ML092230620

SIR-00-045, Revision 2, Leak-Before-Break Evaluation 6-Inch to 12-Inch Safety Injection and Residual Heat Removal Piping Attached to the RCS (Kewaunee Nuclear Plant), Enclosure D

ML092230620
Person / Time
Site:	Kewaunee
Issue date:	01/13/2003
From:	Deardorff A Structural Integrity Associates
To:	Office of Nuclear Reactor Regulation, Wisconsin Public Services Corp
References
09-451, LR/MWH R0 SIR-00-045, Rev 2
Download: ML092230620 (163)

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{{#Wiki_filter:Serial No. 09-451 Docket No. 50-305 ENCLOSURE D SIR-00-045, Revision 2, "Leak-Before-Break Evaluation 6-inch to 12-inch Safety Injection and Residual Heat Removal Piping Attached to the RCS (Kewaunee Nuclear Power Plant)" KEWAUNEE POWER STATION DOMINION ENERGY KEWAUNEE, INC.

RECORD CHANGE NOTICE Type of Change: El Supplement 0 Correction F] Deletion Record ID: Calculation SIR-00-045 Revision: 2 Date: 01/13/2003 Title/

Subject:

Leak-Before-Break Evaluation 6-inch to 12-inch Saftety Injection and Residual Heat Removal Piping Attached to the RCS (Kewaunee Nuclear Power Plant) Effective Date of Change: 03/25/2003 Reason for Change: Replacement of the Revision Control Sheet with corrected sheet per memorandum from Structural Integrity Associates dated March 25, 2003. Reviýew and Approval (Prnt VSign) Date kPrint /Sign) Da-2t-e7 V Or~zation Date Organization (Print / Sign) Date Organization (Print / Sign) Date NOTE: Changes to approved records shall be reviewed and approved by the same organizations that performed the original review and approval. Changes made by: Records Management Christy Zich I 04/24/2007 Organization (Print / Sign) Date Form GNP-15.02.02-5 Rev. G Date: APR 17 2007 Page 27 of 29 INFORMATION USE RECORDS APR 3 0 2007

V StructuralIntegrityAssociates S ural &Materials Reaflity Technology, Inc. 3315 Almaden Expressway Suite 24 San Jose, CA 95118-1557 Phone: 408-978-8200 MEMORANDUM Fax: 408-978-8964 www.structint.com adeardor@stmctint.com March 25, 2003 AFD-03-013 To: Gerald Riste - NMC Charles Tomes - NMC From: Art Deardorff- SI

Subject:

Revised Revision Control Sheet - Report SIR-00-045 "Leak Before Break Evaluation ...Kewanee Nuclear Power Plant'" Based on conversations with Jerry today, we discovered that 1) it was not clearly stated that the report covered your current Power Up-Rate program reflected in Reference 11, and 2) that the Revision Control Sheet did not reflect that Table 4-1 on page 4-4 had been changed. Enclosed is a Revised Revision Control Sheet. Here, we make it clear that Reference 11, which is the basis of Table 4-1, covers the Power Up-Rate conditions. There is no revision to the report itself. Do not hesitate to call if you need further assistance in this matter. cv cc: Nat Cofie File WPS-02Q-101/401 RECORDS APR 3 0 ZN? AUU A AUslin, TX Charlotte, NC Denver, CO N. Stonlnglan, CT Pompano Beach, FL RockvllHe, MD Uniontown, OH 512-533-9191 704-573-1369 303-792-0077 850-599-6050 954-917-2781 301-231-7746 330-899-9753

StructuralIntegrityAssociates, Inc. www. structint.com RECORDS APR 3 0 2187

Report No.: SIR-00-045 Revision No.: 2 Project No.: WPS-02Q File No.: WPS-02Q-401 January 2003 Leak-Before-Break Evaluation 6-inch to 12-inch Safety Injection and Residual Heat Removal Piping Attached to the RCS Kewaunee Nuclear Power Plant Preparedfor: Wisconsin Public Service Contract No. 255443 and P0010447 Preparedby: Structural Integrity Associates San Jose, California Preparedby: r Date: / /003 3 "2 1 Reviewed by: I'll'ilillililliliýýýýýýýýýýýýýýýýýýýýýý 1111. Date: /*/3 V-.. N. G. Cofie, Ph.D. Approved by: Date: *#Z13 A. F. ca6rdof PE C StructuralIntegrityAssociates

REVISION CONTROL SHEET Document Number: SIR-00-045

Title:

Leak-Before-Break Evaluation. 6-inch to 12-inch Safetv Iniection and R~ec*iduia1 Heat Removal Pipinq Attached to the RCS Kewaunee Nuclear Power Plant Client: Wisconsin Public Service SI Project Number: WPS-020 Section Pages Revision Date Comments I ~ i-x 0 10/04/00 Initial Issue 1 1 1-9 2 2-1 2 3 3-1 3 4 4-1 12 5 5-1 42 6 6-1 16 7 7-1 2 8 8-1 3 App. A A A-4 5 5 5-33, 1 May 31, 2002 Corrected definition of leakage flaw 5 5-38, length, specified assumed anchor 5-40-5-42 location for restrain evaluation (all pages Rev. 1) vi 2 1/13/03 Incorporated results from NRC submittal 1 1-2-1-6 (all pages Rev. 2). Revised table on 4 4-3,4-4 page 4-4 reflects that conditions evaluated bound those for power up-rate 5 5-13 as provided Reference 11. 8 8-1,8-3 App. B B B-11 App. C C C-25 App. D D D-15

SUMMARY

This report presents a leak-before-break (LBB) evaluation for piping systems attached to the reactor coolant system (RCS) at Kewaunee Nuclear Power Plant (operated by Wisconsin Public Service Corporation). The evaluation includes portions of the safety injection (SI) and residual heat removal (RHR) systems. It was performed jointly with the Prairie Island Nuclear Generating Plant, Units I and 2 (operated by Northern States Power Company) to take advantage of the similarities of these plants in the LBB evaluations. As such, some of the evaluation results presented in this report are generic to all three units. The LBB evaluation was performed in accordance with the 10 CFR 50, Appendix A GDC-4 and NUREG-1061, Vol. 3 as supplemented by NUREG-0800, Standard Review Plan 3.6.3. Additional criteria to address the application of LBB to small diameter piping taking guidance from NUREG/CR-6443 and NUREG/CR-4572 was developed in Section 5 of this report. The evaluation is based on determining critical flaw sizes and leakage rates at all weld locations using weld-specific loads. The critical flaw size as used herein refers to the flaw length which becomes unstable under a given set of applied loads. Critical flaw sizes were calculated using both the net section plastic collapse and the elastic-plastic fracture mechanics (EPFM) J-Integral/Tearing Modulus (J/T) approach with conservative generic material properties. The "leakage flaw size" was determined as the minimum of one half the critical flaw size with a factor of unity on normal operating plus SSE loads or the critical flaw size with a factor of ii on normal operating plus SSE loads. Thus, the leakage flaw size as referred herein maintains a safety factor of 2 on the critical flaw size under normal plus SSE loads and a safety factor of 1 when the loads are factored by -52I. Leakage rates were then calculated through the leakage flaw sizes per the requirements of NUREG-1061. The determination of critical flaw sizes and leak rates took into account the effects of restraint of pressure induced bending which has been shown to affect LBB analysis results especially for small diameter piping. A fatigue crack growth analysis was also performed to determine the growth of postulated semi-elliptical, inside surface flaws with an initial size based on ASME Code Section XI acceptance standards. SIR-00-045, Rev. 2 iii

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The following summary of the LBB evaluation is formatted along the lines of the "Recommendations for Application of the LBB Approach" in the NUREG-1061 Vol. 3 executive summary: (a) The SI and RHR piping systems are constructed of very ductile stainless steel that is not susceptible to cleavage-type fracture. In addition, it has been shown that these systems are not susceptible to the effects of corrosion, high cycle fatigue or water hammer. (b) Loadings have been determined from the original piping analysis, and are based upon pressure, dead weight, thermal expansion and earthquake seismic motion. All highly-stressed locations in the piping were considered. (c) Although plant specific certified material test report (CMTR) data is available, this information alone is not complete for the fracture mechanics evaluations. As such, lower-bound generic industry material properties for the piping and welds have been conservatively used in the evaluations. (d) Crack growth analysis was conducted at the most critical locations on all the evaluated piping, considering the cyclic stresses predicted to occur over the life of the plant. For a hypothetical flaw with aspect ratio of 10:1 and an initial flaw depth of approximately 11% of pipe wall, it will take about 38 heatup and cooldown cycles to grow the hypothetical flaw to the ASME Section XI allowable flaw size (75% of pipe wall) at the most critical location. For the last ten years, Kewaunee has experienced 13 heatup/cooldown cycles. Given that this piping is inspected in accordance with ASME Section XI requirements in each 10-year interval, it is believed that crack growth can be managed by the current in-service inspection program. (e) Based on evaluation of the critical cracks at all locations in the piping system, it was determined that the leakage at the limiting location was 3.74 gpm. With a margin of 10 on leakage suggested in NUREG-1061 Vol. 3, the leakage detection system at Kewaunee SIR-00-045, Rev. 2 iv T StructuralIntegrity Associates

is capable of measuring leakage of 2.5 gpm. This leakage detection is assumed in the LBB evaluation. (f) Since the systems considered in this evaluation consist of relatively small diameter piping (6-inch to 12-inch OD), the effect of the piping system flexibility and restraint was considered in the determination of the critical flaw sizes and leakage rates at the various weld locations. The most highly restrained piping systems were analytically modeled and various crack configurations were introduced at the weld locations to determine the reduction in applied moments due to piping system restraint. The leakage was then calculated. This evaluation showed that there was not a significant reduction in leakage as a result of piping system restraint. (g) Crack growth of a leakage size crack in the length direction due to an SSE event is no more than 1% of the leakage flaw size. This is not significant compared to the margin between the leakage-size crack size and the critical crack size. (h) For all locations, the critical size circumferential crack was determined for the combination of normal plus safe shutdown earthquake (SSE) loads. The leakage size crack was chosen such that its length was no greater than the critical crack size reduced by a factor of two. Axial cracks were not considered since critical axial cracks always exhibit much higher leakage and more margin than critical circumferentially-oriented cracks. (i) For all locations, the critical crack size was determined for the combination of [2 times the normal plus SSE loads. The leakage size crack was selected to be no greater than this critical crack size. (The minimum of the crack sizes determined by this criterion, and that of the criterion of (h) above, was chosen for calculation of the leakage rate for each location.) (j-n) No special testing (other than information in the CMTRs) was conducted to determine material properties for fracture mechanics evaluation. Instead, generic lower bound SIR-00-045, Rev. 2 v

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material toughness and tensile properties were used in the evaluations. The material properties so determined have been shown to be applicable near the upper range of normal plant operation and exhibit ductile behavior at these temperatures. This data is widely accepted by industry for conducting mechanics analysis. (o) Limit load analysis as outlined in NUREG-0800, SRP 3.6.3, was utilized in this evaluation to supplement the EPFM J/T analyses in order to determine the critical flaw sizes. The most limiting results of these two analytical approaches were used in determining the critical flaw sizes for the various piping systems. Thus, it is concluded that the 6-inch to 12-inch piping evaluated in this report qualifies for the application of leak-before-break analysis to demonstrate that it is very unlikely that the piping couldexperience a large pipe break prior to leakage detection. In this revision to the report, reference is made to a request for additional information (RAI) from the Nuclear Regulatory Commission (NRC) based on the Kewaunee request to use LBB. Appendices are added to the report to provide 1) the responses to the RAI, and 2) the resulting NRC Safety Evaluation that accepted the LBB report. Reference is also made to a companion report that provides a method for evaluating the effects of revised piping moments on this LBB evaluation. SIR-00-045, Rev. 2 vi

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Table of Contents Section Page

1.0 INTRODUCTION

...............................................................................................................                    1-1 1.1 Background ......................................................................................................................            1-1 1.2 Leak-Before-Break M ethodology ....................................................................................                          1-2 1.3 Leak Detection Capability at Kewaunee ..........................................................................                            1-5 2.0 CRITERIA FOR APPLICATION OF LEAK-BEFORE-BREAK .....................................                                                             2-1 2.1 Criteria for Through-W all Flaws                                                                                                             2-1 2.2 Criteria for Part-Through-W all Flaws .............................................................................                          2-2 2.3 Consideration of Other M echanisms ...............................................................................                           2-2 3.0 CONSIDERATION OF WATER HAMMER, CORROSION ANDFATIGUE ................ 3-1 3.1 W ater Hammer ..................................................................................................                        .... 3-1 3.2 Corrosion ..........................................................................................................................         3-2 3.3 Fatigue ..............................................................................................................................       3-2 4.0 PIPING MATERIALS AND STRESSES ......................................................................                                            4-1 4.1 Piping System Description..............................................................................................                      4-1 4.2 M aterial Properties ......................................................................................................                  4-1 4.3 Piping M oments and Stresses ..........................................................................................                      4-2 5.0 LEAK-BEFORE-BREAK EVALUATION ........................................................................                                           5-1 5.1  Evaluation of Critical Flaw Sizes ....................................                                                                      5-1 5.2  Leak Rate Determ ination .................................................................................................                  5-7 5.3  Effect of Piping Restraint on LBB Evaluation ................................................................                               5-8 5.4  LBB Evaluation Results and Discussions ......................................................................                             5-12 6.0 EVALUATION OF FATIGUE CRACK GROWTH OF SURFACE FLAWS .................. 6-1 6.1 Plant Transients ................................................................................................................            6-1 6.2 Stresses for Crack Growth Evaluation .............................................................................                           6-2 6.3 M odel for Stress Intensity Factor .....................................................................................                     6-3 6.4 Fatigue Crack Growth Analysis and Results ...................................................................                                6-4 7.0 SUM MARY AND CONCLUSIONS ..................................................................................                                     7-1

8.0 REFERENCES

...................................................................................................................                  8-1 APPENDIX A DETERMINATION OF RAMBERG-OSGOOD PARAMETERS AT 650°F ...............................................................................................................           A-0 SIR-00-045, Rev. 2                                                       vii

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List of Tables Table Page Table 4-1 RCS Operating Temperature for Kewaunee After Replacement with Model 54F Steam Generators ............................................................................................. 4-4 Table 4-2 Lower Bound SMAW Material Properties Used in the LBB Evaluation ............... 4-5 Table 4-3 Moments for the 6-inch Safety Injection Piping Attached to Cold Leg ................. 4-6 Table 4-4 Moments for the 12-inch Safety Injection Piping Attached to Cold Leg ............... 4-7 Table 4-5 Moment for the 8-inch Residual Heat Removal Piping Attached to Hot Leg ........ 4-8 Table 5-1 Leakage Flaw Size Versus Stress Determined by J/T Analysis for 6-inch Safety Injection Lines Attached to RCS Cold Leg (Temperature = 550°F) .................... 5-14 Table 5-2 Leakage Flaw Size Versus Stress Determined by J/T Analysis for 12-inch Safety Injection Lines Attached to RCS Cold Leg (Temperature = 5500 F) ......... 5-15 Table 5-3 Leakage Flaw Size Versus Stress Determined by J/T Analysis for 8-inch RHR Lines Attached to RCS Hot Leg (Temperature = 607.4F) ............... 5-16 Table 5-4 Leakage Flaw Size Versus Stress Determined by J/T Analysis for 6-inch Draindown Lines and Nozzles Attached to RCS Hot Leg (Temperature = 607.40 F) ................................................................................................................. 5-17 Table 5-5 Leakage Flaw Size Versus Stress Determined by Limit Load for 6-inch Safety Injection Lines Attached to RCS Cold Leg (Temperature = 550 0F) .................... 5-18 Table 5-6 Leakage Flaw Size Versus Stress Determined by Limit Load for 12-inch Safety Injection Lines Attached to RCS Cold Leg (Temperature = 550'F) ......... 5-19 Table 5-7 Leakage Flaw Size Versus Stress Determined by Limit Load for 8-inch RHR Lines Attached to RCS Hot Leg (Temperature = 607.4F) ............... 5-20 Table 5-8 Leakage Flaw Size Versus Stress Determined by Limit Load for 6-inch Draindown Lines and Nozzles Attached to RCS Hot Leg (Temperature = 607.40 F) ........................................................................................-.......................... 5-21 Table 5-9 Predicted Leakage Rates for 6-inch Safety Injection lines Attached to RCS C old Leg ................................................................................................................ 5-22 Table 5-10 Predicted Leakage Rates for 12-inch Safety Injection Lines Attached to RCS C old L eg ............................................................................................................... 5-23 Table 5-11 Predicted Leakage Rates for 8-inch RHR Lines Attached to RCS Hot Leg ......... 5-24 Table 5-12 Predicted Leakage Rates for 6-inch Nozzles Attached to RCS Hot Legs ............ 5-26 Table 5-13 Moments Due to Kink Angle Restraint Effects for 6-inch Safety Injection Line Attached to RCS Cold Leg ........................................................................... 5-27 Table 5-14 Moments Due to Kink Angle Restraint Effects for 6-inch Draindown Line Attached to RC S H ot Leg ..................................................................................... 5-28 Table 5-15 Moments Due to Kink Angle Restraint Effects for 8-inch RHR Lines Attached to R C S Hot Leg ..................................................................................................... 5-29 Table 5-16 Leakage Flaw Size and Leakages for 6-inch Safety. Injection Line Attached to RCS Cold Leg Considering Restraint Effect ........................................................ 5-31 Table 5-17 Leakage Flaw Size and Leak Rates for 8-inch RHR Line Attached to RCS Hot Leg Considering Restraint Effects ................................................................. 5-32 SIR-00-045, Rev. 2 viii r StructuralIntegrity Associates

List of Tables (Continued) Table Page Table 5-18 Leakage Flaw Size and Leak Rates for 6-inch Draindown Line Attached to RCS Hot Leg Considering Restraint Effects ........................................................ 5-33 Table 6-1 Plant Design Transients Used for LBB Evaluations ............................................... 6-6 Table 6-2 Additional System Transients Used Specifically for LBB Evaluations ................. 6-7 Table 6-3 Combined Transients for Crack Growth, Hot Leg .......................... 6-8 Table 6-4 Combined Transients for Crack Growth, Cold Leg ............................................ 6-9 Table 6-5 Bounding Moments ........................................ 6-10 Table 6-6 Maximum and Minimum Transient and Discontinuity Stress .............................. 6-11 Table 6-7 Maximum and Minimum Transient Stress ..................................................... 6-12 Table 6-8 Total Constant (ao) and Linear (cyl) Through-Wall Stresses, 6" Sch 160 Cold Leg S I .................................................................................................................... 6-13 Table 6-9 Total Constant (Go) and Linear (aj) Through-Wall Stresses, 12" Sch 160 SI Accum ulator .......................................................................................................... 6-14 Table 6-10 Total Constant (ao) and Linear (a 1) Through-Wall Stresses, 8" Sch 140 RHR Suction ... ......................................... .... 6-15 Table 6-11 Initial Crack Depths for Various Locations .......................................................... 6-16 Table 6-12 Results of Fatigue Crack Growth Analysis .......................................................... 6-16

                                   /2 SIR-00-045, Rev. 2                                                     ix StructuralIntegrity Associates

List of Figures Figure Page Figure 1-1. Representation of Postulated Cracks in Pipes for Fracture Mechanics Leak-Before-Break A nalysis .................................................................................. 1-7 Figure 1-2. Conceptual Illustration of ISI (UT)/Leak Detection Approach to Protection Against Pipe Rupture ........................................ 1-8 Figure 1-3. Leak-Before-Break Approach Based on Fracture Mechanics Analysis with In-service Inspection and Leak Detection ........................... 1-9 Figure 4-1. Schematic of Piping Model and Selected Node Points for the 6-inch Safety Injection Piping Attached to the Cold Leg (Loops A and B) ............................... 4-10 Figure 4-2. Schematic of Piping Model and Selected Node Points for the 12-inch Safety Injection Piping Attached to the Cold Leg (Loops A and B) ................................ 4-l1 Figure 4-3. Schematic of Piping Model and Selected Node Points for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Loops A and B) .............................. 4-12 Figure 5-1. J-Integral/Tearing Modulus Concept for Determination of Instability During D uctile T earing ..................................................................................................... 5-34 Figure 5-2. Leakage Flaw Size Versus Moment for 6-inch Schedule 160 Pipe Weld Determined by J/T and Limit Load Analyses ..................................................... .5-35 Figure 5-3. Leakage Flaw Size Versus Moment for 6-inch Schedule 160 Nozzle/ Draindown Weld Determined by J/T and Limit Load Analyses .......................... 5-36 Figure 5-4. Critical Flaw Size Versus Moment for 8-inch Schedule 140 Pipe Weld Determined by J/T and Limit Load Analyses ....................................................... 5-37 Figure 5-5. Critical Flaw Size Versus Moment for 12-inch Schedule 160 Pipe Weld Determined by J/T and Limit Load Analyses ....................................................... 5-38 Figure 5-6. Depiction of Restraint Effect on Cracked Piping ................................................. 5-39 Figure 5-7. Schematic of Piping Layout Used to Determine the Effect of Restraint on LBB Evaluation (8-inch RHR Line - Prairie Island Unit I, Loop A) .................. 5-40 Figure 5-8. Schematic of Piping Layout Used to Determine the Effect of Restraint on LBB Evaluation (6-inch Safety Injection Line - Kewaunee, Loop B).......................... 5-41 Figure 5-9. Schematic of Piping Layout Used to Determine the Effect of Restraint on LBB Evaluation (6-inch Draindown Line - Prairie Island Unit 2) .............. 5-42 SIR-00-045, Rev. 2 x C StructuralIntegrity Associates

1.0 INTRODUCTION

1.1 Background This report documents evaluations performed by Structural Integrity Associates (SI) to determine the leak-before-break (LBB) capabilities of the high energy non-isolable 6-inch to 12-inch piping attached to the reactor coolant system (RCS) at Kewaunee Nuclear Power Plant. These encompass portions of the safety injection (SI) system, including that from the SI accumulators, and the residual heat removal (RHR) piping. These evaluations were undertaken to address the potential for high energy line break at these locations. The portions of these lines evaluated extend from the nozzle at the reactor coolant loop to the first isolation valve. The evaluations were performed jointly with Prairie Island Units I and 2 since the plants are very similar, therefore allowing some portions of the evaluation to be performed generically for all three units. Specific results of the LBB evaluation for Prairie Island Units 1 and 2 are provided in Reference 1. It should be noted that all the piping included in the evaluation as delineated below are also present at Prairie Island Units 1 and 2. However, in addition to these lines, Prairie Island also has a 6-inch RCS draindown line on the hot leg (Loop A on Unit 1 and Loop B on Unit 2). This line at Prairie Island was added to the plant following initial construction and consists of a short section of 6-inch diameter piping prior to reducing to 2-inch diameter at the isolation valve. The draindown line is not present at Kewaunee; hence reference to the draindown lines in this report is made only as part of the generic evaluation and does not specifically apply to Kewaunee. The following lines are evaluated in this report:

• 12-inch SI lines (Loop A and Loop B). These lines are connected to the SI accumulators. The Loop B line also serves as the RHR system return line.
• 8-inch RI-IR lines (Loop A and Loop B). These lines serve as the RHR system suction lines.
• 6-inch cold leg SI lines (Loops A and B). These lines provide flow from the high pressure SI pumps.
• 6-inch capped nozzles on the hot leg (Loops A and B).

