Class 2 Piping Welds* All Piping Welds3 Unit Total Selected Total Selected Total Selected 1 690 69 933 41 1623 110 1 I 2 I 705 I 73 I 951 1 40 I 1656 1 113 I Notes

1. Includes all Category B-F and B-J locations.
2. Includes all Category C-F-1 and C-F-2 locations.
3. All in-scope piping components, regardless of risk classification, will continue to receive Code required pressure testing, as part of the current ASME Section XI program. VT-2 visual examinations are scheduled in accordance with the stations pressure test program that remains unaffected by the RI-IS1 program.

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3.5.1 Additional Examinations The RI-IS1 program in all cases will determine through an engineering evaluation the root cause of any unacceptable flaw or relevant condition found during examination. The evaluation will include the applicable service conditions and degradation mechanisms to establish that the element(s) will still perform their intended safety function during subsequent operation. Elements not meeting this requirement will be repaired or replaced.

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 mechanisms. The additional examinations will include high risk significant elements and medium risk significant elements, if needed, up to a number equivalent to the number of elements required to be inspected on the segment or segments 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. No additional examinations will be performed if there are no additional elements identified as being susceptible to the same root cause conditions.

3.5.2 Program Relief Requests An attempt has been made to select RI-IS1 locations for examination such that a minimum of >90% coverage (i.e., Code Case N-460 criteria) is attainable.

However, some limitations will not be known until the examination is performed, since some locations may be examined for the first time by the specified techniques.

In instances where locations are found at the time of the examination that do not meet the >90% coverage requirement, the process outlined in EPRl TR-112657 will be followed.

None of the existing PINGP relief requests are being withdrawn due to the RI-IS1 application.

3.6 Risk Impact Assessment The RI-IS1 Program has been conducted in accordance with Regulatory Guide 1.174 and the requirements of EPRl TR-112657, 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 identified the allocation of segments into High, Medium, and Low risk regions of the EPRl TR-112657 and ASME Code Case N-578 risk ranking matrix, and then determined for each of these risk classes what inspection changes are proposed for each of the locations in each segment. The changes include changing the number and location of inspections within the segment and in many cases improving the effectiveness of the inspection to account for the findings of the RI-IS1 degradation mechanism assessment. For example, for locations subject to thermal fatigue, examinations will be conducted on an expanded volume and will be focused to enhance the probability of detection (POD) during the inspection process.

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3.6.1 Quantitative Analysis Limits are imposed by the EPRl methodology to ensure that the change in risk of implementing the RI-IS1 Program meets the requirements of Regulatory Guides 1.174 and 1.178. The EPRl criterion requires that the cumulative change in core damage frequency (CDF) and large early release frequency (LERF) be less than 1E-07 and 1E-08 per year per system, respectively.

Prairie Island conducted a risk impact analysis per the requirements of Section 3.7 of EPRl TR-112657. The analysis estimates the net change in risk due to the positive and negative influence of adding and removing locations from the inspection program. A risk quantification was performed using the Simplified Risk Quantification Method described in Section 3.7 of EPRl TR-112657. The conditional core damage probability (CCDP) and conditional large early release probability (CLERP) used for high consequence category segments was based on the highest evaluated CCDP (6.8E-02) and CLERP (6.8E-03), whereas, for medium consequence category segments, bounding estimates of CCDP (1E-04) and CLERP (IE-05) were used. 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 xo and is expected to have a value less than 1E-08. Piping locations identified as medium failure potential have a likelihood of 20x0. 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 RI-IS1 approach.

Tables 3.6-1 and 3.6-2 present summaries of the RI-IS1 Program versus the applicable ASME Section XI Code Edition program requirements and identify on a per system basis each applicable risk category for Units 1 and 2, respectively.

The presence of FAC was adjusted for in the performance of the quantitative analysis by excluding its impact on the risk ranking. The exclusion of the impact of FAC on the risk ranking and therefore in the determination of the change in risk is performed, because FAC is a damage mechanism managed by a separate, independent plant augmented inspection program. The RI-IS1 Program credits and relies upon this augmented plant 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 remains the same before and after and no delta exists, there is no need to include the impact of FAC in the performance of the risk impact analysis. However, in an effort to be as informative as possible, for those systems where FAC is present, Tables 3.6-1 and 3.6-2 present the information in such a manner as to depict what the resultant risk categorization is both with and without consideration of FAC. This is accomplished by enclosing the FAC damage mechanism, as well as all other resultant corresponding changes (failure potential rank, risk category and risk rank), in parenthesis. Again, this has only been done for information purposes, and has no impact on the assessment itself.