SIR-00-045, Rev. 2 1-1 StructuralIntegrity Associates

In addition to the above lines, there are also SI lines connected to the reactor vessel (Loops A and B). These lines are composed of 4-inch diameter lines for some distance from the reactor vessel nozzle and a shorter section of 6-inch diameter line near the isolation valves. For these lines, the maximum break flow would be limited by the 4-inch piping and hence these lines were not evaluated. In February 2001, Nuclear Management Company (NMC) submitted this report to the NRC with a request to exclude dynamic effects from pipe rupture for the lines evaluated [28]. In January 2002, a request for additional information (RAI) was received from the NRC [29] regarding leakage detection capability. NMC responded in February 2002 [30]. In May 2002, an additional RAI was received with technical questions concerning the LBB analysis in this report [31 ]. The responses to these questions required additional analysis and were submitted to the NRC in June 2002 [32]. This submittal is reproduced in Appendix B, with the SI technical responses to some of the questions [33] provided in Appendix C. The NRC Safety Evaluation [34] is included in Appendix D. A companion report has also been prepared that provides acceptance diagrams and tables such that the effects of modified piping moments can be assessed without completely revising this LBB analysis [35]. 1.2 Leak-Before-Break Methodology NRC SECY-87-213 [21 covers a rule to modify General Design Criterion 4 (GDC-4) of Appendix A, 10 CFR Part 50. This amendment to GDC-4 allows exclusion from the design basis of all dynamic effects associated with high-energy pipe rupture by application of LBB technology. Definition of the LBB approach and criteria for its use are provided in NUREG-1061 [3], supplemented by NUREG-0800, SRP 3.6.3 [4]. Volume 3 ofNUREG-1061 defines LBB as "...the application of fracture mechanics technology to demonstrate that high energy fluid piping is very unlikely to experience double-ended ruptures or their equivalent as longitudinal or diagonal splits." The particular crack types of interest include circumferential through-wall cracks (TWC) and part-SIR-00-045, Rev. 2 1-2

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• through-wall cracks (PTWC), as well as axial or longitudinal through-wall cracks (TWC), as shown in Figure 1-1.

LBB is based on a combination of in-service inspection (ISI) and leak detection to detect cracks, U coupled with fracture mechanics analysis to show that pipe rupture will not occur for cracks smaller than those detectable by these methods. A discussion of the criteria for application of LBB is I presented in Section 2 of this report, which summarizes NUREG-1061, Vol. 3 requirements. I The approach to LBB which has gained acceptance for demonstrating protection against high energy line break (HELB) in safety-related nuclear piping systems is schematically illustrated in I Figure 1-2. Essential elements of this technique include critical flaw size evaluation, crack propagation analysis, volumetric nondestructive examination (NDE) for flaw detection/sizing, leak I detection, and service experience. In Figure 1-2, a limiting circumferential crack is modeled as having both a short through-wall component, and an axisymmetric part-through-wall crack component. Leak detection establishes an upper bound for the through-wall crack component while volumetric ISI limits the size of undetected part-through-wall defects. These detection methods complement each other, since volumetric NDE techniques are well suited to the detection of long cracks while leakage monitoring is effective in detecting short through-wall cracks. The level of NDE required to support LBB involves volumetric inspection at intervals determined by fracture mechanics crack growth analysis, which would preclude the growth of detectable part-through-wall cracks to a critical size during an inspection interval. A fatigue evaluation is performed to ensure that an undetected flaw acceptable per ASME Section will not grow significantly during service. For through-wall defects, crack opening areas and resultant leak rates are compared with leak detection limits. The net effect of complementary leak detection and ISI is illustrated by the shaded region of Figure 1-2 as the largest undetected defect that can exist in the piping at any given time. Critical flaw size evaluation, based on elastic-plastic fracture mechanics techniques, is used to determine the length and depth of defects that would be predicted to cause pipe rupture under specific design basis 3 loading conditions, including abnormal conditions such as a seismic event and including appropriate safety margins for each loading condition. Crack propagation analysis is used to determine the time U SIR-00-045, Rev. 2 1-3 3

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interval in which the largest undetected crack could grow to a size which would impact plant safety margins. A summary of the elements for a leak-before-break analysis is shown in Figure 1-3. Service experience, where available, is useful to confirm analytical predictions as well as to verify that such cracking tends to develop into "leak" as opposed to "break" geometries. In accordance with NUREG-1061, Vol. 3 [3] and NUREG-0800, SRP 3.6.3 [4], the leak-before-break technique for the high energy piping systems evaluated in this report included the following considerations. Elastic-plastic fracture mechanics analysis of load carrying capacity of cracked pipes under worst case normal loading, with safe-shutdown earthquake (SSE) loads, included. Such analysis includes elastic-plastic fracture data applicable to pipe weldments and weld heat-affected zones where appropriate.

• Limit-load analysis in lieu of the elastic-plastic fracture mechanics analysis described above.
• Linear elastic fracture mechanics analysis of subcritical crack propagation to determine ISI (in-service inspection) intervals for long, part-through-wall cracks.
• A piping system evaluation to determine the effect of piping restraint on leakage for small diameter piping.

Piping stresses have a dual role in LBB evaluations. On one hand, higher maximum (design basis) stresses tend to yield lower critical flaw sizes, which result in smaller flaw sizes for assessing leakage. On the other hand, higher operating stresses tend to open cracks more for a given crack size and create a higher leakage rate. Because of this duality, the use of a single maximum stress location for a piping system may result in a non-conservative LBB evaluation. Thus, the LBB evaluation reported herein has been performed for each nodal location addressed in the plant piping system analysis. SIR-00-045, Rev. 2 1-4

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1.3 Leak Detection Capability at Kewaunee Application of LBB evaluation methodology is predicated on having a very reliable leak detection system at the plant, capable of measuring I/ 10 of the leakage determined in the evaluation. Section 6.5 of Kewaunee FSAR [5] provides details of the capabilities of the leak detection systems. Several leak detection systems are employed for the reactor coolant system but the four most important ones are described below. Containment System Air Particulate Monitor (R- 11) This is the most sensitive instrument available for detection of Reactor Coolant System (RCS) leakage in containment. It is capable of detecting low levels of radioactivity in containment air. Assuming complete dispersion of leaking radioactive solids consistent with very little or no fuel cladding leakage, R- 11 is capable of detecting leaks as small as approximately 0.013 gpm (50 cm3/min) within 20 minutes. Even if only 10% of the particulate activity is actually dispersed, leakage rate of the order of 0.13 gpm are well within detectable range of R- 11. Containment Radiogas Monitor (R- 12) The containment radioactive gas monitor is inherently less sensitive (threshold at 1OE-6 itCi/cc) than the containment air particulate monitor, and would function in the event that significant reactor coolant gaseous activity exists from fuel cladding defects. Assuming a reactor coolant activity of 0.3 gCi/cc, the occurrence of a leak of 2 to 4 gpm would double the zero leakage background in less than an hour's time. In these circumstances this instrument is a useful backup to the air particulate monitor. Humidity Detection The humidity detection instrumentation offers another means of detection of leakage into the containment. Although this instrumentation is not as sensitive as the air particulate monitor, it has the characteristics of being sensitive to vapor originating from all sources within the SIR-00-045, Rev. 2 1-5 StructuralIntegrityAssociates

containment, including the Reactor Coolant, Steam and Feedwater Systems. Plots of containment air dew point variations above a base-line maximum established by the cooling water temperature to the air coolers should be sensitive to incremental leakage equivalent to 2 to 10 gpm. Containment Sump Leakage Measurin2 This leak detection method is based on the principle that the leakage collected by the containment sump will be pumped to the waste holdup tank, with pumping time directly related to the quantity of leakage. Sump pump running time is monitored in the control room, and will provide an indication of deviation from normal leakage rates to the operator. Since the fan-coil units drain to the Containment Vessel sump (Sump A), all condensation from primary coolant leaks is directed to the containment sump. Detection of leakage is possible within 30 to 40 minutes. Leak rates of approximately 0.5 gpm are detectable by this method. Larger leakage rates are detectable in much shorter time periods. In summary, Kewaunee has a very redundant leak detection system capable of detecting leakage as low as 0.013 gpm. However, based on the similarity of Kewaunee and R. E. Ginna Nuclear Power plants and the fact that a leak detection of 0.25 gpm was approved by the NRC for use at, Ginna [6], a minimum detectable leakage rate of 0.25 gpm has been conservatively used for the LBB evaluation for Kewaunee. Since NUREG-l 061, Vol. 3 requires that a margin of 10 be provided on leakage, the minimum allowable evaluated leakage rate is 2.5 gpm. References 29 and 30 contain the NRC RAI and the NMC response, providing additional information on the Kewaunee leakage detection capabilities. SIR-00-045, Rev. 2 1-6

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U I U _ U

a. Circumferential and Longitudinal Through-Wall Cracks of Length 2a.

I I I _ _9336_ ! b. Circumferential 360 Iart-Through-Wall Crack of Depth a. I Figure 1-1. Representation of Postulated Cracks in Pipes for Fracture Mechanics Leak-Before-Break Analysis I SIR-00-045, Rev. 2 1-7 r* Structural Integrity Associates

I I I I U I H I I I-J I I I I I THRU-WALL FLAW LENGTH Figure 1-2. Conceptual Illustration of ISI (UT)/Leak Detection Approach to Protection Against Pipe Rupture SIR-00-045, Rev. 2 1-8

                                                                     !     StructuralIntegrity Associates

Figure 1-3. Leak-Before-Break Approach Based on Fracture Mechanics Analysis with In-service Inspection and Leak Detection SIR-00-045, Rev. 2 1-9 U StructuralIntegrity Associates

2.0 CRITERIA FOR APPLICATION OF LEAK-BEFORE-BREAK NUREG-1061, Vol. 3 [3] identifies several criteria to be considered in determining applicability of the leak-before-break approach to piping systems. Section 5.2 of NUREG-1061, Vol. 3 provides extensive discussions of the criteria for performing leak-before-break analyses. These requirements are restated in NUREG-0800, SRP 3.6.3 [4]. The details of the discussions are not repeated here; the following summarizes the key elements: 2.1 Criteria for Through-Wall Flaws Acceptance criteria for critical flaws may be stated as follows: I. A critical flaw size shall be determined for normal operating conditions plus safe shutdown earthquake (SSE) loads. Leakage for normal operating conditions must be detectable for this flaw size reduced by a factor of two.

2. A critical flaw size shall be determined for normal operating conditions plus SSE loads multiplied by a factor of i-. Leakage for normal operating conditions must be detectable for this flaw size.

It has been found in previous evaluations conducted by Structural Integrity Associates (SI) that in general, the first criterion bounds the second. However, in this evaluation, both criteria were considered for completeness. Either elastic-plastic fracture mechanics instability analysis or limit load analysis may be used in determining critical flaw sizes. NUREG-0800 SRP 3.6.3 [4] provides a modified limit load procedure that may be used for austenitic piping and weldments. Both approaches have been used in this evaluation as presented in Section 5.0 of the report. SIR-00-045, Rev. 2 2-1 StructuralIntegrity Associates

2.2 Criteria for Part-Through-Wall Flaws NUREG-1061, Vol. 3 [3] requires demonstration that a long part-through-wall flaw which is detectable by ultrasonic means will not grow due to fatigue to a depth which would produce instability over the life of the plant. This is demonstrated in Section 6.0 of this report, where the analysis of subcritical crack growth is discussed. 2.3 Consideration of Piping Restraint Effects It was shown in References 21 that restraint of pressure induced bending in a piping system could affect the LBB analysis results. This has been shown to be especially important for small diameter piping (less than 10 inch NPS). An evaluation was therefore performed in Section 5.3 to address this issue for the small diameter piping at Kewaunee. 2.4 Consideration of Other Mechanisms NUREG-1061, Vol. 3 [3] limits applicability of the leak-before-break approach to those locations where degradation or failure by mechanisms such as water hammer, erosion/corrosion, fatigue, and intergranular stress corrosion cracking (IGSCC) is not a significant possibility. These mechanisms were considered for the affected piping systems, as reported in Section 3 of this report. SIR-00-045, Rev. 2 2-2 StructuralIntegrity Associates

3.0 CONSIDERATION OF WATER HAMMER, CORROSION AND FATIGUE NUREG-1061, Vol. 3 [3] states that LBB should not be applied to high-energy lines susceptible to failure from the effects of water hammer, corrosion or fatigue. These potential failure mechanisms are thus discussed below with regard to the affected RCS attached RHR and SI piping at Kewaunee, and it is concluded that the above failure mechanisms do not invalidate the use of LBB for this piping system. 3.1 Water Hammer A comprehensive study performed in NUREG-0927 [7] indicated that the probability of water hammer occurrence in the residual heat removal systems of a PWR is very low. In NUREG-0927, - only a single event of water hammer was reported for PWR residual heat removal systems with the cause being incorrect valve alignment. There was no indication as to which portion of the system was affected but it would not be that portion adjacent to the RCS-attached piping evaluated for LBB. It was also reported in NUREG-0927 that the safety significance of water hammer events in the safety injection system is moderate. With four water hammer events reported in the SI systems, three of these events were associated with voided lines and the other event was associated with steam bubble collapse. Although there was no indication of the affected portions of the SI system, the portions susceptible to water hammer would not be that adjacent to the RCS-attached piping evaluated for LBB. The portions of the piping evaluated for LBB are inboard of the first isolation valves for the SI and RHR piping. Thus, during normal operation, these lines experience reactor coolant pressure and temperature conditions such that there is no potential for steam/water mixtures that might lead to water hammer. The portions of these systems that are adjacent to the reactor coolant piping are not in use during normal operation. The RHR system is not used except during low-pressure low-temperature cooldown conditions. The SI system is used only during loss of coolant-accident (LOCA) conditions. During normal plant operation, the portions of the system beyond the first SIR-00-045, Rev. 2 3-1 6 StructuralIntegrityAssociates

isolation valve are expected to run at low temperature conditions. Thus, there should never be any voiding or potential for steam bubble collapse, which could result in water hammer loads on the piping attached directly to the RCS considered in this evaluation. To date, there has been no experience related to water hammer events in either the RHR or SI systems at Kewaunee. As such, this phenomenon will have no impact on the LBB analysis for the affected portions of the safety injection and residual heat removal systems at Kewaunee. 3.2 Corrosion Two corrosion damage mechanisms which can lead to rapid piping failure are intergranular stress corrosion cracking (IGSCC) in austenitic stainless steel pipes and flow-assisted corrosion (FAC) in carbon steel pipes. IGSCC has principally been an issue in austenitic stainless steel piping in boiling water reactors [8] resulting from a combination of tensile stresses, susceptible material and oxygenated environment. IGSCC is not typically a problem for the primary loop of a PWR such as the SI and RHR systems under consideration since the environment has relatively low concentrations of oxygen. FAC is not anticipated to be a problem for this system since it is fabricated from stainless steel piping which is not susceptible to FAC. 3.3 Fatigue Metal fatigue in piping systems connected to the reactor coolant loops of Westinghouse-designed pressurized water reactor was identified in Bulletin 88-08 [9]. Evaluations performed by Wisconsin Public Service Corporation and submitted to the Nuclear Regulatory Commission have concluded that this does not apply to Kewaunee. For the SI piping, there is no interconnection to the charging pumps that will lead to inleakage leading to cracking such was identified at Farley and Tihange. For the RHR piping, any outleakage at the isolation valve leak off lines is monitored and can be corrected such that cracking similar to that identified at the Japanese Genkai plant will not occur. Thus, there is no potential for unidentified high cycle fatigue. SIR-00-045, Rev. 2 3-2

                                                                              !    Structural Integrity Associates

Known fatigue loadings and the resultant possible crack growth have been considered by the analyses reported in Section 6.0 of this report. Based on the results presented in Section 6.0, it is concluded that fatigue will not be a significant issue for the SI and RHR piping at Kewaunee. SIR-00-045, Rev. 2 3-3 V StructuralIntegrity Associates

4.0 PIPING MATERIALS AND STRESSES 4.1 Piping System Description The piping systems considered in this evaluation have been described in Section 1.1. Schematics of the mathematical models for these lines including selected nodal points are shown in Figures 4-1 through 4-3. The lines are fabricated from Schedule 140 and 160 stainless steel piping. From Reference 10, the RCS operating pressure is 2235 psig while the operating temperature for the cold leg is 550'F. Because of the similarities of Kewaunee and Prairie Island Units 1 and 2, the hot leg temperature was assumed to be 607.4F, the maximum hot leg temperature reported for Prairie Island Units 1 and 2 [1]. Wisconsin Public Service Corporation plans to replace the existing Model 51 steam generators at Kewaunee with Model 54F generators in the Fall of 2001. The new operating temperatures after the replacement are listed in Table 4-1 [111. It can be seen that in all cases, the hot leg temperature (Tho) and the cold leg temperature (To1d) are bounded by the temperatures used in the LBB evaluations (607.4°F and 550°F, respectively). Hence, from an operating temperature viewpoint, the LBB evaluation performed herein bounds the conditions after the replacement. 4.2 Material Properties The material properties of interest for fracture mechanics and leakage calculations are the Modulus of Elasticity (E), the yield stress (Sy), the ultimate stress (S.), the Ramberg-Osgood parameters for describing the stress strain curve (a and n), the fracture toughness (Jic) and power law coefficient for describing the material J Resistance curve (C and N). NUREG- 1061, Vol. 3 requires that actual plant specific material properties including stress-strain curves and J-R material properties be used in the LBB evaluations. In lieu of this requirement, material properties associated with the least favorable material and welding processes from industry wide generic material sources have been used to provide a conservative assessment of critical flaw sizes and leakage rates. SIR-00-045, Rev. 2 4-1 StructuralIntegrityAssociates

The piping material is A-376, Type 316 stainless steel [10]. The piping was fabricated using gas tungsten arc welding (GTAW) process for the root, and filled using the shielded metal arc welding (SMAW) process. The worst properties of GTAW and SMAW weldments have been used in the evaluation. Several studies have shown that of these three materials, the SMAW weldment, because of its low toughness and susceptibility to thermal aging, has the most conservative properties for estimation of critical flaw sizes. Hence, properties of SMAW have been conservatively used in this evaluation. The conservative stress-strain properties for the SMAW weldments at 550¶F in Reference 13, which formed the basis for the flaw acceptance criteria in ASME Section XI, were used for the evaluation. However, for the J-R curve properties, the values provided in Reference 13 for SMAW weldments were compared with the lower bound curve provided in NUREG-6428 [14] for thermally aged welds at 550'F. It was found that the lower bound curve in NUREG-6428 is more conservative and therefore was used in this evaluation. The material properties at the hot leg temperature of 607.40 F were determined by adjusting the properties at 550'F by the ratio of the values in ASME Code Section III. The Ramberg-Osgood parameters were determined at 650'F as presented in Appendix A of this report and the values at 607.40 F were then interpolated from the values at 550°F and 650'F. The fracture toughness is not expected to change significantly from 550'F to 607.4°F and therefore the J-R curve from Reference 14 was also assumed at 607.4°F. The properties used for the SMAW weldments are shown in Table 4-2. 4.3 Piping Moments and Stresses The piping moments and stresses considered in the LBB evaluation are due to pressure (P), dead weight (DW), thermal expansion (TE) and safe shutdown earthquake inertia (SSE) consistent with the guidance provided in NUREG-1061, Vol. 3. Per the guidance provided in NUREG-1061, other secondary stresses such as residual stresses and through-wall thermal stresses were not included in the evaluation. Piping analysis was provided in Reference 10 and included moments for the nozzles, elbows and pipe-to-valve welds for all components. Summaries of the piping moments are shown in Tables SIR-00-045, Rev. 2 4-2 U StructuralIntegrity Associates

4-3 through 4-5, respectively. For calculation of critical flaw size, the moment and stress combination of pressure, dead weight, thermal expansion and SSE loads is used with a factor of unity and factor of j2i. Forleakage calculations, the moment and stress combination of pressure, deadweight and thermal expansion loads is used. These basic moment load combinations are shown in Tables 4-3 through 4-5 for the various nodal locations. Stresses were calculated directly from the piping analysis moments for the various lines considered in this evaluation [10]. The resulting stresses used in the fracture mechanics analysis do not include the 3 effects of stress indices. 3 The axial stress due to normal operating pressure is calculated from the expression: I 3 " D= 3 2 -D2 where p is the internal pressure, D. is the outside diameter of the pipe and Di is the inside I diameter. The bending stress due to dead weight, thermal expansion and SSE is calculated from the bending moments using the expression:

                                                 =M2+M2 +M2 z

where: Z = the section modulus and, 3 M., MY, MK = the three orthogonal moments. 3 Axial loads due to dead weight, thermal expansion, and seismic were not directly available from the piping stress analysis and therefore were not considered in the evaluation. The stresses due 3 to axial loads are not significant compared to those from pressure loads, so their exclusion does not significantly affect the results of this evaluation. Additional analysis presented in Reference 3 33 confirms that consideration of axial loads would not have changed the conclusions reached in I this report (see Appendix C). SIR-00-045, Rev. 2 4-3 3

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Table 4-1 RCS Operating Temperature for Kewaunee After Replacement with Model 54F Steam Generators I Temperature Case i Description ( 0F) 1 2 3 4 590.8 590.8 606.8 606.8 3 THot Tcold 521.9 521.9 539.2 539.2 556.3 556.3 573.0 573.0 U TAverage TSG Outlet 521.6 521.6 538.9 538.9 Tcore Outlet 595.5 595.5 611.3 611.3 I TAverage (zero load) 547 547 547 547 U i I I I I I I I SIR-00-045, Rev. 2 4-4 W, StructuralIntegrity Associates

Table 4-2 Lower Bound SMAW Material Properties Used in the LBB Evaluation [13, 14] Parameter Value Temp ("F) 550 607.4 (Cold Leg) (Hot Leg) E (ksi) 25 x 10' 24.72 x 103 Sy = 0o (ksi) 49.4 48.137 Su (ksi) 61.4 61.4 Sf= 0.5 (Sy + S,) (ksi) 55.4 54.77 Ramberg-Osgood Parameter a 9.0 9.130 Ramberg-Osgood Parameter n 9.8 9.636 Jic (in-k/in 2) 0.288 0.288 J-R Curve Parameter C1 (in-k/in 2) 3.816 3.816 J-R Curve Parameter N 0.643 0.643 Jmax (in-k/in 2) 2.345 2.345 SIR-00-045, Rev. 2 4-5 C Structural IntegrityAssociates

Table 4-3 Moments for the 6-inch Safety Injection Piping Attached to Cold Leg DW + TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs M" My M" SRSS 1 ) Mý M, Mý SRSS0' 275a 536 54 1032 1164 700 98 1378 1549 275b 332 202 1289 1346 534 306 1713 1820 277 332 202 1289 1346 534 306 1713 1820 280 232 252 1336 1379 436 382 1758 1851 560a -752 -124 -729 1055 -816 -152 -811 1160 560b -553 -34 -922 1076 -649 -76 -1022 1213 563 -553 -34 -922 1076- -649 -76 -1022 1213 565 -455 -4 -967 1069 -559 -50 -1067 1206 (1) SRSS= M +M +M, SIR-00-045, Rev. 2 4-6 4V StructuralIntegrity Associates

Table 4-4 Moments for the 12-inch Safety Injection Piping Attached to Cold Leg DW + TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs Mx My Mz SRSS1 ) M,, M M, SRSS0' 110 -30844 11183 -50110 59895 -31422 12893 -51140 61391 112 -25922 17896 -58699 66617 -26436 19764 -59499 68041 115 -18949 27207 -70874 78246 -19427 29713 -71370 79712 119 -17883 28595 -72736 80175 -18363 31231 -73190 81666 120a -17884 28593 -72733 80172 -18364 31229 -73187 81663 120b -5501 36923 -77583 86097 -6917 40411 -77801 87943 125 -5501 36923 -77583 86097 -6917 4041,1 -77801 87943 310 52212 -28479 31924 67500 52874 -29519 32636 68791 315a 52216 -28482 31924 67505 52878 -29522 32636 68795 315b 61105 -37049 21756 74698 61971 -38065 22498 76128 320 61105 -37049 21756 74698 61971 -38065 22498 76128 330 59193 -37049 19179 72417 60347 -38065 19957 74088 (1) SRSS = M + M+M2 SIR-00-045, Rev. 2 4-7 V StructuralIntegrity Associates

Table 4-5 Moment for the 8-inch Residual Heat Removal Piping Attached to Hot Leg DW + TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs M" M M, SRSS1 ) M" M M, SRSS() 10 7466 -3125 4903 9463 11032 -8211 7167 15508 15 5457 -2169 3947 7075 8427 -6821 5875 12331 20a 5457 -2169 3947 7075 8427 -6821 5875 12331 20b 5188 -1989 3512 6573 8030 -6561 5308 11649 25 5188 -1989 3512 6573 8030 -6561 5308 11649 30a 5188 -1989 3512 6573 8030 -6561 5308 11649 30b 3852 -1623 3821 5663 6372 -5829 5273 10119 35 3852 -1623 3821 5663 6372 -5829 5273 10119 40 -3055 -296 7572 8170 -4687 -3204 8370 10114 45 -11098 1031 11938 16332 -12778 2781 12484 18079 50a -11098 1031 11938 16332 -12778 2781 12484 18079 50b -13157 1397 12640 18298 -14739 2951 13196 20002 55 -13157 1397 12640 18298 -14739 2951 13196 20002 955 -10606 1397 8313 13548 -11194 2951 9633 15060 960 -8054 1397 3985 9094 -8964 2951 4863 10617 1960 -7184 1397 2509 7737 -8166 2951 4417 9742 75 -6825 1397 1901 7221 -7891 2951 4305 9461 60 -6792 1397 1843 7175 -7866 2951 4295 9436 875a -6792 1397 1843 7175 -7866 2951 4295 9436 875b -5327 1031 631 5462 -6577 2241 3661 7854 80 -5327 1031 631 5462 -6577 2241 3661 7854 85 -4014 605 -130 4061 -5328 1505 -3216 6403 90 -2461 178 -924 2635 -4347 1316 -5090 6822 95 1072 -248 -2842 3048 3016 -2464 -7016 8024 (1) SRSS== M +M +M SIR-00-045, Rev. 2 4-8 StructuralIntegrity Associates

Table 4-5 Moment for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Continued) DW + TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs M_____M j My M. SRSSO') M. M Mz SRSS(1 ) 330 -2334 -378 -2254 3267 -5058 -954 -3778 6385 335 -5335 -1149 -983 5545 -7057 -1501 -1995 7486 8340a -5335 -1149 -983 5545 -7057 -1501 -1995 7486 8340b -7810 -1809 1112 8094 -9086 -2039 1926 9509 345 -7810 -1809 1112 8094 -9086 -2039 1926 9509 340 -7830 -1809 1311 8142 -9054 -2039 2117 9519 348 -8129 -1809 4293 9369 -9155 -2039 5467 10856 351 -8529 -1809 8268 12016 -9961 -2039 9870 14170 355 -9091 -1809 13868 16681 -10241 -2039 15196 18438 360 -9202 -1809 14961 17657 -10400 -2039 16371 19502 365 -9203 -1809 14978 17672 -10403 -2039 16390 19520 8365a -9203 -1809 14978 17672 -10403 -2039 16390 19520 8365b -7047 -1330 13334 15140 -7935 -1530 14326 16448 370 -7047 -1330 13334 15140 -7935 -1530 14326 16448 375 -1806 -147 7624 7836 -2852 -731 8276 8784 380 3019 1036 2355 3967 5231 2292 4353 7181 385a 3019 1036 2355 3967 5231 2292 4353 7181 385b 4772 1516 1151 5138 7580 3050 3717 8976 390 4772 1516 1151 5138 7580 3050 3717 8976 395a 4772 1516 1151 5138 7580 3050 3717 8976 395b 5470 1749 1717 5994 8574 3355 4287 10156 400 5470 1749 1717 5994 8574 3355 4287 10156 405 9433 3096 3064 10390 14039 5122 5698 15994 (1) SRSS M2 +M2 +M2 SIR-00-045, Rev. 2 4-9 StructuralIntegrity Associates

COLD 563/560B LEG LOOP A 280 COLD 277/275B LEG 275A 99309r0 LOOP B Figure 4-1. Schematic of Piping Model and Selected Node Points for the 6-inch Safety Injection Piping Attached to the Cold Leg (Loops A and B) SIR-00-045, Rev. 2 4-10 V StructuralIntegrity Associates

120A/119 110 125/120B r LOOP A COLD LEG 31 5A/31 0 320/315B 330 LOOP B COLD LEG 99312r0 Figure 4-2. Schematic of Piping Model and Selected Node Points for the 12-inch Safety Injection Piping Attached to the Cold Leg (Loops A and B) SIR-00-045, Rev. 2 4-11

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10 15/20A 1 20B/25/30A 45/50A 30B/35 LOOP A 60/875A HOT f0 4001395B 395A/390/3858 380/385A 8365A/365 LOOP B 34518340B 99307r0 Figure 4-3. Schematic of Piping Model and Selected Node Points for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Loops A and B) SIR-00-045, Rev. 2 4-12

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5.0 LEAK-BEFORE-BREAK EVALUATION The LBB approach involves the determination of critical flaw sizes and leakage through flaws. The critical flaw length for a through-wall flaw is that length for which, under a given set of applied stresses, the flaw would become marginally unstable. Similarly, the critical stress is that stress at which a given flaw size becomes marginally unstable. NUREG-1061, Vol. 3 [3] defines required margins of safety on both flaw length and applied stress. Both of these criteria have been examined in this evaluation. Circumferential flaws are more restrictive than postulated axial flaws because the critical flaw sizes for axial flaw are very long since they are affected by only pressure stress and result in large crack opening areas due to out of plane displacements. For this reason, the evaluation presented herein will be based on assumed circumferential flaws. 5.1 Evaluation of Critical Flaw Sizes Critical flaw sizes may be determined using either limit load/net section collapse criterion (NSCC) approach or J-Integral/Tearing Modulus (J/T) methodology. In this evaluation, both methods were used to determine the critical flaw sizes and the most conservative result of the two methods was chosen for a given location. 5.1.1 CriticalFlawSizes DeterminedBy J-Integral/TearingModulus Analysis A fracture mechanics analysis for determining the stability of through-wall circumferential flaws in cylindrical geometries such as pipes using the J/T approach is presented in References 15 and 16. This procedure was used for the determination of critical stresses and flaw sizes in the safety injection and RHR lines at Kewaunee, using computer program, pc-CRACKTM [17] which has been verified under SI's Quality Assurance program. The expression for the J-integral for a through-wall circumferential crack under tension loading [15] which is applied in this analysis is: SIR-00-045, Rev. 2 5-1 StructuralIntegrity Associates

J =f1' (a. R)pa

                                             +        _.~ )sc~~h,(. , n,-j[K R)[ P -]n+l                  (5-1) where "f.(a,,R) =aF(bR  4    tR)t                                 (5-2) t    47tR 2 t 2                                (-2 ae              -         effective crack length including small scale yielding correction R               =         nominal pipe radius t               =         pipe wall thickness F                         elasticity factor [ 15, 16]

P applied load = a. (2itRt); where a, is the remote tension stress in the uncracked section ac = Ramberg-Osgood material coefficient E elastic modulus Go = yield stress

                        -        yield strain 2a              =         total crack length 2b                        2nrR c               -         b-a hi               =        plasticity factor [15, 16]

PO = limit load corresponding to a perfectly plastic material n = Ramberg-Osgood strain hardening exponent. Similarly, the expression for the J-integral for a through-wall crack under bending loading [16] is given by: SIR-00-045, Rev. 2 5-2 Structural IntegrityAssociates

                                =a   ,jL+aca~sc.            ji+/-n.j~                                (5-3)

The parameters in the above equations are the same as the tension loading case except M = applied moment = a. (r RWt) a= remote bending stress in the uncracked section I = moment of inertia of the uncracked cylinder about the neutral axis M= limit moment for a cracked pipe under pure bending corresponding to n = co (elastic-perfectly plastic case) M'MCos -{Sin(r)] (5-4) Mo = limit moment of the uncracked cylinder = 4a0 RNt The Tearing Modulus (T) is defined by the expression: dW E T=-da --arf (5-5) Hence, in calculating T, J from the above expressions is determined as a function of crack size (a) and the slope of the J versus crack size (a) curve is calculated in order to determine T. (The flow stress, Uf, is taken as the mean of the yield and ultimate tensile strengths.) The material resistance J-R curve can also be transformed into J-T space in the same manner. The intersection of the applied and the material J-T curves is the point at which instability occurs and the crack size associated with this instability point is the critical crack size. The piping stresses consist of both tension and bending stresses. The tension stress is due to internal pressure while the bending stress is caused by deadweight, thermal and seismic loads. Because a fracture mechanics model for combined tension and bending loads is not readily available, an alternate analysis is performed to determine the critical, flaw length under such loading condition SIR-00-045, Rev. 2 5-3

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using the tension and bending models separately. For the first case, the stress combination is assumed to be entirely due to tension and the critical flaw length is determined using the tension model. For the second case, the stress combination is assumed to be entirely due to bending and the critical flaw length is determined as such. The half critical flaw sizes (lengths) obtained with the tension model (at) and the bending model (ab) are combined to determine the actual half critical flaw size (ac) due to a combined tension and bending stress using linear interpolation, as described by the following equation:

a. = at -- + ab (5-6) 0 b + 't 0

                                                               *b + at Where at and 0 bare the piping tensile and bending stresses respectively.

The critical flaw sizes are determined as a function of applied moment for constant pressure stress and are presented in Tables 5-1 through 5-4. This was done so that the relationship between stress and critical flaw size can be used on a generic basis for both Kewaunee and Prairie Island. In these tables, the critical flaw length is the minimum value determined by two approaches as required by NUREG-1061, Vol. 3. In the first approach, the half critical flaw length is determined with a factor of unity on the normal + SSE stress combination. The leakage flaw total length in this case (t 1) is equal to the half critical flaw length (a,). In the second approach, critical flaw length is determined with a factor of F2 on the normal + SSE stresses. The leakage flaw length in this case (e2) is the total flaw length (2a,). The final leakage flaw length is the minimum of f l and f 2 . It was determined that the leakage flaw size based on a factor of unity on the stresses was controlling for all cases and as such are the values shown in Tables 5-1 through 5-4. The fracture mechanics models used in the determination of the critical flaw sizes (lengths) are limited to flaw sizes of half the circumference of the pipe. For cases where the piping moments/stresses are relatively low, the critical flaw sizes are much greater than half the circumference of the pipe. As can be seen in Tables 5-1 through 5-4 and also Figures 5-2 through 5-5, an extrapolation scheme was used to determine the critical flaw sizes. In order to check the SIR-00-045, Rev. 2 5-4 V StructuralIntegrity Associates

validity of the extrapolation, the critical flaw sizes were also determined by limit load analysis (to be discussed in the next section) and compared to the J/T analysis results. As shown in Figures 5-2 through 5-5, the trending of the extrapolated J/T analysis results and the limit load results is very similar, demonstrating that the extrapolation method used for the J/T analysis is reasonable. Nevertheless, both the J/T analysis and limit load analysis results are presented in this evaluation. 5.1.2 CriticalFlaw Sizes Determined by Limit Load Analysis The methodology provided in NUREG-0800 [4] for calculation of critical flaw sizes by net section collapse (NSC-limit load) analysis was used to determine the critical flaw sizes. This methodology involves constructing a master curve where a stress index, SI, given by SI = S-MPm (5-7) is plotted as a function of postulated total circumferential through-wall flaw length, L, defined by L = 2 0R (5-8) where. S 7r f [2 sin3 -sin 0] (5-9) S= 0.5 [(it -0) - i (Pro/or)I, (5-10) 0 = half angle in radians of the postulated throughwall circumferential flaw, R = pipe mean radius, that is, the average between the inner and outer radius, Pm = the combined membrane stress, including pressure, deadweight, and seismic components, M = the margin associated with the load combination method (that is, absolute or algebraic sum) selected for the analysis. Since the moments were added algebraically, a value of 1.4 recommended in Reference 4 was used. SIR-00-045, Rev. 2 5-5 V StructuralIntegrityAssociates

of = flow stress for austenitic steel pipe material categories. The value of 51 ksi recommended in Reference 4 was used in this caste. If 0 + P3from Eqs. (5-9) and (5-10) is greater than 7t, then S ýyf[i I (5-11) 71 where 13 = - 7C(Pm../Ff ) (5-12) The critical flaw sizes correspond to the value of 0 that result is S being greater than zero from Eqs. 5-9 and 5-11. The value of SI used to enter the master curve for base metal and TIG welds is SI = M (Pro + Pb) (5-13) where Pb the combined primary bending stress, including deadweight and seismic components The value of SI used to enter the master curve for SMAW and SAW is SI = M (Pm + Pb + P) Z (5-14) where SIR-00-045, Rev. 2 5-6 StructuralIntegrityAssociates

PC = combined thermal expansion stress at normal operation, Z = 1.15 [1.0 + 0.013 (OD-4)] for SMAW, (5-15) Z = 1.30 [1.0 + 0.010 (OD-4)] for SAW, (5-16) OD = pipe outer diameter in inches. Since the loads were combined algebraically, a second evaluation was conducted with M = 1. For this case, the leakage size was determined as one half the flaw size based on the master curve. The smaller of the leakage size flaws determined from the M = 1 and M = 1.4 evaluations is the required leakage size flaw based on the limit load analysis. In this evaluation, the SMAW parameters are used since the piping was welded using this method. The critical flaw sizes were calculated as a function of moments and presented for the various piping lines in Tables 5-5 through 5-8. These results are applicable to both Kewaunee and Prairie Island. 5.2 Leak Rate Determination The determination of leak rate is performed using the EPRI program, PICEP [18]. The flow rate equations in PICEP are based on Henry's homogeneous nonequlibrium critical flow model [19]. The program accounts for nonequlibrium "flashing" mass transfer between liquid and vapor phases, fluid friction due to surface roughness and convergent flow paths. In the determination of leak rates using PICEP, the following assumptions are made: - A plastic zone correction is included. This is consistent with fracture mechanics principles for ductile materials. The crack is assumed to be elliptical in shape. This is the most common approach that is available in PICEP for calculations of leakage.

-       Crack roughness is taken as 0.000197 inches [20].
-       There are no turning losses assumed since the crack is assumed to be initiated by some mechanism other than IGSCC.

SIR-00-045, Rev. 2 5-7 StructuralIntegrityAssociates

A sharp-edged entrance loss factor of 0.61 is used (PICEP default). The default friction factors of PICEP are utilized. The stress combination used includes pressure, dead weight and thermal expansion stresses. The leakage was calculated for an operating pressure of 2235 psig and a temperature of 550°F or 607.4 0 F as appropriate using location-unique moments and material properties. For each location, the leakage flaw size was determined based on the information provided in Tables 5-1 through 5-4 for EPFM analysis and also Table 5-5 through 5-8 for net section collapse analysis using the actual moments at each location. The leakage was then determined using the normal operating moment at each location. Tables 5-9 through 5-12 show the predicted leakage for the leakage flaw length for each location. In all cases, the leakage for cracks determined with net section collapse analyses was less than the leakage for cracks determined using ,f/Tanalysis. The leakage associated with net section collapse analyses is therefore conservatively used in the LBB evaluation. 5.3 Effect of Piping Restraint on LBB Evaluation In NUREG/CR-6443 [2 11, a study was performed which showed that restraint of pressure induced bending in a piping system has an effect on LBB analysis results. This was shown to be especially important for small diameter piping such as those being considered for Kewaunee and Prairie Island. In this section, an evaluation is performed to assess the impact of the piping restraint on the LBB evaluation. Recall that the above determination of critical flaw sizes and leakage rates assumes that the pipe is free to displace. With a crack in an unrestraint pipe, there is localized bending of the pipe concentrated in the crack region. This results in a "kink angle" which can be described as a change in direction of the straight pipe due to the presence of the crack. However, all the piping systems considered in this LBB evaluation are restrained to varying degrees. The opening of the crack and the resulting localized kink angle is resisted by the piping restraints, resulting in a bending moment at the crack location that is in the opposite direction of the kink angle. The presence of the restraint in a flawed piping has two effects. SIR-00-045, Rev. 2 5-8 C StructuralIntegrity Associates

1) There is a restraint of pressure induced bending for a crack in the piping system. If the pipe is free to displace, a bending moment is developed for a pipe under axial load (resulting from pressure) which is equal to the load times eccentricity (distance from center of the crack plane to the center of the pipe). In a restrained piping system, this induced bending can be restrained resulting in an increased load capacity for the flawed piping (i.e., the critical flaw size increases).

2) The restraint of the bending moment decreases the crack opening displacement and hence reduces the leakage that would have otherwise been calculated.

The effect of these two factors is what effectively introduces a bending moment in the piping system which is in opposite direction to that of the thermal restraint bending moment. This is illustrated in Figure 5-6. The uncracked pipe is shown in 5-6 (a). In 5-6 (b), the piping is shown with a crack that creates the local slope discontinuities. Here, it is assumed that there is no constraint and the piping freely displaces. In 5-6 (c), the restraint is added, causing a crack-closing moment to occur. In LBB evaluation, the effects of restraint increasing critical flaw sizes and reducing leakage have compensating effects. However, the exact contribution of each factor cannot be easily quantified in order to determine if the results of the LBB evaluations presented above will be affected. As such, an evaluation is performed using some of the representative piping systems at Kewaunee and Prairie Island to determine the affect of restraint on the LBB evaluation results. Hence, this evaluation is applicable to both Kewaunee and Prairie Island. To select the lines to use in this analysis, a set of simple criteria was adopted.

1) Compare the similarity of the geometrical configurations of the lines

2) Use thermal anchor stresses as a measure of overall piping system restraint and select the piping lines with the highest thermal stresses at the anchor locations.