The use of this approach to depict the impact of degradation mechanisms managed by augmented inspection programs on the risk categorization is consistent with that used in the delta risk assessment for the Arkansas Nuclear One, Unit 2 (ANO-2) pilot application. An example is provided below.

Page 11 of 35

Risk Consequence Failure Potential System Category Rank( Rank DMs Rank In this example if FAC is not considered, the failure potential r

rank is medium instead of high based on the TASCS and TT damage mechanisms. When a medium failure potential rank is combined with a medium consequence rank, it results in risk category 5 (medium risk) being assigned instead of risk category 3 (high risk).

FW 5 (3) t

Medium (High) : Medium L In this example if FAC were considered, the failure potential rank would be high instead of medium. If a high failure potential rank were combined with a medium consequence rank, it would result in risk category 3 (high risk) being assigned instead of risk category 5 (medium risk).

Note

1. The risk rank is not included in Tables 3.6-1 or 3.6-2 but it is included in Tables 5-2-1 and 5-2-2.

As indicated in the tables below, this evaluation has demonstrated that unacceptable risk impacts will not occur from implementation of the RI-IS1 Program, and satisfies the acceptance criteria of Regulatory Guide 1.174 and EPRl TR-112657.

ARiSkcoF ARiSkLERF System) .

wl POD wlo POD wl POD wlo POD RC -2.00E-07 -6.16E-08 -2.00E-08 -6.16E-09 I RHR I -1.60E-08 I -1.06E-08 I -1.60E-09 I -1.06E-09 I I SI I -1.37E-09 I -1.37E-09 I -1.37E-10 I -1.37E-10 I cvc -1.41E-09 -1.39E-09 -1.41E-10 -1.39E-10 MS negligible negligible negligible negligible FW -2.40E-11 negligible -2.40E-12 negligible I cs I -3.40E-10 I -3.40E-10 I -3.40E-11 I -3.40E-11 I AFW -6.00E-12 1.00E-11 -6.00E-13 1.00E-12 Total -2.19E-07 -7.52E-08 -2.19E-08 -7.52E-09 Page 12 of 35