SIR-00-045, Rev. 2 5-9

• StructuralIntegrityAssociates

Based on the criteria above, it was concluded that all six 8-inch RHR lines are similar enough in geometry that the line with the highest thermal anchor stresses (Prairie Island Unit 1, Loop A) can be conservatively used to represent all the RHR lines. Similar conclusions were reached for the 6-inch SI lines attached to the cold leg, and hence, the Kewaunee, Loop B line was used. The 6-inch draindown line in Prairie Island Unit 2 was used for the evaluation. The evaluation consists of first modeling the piping lines and then applying a kink angle at all weld locations from the LBB analyses. This process resulted in applied moments at each location that could be used in assessing leakage rate reduction. The three selected piping lines were modeled as PIPE16 elements using the ANSYS computer code [22]. All three models were bounded by two anchors, one of them being the connection to the RCS system. The other was placed at a significant distance away from welds of interest. The piping models used in the analysis are shown in Figures 5-7 through 5-9. The kink angle was determined using the methodology in NUREG/CR-4572 [23], and is given by:

                               - .E   blb(

0 e)+StIt( 0 e)l+a(Sb +S n (5-17) where: af = flow stress a 0.5(,+cay) = Average of ultimate and yield strength of the material, ksi E = Young's modulus in ksi, Sb = b/f = normalized bending stress, St= Ct/f = normalized tensile stress, lb and It are compliance functions given in Appendix B of Reference 23, OC = effective half-crack angle corrected for plastic zone size, in radians, described below, a ' = C(CFV*o)'1 ax and n are Ramberg-Osgood parameters, described below. SIR-00-045, Rev. 2 5-10

• StructuralIntegrity Associates

The plastic stress-strain behavior is represented in the Ramberg-Osgood form (Eq. 2.18 in [231), a 7, (5-18) co ao Lao) 0 0\0 where: a = crb-t, Cr0 = reference stress used in determining the Ramberg-Osgood constants, usually ay, C0 ao0]E, ax and n are material parameters obtained from curve-fitting to tensile test results. The effective half-crack angle (0) corrected for plastic zone size is (Eq. 2.8 in [23]): K2 0e R 2 +0o (5-19) where: 00 = a/R = original crack size, a = circumferential crack length, R = mean radius of the pipe, K = stress intensity factor (Eq. 2.2 in [28]), i.e.,

                                     =      ROO(atFt (0O) +abFb(Oo)                             (5-20)

Ft = geometry factor for tension (See Appendix A of Reference 23), Fb = geometry factor for bending (See Appendix A of Reference 23), [p = 2, for plane stress condition, parameter in Irwin plastic zone correction (Eq. 2.4 in [23]) SIR-00-045, Rev. 2 5-11

• StructuralIntegrityAssociates

The kink angle was applied individually at all weld locations from the LBB analysis on the piping lines considered in the analysis. At each weld location, the kink angle is applied in four different directions (0', 450, 900, and 1350) simulating different possible locations of a crack at that location. The resulting moments due to the introduction of the kink angles at the various weld locations on the various lines is summarized in Tables 5-13 through 5-15. These moments act in the opposite direction to the thermal restraint moments and were therefore subtracted from the moments used in calculating the leakage rate. The resulting leakage rates for the three lines considered in this analysis are shown in Tables 5-16 through 5-18. In comparing these results to the corresponding ones without the restraint, it can be seen that the effect of the restraint did not change the leakage rate significantly for the 6-inch piping. However, the leakage for the 8-inch pipe was reduced by approximately 13%. This is a conservative estimate of leakage reduction since no credit was taken for the effects of restraint on increasing the critical flaw sizes. These results are consistent with the conclusions in a similar study in Reference 27. 5.4 LBB Evaluation Results and Discussions It can be seen from Tables 5-9 through 5-16 that the limiting leakage is obtained from the limit load evaluation. Without the consideration of piping restraint effect, the predicted leakage ranges for all the lines considered in this evaluation are summarized below. 6-inch Safety Injection Lines Attached to Cold Leg 5.189- 5.289 gpm 8-inch RHR Lines Attached to Hot Leg 7.480 - 11.276 gpm 12-inch Safety Injection Lines Attached to Cold Leg 30.128 - 31.126 gpm 6-inch Hot Leg Capped Nozzles 3.740 gpm The piping restraint has no significant impact on the predicted leakages for the 6-inch safety injection and draindown lines. At the worst location, piping restraint produced about 13% reduction of the leak rate on the 8-inch RHR line. The minimum leakage is 7.480 gpm SIR-00-045, Rev. 2 5-12 r StructuralIntegrity Associates

associated with the 8-inch RHR piping without the consideration of the piping restraint effect. If this effect is taken into account, it is expected that the leakage would reduce to 6.51 gpm. The minimum leakage for all the systems considered in the evaluation is 3.74 gpm associated with the 6-inch hot leg nozzles. This is well above the required leak detection of 2.5 gpm for Kewaunee as discussed in Section 1.3 of this report thereby justifying LBB for all the piping considered in this evaluation. 5.5 Effect of Revised Piping Moments It is not uncommon in nuclear power plants that piping stress analysis must be revised to assess inoperable pipe supports, new loads, etc. Analysis was performed to determine the relationship between NOP and NOP+SSE moments that would result in the minimum 3.74 gpm leakage rate [35]. Choosing this leakage rate retains margin above the 2.5 gpm required minimum leakage rate consistent with the plant leakage detection capability and is consistent with the NRC acceptance of the report [34]. The allowable combination of moments for all piping systems considered in this report are presented in tabular and graphical form in Reference 35. SIR-00-045, Rev. 2 5-13 V StructuralIntegrity Associates

Table 5-1 Leakage Flaw Size Versus Stress Determined by J/T Analysis for 6-inch Safety Injection Lines Attached to RCS Cold Leg (Temperature = 550'F) Leakage Flaw Total Stress, Bending Stress, Tension Stress, Bending Moment, Size** (a), CT, ksi ab, ksi crt, ksi in-kips inches 3.55 0.00 3.55 0.0 2.81* 3.83 0.28 3.55 5.0 2.79* 4.11 0.56 3.55 10.0 2.77* 5.24 1.69 3.55 30.0 2.69* 6.36 2.81 3.55 50.0 2.60* 7.48 3.93 3.55 70.0 2.52* 8.60 5.05 3.55 90.0 2.44* 9.17 5.62 3.55 100.0 2.40* 9.73 6.18 3.55 110.0 2.36* 10.29 6.74 3.55 120.0 2.32* 10.85 7.30 3.55 130.0 2.27* 11.0 7.45 3.55 132.7 2.26* 12.0 8.45 3.55 150.5 2.19 13.0 9.45 3.55 168.3 2.12 14.0 10.45 3.55 186.1 2.04

• Linearly extrapolated values
  • Leakage flaw size (a) is one half the total flaw length.

SIR-00-045, Rev. 2 5-14 StructuralIntegrity Associates

Table 5-2 Leakage Flaw Size Versus Stress Determined by J/T Analysis for 12-inch Safety Injection Lines Attached to RCS Cold Leg (Temperature = 550°F) Leakage Flaw Total Stress, Bending Stress, Tension Stress, Bending Moment, Size** (a),

   .aT, ksi            ab, ksi              at, ksi      J      in-kips           inches 3.82               0.00                 3.82                  0.00            5.39*

4.23 0.41 3.82 50.00 5.32* 4.63 0.82 3.82 100.00 5.26* 5.45 1.63 3.82 200.00 5.t4* 6.27 2.45 3.82 300.00 5.02* 7.08 3.26 3.82 400.00 4.90* 7.90 4.08 3.82 500.00 4.78* 8.71 4.90 3.82 600.00 4.66* 9.53 5.71 3.82 700.00 4.54* 10.35 6.53 3.82 800.00 4.42* 11.00 7.18 3.82 880.00 4.32* 12.00 8.18 3.82 1002.54 4.18 13.00 9.18 3.82 1125.07 4.03 14.00 10.18 3.82 1247.60 3.89 14.50 10.68 3.82 1308.86 3.82

• Linearly extrapolated values

 ** Leakage flaw size (a) is one half the total flaw length.

SIR-00-045, Rev. 2 5-15 StructuralIntegrity Associates

Table 5-3 Leakage Flaw Size Versus Stress Determined by J/T Analysis for 8-inch RHR Lines Attached to RCS Hot Leg (Temperature = 607.4°F) Leakage Flaw Total Stress, Bending Stress, Tension Stress, Bending Moment, Size** (a), I T, ksi [ rb, ksi at, ksi in-kips inches 4.32 0.00 4.32 0.00 3.63* 5.02 0.70 4.32 25.00 3.56* 5.72 1.40 4.32 50.00 3.*49* 6.14 1.82 4.32 65.00 3.44* 6.50 2.18 4.32 77.81 3.40* 8.00 3.68 4.32 131.28 3.25* 9.00 4.68 4.32 166.93 3.14* 10.00 5.68 4.32 202.57 3.04*. 11.00 6.68 4.32 238.22 2.93 11.50 7.18 4.32 256.04 2.88 12.00 7.68 4.32 273.8,7 2.83 12.50 8.18 4.32 291.69 2.78 14.00 9.68 4.32 345.16 2.63 15.00 10.68 4.32 380.80 2.54 16.50 12.18 4.32 434.27 2.41 17.50 13.18 4.32 469.92 2.32 18.00 13.68 4.32 487.74 2.28

• Linearly extrapolated values

 ** Leakage flaw size (a) is one half the total flaw length.

SIR-00-045, Rev. 2 5-16 V StructuralIntegrity Associates

Table 5-4 Leakage Flaw Size Versus Stress Determined by J/T Analysis for 6-inch Draindown Lines and Nozzles Attached to RCS Hot Leg (Temperature = 607.4°F) (Applicable Only to Prairie Island Units I and 2) Leakage Flaw Total Stress, Bending Stress, Tension Stress, Bending Moment, Size** (a), ET, ksi Ob, ksi Ct, ksi in-kips inches 3.55 0.00 3.55 0.0 2.89* 3.83 0.28 3.55 5.0 2.87* 4.11 0.56 3.55 10.0 2.85* 5.24 1.69 3.55 30.0 2.75* 6.36 2.81 3.55 50.0 2.65* 7.48 3.93 3.55, 70.0 2.56* 8.60 5.05 3.55 90.0 2.46* 9.17 5.62 3.55 100.0 2.41* 9.73 6.18 3.55 110.0 2.36* 10.29 6.74 3.55 120.0 2.31

• 10.85 7.30 3.55 130.0 2.27*

11.00 7.45 3.55 132.7 2.25 12.00 8.45 3.55 150.5 2.17 13.00 9.45 3.55 168.3 2.09

• Linearly extrapolated values.
  • Leakage flaw size (a) is one half the total flaw length.

SIR-00-045, Rev. 2 5-17 V StructuralIntegrity Associates

Table 5-5 Leakage Flaw Size Versus Stress Determined by Limit Load for 6-inch Safety Injection Lines Attached to RCS Cold Leg (Temperature = 550 0F) Moment, in-kips LLeakage Flaw Size* (a), inches 0 2.710 18.6 2.619 37.2 2.534 55.8 2.452 74.5 2.377 93.1 2.304 111.7 2.236 130.3 2.170 148.9 2.106 167.5 2.044 186.1 1.986

• Leakage flaw size (a) is one half the total flaw length.

SIR-00-045, Rev. 2 5-18 StructuralIntegrityAssociates

Table 5-6 Leakage Flaw Size Versus Stress Determined by Limit Load for 12-inch Safety Injection Lines Attached to RCS Cold Leg (Temperature = 5500F) Moment, in-kips Leakage Flaw Size* (a), inches 0.0 5.111 130.9 4.926 261.8 4.753 392.7 4.594 523.5 4.440 654.4 4.295 785.3 4.157 916.2 4.023 1047.1 3.895 1178.0 3.770 1308.9 3.650

• Leakage flaw size (a) is one half the total flaw length.

SIR-00-045, Rev. 2 5-19

2. StructuraiIntegrityAssociates

Table 5-7 Leakage Flaw Size Versus Stress Determined by Limit Load for 8-inch RHR Lines Attached to RCS Hot Leg (Temperature = 607.4°F) Moment, in-kips Leakage Flaw Size* (a), inches 0.0 3.414 47.4 3.274 94.8 3.143 142.2 3.020 189.6 2.903 237.0 2.795 284.4 2.689 331.8 2.588 379.2 2.491 426.6 2.396 474.0 2.306

• Leakage flaw size (a) is one half the total flaw length.

SIR-00-045, Rev. 2 5-20 V StructuralIntegrity Associates

Table 5-8 Leakage Flaw Size Versus Stress Determined by Limit Load for 6-inch Draindown Lines and Nozzles Attached to RCS Hot Leg (Temperature 607.4°F) (Applicable Only to Prairie Island Units I and 2) Moment, in-kips Leakage Flaw Size* (a), inches 0 2.710 16.8 2.628 33.7 2.549 50.5 2.475 67.3 2.406 84.1 2.339 100.9 2.275 117.8 2.214 134.6 2.155 151.4 2.098 168.2 2.042

• Leakage flaw size (a) is one half the total flaw length.

SIR-00-045, Rev. 2 5-21 C Structural IntegrityAssociates

Table 5-9 Predicted Leakage Rates for 6-inch Safety Injection lines Attached to RCS Cold Leg Moments EPFM Results Net Section Collapse Results Node Leakage Leakage NOP NOP+SSE Flaw Size* Leakage Flaw Size* Leakage in-kips in-kips (a), inches Rate, gpm (a), inches Rate, gpm 275a 13.97 18.59 2.735 6.293 2.619 5.189 275b 16.15 21.84 2.722 6.374 2.604 5.251 277 16.15 21.84 2.722 6.374 2.604 5.251 280 16.55 22.21 2.720 6.397 2.603 5.270 560a 12.66 13.92 2.754 6.354 2.642 5.289 560b 12.91 14.56 2.751 6.353 2.639 5.282 563 12.91 14.56 2.751 6.353 2.639 5.282 565 12.83 14.47 2.752 6.348 2.639 5.278

• Leakage flaw size (a) is one half the total flaw length.

I,ý SIR-00-045, Rev. 2 5-22 C StructuralIntegrity Associates

Table 5-10 Predicted Leakage Rates for 12-inch Safety Injection Lines Attached to RCS Cold Leg Moments EPFM Results Net Section Collapse Results Node Leakage Leakage NOP NOP+SSE Flaw Size* Leakage Flaw Size* Leakage in-kips in-kips (a), inches Rate, gpm (a), inches Rate, gpm 110 718.74 736.69 4.496 38.116 4.208 30.128 112 799.40 816.49 4.400 38.238 4.125 30.498 115 938.95 956.54 4.231 38.173 3.984 31.062 119 962.10 979.99 4.202 38.066 3.961 31.126 120a 962.06 979.96 4.202 38.066 3.961 31.126 120b 1033.16 1055.32 4.112 37.615 3.887 31.106 125 1033.16 1055.32 4.112 37.615 3.887 31.106 310 810.00 825.49 4.389 38.314 4.116 30.599 315a 810.06 825.54 4.389 38.315 4.116 30.599 315b 896.38 913.54 4.283 38.272 4.026 30.888 320 896.38 913.54 4.283 38.272 4.026 30.888 330 869.00 889.06 4.312 38.160 4.051 30.736

• Leakage flaw size (a) is one half the total flaw length.

SIR-00-045, Rev. 2 5-23 IV StructuralIntegrity Associates

Table 5-11 Predicted Leakage Rates for 8-inch RHR Lines Attached to RCS Hot Leg Moments EPFM Results Net Section Collapse Results Leakage Leakage Node NOP NOP+SSE Flaw Size* Leakage Flaw Size* Leakage in-kips in-kips (a), inches Rate, gpm (a), inches Rate, gpm 10 113.56 186.10 3.085 10.643 2.912 8.576 15 84.90 147.97 3.196 10.622, 3.006 8.400 20a 84.90 147.97 3.196 10.622 3.006 8.400 20b 78.88 139.79 3.220 10.597 3.026 8.346 25 78.88 139.79 3.220 10.597 3.026 8.346 30a 78.88 139.79 3.220 10.597 3.026 8.346 30b 67.96 121.43 3.274 10.685 3.074 8.355 35 67.96 121.43 3.274 10.685 3.074 8.355 40 98.04 121.37 3.274 12.442 3.074 9.776 45 195.98 216.95 2.995 13.355 2.841 11.071 50a 195.98 216.95 2.995 13.355 2.841 11.071 50b 219.58 240.02 2.927 13.359 2.788 11.276 55 219.58 240.02 2.927 13.359 2.788 11.276 955 162.58 180.72 3.101 13.370 2.925 10.817 960 109.13 127.40 3.256 12.801 3.058 10.103 1960 92.84 116.90 3.287 12.339 3.086 9.667 75 86.65 113.53 3.297 12.119 3.094 9.471 60 86.10 113.23 3.298 12.099 3.095 9.453 875a 86.10 113.23 3.298 12.099 3.095 9.453 875b 65.54 94.25 3.354 11.622 3.145 8.973 80 65.54 94.25 3.354 11.622 3.145 8.973 85 48.73 76.84 3.405 11.195 3.193 8.649 90 31.62 81.86 3.390 9.933 3.179 7.637 95, 36.58 96.29 3.348 9.747 3.139 7.480 SIR-00-045, Rev. 2 5-24 C StructuralIntegrityAssociates

Table 5-11 Predicted Leakage Rates for 8-inch RHR Lines Attached to RCS Hot Leg (Continued) Moments EPFM Results Net Section Collapse Results Node Leakage Leakage NOP NOP+SSE Flaw Size* Leakage Flaw Size* Leakage in-kips in-kips (a), inches Rate, gpm (a), inches Rate, gpm 330 39.20 76.62 3.405 10.591 3.193 8.165 335 66.54 89.83 3.367 11.861 3.157 9.170 8340a 66.54 89.83 3.367 11.861 3.157 9.170 8340b 97.13 114.11 3.295 12.719 3.093 9.958 345 97.13 114.11 3.295 12.719 3.093 9.958 340 97.70 114.23 3.295 12.748 3.093 9.982 348 112.43 130.27 3.248 12.851 3.051 10.161 351 144.19 170.04 3.132 12.871 2.951 10.372-355 200.17 221.26 2.982 13.357 2.831 11.107 360 211.88 234.02 2.944 13.297 2.802 11.162 365 212.06 234.24 2.944 13.295 2.801 11.162 8365a 212.06 234.24 2.944 13.295 2.801 11.162 8365b 181.68 197.38 3.052 13.555 2.885 11.077 370 181.68 197.38 3.052 13.555 2.885 11.077 375 94.03 105.41 3.321 12.926 3.116 10.075 380 47.60 86.17 3.377 10.778 3.167 8.306 385a 47.60 86.17 3.377 10.778 3.167 8.306 385b 61.66 107.71 3.314 10.852 3.110 8.418 390 61.66 107.71 3.314 10.852 3.110 8.418 395a 61.66 107.71 3.314 10.852 3.110 8.418 395b 71.93 121.87 3.273 10.899 3.073 8.530 400 71.93 121.87 3.273 10.899 3.073 8.530 405 124.68 191.93 3.068 10.972 2.898 8.877

• Leakage flaw size (a) is one half the total flaw length.

SIR-00-045, Rev. 2 5-25

                                                                       !V     StructuralIntegrityAssociates

Table 5-12 Predicted Leakage Rates for 6-inch Nozzles Attached to RCS Hot Legs Moments EPFM Results Net Section Collapse Results Leakage Leakage NOP NOP+SSE Flaw Size* Leakage Flaw Size* Leakage Node in-kips in-kips (a), inches Rate, gpm (a), inches Rate, gpm N/A 0 1 0 2.894 5.073 [ 2.710 3.740

• Leakage flaw size (a) is one half the total flaw length.

SIR-00-045, Rev. 2 5-26 C StructuralIntegrity Associates

Table 5-13 Moments Due to Kink Angle Restraint Effects for 6-inch Safety Injection Line Attached to RCS Cold Leg Crack M M Limiting Load Node Orientation (Degrees) [in-kips) My-ips [in-kips] [in-kips[i-is[i-is [i-i] Reduction nki]Moment 280 0 -0.019 -0.565 -0.157 0.587 0.587 45 -0.068 -0.492 0.230 0.547 90 -0.078 -0.105 0.157 0.204 135 -0.042 -0.178 -0.230 0.294 275B 0 -0.011 -0.516 -0.141 0.535 0.535 45 -0.048 -0.447 0.21.0 0.496 90 -0.057 -0.096 0.141 0.180 135 -0.033 -0.164 -0.210 0.269 275A 0 -0.057 -0.478 0.046 0.484 0.487 45 -0.107 -0.392 0.040 0.408 90 -0.094 -0.398 -0.046 0.412 135 -0.026 -0.484 -0.040 0.487 Note: Based on Kewaunee Loop B line. SIR-00-045, Rev, 2 5-27 StructuralIntegrity Associates

Table 5-14 Moments Due to Kink Angle Restraint Effects for 6-inch Draindown Line Attached to RCS Hot Leg Crack M" MY M. SRSS Limiting Load Node Orientation in-kps] [in-kips] [in-kips) jin-kips] Reduction Moment (Degrees) = [ [in-kips] 7 0 0.46 -0.34 -0.06 0.57 0.57 45 0.34 -0.26 0.14 0.45 90 0.03 -0.06 0.06 0.09 135 -0.31 -0.14 -0.14 0.36 10 0 0.34 -0.26 -0.05 0.43 0.43 45 0.26 -0.21 0.10 0.34 90 0.02 -0.06 0.05 0.08 135 -0.23 -0.11 -0.10 0.27 Note: Based on Prairie Island Unit 2 line. SIR-00-045, Rev. 2 5-28 VStructural Integrity Associates

Table 5-15 Moments Due to Kink Angle Restraint Effects for 8-inch RHR Lines Attached to RCS Hot Leg Limiting Crack Load Reduction Orientation M- MY M, SRSS Moment Node (Degrees) [in-kps] [in-kips] [in-kips] [in-kips] [in.kips] 2000 0 8.02 -34.58 4.32 35.77 35.77 45 2.93 -20.83 9.43 23.05 90 -3.85 -15.72 -4.32 16.76 _135 -8.41 -29.48 -9.43 32.08 2010A 0 6.33 -23.46 3.84 24.59 24.59 45 1.86 -14.34 5.28 15.38 90 -3.69 -12.93 -3.84 13.97 135 -7.08 -22.05 -5.28 23.73 2010B 0 1.64 -21.86 7.17 23.05 24.91 45 3.34 -10.12 4.53 11.59 90 3.07 -12.77 -7.17 14.96 135 1.03 -24.47 -4.53 24.91 2020B 0 0.07 -19.21 0.00 19.21 19.21 45 -1.81 -12.07 7.14 14.15 90 -2.66 -4.97 0.00 5.62 135 -1.94 -12.07 -7.14 14.16 2040A 0 -0.15 -16.57 0.25 16.58 16.58 45 0.10 -10.09 6.22 11.87 90 0.28 -4.12 -0.25 4.14 135 0.30 -10.59 -6.22 12.29 2040B 0 -0.20 -20.16 -0.20 20.16 20.16 45 -0.59 -13.97 6.39 15.37 90 -0.63 -7.38 0.20 7.40 135 -0.32 -13.57 -6.39 15.00 SIR-00-045, Rev. 2 5-29

• StructuralIntegrity Associates

Table 5-15 Moments Due to Kink Angle Restraint Effects for 8-inch RHR Lines Attached to RCS Hot Leg (Continued) Limiting Crack Load Reduction Orientation M" MY M, SRSS Moment Node (Degrees) [in-kips] [in-kips] [in-kips] [in-kips] [in-kips] 2070A 0 0.50 -4.75 1.79 5.08 7.03 45 1.18 -3.46 -0.50 3.68 90 1.21 -5.71 -1.79 6.10 135 0.50 -7.00 0.50 7.03 1 2070B 0 1.61 -4.13 0.39 4.45 4.45 45 1.89 -2.91 0.84 3.56 90 1.05 -2.49 -0.39 2.71 135 -0.42 -3.71 -0.84 3.81 1 Note: Based on Prairie Island Unit I Loop A line. SIR-00-045, Rev. 2 5-30 U Structural Integrity Associates

Table 5-16 Leakage Flaw Size and Leakages for 6-inch Safety Injection Line Attached to RCS Cold Leg Considering Restraint Effect Leakage Results without Restraint Effects Leakage Results with Restraint Effects EPFM Limit Load EPFM Limit Load Node Leakage Leakage Leakage Leakage Leakage Flaw Flow Flaw Flow Flaw Flow Flaw Flow Size (a)* Rate Size (a)* Rate Size (a)* Rate Size (a)* Rate (in) (gpm) (in) (gpm) (in) (gpm) (in) (gpm) 280 2.720 6.397 2.603 5.270 2.720 6.340 2.603 5.221 275B 2.722 6.374 2.604 5.251 2.722 6.321 2.604 5.206 275A 2.735 6.293 2.619 5.189 2.735 6.245 2.619 5.148

• Leakage flaw size (a) is one half the total flaw length.

Note: Based on evaluating Kewaunee Loop B line. SIR-00-045, Rev. 2 5-31 V StiructuralIntegrity Associates

Table 5-17 Leakage Flaw Size and Leak Rates for 8-inch RHR Line Attached to RCS Hot Leg Considering Restraint Effects Leakage Results without Restraint Effects Leakage Results with Restraint, Effects EPFM Limit Load EPFM Limit Load Node Leakage Leakage Leakage Leakage Leakage Flaw Flow Flaw Flow Flaw Flow Flaw Flow Size (a)* Rate Size (a)* Rate Size (a)* Rate Size (a)* Rate (in) (in) in) (gpm) (,i) (gpm) (in) 200 2.983 12.963 2.832 10.770 2.983 11.316 2.832 9.378 2010A 2.118 13.178 2.940 10.640 3.118 11.884 2.940 9.571 2010B 3.133 13.306 2.953 10.730 3.133 11.975 2.953 9.631 2020B 3.208 13.037 3.016 10.345 3.208 11.959 3.016 9.466 2040A 2.940 12.742 2.798 10.940 2.940 11.980 2.798 10.051 2040B 2.844 12.791 2.725 11.066 2.844 11.955 2.725 10.334 2070A 3.200 8.866 3.009 6.963 3.200 8.491 3.009 6.659 2070B 3.205 9.153 3.013 7.189 3.205 8.911 3.013 6.992

• Leakage flaw size (a) is one half the total flaw length.

Note: Based on Prairie Island Loop A line.

                                                                                            .1 SIR-00-045, Rev. 2                                5-32

(- StructuralIntegrity Associates

Table 5-18 Leakage Flaw Size and Leak Rates for 6-inch Draindown Line Attached to RCS Hot Leg Considering Restraint Effects Leakage Results without Restraint Effects Leakage Results with Restraint Effects EPFM Limit Load EPFM Limit Load Node Leakage Leakage Leakage Leakage

         . Flaw        Flow        Flaw         Leakage       Flaw      Flow      Flaw        Flow.

Size (a)* Rate Size (a)* Flow Rate Size (a)* Rate Size (a)* Rate (in) (gpm) (in) (gpm) (in) (gpm) (in) (gpm) 7 2.845 5.245 2.661 3.884 2.845 5.195 2.661 3.845 10 2.848 5.264 2.664 3.899 2.848 5.226 2.664 3.869

• Leakage flaw size (a) is one half the total flaw length.

Note: Based on Prairie Island Unit 2 line. SIR-00-045, Rev. 2 5-33 C StructuralIntegrityAssociates

J J INSTABILITY 2J ic dJAT K.. z- MATERIAL da, APPLIED

                                                                         -    WdJ(E da    C S2=

93220d0 Note: Linear extrapolation used to determine Tmanteriai for J values greater than 2 Jic Figure 5-1. J-Integral/Tearing Modulus Concept for Determination of Instability During Ductile Tearing SIR-00-045, Rev. 2 5-34

• StructuralIntegrity Associates

Leakage Flaw Size vs. Moment, 6rinch Sch 160 Pipe Weld 4.5

       .4.0
   .c 3.5 i 3.0 2.5
                                      ---   - -=   -    -    -----                    t Ca
    ,IL.

a 2.0 6m 1,5

                                                                                -.-      N.S.C. Results 1.0                                                                         -- EPFM Results
                                                                                       ...Extrapolated EPFM 0.5 0.0               _______________I          ___________                                 T.1 0.0   20.0    40.0          60.0        80.0          100.0 12 0.0     140.0       160.0     180.0 Moment (NOP+SSE), in-kips Note: Leakage flaw size (a) is one half the total flaw length.

Figure 5-2. Leakage Flaw Size Versus Moment for 6-inch Schedule 160 Pipe Weld Determined by J/T and Limit Load Analyses SIR-00-045, Rev. 2 5-35 V StructuralIntegrity Associates

Leakage Flaw Size vs. Moment, 6-Inch Sch 160 NozzlelOraindown Weld r r r 7 I 1 I 3.0

                ," - .D . ....
                                               ----------a 2.5 12.0 0

u. 1.5 0

      *, 1.0                                                                             __-.----  -NSC      Results
                                                                                            ---        EPFM Results 0.5                                                                             [   .... 0--- Extrapolated  EPFM 0.0
             .0.0              20.0        40.0            60.0        80.0      100.0     120.0         140.0         160.0 Moment l%OP+SSE), In-kips Note: Leakage flaw size (a) is one half the total flaw length.

Figure 5-3. Leakage Flaw Size Versus Moment for 6-inch Schedule 160 Nozzle/ Draindown Weld Determined by J/T and Limit Load Analyses SIR-00-045, Rev. 2 5-36 U StructuralIntegrity Associates

Leakage Flaw Size vs. Moment. 8-Inch Sch 140 Pipe Weld U 03

      - 1_ _   I

_0 ----- I, 0 N In U- -.-- I N.S.C. Results 61 m 1.o 3, 4l . .. -u EPF.M Results U 63 I

• xtrpolaesjEPFM

 -J                      9.0~~7-                                                                             1_____   7___

_ _D -_ _ __ 20.0 40.0 6D.D 00.0 I6D.0 120.0 140.6 160.0 180.0 200.0 M0.a 246.0 20.0 2W.0 Moment (NOP+SSE), in-kips Note: Leakage flaw size (a) is one half the total flaw length. Figure 5-4. Leakage Flaw Size Versus Moment for 8-inch Schedule 140 Pipe Weld Determined by J/T and Limit Load Analyses SIR-00-045, Rev. 2 5-37 V Structural Integrity Associates

Leakage Flaw Size vs. Moment, 12-inch Sch 160 Pipe Weld 6.0 5.0

     *.4.0 S 3=.0 LA
  .*   2.0 1.0 0.0 0.0 100.0 200.0 300.0  400.0   500.0   600.0   700.0   800.0   900.0   1000.0 1100.0 1200.0 1300.0 Moment (NOP+SSE), in-kips Note: Leakage flaw size (a) is one half the total flaw length..

Figure 5-5. Leakage Flaw Size Versus Moment for 12-inch Schedule 160 Pipe Weld Determined by J/T and Limit Load Analyses SIR-00-045, Rev..2 5-38 StructuralIntegrity Associates

Without Crack PIPE RESTRAINT a) Uncracked piping. Kink angle due to crack & applied loads PIPING REMOVED b) Cracked pipe without restraint. Kink angle due to crack & applied loads 10 A K" Moment induced due to restraint PIPE RESTRAINT 00034r0 c) Cracked pipe with restraint. Figure 5-6. Depiction of Restraint Effect on Cracked Piping SIR-00-045, Rev. 2 5-39 StructuralIntegrity Associates

N Note: For evaluation of restraint, piping evaluated between Node 2000 and an assumed anchor located at Node 2160. I Figure 5-7. Schematic of Piping Layout Used to Determine the Effect of Restraint on LBB Evaluation (8-inch RHR Line - Prairie Island Unit 1, Loop A) I SIR-00-045, Rev. 2 5-40 I C StructuralIntegrityAssociates

COLD LEG LOOP B W'X 2. REEL Note: For evaluation of restraint, piping evaluated between Node 280 and an assumed anchor located at Node 200. Figure 5-8. Schematic of Piping Layout Used to Determine the Effect of Restraint on LBB Evaluation (6-inch Safety Injection Line - Kewaunee, Loop B) SIR-00-045, Rev. 2 5-41

• StructuralIntegrity Associates

20 60 is is g$ 79 IsI0

                                                                                *,4b RO-1o LOO 1Os W*01- 71 1S7 Wb~All -13                                                        - 601 275~

Its

826 2Z0 St$

no0 255, 20X 4CDAWN 771/K Note: For evaluation of restraint, piping evaluated between Node 5 and an assumed anchor located at Node 150. Figure 5-9. Schematic of Piping Layout Used to Determine the Effect of Restraint on LBB Evaluation (6-inch Draindown Line - Prairie Island Unit 2) SIR-00-045, Rev. 2 5-42 StructuralIntegrity Associates

6.0 EVALUATION OF FATIGUE CRACK GROWTH OF SURFACE FLAWS In accordance with the NRC criteria [3] set forth in Section 2 of this report, the growth of postulated surface cracks by fatigue is evaluated to demonstrate that such growth is insignificant for the plant life, when initial flaw sizes meeting ASME Code Section XI IWB-3514 acceptance standards [24] are postulated. The crack growth analysis is performed for the locations with the maximum stresses. The evaluation is performed using bounding stresses from Prairie Island Units 1 and 2 and Kewaunee such that it is applicable to all three units. 6.1 Plant Transients Since Kewaunee RCS attached piping lines were designed to the requirements of ANSI B3 1.1, no specific line unique transients exist in the design basis. Hence, transient information specific only to this LBB evaluation is developed to perform the crack growth evaluation. The transients used in the evaluation consist of those specified in the Plant Technical Specification and additional transients specific to the operation of these systems. The plant transients used in this evaluation are presented in Table 6-1. These are consistent with those in the Plant Technical Specification except that the number of heatup/cooldown cycles was modified from 200 to 250 to account for future potential license renewal. The pressure change due to normal fluctuations is assumed for those events with no significant pressure change defined. Table 6-2 shows the additional thermal transients assumed for the systems. Inadvertent safety injections and accumulator blowdown transients are not evaluated, since these transients have never occurred at Kewaunee and hence are considered as very unlikely events. There are no local piping system transients for the 6-inch hot leg nozzles. For crack growth analysis, the design basis transients are combined into load set pairs to give the largest pressure and temperature ranges. The combined transients and the associated number of cycles are shown in Table 6-3 for the hot leg and Table 6-4 for the cold leg. They are in order of decreasing AT except for the test events. For purposes of this analysis, the test events in Table 6-1 and the Table 6-2 transients are treated as standalone events and not combined with the normal system transients. SIR-00-045, Rev. 2 6-1 StructuralIntegrity Associates

6.2 Stresses for Crack Growth Evaluation The axial stresses due to pressure and thermal loads are calculated as described below. For pressure loads, P, the axial stress is calculated as: 2 UP=P_ Di Do 2 -D 2 where Do is the outside diameter and Di is the inside diameter of the pipe. 0 Bending stress is given by b = D0 (M)/2I, where M = bending moment I = moment of inertia 4 4)

                                           = (-r/64)*(D0 -Di For thermal expansion moments, the maximum operating thermal moments (Mmu                ) from Section 4, are scaled by the ratio of the transient temperature range (AT) to the operating temperature range (AToper):

Mt Mmax oper (AT/ATop), where ATopa is based on the temperatures at which the thermal expansion moments were calculated. ATo0p = 607.4 - 70 = 537.4F for the hot leg and 552 - 70 = 482°F for the cold leg. Table 6-5 gives the bounding non-scaled moments, based on the Section 4 tables. The operating conditions used for this evaluation have been presented in Section 4.1. Non-cyclic stresses were also considered as they affect crack growth rate. The dead weight stresses are computed.from the dead weight moments presented in Table 6-5. In addition, weld SIR-00-045, Rev. 2 6-2

• StructuralIntegrity Associates

residual stresses are considered in the evaluation. The weld residual stress is conservatively represented by a pure through-wall bending stress approximately equal to the base metal material yield stress (Sy) at the operating temperature. Thus, for the cold leg, Sy = 19.3 ksi at 550'F was used while for the hot leg, Sy = 18.8 ksi at 607.4 0 F was used. Thermal transient stresses (arr) and thermal stresses associated with material discontinuities (aTO) are also included in this evaluation and are presented in Tables 6-6 and 6-7. The computer program PIPETRAN [25] was used to derive the through-wall thermal transient and discontinuity stresses for the given transients. This program performs two-dimensional axisymmetric transient thermal stress analysis for cylindrical components. This program is maintained under SI's software quality assurance program. The axial pressure, thermal, dead weight and residual stresses were combined to obtain the stress ranges corresponding to each load group. Within a load group, the maximum stresses were used. The resulting stress ranges are shown in Tables 6-8 through 6-10 where the pressure and bending moment stresses are taken as uniform tension across the pipe thickness and the other stresses are considered to have a linear through-wall distribution. 6.3 Model for Stress Intensity Factor The stress intensity factors, K, corresponding to the point of the maximum depth of a semi-elliptical crack are calculated using fracture mechanics solutions presented in Reference 13. The stress intensity factors are determined for a conservative aspect ratio (a/' ) of 0.1. The stress intensity factor for the deepest point on the semi-elliptical flaw from Reference 13 is given as: KI (7)O.'5 *or(a/t)iG] E SIR-00-045, Rev. 2 6-3 Structuralintegrity Associates

where ci are the coefficients of the stress polynomial describing the axial stress (a) variation through the cylinder wall and are defined below. Cr=(Oo + Ul (Z/t) + Cr2 (z/t)2 +U3 (z/t)', z is the distance measured from the inner surface of the cylinder wall and t is the cylinder wall thickness. The G are the influence coefficients associated with the coefficients of the stress polynomial oj and are expressed by the following general form: Gi =Alai +A 2 ai2 + A3 Xiz3 + A 4 tiz4 +tA5a 1 i 5 + A 6 cti(R/t-5) c=i- (a/t)/(a/c)Y The values of A1 through A 6 and m are provided in Reference 13 for each Gi. The constant R is the mean radius of the cylinder. The parameters 2c and a are the flaw length measured at the cylinder inner surface and flaw depth at the deepest point of the flaw, respectively. 6.4 Fatigue Crack Growth Analysis and Results Fatigue crack growth analysis requires the use of appropriate fatigue crack growth law for the stainless steel piping. Per the recommendation of ASME Code, Section XI Task Group for Piping Flaw Evaluation [26], the fatigue crack growth law for stainless steel is given as: da d= CES (AK , )n dN where n equals 3.3, C = 2 x I0-'9 (in/cycle) (psi/Jik), and E is the environmental factor, equal to 2 for the PWR water environment. S is a scaling parameter to account for the R ratio (Kmiu/Kmax), and is given by: SIR-00-045, Rev. 2 6-4

• StructuralIntegrity Associates

S = (1.o - 0.5-R3) The R ratio was calculated for each Km, and Kmin for each location. The stresses are cycled between maximum and the minimum stress conditions shown in Tables 6-2 through 6-4. For each location, the actual K values for the fatigue crack growth are calculated based on the stresses. The initial flaw size is linearly interpolated based on the allowable flaw sizes for various thicknesses from Table IWB-3514-2, Inservice Examination, surface crack, for a crack with aspect ratio a/l = 0.15. However, for the crack growth analysis, an aspect ratio of 0.1 has been conservatively used. The crack depths used as input are presented in Table 6-11. The results of the fatigue crack growth analysis are presented in Table 6-12. The results show that for the 6-inch cold leg safety injection piping, crack growth is very minimal. After 250 heatup/cooldown cycles, the crack depth is significantly below the ASME Section XI Code allowables. It should be noted that the results for the 6-inch cold leg safety injection piping can be conservatively applied to the 6-inch capped nozzle on the hot leg since only pressure stresses exist at the capped nozzle. However, for the 12" Sch 160 SI Accumulator line, it takes 38 heatup/cooldowns at the worst location to reach the allowable flaw size. For the 8" Sch 140 RHR Suction line, it takes 123 heatup/cooldowns at the most critical location to reach the allowable flaw size. The relatively few number of cycles for the 8-inch RIHR and 12" safety injection accumulator piping can be attributed to the RHR transients listed in Table 6-2. For the last ten years, Kewaunee has experienced 13 heatup/cooldown cycles which are significantly less than the minimum allowable number of 38 calculated at the most critical location. Given that the piping is inspected in accordance with ASME Section XI requirements in each 10-year interval, it is believed that the potential for crack growth can be managed by the current in-service inspection program at Kewaunee. SIR-00-045, Rev. 2 6-5 StructuralIntegrity Associates

In reference 35, alternate maximum TE, DW, and OBEmoments, that are significantly greater than those evaluated herein, were shown to reduce the allowable number of heatup/cooldown cycles to 30. This does not alter the conclusion that inservice inspection is adequate to manage crack growth. Table 6-1 Plant Design Transients Used for LBB Evaluations Hot Leg oldL PM., PM,, Event Cycles T...., OF T.,, OF AT, OF T.j., OF T..., OF AT, OF psig psig AP, psi Plant HeatuplCooldown (HU/CD) 250 70 547 477 70 547 477 0 2235 2235 Plant Loading/Unloading 18,300 547 596 49 532.2 547 14.8 2135 2335 200 10% Step Load Decrease 2,000 585 601 16 531.2 547.2 16 2135 2335 200 10% Step Load Increase 2,000 591 606 15 517.2 533.2 16 2135, 2335 200 Large Step Decrease 200 516 602 86 522.2 546.2 24 2135 2335 200 Loss of Load 80 536 624 88 536.2 572.2 36 2135 2335 200 Loss of Power 40 576 616 40 530.2 542.2 12 2135 2335 200 Loss of Flow 80 486 602 116 489.2 532.2 43 1855 2235 380 eactor Trip from Full Power 400 520 596 76 522.2 535.2 13 2135 2235 2235 Turbine Roll Test 10 480 547 67 480 547 67 1935 2235 300 Primary Side Hydro Test 5 120 120 0 120 120 0 0 3105 3105 Primary Side Leak Test 50 120 547 427 120 547 427 0 2485 2485 Operating Basis Earthquake (+/-) 200 ______I_ I SIR-00-045, Rev. 2 6-6 StructuralIntegrity Associates

Table 6-2 Additional System Transients Used Specifically for LBB Evaluations Piping Transient [Cycles ITmin, OF[T.,,, 'F AT, OF 6" Cold Leg SI High Head Safety Injection 10 32 560 528 12" SI Accumulator RHR Operation at Cooldown 250 100 400 300 12" SI Accumulator Refueling Floodup 120 50 150 100 8" RHR Suction RHR Initiation (away from RC nozzle) 250 100 400 300 SIR-00-045, Rev. 2 6-7 U StructuralIntegrity Associates

Table 6-3 Combined Transients for Crack Growth, Hot Leg od tP Tmin, Tmax,q. Pin, Pmax,' AP, No. __Cycles Load Set Pair 1 F °F IAT, OF psig Ipsig psi 1 CD & HU/Loss of Load/OBE 20 70 624 554 0 2335 2335 2 CD &HU/Loss of Load 60 70 624 554 0 2335 2335 3 CD &HU/Loss of Power 40 70 616 546 0 2335 2335 4 CD & HU/10% Load Increase 130 70 606 536 0 2335 2335 5 TR Test& 10% Load Increase 10 480 606 126 1935 2335 400 6 Loss of Flow& 10% LoadlIncrease 80 486 606 120 1855 2235 380 7 StepDeer. & 10% Load Increase 200 516 606 90 2135 2335 200 8 Rx Trip & 10% Load Increase 400 520 606 -86, 2135 2335 200 9 Unload & Load/10%Load Increase 1180 547 606 59 2135 2335 200 10 Unload& Load/10%Load Decrease 2000 547 601 54 2135 2335 200 11 Loading/Unloading 15120 547 596 49 2135 2335 200 12 Primary SideHydro Test 5 120 120 0 0 3105 3105 13 Primary Side Leak Test 50 120 547 427 0 2485 2485 SIR-00-045, Rev. 2 6-8 StructuralIntegrity Associates

Table 6-4 Combined Transients for Crack Growth, Cold Leg No. Load Set Pair Cycles I .Tmin OF Tmax,

                                                          'IF AT, OFt  Pmin, psig   Pmax, psig    AP, psi 1   CD & HU/Loss of Load/OBE               20       70  572.2 502.2      0    2335    2335 2   CD & HU/Loss of Load                   60       70  572.2 502.2      0    2335    2335 3   CD &HU                                 170      70   547    477      0    2235    2235 4   Turbine Roll Test Range                 10     480   547     67    1935   2335     400 5   FlowLoss& 10% Load Decrease            80    489.2  547.2    58    1855   2335     480 6   10%Load Incr. & 10% Load Der.         1920   517.2  547.2    30    2135   2335     200 7   10% Load Incr & Load/Unload            80    517.2   547   29.8    2135   2335     200 8   Reactor Trip & Load/Unload            400     522.2  547   24.8    2135   2335     200 9   Large Step Decrease & Load/Unload     200     522.2  547   24.8    2135   2335     200 10  Loading/Unloading Range              17620    532.2  547    14.8   2135   2335     200 11  Loss of Power Range                    40     530.2 542.2    12    2135   2335     200 12  Primary Side Hydro Test                 5      120   120     0       0    3105    3105 13  Primary Side Leak Test                 50      120   547    427      0    2485    2485 SIR-00-045, Rev. 2                         6-9
                                                                    !V  StructuralIntegrity Associates

Table 6-5 Bounding Moments TE Moment, ft-lb I DW Moment, ft-lb JOBE Moment, ft-lb Line Plant Node M"'[ MJ I M, M Mý M1 M. M, , 6" Sch 160 Cold Leg Sl Kewaunee 280 750 254 941 -518 -2 395 102 65 211 PI Unit 2 826 -846 49 -252 -4 -2 1 76 11 54 12" Sch 160 SI Accumulator Kewaunee 125 -6207 37869 -76432 706 -946 -1151 708 1744 109 Kewaunee 310 53964 -28733 32398 -1752 254 -474 331 520 356 PI Unit 1 855 - 46008 -11027 -18203 2559 -476 -2946 4894 809 5269 PT Unit 1 910 -34147 -27905 -1668 -1102 -400 -3334 3322 1620 6171 8"Sch 140 RHR Suction PIUnit 1 2000 2967 -4507 16159 -142 -216 -1161 667 1892 396 PI Unit 1 2324 7449 -2958 -4764 -763 278 -2078 2551 425 4261 PIUnit2 246 -1295 -6489 -1932 -825 10 1622 4857 1661 15274 P1Unit2 255A 7466 -8370 32915 51 -6 367 733 1390 1588 PIUnit2 270 7719 3075 5261 1775 -53 -868 445 3167 12240 6" Sch 160 Draindown PI Unit 1 730 -355 81 184 -528 -2 410 117 276 275 SIR-00-045, Rev. 2 6-10 StructuralIntegrity Associates