Unit 2 Risk Impact Results

~~~~~

wl POD wlo POD wl POD wloPOD I RC -1.91 E-07 -4.69E-08 -1.91 E-08 -4.69E-09 RHR -1.60E-08 -1.06E-08 -1.60E-09 -1.06E-09 I SI I -7.1 5E-09 I -1.71 E-09 I -7.15E-10 I -1.71 E-10 I cvc -1.07E-09 -1.05E-09 -1.07E-10 -1.05E-10 MS negligible negligible negligible negligible FW -6.00E-12 3.00E-11 -6.00E-13 3.00E-12 I cs I -3.40E-10 I -3.40E-10 I -3.40E-11 I -3.40E-11 I I AFW I -6.00E-12 I 1.00E-11 I -6.00E-13 I 1.00E-12 I Total -2.16E-07 -6.05E-08 -2.1 6E-08 -6.05E-09 Note

1. Systems are described in Table 3.1-2.

3.6.2 Defense-in-Depth The intent of the inspections mandated by ASME Section XI for piping welds is to identify conditions such as flaws or indications that may be precursors to leaks or ruptures in a systems pressure boundary. Currently, the process for picking inspection locations is based upon structural discontinuity and stress analysis results. As depicted in ASME White Paper 92-01-01 Rev. 1, Evaluation of lnservice Inspection Requirements for Class 1, Category B-J Pressure Retaining Welds, this method has been ineffective in identifying leaks or failures. EPRl TR-112657 and Code Case N-578 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 locations 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 locations susceptibility to degradation, the likelihood of finding flaws or indications that may be precursors to leak or ruptures is increased. Secondly, the consequence assessment effort has a single failure criterion. As such, no matter how unlikely a failure scenario is, it is ranked High in the consequence assessment, and at worst Medium in the risk assessment (i.e., Risk Category 4), if as a result of the failure there is no mitigative equipment available to respond to the event. In addition, the consequence assessment takes into account equipment reliability, and less credit is given to less reliable equipment.

All locations within the Class 1 and 2 pressure boundaries will continue to receive a system pressure test and visual VT-2 examination as currently required by the Code regardless of its risk classification.

Page 13 of 35

4. IMPLEMENTATION AND MONITORING PROGRAM Upon approval of the RI-IS1 program, procedures that comply with the guidelines described in EPRl TR-112657 will be prepared to implement and monitor the program. The new program will be integrated into the fourth inservice inspection interval. No changes to the Technical Specifications or Updated 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 RI-IS1 process, as appropriate.

The monitoring and corrective action program will contain the following elements:

A. Identify

6. Characterize C. (1) Evaluate, determine the cause and extent of the condition identified (2) Evaluate, develop a corrective action plan or plans D. Decide E. Implement F. Monitor G. Trend The RI-IS1 program is a living program requiring feedback of new relevant information to ensure the appropriate identification of high safety significant piping locations. As a minimum, risk ranking of piping segments will be reviewed and adjusted on an ASME period basis. In addition, significant changes may require more frequent adjustment as directed by NRC Bulletin or Generic Letter requirements, or by industry and plant specific feedback.
5. PROPOSED IS1 PROGRAM PLAN CHANGE A comparison between the RI-IS1 program and ASME Section XI Code 1989 Edition program requirements for in-scope piping is provided in Tables 5-1-1 and 5-2-1 for Unit 1 and Tables 5 2 and 5-2-2 for Unit 2. Tables 5-1-1 and 5-1-2 provide summary comparisons by risk region.

Tables 5-2-1 and 5-2-2 provide the same comparison information, but in a more detailed manner by risk category, similar to the format used in Table 3.6-1 and 3.6-2.

PINGP is implementing the RI-IS1 program during the first period of its fourth inspection interval.

As such, 100% of the required RI-IS1 program inspections will be completed in the fourth interval. Examinations shall be performed during the interval such that the period examination percentage requirements of ASME Section XI, paragraphs IWB-2412 and IWC-2412 are met.

Page 14 of 35

6. REFERENCEWDOCUMENTATION EPRl TR-112657, "Revised Risk-Informed lnservice Inspection Evaluation Procedure", Rev. B-A ASME Code Case N-578, "Risk-Informed Requirements for Class 1, 2, and 3 Piping, Method 6,Section XI, Division 1" Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions On Plant-Specific Changes to the Licensing Basis" Regulatory Guide 1.178, "An Approach for Plant-Specific Risk-Informed Decisionmaking lnservice Inspection of Piping" Supporting Onsite Documentation Structural Integrity Calculation/File No. NMC-01-320, "Degradation Mechanism Evaluation for the Prairie Island Nuclear Generating Plant (PINGP) - Units 1/2", Revision 5 (NMC Document NO. ENG-ME-594)

Structural Integrity Calculation/File No. NMC-01-321, "Risk-Informed Inservice Inspection Consequence Evaluation of Class 1 & 2 Piping - Prairie Island Nuclear Generating Plant Units 1

& 2 (Sept 04 Addendum)", Revision 0 (NMC Document No. ENG-ME-595)

NMC Document No. ENG-ME-583, "Service History Review for the Prairies Island Nuclear Generating Station" , Revision 0 Structural Integrity CalculationlFile No. NMC-01-324, "Risk Ranking Summary, Matrix and Report for the Prairie Island Nuclear Generating Plant", Revision 2 (NMC Document No. ENG-ME-596)

Structural Integrity Calculation/File No. NMC-01-325, "Risk Impact Analysis for the Prairie Island Nuclear Generating Plant", Revision 2 (NMC Document No. ENG-ME-596)

Structural Integrity File No. NMC-01-103-3, Record of Conversation No. ROC-005, "Minutes of the Element Selection Meeting for the Risk-Informed IS1 Project at the Prairie Island Nuclear Generating Plant", Revision 2, dated April 25-26, 2002, as updated October 22, 2004 and December 5,2004 (NMC Document No. ENG-ME-597)

Areva Engineering Information Record No. 51-505193-00, "Prairie Island PRA Revision 2.0 Impact Review", dated November 1, 2004 Page 15 of 35

Table 3.1-1 Unit 1 System Selection and Segment / Element Definition System Description Number of Segments Number of Elements RC - Reactor Coolant 58 427 RHR - Residual Heat Removal I 37 I 297 SI - Safety Injection I 74 I 510 I CVC - Chemical and Volume Control I 13 I 161 MS - Main Steam 15 78 FW - Feedwater 15 52 CS - Containment Spray 8 55

~ ~

AFW - Auxiliary Feedwater 6 43 Totals 226 1623 Page 16 of 35

Table 3.1-2 System Description Number of Segments Number of Elements RC - Reactor Coolant 60 418 RHR - Residual Heat Removal I 38 I 302 SI - Safety Injection I 73 I 536 CVC - Chemical and Volume Control 13 168 MS - Main Steam 20 92 FW - Feedwater 12 48 CS - Containment Spray 8 49 AFW -Auxiliary Feedwater 6 43 Totals 230 1656 Page 17 of 35

Table 3.3-1 Unit 1 Failure Potential Assessment Summary Note

1. Systems are described in Table 3.1-1, Page 18 of 35

Thermal Fatigue Stress Corrosion Cracking Localized Corrosion Flow Sensitive System"'

I TASCS TT IGSCC I TGSCC I ECSCC I PWSCC MIC PIT cc E-C FAC RC X X X X RHR X X SI X X X cvc X MS FW X X cs AFW X X Note

1. Systems are described in Table 3.1-2.

Page 19 of 35

Table 3.4-1 Unit 1 Number of Segments by Risk Category With and Without Impact of FAC I High Risk Region I Medium Risk Region I Low Risk Region System"' Category 2 Category 3 Category 4 Category 5 Category 6 Category 7 1 With Without With Without With Without With Without With Without pq-iizz RC 12 12 39 39 2 2 5 5 I RHR I I 1 1 1 1 1 1 7 1 1 7 1 1 1 1 1 1 8 1 1 8 1 1 24 24 2 2 43 43 4 4 3 3 6 6

+

15 15 FW -1 cs AFW 1 2 1 2 1 4 1 4 Total I I 14 I 14 I 7 I 0 I 86 I 86 I 13 I 17 I 102 I 105 4 1 4 Notes

1. Systems are described in Table 3.1-1.
2. Of these seven segments, four segments become Category 5 after FAC is removed from consideration due to the presence of another "medium" failure potential damage mechanism, and three segments become Category 6 after FAC is removed from consideration due to no other damage mechanism being present.

Page 20 of 35