Table 6-6 Maximum and Minimum Transient and Discontinuity Stress Transition Transient .. Stress, ksi 6" Si Line to CL Nozzle High Head Safety Injection 100.23 6" SI Line to CL Nozzle High Head Safety Injection -67.87 12" SI Line to CL Nozzle RHR Operation at Cooldown 65.09 12" SI Line to CL Nozzle RHR Operation at Cooldown -1.96 12" SI Line to CL Nozzle Inadvertent Accumulator Blowdown 53.45 12" SI Line to CL Nozzle Inadvertent Accumulator Blowdown -59.08 12" SI Line to CL Nozzle Refueling Floodup 20.93 6" SI Line to Valve High Head Safety Injection 124.05 6" SI Line to Valve High Head Safety Injection -99.03 12" SI Line to Valve RHR Operation at Cooldown 69.56 12" SI Line'to Valve RHR Operation at Cooldown -0.50 12" SI Line to Valve Inadvertent Accumulator Blowdown 78.20 12" SI Line to Valve Inadvertent Accumulator Blowdown -82.54 12" SI Line to Valve Refueling Floodup 24.84 8" RHR Line to Valve -RHR Initiation -57.24 SIR-00-045, Rev. 2 6-11 U StructuralIntegrity Associates

Table 6-7 Maximum and Minimum Transient Stress Transition Transient Stress, ksi 6"SI Line to CL Nozzle High Head Safety Injection 96.60 6" SI Line to CL Nozzle High Head Safety Injection -64.80 12" SI Line to CL Nozzle RHR Operation at Cooldown 65.09 12" SI Line to CL Nozzle RHR Operation at Cooldown -2.08 12" SI Line to CL Nozzle Inadvertent Accumulator Blowdown 52.72 12" SI Line to CL Nozzle Inadvertent Accumulator Blowdown -58.36 12" SI Line to CL Nozzle Refueling Floodup 20.82 6" SI Line to Valve High Head Safety Injection 96.28 6" SI Line to Valve High Head Safety Injection -64.66 12" SI Line to Valve RHR Operation at Cooldown 64.85 12" SI Line to Valve RHR Operation at Cooldown -2.05 12" SI Line to Valve Inadvertent Accumulator Blowdown 52.64 12" SI Line to Valve Inadvertent Accumulator Blowdown -58.28 12" SI Line to Valve Refueling Floodup 20.84 8" RHR Line to Valve RHR Initiation -36.13 SIR-00-045, Rev. 2 6-12 C Structural IntegrityAssociates

Table 6-8 Total Constant (a0 ) and Linear (a,) Through-Wall Stresses, 6" Sch 160 Cold Leg SI Stresses (psi) Minimum Maximum Load Set Pair Cycles CFO ao1 0l CD & HU/Loss of Load/OBE 20 19395 -53760 24268 -53760 CD & HU/Loss of Load 60 19397 -53760 24109 -53760 CD & HU 170 19402 -53760 23912 -53760 Turbine Roll Test Range 10 23178 -53760 23928 -53760 Flow Loss & 10% Load Decrease 80 23067 -53760 23928 -53760 10% Load Incr. & 10% Load Deer. 1920 23559 -53760 23928 -53760 10% Load Incr & Load/Unload 80 23559 -53760 23928 -53760 Reactor Trip & Load/Unload 400 23568 -53760 23928 -53760 Large Step Decrease & Load/Unload 200 23568 -53760 23928 -53760 Loading/Unloading Range 17620 23585 -53760 23928 -53760 Loss of Power Range 40 23583 -53760 23921 -53760 Primary Side Hydro Test 5 19746 -53760 24674 -53760 Primary Side Leak Test 50 19488 -53760 24166 -53760 SIR-00-045, Rev. 2 6-13 Structural IntegrityAssociates

Table 6-9 Total Constant (ac) and Linear (crj) Through-Wall Stresses, 12" Sch 160 SI Accumulator Stresses (psi) Minimum Maximum Load Set Pair Cycles __ __ CFO a1 CD & HU/Loss of Load/OBE 20 19134 -29421 30357 -29421 CD & HU/Loss of Load 60 19134 -29421 30337 -29421 CD & HU 170 19134 -29421 29812 -29421 Turbine Roll Test Range 10 28204 -29421 29829 -29421 Flow Loss & 10% Load Decrease 80 28196 -29421 29832 -29421 10% Load Incr. & 10% Load Decr. 1920 29068 -29421 29832 -29421 10% Load Incr & Load/Unload 80 29068 -29421 29829 -29421 Reactor Trip & Load/Unload 400 29139 -29421 29829 -29421 Large Step Decrease & Load/Unload 200 29139 -29421 29829 -29421 Loading/Unloading Range 17620 29279 -29421 29829 -29421 Loss of Power Range 40 29251 -29421 29761 -29421 Primary Side Hydro Test 5 19841 -29421 25145 -29421 Primary Side Leak Test 50 19837 -29421 30085 -29421 Refueling Floodup 80 18855 -29421 49346 -79101 RHR Operation at Cooldown 250 19056 -28421 94359 -168541 SIR-00-045, Rev. 2 6-14 V StructuralIntegrityAssociates

Table 6-10 Total Constant (0o) and Linear (a 1 ) Through-Wall Stresses, 8" Sch 140 RHR Suction Stresses (psi) Minimum Maximum Load Set Pair Cycles CFO 1 ____ _ a1 CD & HU/Loss of LoadiOBE 20 19147 -47537 27393 -47537 CD & HU/Loss of Load 60 19504 -47537 27377 -47537 CD & HU/Loss of Power 40 19504 -47537 27184 -47537 CD & HU/l0% Load Increase 130 23243 -47537 27146 -47537 TR Test & 10% Load Increase 10 25483 -47537 27146 -47537 Loss of Flow & 10% Load Increase 80 26059 -47537 27146 -47537 Step Decr. & 10% Load Increase 200 26235 -47537 27146 -47537 Rx Trip& 10% Load Increase 400 26258 -47537 27146. -47537 Unload & Load/10% Load Increase 1180 26416 -47537 27146 -47537 Unload & Load/l0% Load Decrease 2000 26416 -47537 27118 -47537 Loading/Unloading 15120 26417 -47537 27090 -47537 Primary Side Hydro Test 5 20149 -47537 26146 -47537 Primary Side Leak Test 50 19807 -47537 28299 -47537 RHR Operation at Cooldown 250 -37688 66943.1 22639 -47537 SIR-00-045, Rev. 2 6-15 StructuralIntegrityAssociates

Table 6-11 Initial Crack Depths for Various Locations _ (_n.) aft a (in.) J6" Sch 160 Cold Leg SI 0.718 0.1163 0.0835 12" Sch 160 SIAccumulator 1.312 0.1091 0.1432 8" Sch 140 RHR Suction 0.812 0.1146 0.0930 Table 6-12 Results of Fatigue Crack Growth Analysis Code Calculated Assumed Allowable Heatup/Cooldown Initial Depth Final Depth Depth Cycles to Reach (in.) (in.) (in.) Allowable Depth 6" Sch 160 Cold Leg SI 0.0835 0.0839 0.5385 > 250 12" Sch 160 SI Accumulator 0.1432 0.984 0.984 38 8" Sch 160 RHR Suction 0.0930 0.609 0.609 123 SIR-00-045, Rev. 2 6-16 StructuralIntegrity Associates

7.0

SUMMARY

AND CONCLUSIONS Leak-before-break (LBB) evaluations are performed for the RCS attached piping at Kewaunee Units I in accordance with the requirements of NUREG-1061. The evaluation included portions of the safety injection and the residual heat removal systems. The nominal pipe sizes range from 6 inches to 12 inches. The analysis has been performed using conservative generic material properties for the base metals and weldments and location specific stresses consisting of pressure deadweight, thermal and seismic loads. In the evaluations, circumferential flaws have been considered since they are more limiting than axial flaws. Critical flaw sizes and leakage flaw sizes were calculated on a location specific basis using both elastic-plastic J-Integral/Tearing modulus and limit load analyses. The most limiting critical flaw size at each location from these two analyses methods has been used in the LBB evaluation. The leakage flaw size is defined as the minimum of one half the critical flaw size with a factor of one on the stresses or the full critical flaw size with a factor of -I2 on the stresses. Leakage was then calculated through the leakage flaw size. Because all the piping is of relatively small diameter, the effect of piping restraint was considered in the LBB evaluation. Fatigue crack growth analysis was also performed to determine the extent of growth of any pre-existing flaws. Based on these evaluations, the following conclusions can be made. Without the consideration of piping restraint effect, the predicted leakage range for all the lines considered in this evaluation are summarized below: 6-inch Safety Injection Lines Attached to Cold Leg 5.189 - 5.289 gpm 8-inch RHR Lines Attached to Hot Leg 7.480 - 11.276 gpm 12-inch Safety Injection Lines Attached to Cold Leg 30.128 - 31.126 gpm 6-inch Hot Leg Capped Nozzles 3.740 gpm SIR-00-045, Rev. 2 7-1 StructuralIntegrity Associates

" The piping restraint effects have no significant impact on the predicted leakages for the 6-inch safety injection and 8-inch RHR lines. At the worst location, piping restraint produces about 13% reduction of the leak rate on the 8-inch RHR line.

• The lowest predicted leakage for the safety injection and RHR lines considered in this evaluation is 3.74 gpm (the 6-inch nozzle attached to the RCS hot leg) without consideration of the piping restraint effect. When the restraint effect is considered, the minimum leakage for all the piping systems considered is still 3.74 gpm since piping restraint has no affect on the 6-inch piping.
• Based on the capability of all the available leak detection systems, Kewaunee is capable of detecting leak rates as low as 0.13 gpm. However, for this evaluation a detectable leak rate of 0.25 gpm is assumed based on previous NRC approval for a sister plant. When the NUREG-1061 margin of 10 is applied to this rate, Kewaunee leak detection capability is 2.5 gpm. The minimum predicted leakage of 3.74 gpm is greater than the leak detection at Kewaunee hence justifying leak-before-break for all the systems considered.

Fatigue crack growth of an assumed subsurface flaw of 11% of pipe wall shows that fatigue crack growth can be managed by the current Section XI inservice inspection program at Kewaunee and therefore does not invalidate the application of leak-before-break evaluation of the safety injection and RHR lines under consideration. The effect of degradation mechanisms which could invalidate the LBB evaluations were considered in the evaluation. It was determined that there is no potential for water hammer, intergranular stress corrosion cracking (IGSCC) and erosion-corrosion for portions of the safety injection and RHR systems considered in the LBB evaluations. SIR-00-045, Rev. 2 7-2

• StructuralIntegrityAssociates

8.0 REFERENCES

1. Structural Integrity Associates Report No. SIR-99-147, Rev. 1"Leak-Before-Break Evaluation, 6-inch to 12-inch Safety Injection and Residual Heat Removal Piping Attached to the RCS, Prairie Island Nuclear Generating Station Units 1 and 2," May 2002.

2. Stello, Jr., V., "Final Broad Scope Rule to Modify General Design Criterion 4 of Appendix A, 10 CFR Part 50," NRC SECY-87-213, Rulemaking Issue (Affirmation), August 21, 1987.

3. NUJREG-1061, Volumes 1-5, "Report of the U. S. Nuclear Regulatory Commission Piping Review Committee," prepared by the Piping Review Committee, NRC, April 1985.

4. NUREG-0800, "U.S. Nuclear Regulatory Commission Standard Revision Plan, Office of Nuclear Reactor Regulation, Section 3.6.3, Leak-Before-Break Evaluation Procedure," August 1987.

5. Kewaunee Nuclear Power Plant USAR, Rev. 14, Section 6.5, "Leakage Detection and Provisions for the Primary and Auxiliary Coolant Loops."

6. Letter from G. S. Vissing (USNRC) to R. C. Mecredy (RG&E) including Safety Evaluation Report, "Staff Review of the Submittal by Rochester Gas and Electric Company to Apply Leak-Before-Break Status to Portions of the R. E. Ginna Nuclear Power Plant Residual Heat Removal System Piping (TAC No. MA039)," dated February 25, 1999, Docket No. 50-244.

7. NUREG-0927, "Evaluation of Water Hammer Occurrence in Nuclear Power Plants," Revision 1.

8. W. S. Hazelton and W. H. Koo, "Technical Report on Material Selection and Processing Guidelines for BWR Coolant Pressure Boundary Piping," NUREG-0313, Rev. 2, USNRC, January 1988.

9. U. S. Nuclear Regulatory Commission, Bulletin 88-08, "Thermal Stresses in Piping Connected to Reactor Coolant Systems," June 22, 1998 (Plus Supplements 1, 2 and 3).

10. FLUOR Engineering Inc. Calculations for Wisconsin Public Service Corporation, Kewaunee Nuclear Power Plant, Project No. 834823.

a) Stress Report No. SI-33-007, Analytical Part No. SI-33-007, Rev. 0, "Safety Injection Piping System," December 1988. SIR-00-045, Rev. 2 8-1 W StructuralIntegrity Associates

b) Stress Report No. SI-33-006, Analytical Part No, SI-33-006, Rev. 1, August 1989. c) Stress Report No. SI-33-004, Analytical Part No. SI-33-004, Rev. 3, "Safety Injection System," July 1995. d) Stress Report No. RHR-34-001, Analytical Part No. RHR-34-001, Rev. 1, "Residual Heat Removal Piping System," December 1989. e) Stress Report No. SI-33-003, Analytical Part No. SI-33-003, Rev. OA, May 1989.

11. D.K. Solomon, "Kewaunee (WPS): Category III (for Contract) Approval of PCWG Parameters to Support Uprated Conditions for the RTSRIUprate Program," PCWG-2707, October 25, 2001 (7.4% Power Uprate NSSS Engineering Report, Section 2.0).

12. NSP Document SS-M327, Sheet 52A, "Standard Specification - Mechanical, "Piping Design Tables," Rev. 5-22-72.

13. EPRI Report No. NP-6301-D "Ductile Fracture Handbook," June 1989.

14. Chopra, O.K., "Estimation of Fracture Toughness of Cast Stainless Steels during Thermal Aging in LWR Systems," NUREG/CR-4513, ANL-93/22, Rev. 1.

15. Kumar, V., et al., "An Engineering Approach for Elastic-Plastic Fracture Analysis,"

EPRI NP-1 931, Electric Power Research Institute, Palo Alto, CA, July 1981.

16. Kumar, V., et al., "Advances in Elastic-Plastic Fracture Analysis," EPRI NP-3607, Electric Power Research Institute, Palo Alto, CA, August 1984.

17. Structural Integrity Associates, Inc., "pc-CRACKTm Fracture Mechanics Software,"

Version 3.0 - 3/27/97.

18. EPRI Report NP-3596-SR, "PICEP: Pipe Crack Evaluation Computer Program,"

Rev. 1, July 1987.

19. P.E. Henry, "The two-Phase Critical Discharge of Initially Saturated or Subcooled Liquid," Nuclear Science and Engineering, Vol. 41, 1970.

20. EPRI Report NP-3395, "Calculation of Leak Rates Through Crack in Pipes and Tubes," December 1983.

21. NUREG/CR-6443, BMI-2191, "Deterministic and Probabilistic Evaluation for Uncertainty in Pipe Fracture Parameters in Leak-Before-Break and in Service Flow Evaluations," June 1996.

SIR-00-045, Rev. 2 8-2

• StructuralIntegrity Associates

22. ANSYS LinearPlus/Thermal, Revision 5.5.1, ANSYS, Inc., October 1998.

23. NUREG/CR-4572, BMI-2134, "NRC Leak-Before-Break (LBB.NRC) Analysis Method for Circumferentially Through-Wall Cracked Pipes Under Axial Plus Bending Loads," May 1986.

24. ASME Boiler and Pressure Vessel Code, Section XI, 1989 Edition.

25. PIPETRAN, Version 2.0, Structural Integrity Associates, Inc., 4/8/99;

26. ASME Section XI Task Group for Piping Flaw Evaluation, "Evaluation of Flaws in Austenitic Steel Piping," Journal of Pressure Vessel Technology, Vol. 108, August 1986, pp. 3524366.

27. E. Smith, "The Effect of System Flexibility on the Formulation of a Leak Before Break Case for Cracked 'Piping," Proceedings, ASME Pressure Vessel and Piping Conference, PVP - Vol. 313-1, Codes and Standards, Vol. 1, 1995.

28. M. E. Reddemann (NMC) to U.S. Nuclear Regulatory Commission Document Control Desk, "Request to Exclude Dynamic Effects Associated with Postulated Pipe Ruptures From Licensing Basis For Residual Heat Removal, Accumulator Injection, and Safety Injection System Piping Based Upon Leak Before Break Analysis," February 23,2001.

29. J. G. Lamb (USNRC) to M. Reddemann (NMC), "Kewaunee Nuclear Power Plant - Request For Additional Information Related To Request To Exclude Dynamic Effects Associated With Postulated Pipe Ruptures From Licensing Basis For Residual Heat Removal, Accumulator Injection, and Safety Injection System Piping Based On Leak Before Break Analysis (TAC No. MB 1301)," January 3 1, 2002.

30. M. E. Warner (NMC) to U.S. Nuclear Regulatory Commission Document Control Desk, "Response to NRC Request For Additional Information Concerning Leak Before Break Analysis For Kewaunee Nuclear Power Plant,"

February 28, 2002.

31. J. G. Lamb (USNRC) to M. Warner (NMC), "Kewaunee Nuclear Power Plant -

Request For Additional information Related To Request To Exclude Dynamic Effects Associated With Postulated Pipe Ruptures From Licensing Basis For Residual Heat Removal, Accumulator Injection, and Safety Injection System Piping Based On Leak Before Break Analysis (TAC No. MB1301)," May 23, 2002.

32. M. E. Warner (NMC) to U.S. Nuclear Regulatory Commission Document Control Desk, "Response to NRC Request For Additional Information Concerning Leak Before Break Analysis For Kewaunee Nuclear Power Plant," June 24, 2002.

SIR-00-045, Rev. 2 8-3 Structural IntegrityAssociates

33. A. F.

Deardorff,

et. al. (SI) to Gerald Riste (WPS), "Response to NRC Request for Additional Information, SIR-02-074," June 18, 2002.

34. J. G. Lamb (USNRC) to R. Coutu (NMC), "Kewaunee Nuclear Power Plant-Review of Leak-Before-Break Evaluation for the Residual Heat Removal, Accumulator Injection Line, and Safety Injection System, (TAC No. MB 1301),"

September 5, 2002.

35. Structural Integrity Associates Report No. SIR-02-157, Rev. 0, "Development of Acceptable Moments for LBB Acceptability of 6-inch to 12inch Safety Injection and Residual Heat Removal Piping, Kewaunee and Prairie Island," January 2002.

SIR-00-045, Rev. 2 8-4 StructuralIntegrityAssociates

APPENDIX A DETERMINATION OFRAMBERG-OSGOOD PARAMETERS AT 650 0 F SIR-00-045, Rev. 2 A-0 V StructuralIntegrity Associates

A.1 INTRODUCTION The Ramberg-Osgood stress-strain parameters (a and n) are necessary for elastic-plastic fracture mechanics analysis. These parameters may be a function.of temperature. This section provides the methodology for making adjustment for the Ramberg-Osgood stress-strain parameters at a different temperature when the parametersTor another temperature are known. In this case, the Ramberg-Osgood parameters are derived for at 6501F for given values at 550°F for the Type 316 stainless steel piping SMAW welds at Prairie Island and Kewaunee. A.2 METHODOLOGY The Ramberg-Osgood model is in the form:

                                   -      a   +-+a                                     (1)

C. 13"o -a". Where a and c are the true stress and true strain, cro and cs,are the reference stress and reference strain (in general yield stress and yield strain) and a and n are the so called Ramberg-Osgood (R-O) parameters. When the stress-strain curve at the temperature of interest is available, the R-O parameters can be obtained by curve fitting over the strain range of interest. In the absence of the stress-strain curve of the material, a methodology for determining the R-O parameters based on ASME Code-specified mechanical properties is provided in Reference A-1. The suggested method is described by the following equations: 0.002 a * *(2) SIR-00-045, Rev. 2 A-I

• Structural Integrity Associates

Lt-nOl +e.)-7 S,(I+e,)J cif £nQ+e-)i S,(l+e,,) Ln= n (1 +e)] J (3) where S, and Sy represent ultimate stress and yield stress respectively. They can be obtained from the ASME Code [A-2] for a wide range of temperatures. The yield strain (ey) is determined as: S ey sL E (4) where E (modulus of elasticity) can also be obtained from the ASME Code. The ultimate strain (e.) is not specified at all temperatures in the ASME Code, hence the room temperature elongation value specified in the ASME Code, Section II [A-2] is assumed for all temperatures. The methodology in any case is not sensitive to the choice of eu [A-I] when determining, and n by using equation (2) and (3). It is obvious that a is a function of e., n is a function of a, eu, ey, SD, and S,, and both are the function of temperature. Therefore, an adjustment scheme can be used as follows where the material properties at 650°F are adjusted based on the ratio of piedicted properties from Equations (2) and (3) using Code minimum properties: (aX)650 0 F = (a)BasC, 5OF X Equation(2) 550F, COdeminP.pey (5) Equation(2) 65 0 F,Codemin.property (n)650Tr (n)Bas. 55Q-F x Equation(3) 5 50oF, Code mii.property (6) Equation,(3) 650-F,C~oemin.property SIR-00-045, Rev. 2 A-2

• StructuralIntegrityAssociates

Hence, Equations (2), (3), (4), (5) and (6) can be used to obtain R-O parameters at 650'F from the given values at 550°F. A.3 RESULTS The inputs into the evaluation consist of the R-O parameters provided in Tables 4-1 in the main body of the report and ASME Code properties at 550°F and 650'F. The inputand results of theanalysis which determines the R-O parameters at 650°F are provided in Table A- 1. A.4 REFERENCES A-1. Cofie, N.G., Miessi, G.A., and

Deardorff,

A.F., "Stress-Strain Parameters in Elastic-Plastic Fracture Mechanics," Smirt 10 International Conference, August 14-18, 1989. A-2 ASME Boiler and Pressure Vessel Code, Sections II and III Appendices, 1989 Edition. SIR-00-045, Rev. 2 A-3 V StructuralIntegrityAssociates

Table A-I Determination of Ramberg-Osgood Parameters for SMAW at 650°F a, 550"F 9 n, 550°F 9.8 Temperature (0 F) 550 650 E (ksi) 25550 25050 Sy (ksi) 19.35 18.5 S, (ksi) 67 67 eu (in/in) 0.3 0.3 ey (in/in) 0.0007573 0.0007385 Eo= in (I +ey) 0.0007571 0.0007383

          &,= in (I +e.)                 0.2623643         0.2623643 a'                             2.6408269         2.7081081 nt                             3.2348215         3.1407678 ac                                    9.0              9.227 n                                      9.8             9.515 SIR-00-045, Rev. 2                     A-4 V     StructuralIntegrity Associates

APPENDIX B RESPONSES TO NRC RAI (Reference 32) SIR-00-045, Rev. 2 B-0 V StructuralIntegrity Associates

Docket 50-305 NRC-02-058 June 24, 2002 Page 1 NRC-02-058 June 24, 2002 10CFR50, Appendix A, Criterion 4 U.S. NRC Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555 Ladies/Gentlemen: Docket 50-305 Operating License DPR-43 Kewaunee Nuclear Power Plant RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION CONCERNING LEAK BEFORE BREAK ANALYSIS FOR KEWAUNEE NUCLEAR POWER PLANT References 1) Letter from Mark E. Reddeman (NMC) to Document Control Desk (NRC) dated February 23,2001, "Request to Exclude Dynamic Effects Associated with Postulated Pipe Ruptures From Licensing Basis for Residual Heat Removal, Accumulator Injection, and Safety Injection System Piping Based Upon Leak Before Break Analysis."