Table 3.4-2 Unit 2 Number of Segments by Risk Category With and Without Impact of FAC I High Risk Region I Medium Risk Region 1 Low Risk Region System"' Category 1 Category 2 Category 3 Category 4 Category 5 Category 6 Category 7 With Without With Without With Without With Without With Without With Without With Without I 3 9 I 3 9 I 2 I 2 I 5 I 5 I 1 2 1 2 1 I SI I I 1 3 1 3 1 I cvc 4 4 3 3 6 6 MS 20 20 FW 0 5 6 5 6 I AFW I 1 2 1 2 1 4 1 4 1 I Total I Notes

1. Systems are described in Table 3.1-2.
2. Of these two segments, one segment becomes Category 5 after FAC is removed from consideration due to the presence of another "medium" failure potential damage mechanism, and one segment becomes Category 6 after FAC is removed from consideration due to no other damage mechanism being present.

Page 21 of 35

Table 3.5-1 Unit 1 Number of Elements Selected for Inspection by Risk Category Excluding Impact of FAC 1 High Risk Region I Medium Risk Region I Low Risk Region System) I Category I Category2 1 Category3 Category 4 Category 5 Category 6 Category 7 Total Selected Total Selected Total Selected Total Selected Total Selected Total Selected Total Selected RC 79 20 RHR I I 4 1 1 1 1 7 4 1 18 1 4 1 1 1 1 1 5 1 0 1 0 1 0 SI I I 2 3 0 1 23 1 2 1 1 1 2 4 8 1 0 I 2 8 1 0 I

40 4 24 3 97 0 0 0 0 0 0 0 78 0 0 0 0 0 14 2(2) 38 0 0 0 0 I 0-- I AFW I 0 1 0 1 ss 1221 Notes

1. Systems are described in Table 3.1-1.
2. One of the two welds was selected for examination by both the FAC and RI-IS1 Programs. Since a damage mechanism other than FAC was identified, this weld will be subject to both FAC and RI-IS1 examinations.

Page 22 of 35

Table 3.5-2 Unit 2 Number of Elements Selected for Inspection by Risk Category Excluding Impact of FAC I High Risk Region I Medium Risk Region I Low Risk Region System"' Category I Category 2 Category 3 1 Category4 Category 5 Category 6 Category 7 Total Selected Total Selected Total Selected Total Selected Total Selected Total Selected Total Selected RC 81 21 319 32 2 1 16 0 0 0 RHR 2 1 1 178 18 4 1 118 0 0 0 SI 7 2 254 26 2 1 240 0 33 0 cvc 0 0 25 3 24 3 119 0 0 0 l o 1 0 I cs I I 1 0 1 0 1 I AFW 0 0 0 0 10 1 33 0 0 0 Total 90 24 782 80 56 9 695 0 33 0 Notes

1. Systems are described in Table 3.1-2.
2. One of the two welds was selected for examination by both the FAC and RI-IS1 Programs. Since a damage mechanism other than FAC was identified, this weld will be subject to both FAC and RI-IS1 examinations.

Page 23 of 35

Table 3.6-1 Page 24 of 35

It 1 Table 3.6-1 I Consequence Failure Potential Inspections CDF ~mpact'~' LERF Impact'4)

System") Category Rank DMs Rank sxp and 3) RI-IS1 Delta wl POD wlo POD wl POD wlo POD MS 6 Medium None Low 11 0 -1 1 negligible negligible negligible negligible MS Total negligible negligible negligible negligible

~

FW 5 (3) Medium TASCS:(FAC) Medium (High) 1 1 0 -1.20E-11 no change -1.20E-12 no change FW 5 Medium TASCS Medium 1 1 0 -1.20E-11 no change -1.20E-12 no change FW 6 (3) Medium None (FAC) Low (High) 2 0 -2 negligible negligible negligible negligible FW 6 Medium None Low 4 0 -4 negligible negligible negligible negligible FW Total -2.40E-11 negligible -2.40E-12 negligible cs 4 High None Low 0 1 1 -3.40E-10 -3.40E-10 -3.40E-11 -3.40E-11 cs 6 Medium None Low 0 0 0 nochange nochange nochange nochange CS Total -3.40E-10 -3.40E-10 -3.40E-11 -3.40E-11 AFW 1 5 I Medium 1 TASCS,TT I Medium 2 1 -1 I -6.00E-12 I 1.00E-11 1 -6.00E-13 I 1.00E-12 AFW 6 Medium None Low 5 0 -5 negligible negligible negligible negligible AFW Total -6.00E-12 1.00E-11 -6.00E-13 1.00E-12

[Grand Totad I I I I I I I -2.19E-07 I -7.52E-08 I -2.19E-08 I -7.52E-09 I Notes

1. Systems are described in Table 3.1-1.
2. Only those ASME Section XI Code inspection locations that received a volumetric examination in addition to a surface 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. Piping weld examinations performed during the third interval per the 1989 Edition of ASME Code Section XI were used for comparison purposes for both units. In addition, for comparison purposes, the criteria of the 1998 Edition through 2000 Addenda of ASME Code Section XI were used to project the number of AFW piping welds that would have required examination since these requirements will be imposed in the upcoming fourth interval.
4. Per Section 3.7.1 of EPRl TR-112657, the contribution of low risk categories 6 and 7 need not be considered in assessing the change in risk. They are excluded from analysis because they have an insignificant impact on risk. Hence, the word "negligible" is given in these cases in lieu of values for CDF and LERF Impact. For those cases in high, medium or low risk region piping where no impact to CDF or LERF exists, "no change" is listed.

Page 25 of 35

Consequence Failure Potential Inspections CDF ~mpact'~' LERF Impact'4' System"' Category Rank DMs Rank SXI" and 3' RI-IS1 Delta wl POD wlo POD wl POD wlo POD RC 2 Hiah TASCS. TT Medium 3 7 4 -7.34E-08 -2.72E-08 -7.34E-09 -2.72E-09 RC 2 High TT, PWSCC Medium 1 1 0 nochange nochange nochange nochange RC 2 High TASCS Medium 5 3 -2 -1.63E-08 1.36E-08 -1.63E-09 1.36E-09 RC 2 High TT Medium 5 10 5 -1.02E-07 -3.40E-08 -1.02E-08 -3.40E-09 I RC 1 4 I Hiah I None I Low I 34 I 32 I -2 1 6.80E-10 I 6.80E-10 I 6.80E-11 I 6.80E-11 I RC 5 Medium TT, IGSCC Medium 0 1 1 -1.00E-11 -1.00E-11 -1.00E-12 -1.00E-12 RC 6 Medium None Low 0 0 0 nochange nochange nochange no change RC Total -1.91E-07 -4.69E-08 -1.91E-08 -4.69E-09 RHR 2 Hiuh I TASCS Medium 0 1 1 -1.22E-08 -6.80E-09 -1.22E-09 -6.80E-10 RHR 4 High None Low 7 18 11 -3.74E-09 -3.74E-09 -3.74E-10 -3.74E-10 RHR 5 Medium E-C Medium 0 1 1 -1.00E-11 -1.00E-11 -1.00E-12 -1.00E-12 RHR 6 Medium None Low 3 0 -3 negligible negligible negligible negligible RHR Total -1.60E-08 -1.06E-08 -1.60E-09 -1.06E-09 SI 2 Hiah TT. IGSCC Medium 1 1 0 nochanae nochanae nochanae nochanae SI 2 High TASCS Medium 0 1 1 -1.22E-08 -6.80E-09 -1.22E-09 -6.80E-I0 SI 2 High IGSCC Medium 1 0 -1 6.80E-09 6.80E-09 6.80E-10 6.80E-10 I SI I 4 I Hinh I None I Low I 21 I 26 I 5 I -1.70E-09 I -1.70E-09 I -1.70E-10 I -1.70E-10 I SI 5 Medium TT, IGSCC Medium 0 1 1 -1.00E-11 -1.00E-11 -1.00E-12 -1.00E-12 SI 6 Medium None Low 8 0 -8 negligible negligible negligible negligible SI 7 Low None Low 2 0 -2 negligible negligible negligible negligible SI Total -7.15E-09 -1.71E-09 -7.15E-10 -1.71E-10 cvc 4 High None Low 0 3 3 -1.02E-09 -1.02E-09 -1.02E-10 -1.02E-10 ~

cvc 5 Medium TT Medium 0 3 3 -5.40E-11 -3.00E-11 -5.40E-12 -3.00E-12 cvc 6 Medium None Low 0 0 0 nochange nochange nochange nochancle CVC Total I I -1.07E-09 1 -1.05E-09 I -1.07E-10 I -1.05E-10 Page 26 of 35

I Table 3.6-2 Unit 2 Risk Impact Analysis Results I Consequence Failure Potential Inspections CDF Impact'41 LERF ~mpact'~'

System") Category Rank DMs Rank RI-IS1 Delta w/ POD w/o POD

~ ~ 1and

' 3) 2 wl POD w/o POD Medium None Low 16 0 -16 negligible negligible MS Total negligible negligible Medium TASCS, (FAC) Medium (High) 2 1 -1 -6.00E-12 1.00E-11 I FW I 5 I Medium I TASCS I Medium I 3 I 1 I -2 I nochange I 2.00E-11 1 no chanae 1 2.00E-12 I Fw 6 (3) Medium None (FAC) Low (High) 2 0 -2 negligible negligible negligible negligible FW 6 Medium None Low 2 0 -2 negligible negligible negligible negligible M Total -6.00E-12 3.00E-11 -6.00E-13 3.00E-12 cs 4 High None Low 0 1 1 -3.40E-10 -3.40E-10 -3.40E-11 -3.40E-11 cs 6 Medium None Low 0 0 0 nochange nochange nochange nochange CS Total -3.40E-10 -3.40E-10 -3.40E-11 -3.40E-11 AFW 5 Medium TASCS, TT Medium 2 1 -1 -6.00E-12 1.00E-11 -6.00E-13 1.00E-12 AFW 6 Medium None Low 5 0 -5 negligible negligible negligible negligible AFW Total -6.00E-12 1.OOE-I1 -6.00E-13 1.00E-12 Grand Total -2.16E-07 -6.05E-08 -2.16E-08 -6.05E-09 Notes

1. Systems are described in Table 3.1-2.
2. Only those ASME Section XI Code inspection locations that received a volumetric examination in addition to a surface 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. Piping weld examinations performed during the third interval per the 1989 Edition of ASME Code Section XI were used for comparison purposes for both units. In addition, for comparison purposes, the criteria of the 1998 Edition through 2000 Addenda of ASME Code Section XI were used to project the number of AFW piping welds that would have required examination since these requirements will be imposed in the upcoming fourth interval.