2) Letter from John G. Lamb (NRC) to Mark E. Warner (NMC),

dated May 23, 2002, "Request For Additional Information Related To Request To Exclude Dynamic Effects Associated With Postulated Pipe Ruptures From Licensing Basis For Residual Heat Removal, Accumulator Injection, And Safety Injection System SIR-00-045, Rev. 2 B-1 r Structural Integrily Associates

Docket 50-305 NRC-02-058 June 24, 2002 Page 2 Piping Based Upon Leak Before Break Analysis (TAC NO. MBI301)." By reference 1, the Nuclear Management Company, LLC, (NMC) requested Nuclear Regulatory Commission (NRC) review and approval to exclude the dynamic effects associated with postulated pipe ruptures from the Kewaunee Nuclear Power Plant (KNPP) licensing basis. This request is for portions of the KNPP Residual Heat Removal (RHR), Accumulator Injection, and Safety Injection (SI) system piping. In reference 2, the NRC requested additional information associated with NMC's submittal. Enclosed, as attachments I through 3, is NMC's response to this request for additional information. During Structural Integrity Associates' review of their Leak-Before-Break report, sent to the NRC in reference 1, a typographical error was uncovered in several tables in section

5. The report identified the leakage flaw sizes as the total crack length (2a) whereas the actual parameter in the tables was the flaw size (a). Those changes had no affect on the technical content of the report and are identified in the report on the revision control page. This revised report is contained in attachment 4 In this response, NMC makes no new commitments.

Please contact Mr. Gerald Riste at (920) 388-8424, if there are any questions or if we can be of assistance regarding the review of this request. To the best of my knowledge and belief, the statements contained in this document are true and correct. In some respects, these statements are not based entirely on my personal knowledge, but on information furnished by cognizant NMC employees and consultants. Such information has been reviewed in accordance with company practice and I believe it to be reliable. Mark E. Warner Site Vice President - Kewaunee and Point Beach Nuclear Power Plants GOR Attachment 1, NMC Response Attachment 2, Requested Plant Drawings Attachment 3, Structural Integrity Response Attachment 4, Structural Integrity Technical Report SIR-00-045, Rev. 2 B-2 StructuralIntegrity Associates

Docket 50-305 NRC-02-058 June 24, 2002 Page 3 cc - US NRC - Region III NRC Senior Resident Inspector Electric Division, PSCW SIR-00-045, Rev. 2 B-3 StructuralIntegrity Associates

ATTACHMENT 1 I Letter from Mark E. Warner (NMC) To I Document Control Desk (NRC) I U Dated I June 24, 2002 I I Nuclear Management Company, LLC Response to NRC's Request for Additional Information Regarding Request to Exclude Dynamic Effects I Associated with Postulated Pipe Ruptures From Licensing Basis for Residual Heat Removal, Accumulator Injection, and Safety Injection System Piping I Based Upon Leak Before Break Analysis. SIR-00-045, Rev. 2 B-4 StructuralIntegrity Associates

Docket 50-305 NRC-02-058 June 24, 2002 , Page 5 NRC Question #1. The cover letter to NMC's February 23, 2001, submittal states that NMC is requesting Leak-Before-Break approval for the following piping at the Kewaunee Nuclear Power Plant (KNPP), along with some description of each item: (1) 12-inch diameter safety injection system piping; (2) 8-inch diameter residual heat removal system piping; (3) 6-inch diameter cold leg safety injection system piping; (4) 6-inch diameter reactor vessel safety injection system piping. Confirm!whether or not item (4) is actually included in the KNPP submittal inasmuch as no specific tabular information in the report was identified as applying to the 6-inch diameter reactor vessel safety injection system piping. Provide piping diagrams (similar to those shown in Figures 5-7, 5-8, and 5-9 of report SIR-00-045, Rev. 0), which show the specific portions of the KNPP piping systems for which LBB approval being sought. Confirm that the information in Tables 4-3, 4-4, and 4-5 represent nodal moments specific to the KNPP systems in question. NMC Response The 6-inch diameter reactor vessel safety injection system piping identified as item 4 is not to be included in the KNPP LBB application. However, there is also a 6-inch nozzle attached to the hot leg that is included in the KNPP LBB analysis.' Tables 4-3, 4-4 and 4-5 do represent the nodal moments specific to the KNPP systems in question. For the 6-inch hot leg nozzle, there are no moments since the nozzle is capped. The requested KNPP piping drawings are provided in attachment 2 for each section of piping included in the KNPP LBB analysis. NRC Question #2. Based on the desdription provided inSection 4.2, "Material Properties," of report SIR-00-045, Rev. 0, it appears that no cast austenitic stainless steel piping sections, elbows, safe ends, etc., are present in any of analyzed portions of piping for which NMC is seeking LBB approval for Kewaunee. Confirm that this observation is correct. SIR-00-045, Rev. 2 B-5 StructuralIntegrity Associates

Docket 50-305 NRC-02-058 June 24, 2002 , Page 6 NMC Response There are no cast austenitic steel piping sections present in any of the analyzed portions of piping. However, two valves (SI-22A and SI-22B) that function to isolate reactor coolant fluid are fabricated from CF-8 material. These valves are part of the 12-inch diameter safety injection system piping identified under item I in NRC question 1. A drawing for these valves is provided in attachment 2. Since the valves are much thicker than the attachment piping and pipe-to-valve weldments, standard practice in LBB evaluations has been not to include these relatively thicker components in the LBB. evaluation. NRC Question #3. Based on the description provided in Section 4.2, "Material Properties," of report SIR-00-045, Rev. 0, it appears that no Inconel 600 safe ends or welds manufactured in whole or in part (i.e., buttered with) Inconel 82/182 are present in any of analyzed portions of piping for which NMC is seeking LBB approval for Kewaunee. Confirm that this observation is correct. NMC Response There are no Alloy 600 safe ends or welds, manufactured in whole or in part (i.e., buttered with ) Inconel 82/182 or other nickel alloy weldments, in the portions of piping for which LLB approval is being sought. NRC Question #4. Generic material property values (tensile and fracture toughness) for austenitic stainless steel shielded metal arc welds are provided in Table 4-2 of report SIR-00-045, Rev. 0. Section 4.2, "Material Properties," of the report suggests that these welds are likely to be the most limiting locations with respect to the LBB analyses. However, for some evaluational methods, the tensile material properties of the piping which adjoins the welds is also required. Explain whether any specific tensile material properties for the piping which adjoins the welds in the subject piping was assumed in the analyses and, if so, provide those values NMC Response The analysis was based on conservative generic properties as documented in the report. For the tensile material properties, of the piping which adjoins the welds, the LBB analysis did not use plant-specific properties. This approach of using conservative generic properties integrates an unquantified margin into the LBB analysis. SIR-00-045, Rev. 2 B-6 StructuralIntegrity Associates

Docket 50-305 NRC-02-058 June 24, 2002 , Page 7 NRC Question #5. Section 4.3, "Piping Moments and Stresses," notes, "[a]xial loads due to dead weight, thermal expansion, and seismic were not available from the piping stress analysis and therefore were not considered in the evaluation. The stresses due to axial loads are not significant compared to those from pressure loads, so their exclusion does not significantly affect the results of the evaluation." Explain your basis for this conclusion. Cite any available information which provides insight into the relative magnitudes of the axial loads due to the contributing factors noted above for the subject piping-versus the axial load due to internal pressure. This information may not be KNPP specific, but should reflect observations/analyses of etc. piping of similar size, geometrical configuration, operational environment, NMC Response. Structural Integrity Associates (SIA) developed the original LBB analysis. Accordingly, NMC has contracted SIA to develop a response to this question. Attachment 3 provides a detailed response to this question. NRC Question #6. In Section 5.2, "Leak Rate Determination," assumptions are made regarding the crack morphology assumed for the leakage flaw analysis. Specifically, a crack roughness of 0.000197 inches and no turning losses were assumed since the crack was assumed to be initiated by some other mechanism other than intergranular stress corrosion cracking (IGSCC). The staff would not that one fundamental criteria for LBB approval is that no active degradation mechanism be present in the subject'line. Hence, the exclusion of crack morphologies related to SCC mechanisms could also be used to exclude morphology parameters associated with thermal fatigue, vibrational fatigue, etc. Although the staff concurs that, to date, IGSCC of stainless steel piping in PWR environments has not been observed, SCC has been demonstrated by recent events (e.g., of an Inconel 82/182 weld at V.C. Summer) to be a credible cracking mechanism. Therefore, the staff requests that you evaluate the sensitivity of your leakage rate determination to the specific crack morphology parameters selected. The staff requests that parameters (surface roughness and number of turns) characteristic of transgranular stress corrosion cracking (TGSCC) be used, although the staff acknowledges that, to date, TGSCC has not been observed in PWR stainless steel piping (TGSCC has, however, been observed to occur in other stainless steels components in PWR primary system pressure 'boundary applications). Information contained in NRC NUREG/CR-6443, "Deterministic and Probabilistic Evaluations for Uncertainty in Pipe Fracture Parameters in Leak-Before-Break and In-Service Flaw Evaluations," may be useful. Evaluate what effect these modified leakage rate calculations may have on your conclusion that the subject lines are qualified for LBB approval. SIR-00-045, Rev. 2 B3-7 VStructural IntegrityAssociates

Docket 50-305 NRC-02-058 June 24, 2002 , Page 8 NMC Response Structural Integrity Associates (SIA) developed the original LBB analysis. Accordingly, NMC has contracted SIA to develop a response to this question. Attachment 3 provides a detailed response to this question. NRC Question #7. It is stated on page 5-10 of SIR-00-045, Rev. 0 that, "[tlhe evaluation consists of first modeling the piping lines and then applying a kink angle at all weld locations from the LBB analysis. The process resulted in applied moments at each weld location that could be used in assessing leakage rate reduction. The three selected piping lines were modeled as PIPEI 6 elements using the ANSYS computer code [22]. All three models were bounded by two anchors, one of them being the connection to the RCS system. The other was placed at a significant distance away from the welds of interest." Explain what is meant by the last sentence of this passage. The sentence seems to imply that an arbitrary choice for the location of a second anchor was used. The staff would assume that the piping systems were modeled in the as-built configuration and the location of any anchors would be known. The proximity of any anchor to a weld of interest would, therefore, be known. NMC Response Structural Integrity Associates (SIA) developed the original LBB analysis. Accordingly, NMC has contracted SIA to develop a response to this question. Attachment 3 provides a detailed response to this question. NRC Question #8. With regard to the issue of addressing restraint of pressure induced bending, confirm that the moments provided in Tables 5-13 through 5-15 represent "bounding" restraint or closure moments (moments which would conservatively act to close the leakage flaw and reduce the calculated leakage per unit crack length) which were calculated based on your analysis of the least compliant representative system from any of the three units (KNPP, Prairie Island I and 2) which provided information for report SIR-00-045, Rev. 0. It is the staff's understanding that in your analysis the greatest restraint moments were calculated and used to reduce the KNPP plant-specific moments from the piping analysis in order to account for their effect on the leakage flaw size determination (as reflected in the information in Tables 5-16, 5-17, and 5-18), but were not used to modify your analysis of the critical flaw size. NMC Response Structural Integrity Associates (SIA) developed the original LBB analysis. Accordingly, NMC has contracted SIA to develop a response to this question. Attachment 3 provides a detailed response to this question. SIR-00-045, Rev. 2 B-8

• StructuralIntegrity Associates

Docket 50-305 NRC-02-058 June 24, 2002 , Page 9 ATTACHMENT 2 Letter from Mark E. Warner (NMC) To Document Control Desk (NRC) Dated June 24, 2002 Drawings Discussed in Response to NRC Questions 1 and 2 M-935, M-936, M-938-1, M-938-2, M-939, M-957-1, M-982, & XK100-902 (Note that these drawingsare not reproducedin Report SIR-00-045, Rev. 2) SIR-00-045, Rev. 2 B-9 t StructuralIntegrity Associates

Docket 50-305 NRC-02-058 June 24, 2002 , Page 10 ATTACHMENT 3 Letter from Mark E. Warner (NMC) To Document Control Desk (NRC) Dated June 24, 2002 Structural Integrity Associates (SIA) Evaluation for NRC Questions 5 Through 8 (Note: In this Report, SIR-00-045, Rev. 2, the information submitted in Attachment 3 is includedin Appendix C) SIR-00-045, Rev. 2 B-10 Structural Integrity Associates

Docket 50-305 NRC-02-058 June 24, 2002 , Page 11 ATTACHMENT 4 Letter from Mark E. Warner (NMC) To Document Control Desk (NRC) Dated June 24, 2002 Structural Integrity Technical Report Leak-Before-Break Evaluation 6-inch to 12-inch Safety Injection and Residual Heat Removal Piping Attached to the RCS Kewaunee Nuclear Power Plant Revision No. 1 (Note thatAttachment 4 was Revision 1 of Report SIR-00-045 and is not includedherein.) SIR-00-045, Rev. 2 B-11 StructuralIntegrity Associates

U U I APPENDIX C RESPONSES TO RAI QUESTIONS NOS.5-8 (SIR-02-074, Reference 33) SIR-00-045, Rev. 2 C-0

                                                       !U StructuralIntegrityAssociates

Attachment A NRC Question #5: Section 4.3,"Piping Moments and Stresses," notes, "[a]xial loads due to dead weight, thermal expansion, and seismic were not available from the piping stress analysis and therefore were not considered in the evaluation. The stresses due to axial loads are not significant compared to those from pressure loads, so their exclusion does not significantly affect the results of the evaluation." Explain your basis for this conclusion. Cite any available information which provides insight into the relative magnitudes of the axial loads due to the contributing factors noted above for the subject piping versus the axial load due to internal pressure. This information may not be KNPP specific, but should reflect observations/analyses of piping of similar size, geometrical configuration, operational environment, etc. 8.1 Response As noted, the axial piping loads were not available from the KNPP piping stress analysis made available to~perform the leak before break analysis. Instead, the piping loads were listed in a global coordinate system. From the information available, it was not always possible to determine the force along the piping system nor was it possible to determine if the forces would be positive or negative. The magnitudes of the global forces were determined to be small, however, compared to the axial forces due to pressure. Thus, they were considered to be small enough that the effects would be negligible. This fact is recognized by the ANSI B3 1.1 and ASME Section III Codes in that axial forces due to loads other than pressure are not included in piping stress evaluation. However, to demonstrate the potential effect on the KNPP LBB behavior, some typical stresses as well as some KNPP-specific loads have been evaluated. In a presentation to the ACRS on March 26, 1987, a set of highly stressed components from a Westinghouse PWR plant were presented, as shown in Table A-i,. Although there is no indication of the direction of the axial loads in this table, the maximum of the listed axial loads presented in this table have been assumed to be along the pipe and used as the normal operating (NOP) axial loads (not including pressure) and the seismic (SSE) axial loads. The maximum ratio of these loads to the axial load due to pressure (P), actually determined for the relatively larger 12" and 14" piping systems, was determined to be: Normal Operating Axial Load Ratio (NOP/P) - + 0.03 to - 0.06 SSE Axial Load Raito (SSE/P) +/-0.03 As a demonstration of the effect of axial loads, the above ratios have been used to determine the effect on the KNPP Safety Injection and RHR piping since these have relatively lower margins to the detectable leakage rate. Note that the Hot Leg Nozzle location is not evaluated since the axial load is solely due to pressure on the end cap; there is no piping load. In performing the evaluation, the normal operating axial load sign is evaluated as being either plus or minus and SIR-00-045, Rev. 2 .C-1 StructuralIntegrity Associates

the seismic moment is always positive (since it is a dynamic load and the sign can vary from positive to negative). The results on the leakage flaw sizes and leakage rates are shown in Table A-2. As shown in the Table A-2, the leakage flaw size is affected only very slightly by the addition of the NOP + SSE loads. The predicted leakage is reduced very slightly for the assumed 6 percent compressive axial load. The leakage increases by a small amount if the NOP axial load is tensile by 3 percent. Given the margins between the predicted leakage without axial loads and the required minimum leakage rate of 2.5 gpm (without the factor of 10 between predicted leakage and minimum leakage detection capability), neglecting the axial loads does not change the conclusions reached for the LBB evaluation. After performing the above evaluation with typical load ratios derived from the Beaver Valley piping forces, it was recognized that the KNPP global forces were available from the piping stress analysis. Therefore, loadings at the limiting locations for KNPP were evaluated in order to assess the significance of the axial loads and to validate and show the conservatism of analysis based on the Beaver Valley load data. The axial loads for the limiting 6" and 8" KNPP lines are shown in Tables A-3 and A-4. The' axial forces are very small:

            -   6" Safety Injection: The maximum DW+T global load in Table A-3 is less than one percent of the axial pressure load; the maximum SSE global load is less than 0.3 percent of the pressure load.
            -   8" RHR: The critical location (Node 95) is at the horizontally-oriented valve at the lower end of the piping (although not shown in Figure 4-3 of SIR-00-045).

The magnitude of the Fy load increases with height along the piping section, except for the decrease at the vertical support at Node 60, so it is obviously that the F. loads in Table A-4 are vertical. Thus, maximum axial load at Node 95 can not exceed the SRSS of the Fx and F1loads. Thus, the maximum DW+T axial load at Node 95 is less than 860 lb (<1% of pressure load) and the SSE load is less than 1500 lb (<2% of pressure load). Because the KNPP plant specific loads are very small, the leakage flaw sizes and leakage rates shown in Table A-2 based on the Beaver Valley information are judged to be adequate for assessing the impact of the axial loadings on LBB analysis. This sensitivity analysis concludes that the LBB results, when considering the effects of axial loads, would continue to satisfy the applicable regulatory requirements by a large margin. The exclusion of the axial loadings has an insignificant effect on the results of the LBB evaluation. Therefore, additional plant specific analysis to determine the leakage flaw sizes and leakage rages considering the effects of axial loads need not be performed. SIR-00-045, Rev. 2 C-2 StructuralIntegrity Associates

Table A-I. Beaver Valley Power Station High Stress Locations For WHIPJET LBB Analysis (ACRS Presentation 3/26/87) LOADING FORCES (Ibs) MOMENTS (ft-Ibs) NCONDITIONS Fy Fz -Mx My Mz DEADWEIGHT -1067 -10 -5 10 -43 135 SIS 6-INCH THERMAL -16 -043 80 1135 721 11223 SSE 169 172 283 732 2720 1610 DEADWEIGHT 1115 -1967 114 285 52 4344 RCS 8-INCH THERMAL -2128 -763 -884 -3884 -4314 11098 SSE 1258 1735 396 1219 854 1761 DEADWEIGHT 7 -2949 9, -7 -179 -4015 RHS 10-INCH THERMAL 48 -2318 -80 2162 714 -31215 SSE 2566 3338 2017 5194 4998 7880 DEADWEIGHT -77 4500 318 -6440 -1555 6306 RHS 12-INCH THERMAL -1319 -2369 -1679 15713 361 -17014 SSE 5210 3639 2077 7147 20757 29201 DEADWEIGHT 2807 579 38 1031 -4231 -2405 SIS 12-INCH THERMAL -737 3706 4866 -38393 -22826 38127 SSE 1894 1109 1676 2847 10799 9045 DEADWEIGHT 105 2135 59 -2237 -1729 10360 RCS 14-INCH THERMAL 11592 3479 -14015 2951 161404 47651 SSE 1791 1241 1529 1525 12814 8969 Table A-2. Leakage Flaw Sizes and Leakage Rates With Modified Axial Loads Leakage Flaw Sizes Nominal Assumed Jin. Leakage Rate (gpm) Pipe Size Piping Axial EPFM NSC EPFM NSC Stress Ratio (2a) (2a) Pressure Only 5.470 5.238 6.293 5.189 6"SCH 160 Safety Injection +3% NOP/+3%SSE 5.447 5.206 6.394 5.243 Node 275a

                            -6% NOP/+3%SSE                 5.515       5.304       6.015       5.059 P ressure Only                 6.695       6.278       9.747       7.480 8" SCH 140 RHR                 +3% NOP/+3%SSE                 6.655       6.236       9.792       7.525 Node 95
                            -6% NOP/+3%SSE                 6.777       6.362       9.458       7.291 SIR-00-045, Rev. 2                                 C-3 StructuralIntegrity Associates

TableA-3. KNPP 6-inch Cold Leg Safety Injection Line Global Axial Loads U N.ode DW+T Loads (Ibs) - SSE Loads (Ibs) Number. F. F F,2 Y I 275a 174 356 -97 108 50 48 I 275b 277 174 "174 431 431

                                            -97.
                                            -97.