4. Per Section 3.7.1 of EPRl TR-112657, the contribution of low risk categories 6 and 7 need not be considered in assessing the change in risk. They are excluded from analysis because they have an insignificant impact on risk. Hence, the word "negligible" is given in these cases in lieu of values for CDF and LERF Impact. For those cases in high, medium or low risk region piping where no impact to CDF or LERF exists, "no change" is listed.

Page 27 of 35

Table 5-1-1 Unit 1 Inspection Location Selection Comparison Between 1989 ASME Section XI Code and EPRl TR-112657 by Risk Region I High Risk Region I Medium Risk Region I Low Risk Region Weld 1989 Section XI("I EPRl TR-112657 Weld 1989 Section ~ 1 ' ~ EPRI

) TR-112657 Weld 1989 Section XI'^) EPRI TR-112657 Count VollSur lSur Only1 RI-IS1 I Other'3' Count VollSur Sur Only RI-IS1 Other'3' Count VollSur Sur Only RI-IS1 Other'3' 2 13 13 0 0 0 0 0 0 77 311 19 57 34 24 0 7 0 RHR l xC-F-1 0

4 0

O l 0

O l 0

l I 28 150 7

0 0

0 4

15 0

115 0

7 0

0 0

0 I B-J 2 21 5 1 3 51 1 13 0 C-F-2 0 0 0 0 2 1I 1 1I 0 1I 0 1I 1 I

2 1I 0 1I 0 0 1 cvc B-J 0 0 0 0 64 0 16 7 97 0 23 MS C-F-2 0 0 0 0 0 0 0 0 78 11 2 FW C-F-2 0 0 0 0 14 2 1 2'4) 38 6 0 cs C-F-1 0 0 0 0 8 0 0 1 47 I 0 0 AFW'5' C-F-2 0 0 0 0 1 3 3 1 5 1 0

~ ~

B-F 2 2 0 1 13 13 0 0 0 0 0 0 B-J 79 9 13 20 424 31 74 48 172 1 43 0 Total C-F-1 4 0 0 1 367 33 3 37 385 16 8 0 C-F-2 0 0 0 0 26 5 1 3 151 22 2 0 Notes

1. Systems are described in Table 3.1-1.
2. Since no examination selections had been made for the fourth interval IS1 Program prior to the development of the RI-IS1 Program, the third interval selections were used for comparison purposes. The Code of record for the third interval was the 1989 Edition of ASME Section XI. The Code Categories listed in the table are therefore in accordance with the 1989 Edition of ASME Section XI.
3. The column labeled "Other" is generally used to identify augmented inspection program locations credited per Section 3.6.5 of EPRl TR-112657. The EPRl methodology allows augmented inspection program locations to be credited if the inspection locations selected strictly for RI-IS1 purposes produce less than a 10% sampling of the overall Class 1 weld population. As stated in Section 3.5 of this template, PINGP Unit 1 achieved a 10.Oo/~sampling without relying on augmented inspection program locations beyond those selected by the RI-IS1 process. The "Other" column has been retained in this table solely for uniformity purposes with the other RI-IS1 application template submittals.

Page 28 of 35

Notes for Table 5-1-1 (cont'd)

4. One of the two welds was selected for examination by both the FAC and RI-IS1 Programs. Since a damage mechanism other than FAC was identified, this weld will be subject to both FAC and RI-IS1 examinations.
5. The 1989 Edition of ASME Section XI did not require examinations on the AFW piping welds listed in this table. However, in accordance with the 1998 Edition through 2000 Addenda of ASME Section XI, AFW piping is being added to the IS1 Program for the fourth IS1 interval. The criteria of the 1998 Edition through 2000 Addenda of ASME Section XI were used to project the number of AFW welds that would have required examination during the fourth IS1 interval per a standard IS1 Program application.

Page 29 of 35

Table 5-1-2 Unit 2 lnspectior Location Selection Comparison Between 1989 Section XI Code and EPRl TR-112657 by Risk Region I ~

High Risk Region

-~ ~

I ~-

Medium Risk Region I Low Risk Region

~

Weld 1989 Section XI(') EPRI TR-112657 Weld 1989 Section XI(') EPRI TR-112657 Weld 1989 Section XI(^) EPRI TR-112657 Count VollSur Sur Only RI-IS1 Other(3) Count VollSur Sur Only RI-IS1 Other(3) Count VollSur Sur Only RI-IS1 Other(3) 2 2 0 1 13 13 0 0 0 0 0 0 79 12 9 20 308 21 60 33 16 0 7 0

~ ~ -~ ~

B-J 0 0 0 0 39 7 0 6 0 0 0 0 RHR C-F-1 2 0 0 1 143 0 0 13 118 3 0 0 SI C-F-1 3 0 0 1 224 15 3 21 225 7 3 0 C-F-2 0 0 0 0 2 0 0 0 2 1 0 0 cvc B-J 0 0 0 0 49 0 14 6 119 0 28 0 MS C-F-2 0 0 0 0 0 0 0 0 92 16 4 0 I 3 4 I 4 I 0 1 0 - 1 AFW'5' I C-F-2 I 0 I 0 I 0 1 0 I I 1 0 I 2 I 0 I 1 I 1 3 3 1 5 I 0 I 0 I B-J 83 14 9 21 426 34 75 51 181 2 43 0 Total C-F-1 5 0 0 2 373 15 3 35 386 10 3 0 C-F-2 0 0 0 0 26 7 1 3 161 26 4 0 Notes

1. Systems are described in Table 3.1-2.
2. Since no examination selections had been made for the fourth interval IS1 Program prior to the development of the RI-IS1 Program, the third interval selections were used for comparison purposes. The Code of record for the third interval was the 1989 Edition of ASME Section XI. The Code Categories listed in the table are therefore in accordance with the 1989 Edition of ASME Section XI.

Page 30 of 35

II 0 L L I G61 1-43 MOl auoN 9 IS I o I E L I 1 I i s I r-a I 1 1 0 Z r-a un!Paw 33831 ll UJn!Paw un!Paw s IS 0 0 1 Z Z-4-3 1z E EE 60Z 1-4-3 MOl auoN Y6!H uJn!Paw P IS Z 0 s 61 r-a 1 0 0 Z r-a UJn!Paw 33831 46!H 46!H Z IS P1 P

0 0 L 0 9P 1 82 1-45 r-a MOl I auoN I Y6!H UJn!Paw P 1 YHtl I I 1 I 0 I 0 I P I 1-45 I un!Paw I S3SVl I 46!H I 46!H I Z I 8Htl

-1. P 3tl 0 0 El El 4 -a It 11 9 1s r-a un!Paw ll Y6!H Y6!H Z 3tl 1 0 Z Z 4-H

3 P

E Z

1 0 Z 11 8L Z-4-3 MOl auoN wn!Paw MOl 9 sw 0 SZ 0 L6 r-a MOl auoN wn!PaW MO7 9 3A3 E s 0 PZ r-a wn!PaW 11 uJn!Paw un!Paw s 3A3

I I

I 0

0 0

L I I

Z 6

161 I 1-4-3 Z-4-3 1-43 auoN 9 I 0 y

0 0 0 z

E z

1 I

1 r-a Z-4-3 1-4-3 r-a 1-4-3 r-a 33831 I 46!H Z IS 811 I 1 3 P I 1-d-3 6E1 1 1-33 I 9 I 1 0 1 0 z I 1-4-3 z I r-a 1 -7 3-9 Y6!H z I 3H 1 1 9-9 LZ I r-a I

(c,JawO ISI-ltl LESZCC-tllltld3

Table 5-2-2 (cont'd)

Unit 2 Inspection Location Selection Comparison Between 1989 Section XI Code and EPRl TR-112657 by Risk Category FW 5 Medium Medium TASCS Medium C-F-2 10 3 1 1 FW 6 (3) Low (High) Medium None (FAC) Low (High) C-F-2 2 2 0 0 FW 6 Low Medium None Low C-F-2 32 2 0 0 cs 4 Medium High None Low C-F-1 6 0 0 1 cs 6 Low Medium None Low C-F-1 43 0 0 0 AFW'5' 5 Medium Medium TASCS, TT Medium C-F-2 10 2 0 1 AFW'5' 6 Low Medium None Low C-F-2 33 5 0 0 Notes

1. Systems are described in Table 3.1-2.
2. Since no examination selections had been made for the fourth interval IS1 Program prior to the development of the RI-IS1 Program, the third interval selections were used for comparison purposes. The Code of record for the third interval was the 1989 Edition of ASME Section XI. The Code Categories listed in the table are therefore in accordance with the 1989 Edition of ASME Section XI.
3. The column labeled "Other" is generally used to identify augmented inspection program locations credited per Section 3.6.5 of EPRl TR-112657. The EPRl methodology allows augmented inspection program locations to be credited if the inspection locations selected strictly for RI-IS1 purposes produce less than a 10% sampling of the overall Class 1 weld population. As stated in Section 3.5 of this template, PINGP Unit 2 achieved greater than a 10% sampling without relying on augmented inspection program locations beyond those selected by the RI-IS1 process. The "Other" column has been retained in this table solely for uniformity purposes with the other RI-IS1 application template submittals.
4. This weld was selected for examination by both the FAC and RI-IS1 Programs. Since a damage mechanism other than FAC was identified, this weld will be subject to both FAC and RI-IS1examinations.
5. The 1989 Edition of ASME Section XI did not require examinations on the AFW piping welds listed in this table. However, in accordance with the 1998 Edition through 2000 Addenda of ASME Section XI, AFW piping is being added to the IS1 Program for the fourth IS1 interval. The criteria of the 1998 Edition through 2000 Addenda of ASME Section XI were used to project the number of AFW welds that would have required examination during the fourth IS1 interval per a standard IS1 Program application.

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