108 108

                                                              ,, 50 50 48 48 I                     280   174      447     -97       108'       50      48 560a    -90     349      92       24         38      16 I                    560b    -90     424      92       24         38      16 563    -90     424      92       24         38      16 I                     565    -90   .440       92       24         38      16 (Axial Load due to Pressure: 47,270 lbs)

I I I I I I I I, SIR-00-045, Rev. 2 C-4

                                                                       !    'StructuralIntegrityAssociates

Table A-4. KNPP 8-inch Residual Heat Removal Line Global Axial Loads Nde : -DW Loads::: s SSE Loadils I .b - Number Fx :I FYi Fz Fx fy : Fz 10 612 1540 361 304 438 316 15 612 1756 361 304 438 .316 20a 612 1756 361 304 438 316 20b 612 1834 361 304 438 316 25 612 1834 361 304 438 316 30a 612 1834 361. 292 434 318 30b 612 1987 361 292 434 318 35 612 1987 361 292 434 318 40 612 2343 361 292 434 318 45 612 2699 361 292 434 318 50a 612 2699 361 176 352 260 50b 612 2853 361 176 352 260 55 612 2853 361 176 352 260 955 612 3546 361 176 352 260 960 612 4239 361 248 352 128 1960 612 4496 361 534 188 184 75 612 4593 361 534 188 184 60 612 4602 361 534 188 184 60 612 1158 361 534 248 184 875a 612 1158 361 534 248 184 875b 612 1312 361 534 248 184 80 612 1312 361 534 248 184 85 612 1426 361 694 248 264 90 612 1426 361 694 248 264 90 612 3446, 361 1262 334 690 95 612 3446 361 1262. 334 690 330 320 -4801 338 480 426 846 330 795 -2781 80 250 496 316 335 795 -2781 80 250 496 316 8340a 795 -2781 80 250 496 316 8340b 795 -2627 80 250 496 316 345 795 -2627 80 250 496 316 340 795 -2602 80 250 496 316 348 795 -2235 80 250 496 316 351 795 -1745 80 146 496 196 355 795 -1055 80 182 814 148 355 795 -3544 80 182 708 148 360 795 -3409 80 182 708 148 365 795 -3407 80 204 740 158 8365a 795 -3407 80 204 740 158 i8365b 795 -3253 80 204 740 158 370 795 -3253 80 204 740 158 375 795 -3010 80 204 740 158 380 795 -2768 80 254 820 192 385a 795 -2768 80 254 820 192 385b 795 -2614 80 254 820 192 390 795 -2614 80 254 820 192 395a 795 -2614 80 266 830 196 395b 795 -2537 80 266 830 196 400 795 -2537 80 266 830 196 405 795 -2302 80 266 830 196 (Axial Load due to Pressure: 86,048 lbs) SIR-00-045, Rev. 2 C-5 Structuralintegrity Associates

Attachment B NRC Question #6: In Section 5.2, "Leak Rate Determination," assumptions are made regarding the crack morphology assumed for the leakage flaw analysis. Specifically, a crack roughness of 0.000197 inches and no turning losses were assumed since the crack was assumed to be initiated by some other mechanism other than intergranular stress corrosion cracking (IGSCC). The staff would note that one fundamental criteria for LBB approval is that no active degradation mechanism be present in the subject line. Hence, the exclusion of crack morphologies related to SCC mechanisms could also be used to exclude morphology parameters associated with thermal fatigue, vibrational fatigue, etc. Although the staff concurs that, to date, IGSCC of stainless steel piping in PWR environments has not been observed, SCC has been demonstrated by recent events (e.g., of an Inconel 82/182 weld at V.C. Summer) to be a credible cracking mechanism. Therefore, the staff requests that you evaluate the sensitivity of your leakage rate determination to the specific crack morphology parameters selected. The staff requests that parameters (surface roughness and number of turns) characteristic of transgranular stress corrosion cracking (TGSCC) be used, although the staff acknowledges that, to date; TGSCC has not beeWi observed in PWR stainless steel piping (TGSCC has, however, been observed to occur in other stainless steels components in PWR primary system pressure boundary applications). Information contained in NRC NUREG/CR-6443, "Deterministic and Probabilistic Evaluations for Uncertainty in Pipe Fracture Parameters in Leak-Before-Break and In-Service Flaw Evaluations," may be useful. Evaluate what effect these modified leakage rate calculations may have on your conclusion that the subject lines are qualified for LBB approval. 8.2 Response It is recognized that there have been some instances of SCC in recent PWR industry events. However, it is highly unlikely that the RCS-attached piping systems at KNPP would be affected. There are no Inconel 82/182 weldments in the piping being proposed for LBB. The occurrence of TGSCC such as that which has occurred in CEDMs at Palisades is not expected at KNPP since the water in the RCS-attached lines is free to communicate with the RCS such that high levels of oxidants can not concentrate. On the other hand, the piping systems at all nuclear plants are affected by cyclic stresses due to normal operating pressure and thermal expansion loadings. Because these stresses could potentially contribute to growth of cracks, fatigue crack growth was addressed in Section 6.0 of Report SIR-00-045. It was shown that the current Section XI ISI program at KNPP can be used to assure that growth of any potential cracks in the subject lines can be readily detected. Since SCC cracks are of such low probability and the only credible growth mechanism is due to cyclic stresses and fatigue crack growth, fatigue crack morphology has typically been the basis of LBB evaluations. However, as requested, hypothetical flaws due to IGSCC/TGSCC have been evaluated, and the results are reported herein. SIR-00-045, Rev. 2 C-6

• StructuralIntegrity Associates

In NUREG/CR-6443, Section 3.3, a sensitivity study of leakage size flaws is described based on using different crack morphologies. In Table 3.1 of NUREG/CR-6643, summaries of surface roughness for IGSCC and corrosion-fatigue are presented for a set of leak rate calculations performed by Battelle Columbus. Surface roughness values are given for evaluations by both SQUIRT (developed by Battelle) and PICEP (developed by EPRI). The reference for the roughness and number of turns used for either case is not readily available. The parameters used in the sensitivity study using PICEP do not agree with the recommendations from the PICEP manual [1] except for the surface roughness for IGSCC. The number of 90-degree turns for IGSCC for PICEP is four times the PICEP manual recommendation. Thus, Reference 3.15 of NUREG/CR-6443 (NUREG/CR-6300) was reviewed to determine the source of the roughness and number of turns in the series of reports produced by Battelle. In NUREG/CR-6300, magnified pictures from several specimens were evaluated to determine global and local surface roughness and number of turns for IGSCC specimens. The data referred to in NUREG/CR-6300 are all for IGSCC in BWR piping. Since TGSCC is more likely than IGSCC, additional' evaluation was performed by SI to investigate TGSCC cracking morphology. The approach used was to independently reproduce the results presented in Tables 9-1 and 9-3 of NUREG/CR-6300 for four of the IGSCC cracks presented (where the references could be obtained) and then use this same approach to evaluate transgranular cracks representative of field TGSCC. Evaluation of number of turns and global and local surface roughness from micrographs is highly subjective. The results of the independent evaluation for the four referenced cracks showed that the NUREG/CR-6300 values could be reproduced within approximately 40% for both roughness and the number of 90-degree turns per inch. The exception was for the data presented for NP-2472 Vol. 2 Figure I-1 referenced in Table 9.1 of NUREG/CR-6300. Examination of the actual Figure and the corresponding text from EPRI Report NP-2472 Vol. 2, indicates that the magnification of 400X reported in Figure I-1 is in error., By examining the text and comparing the cracks in Figures 1-1(a) to 1-1(b), one can demonstrate that the actual magnification of Figure I-1 (a) is I OOX, resulting in an overstatement of the number of turns and roughness by a factor of four. The same evaluation method for evaluating roughness and counting turns was then used bu SI to examine the leak rate parameters for field produced TGSCC (Ft. Calhoun CEDM upper housing crack) [2], and a laboratory pipe test which produced IGSCC and TGSCC in the same sample [3]. Table B-I presents results of the evaluation of these samples. The laboratory test examined a four-inch schedule 80 Type 304 stainless steel pipe tested in an intentionally contaminated environment containing chlorides. The test produced both IGSCC and TGSCC adjacent to each other in the pipe. Metallography was performed on both the IGSCC and the TGSCC with results presented in Figures 4.15 and 4.16 of Reference 3. The crack opening parameters for this test are also presented in Table B-1. Also presented in Table B-1 is the calculated roughness and number of turns obtained from a failed Type 348 stainless steel housing at the Ft. Calhoun Nuclear Power Station, as reported in Reference 2. One observes that the TGSCC observed in SIR-00-045, Rev. 2 C-7 Structural IntegrityAssociates

the laboratory pipe test and the TGSCC from Ft. Calhoun should have much less flow resistance than IGSCC. To evaluate the effects of surface roughness and number of turns on the KNPP leakage rate calculations, the data from Tables 9.1 and 9.3 of NUREG/CR-6300 were evaluated for the limiting component that is the 6-inch diameter hot leg nozzle. Only the EPFM results were used in this sensitivity evaluation. Five separate sets of roughness and number of turns were evaluated where both roughness and number of turns per inch were reported in Tables 9.1 and 9.3. The effective roughness and number of turns were calculationed based on the model proposed in NUREG/CR-6300. The computed crack opening displacements from the KNPP PICEP evaluations were used in this analysis, since the effective roughness in the NUREG/CR-6300 model is a function of the crack opening displacement. See Tables B-2 and B-3. In addition, the recommendations from the PICEP manual for IGSCC cracking were evaluated, where the PICEP manual [1] recommends a surface roughness of 0.0002 inches combined with 24 45-degree turns per inch of thickness. It should be noted that the PICEP leak rate prediction recommendations were validated against actual leakage data [1]. There is no evidence that the surface roughness and number of turns data presented in NUREG/CR-6300 have been validated with actual test data. The only recommendation in NUJREG/CR-6300 is that" ... further studies are needed to verify these results." In qualifying piping systems for LBB, there is a factor of two required between the critical flaw size and the leakage flaw size. Although in some situations the leakage flaw size may be limited by a factor of 42 on the applied load, the factor of two governed for all cases in the KNPP evaluations. In addition, there must be a factor of 10 between the predicted leakage and the detection capability of plant leakage detection systems. Since the occurrence of IGSSC or TGSCC in the KNPP piping has such a low probability of occurrence, the leakage calculations with hypothetic IGSCC cracking are conducted for both the leakage flaw size from the KNPP LBB report, and for a flaw size that is the average of the leakage flaw size and the critical flaw size. The latter flaw size (referred to as 1.5 times the leakage flaw size) still represents considerable margin as compared to the critical flaw size. The results of this evaluation and a comparison to the results in the KNPP LBB report for a fatigue crack are shown in Tables B-1 to B-3. Table B-1 shows the effective roughness for each case. Table B-2 shows the effective number of turns. Table B-3 shows the resulting leakage. 'The following conclusions can be reached from this sensitivity study. Based on the limiting location, the leakage predicted using the recommendations from the PICEP manual for the leakage size flaw yields 2.77 gpm, greater than the 2.5 limit that was established for LBB acceptance. SIR-00-045, Rev. 2 C-8

• StructuralIntegrity Associates

For the increased roughness and number of turns based on the NUREG/CR-6300 model for IGSCC, the predicted leakage is greater than 0.33 gpm, excluding the erroneous dimensions in the NP-2472, Vol. 2 (Figure I-1) numbers. This predicted leakage is greater than the KNPP leakage detecting system capability. If one considers a flaw that is the average between the leakage and the critical flaw size, the predicted leakage exceeds 2.5 gpm (excluding the evaluation for the NP-2472 Volume 2 flaw which erroneously recorded excessive number of turns). Thus, the margin of 10 on leakage can be maintained for a flaw size that is significantly less than the critical flaw size.

          -   Leakage from a TGSCC flaw would produce greater flow than for an IGSCC flaw due to the lesser number of turns and less roughness.

This evaluation demonstrates that leakage from cracks with these extremely low probability crack morphologies can be detected although margins may be reduced slightly. REFERENCES

1. EPRI-NP-3596-SR, "PICEP: Pipe Crack Evaluation Computer Program." Revision 1, July 1987.

2. Sixth International Symposium on Environmental Degradation of Materials in Nuclear Power Systems-Water Reactors-, Paper Entitled: "Evaluation of Cracking In Type 348 Stainless Steel Control Element Drive Mechanism Housings", B. Lisowyj, August 1-5, 1993, San Diego, CA, pp 343-350.

3. EPRI NP-2671-LD, "Alternative Alloys for BWR Pipe Applications", Final Report, October 1982, pp. 4-55, 4-56.

SIR-00-045, Rev. 2 C-9 Structural Integrity Associates

Table B-1. Comparison of TGSCC Crack Morphology to that for IGSCC Source sRoughnes (p inch) Turns (# per inch) Local Global Sixth International Symposium on Environmental Degradation of Materials In Nuclear Power 12-65 -1250 -240 Systems Water Reactors TGSCC (Page 347) EPRI-NP-2671LD 10-20 -1000 -170 Figure 4.15 TGSCC EPRI-NP-2671 LD ERNP27D30-60 -3000 -410 Figure 4.16 IGSCC IGSCC Values from NUREG/CR-6300, Table 9.1 and Table 9.3 80 3,990 1,450 NP-2472 Vol. 2 (see Figure I-I) 290 2,930 352 NP-3684SR, Vol. 3 (Paper 4, Figure 11) 412 1,650 873 NP-3684SR, Vol. 3 (Paper 4, Figure 5) 25.0 to 250 5,000 240 NP-3684SR, Vol. 2 (Paper 5, Figure 21) 55 1,100 670 NP-3684SR, Vol. 2 (Paper 19, Figure 12) SIR-00-045, Rev. 2 C-10 StructuralIntegrity Associates

Table B-2. Effective Roughness Calculated per NUREG/CR-6300 Model Roughness, inches* Case Leakage Flaw Length, 1.5 x Leakage Flaw 5.42" Length, 8.13" Base Case (Fatigue Crack) 0.00020 0.00020 PICEP Recommended IGSCC Crack 0.00020 0.00020 Cases from NUREG/CR-6300 NP-2472 Vol. 2 (Figure I-1) 0.00043 0.00138 NP-3684SR Vol. 3 (Paper 4, Figure 11) 0.00062 0.00150 NP-3684SR Vol. 3 (Paper 4, Figure 5) 0.00070 0.00143 NP-3684SR Vol. 2 (Paper 5, Figure 21) 0.00058 0.00150 NP-3684SR Vol. 2 (Paper 19, Figure 12) 0.00042 0.00110

• EPFM Results; Crack Opening Displacements were 0.00391" (Leakage Flaw Length) and 0.01357" (1.5 x Leakage Flaw Length).

Table B-3. Effective Number of Turns Calculated per NUREG/CR-6300 Model (for 0.718 pipe thickness) Number of Turns* Case Leakage Flaw Length, 1.5 x Leakage Flaw 5.42" Length, 8.13" Base Case (Fatigue Crack) 0 0 PICEP Recommended IGSCC Morphology 17 17 Cases from NUREG/CR-6300 NP-2472 Vol. 2 (Figure I-1) 958 729 NP-3684SR Vol. 3 (Paper 4, Figure 11) 224 149 NP-3684SR Vol. 3 (Paper 4, Figure 5) 497 164 NP-3684SR Vol. 2 (Paper 5, Figure 21) 162 131 NP-3684SR Vol. 2 (Paper 19, Figure 12) 330 48

• EPFM Results; Crack Opening Displacements were 0.00391" (Leakage Flaw Length) and 0.01357" (1.5 x Leakage Flaw Length)

SIR-00-045, Rev. 2 C-1I C StructuralIntegrityAssociates

Table B4. Predicted Leakage for PICEP and NUREG/CR-6300 Crack Morphologies Leakage, gpm Case Leakage Flaw Length, 1.5 x Leakage Flaw 5.42" Length, 8.13" Base Case (Fatigue Crack) 5.07 39.04 PICEP Recommended IGSCC Morphology 2.77 18.80 Cases from NUREGICR-6300 NP-2472 Vol. 2 (Figure I-1) 0.27 1.65 NP-3684SR Vol. 3 (Paper 4, Figure 11) 0.51 3.55 NP-3684SR Vol. 3 (Paper 4, Figure 5) 0.33 3.43 NP-3684SR Vol. 2 (Paper 5 Figure 21) 0.60 3.78 NP-3684SR Vol. 2 (Paper 19, Figure 12) 0.46 6.63 SIR-00-045, Rev. 2 C-12 StructuralIntegrityAssociates

Attachment C NRC Question #7: It is stated on page 5-10 of SIR-00-045, Rev. 0 that, "[t]he evaluation consists of first modeling the piping lines and then applying a kink angle at all weld locations from the LBB analysis. The process resulted in applied moments at each weld location that could be used in assessing leakage rate reduction. The three selected piping lines were modeled as PIPE 16 elements using the ANSYS computer code [22]. All three models were bounded by two anchors, one of them being the connection to the RCS system. The other was placed at a significant distance away from the welds of interest." Explain what is meant by the last sentence of this passage. The sentence seems to imply that an arbitrary choice for the location of a second anchor was used. The staff would assume that the piping systems were modeled in the as-built configuration and the location of any anchors would be known. The proximity of any anchor to a weld of interest would, therefore, be known. 8.3 Response The piping systems considered in the analysis were all relatively flexible piping modified systems. To minimize the cost associated with the analysis, the piping systems between the RCS nozzles and the end anchor points was not all included in the models. Instead, a point on the piping system closer to the RCS nozzle, but far enough away to provide sufficient flexibility was chosen based on engineering judgment. In choosing this assumed anchor location, the modeled piping system would be stiffer than that which actually exists in the field, and would produce higher moments due to restraint than would actually exist in the field. Figures 5-7 to 5-9 from the report included herein, have been modified to indicate the locations of the assumed anchor points. SIR-00-045, Rev. 2 C-13 C StructuralIntegrityAssociates

x oC Note: For evaluation of restraint, piping evaluated between Node 2000 and an assumed anchor located at Node 2160. Figure 5-7. Schematic of Piping Layout Used to Determine the Effect of Restraint on LBB Evaluation (S-inch RHR Line - Prairie Island Unit 1, Loop A) I SIR-00-045, Rev. 2 C-14 StructuralIntegrity Associates

COLD LEG LOOP 8 I "X 2" REE. FLOOR Note: For evaluation of restraint, piping evaluated between Node 280 and an assumed anchor located at Node 200. Figure 5-8. Schematic of Piping Layout Used to Determine the Effect of Restraint on LBB Evaluation (6-inch Safety Injection Line - Kewaunee, Loop B) SIR-00-045, Rev. 2 C-15 SStructural Integrity Associates

j4 LM ~ijj. 5Z 20 so 35

                                                                                                    '5 WARN -&#                   2U0 to Wa*,e- 7 f 170 flann -)3                                    flu
                                                                            -  6u' 200 210 315 250 255              . M Note:  For,evaluation of restraint, piping evaluated between Node 5 and an assumed anchor located at Node 150.

Figure 5-9. Schematic of Piping Layout Used to Determine the Effect of Restraint on LBB Evaluation (6-inch Draindown Line - Prairie Island Unit 2) SIR-00-045, Rev. 2 C-16 V StructuralIntegrity Associates

Attachment D NRC Question #8: With regard to the issue of addressing restraint of pressure induced bending, confirm that the moments provided in Tables 5-13 through 5-15 represent "bounding" restraint or closure moments (moments which would conservatively act to close the leakage flaw and reduce the calculated leakage per unit crack length) which were calculated based on your analysis of the least compliant representative system from any of the three units (KNPP, Prairie Island 1 and 2) which provided information for report SIR-00-045, Rev. 0. It is the staff's understanding that in your analysis the greatest restraint moments were calculated and used to reduce the KNPP plant-specific moments from the piping analysis in order to account for their effect on the leakage flaw size determination (as reflected in the information in Tables 5-16, 5-17, and 5-18), but were not used to modify your analysis of the critical flaw size. 8.3.1 Response The restraint moments in Tables 5-13 to 5-15 of SIR-00-045, Rev. 1, were based on three typical lines at Prairie Island and KNPP which exhibited the highest thermal expansion moments. These lines were judged to be the stiffest of the 6" and 8" lines at the two plants. The stiffest lines were chosen since they would offer the greatest restraint to crack opening. The specific lines represented are:

                   -   6" Cold Leg SI Line - KNPP, Loop B (Table 5-13)
                   -   6" Draindown Line - Prairie Island Unit 2 (Table 5-14) - no such line at KNPP
                   -   8" Hot Leg RHR Line - Prairie Island Unit 1, Loop A (Table 5-15)

Tables 5-16 to 5-18 show the effects of restraint on the leakage for the lines. The moment loadings for these lines at Prairie Island have been extracted from the SI LBB report for Prairie Island and are included in Table D-I to D-6 so that you may review the choice of the lines selected for addressing piping restraint effects. It is confirmed that no credit was taken for the effect of piping restraint in calculating critical flaw size. If one were to consider this effect, the calculated critical flaws size (and associated leakage flaw size) would increase, which would result in increased leakage for some cases. Since the effects of restraint were shown to be insignificant, no credit was taken for restraint effects that could increase the critical flaw size. SIR-00-045, Rev. 2 C-17

• StructuralIntegrity Associates

Table D-1 Moments for the 6-inch Safety Injection Piping Attached to Reactor Pressure Vessel and Cold Leg (Prairie Island Unit 1) Thermal + DW Thermal + DW + DBE Nodes Moment, ft-lbs Moment, ft-lbs M, my Mz SRSS") M, M, Mz SRSS(* 1 1621(2) -343 552 -337 732 -967 810 -1073 1656 1622(2) -145 552 -386 689 -611 810 -934 1379 1630(2) 1136 552 -702 1445 1714 810 -1386 2348 1640A(2 ) 1246 552 -730 1546 1898 810 -1492 2546 1640B(2) 1262 466 -641 1490 1994 1008 -1713 2815 1645(2) 1151 438 -579 1361 1835 1080 -1677 2710 164602) 1245 409 -632 1455 1929 1153 -1730 2836 1045(2) -389 248 392 605 -589 534 610 1002 1040(2) -23 258 192 322 -215 524 402 695 1025 -220 9 -6 220 -278 77 -158 329 1027 -231 9 -7 231 -299 77 -185 360 1030 -252 9 -12 252 -338 77 -238 420 1031 -274 9 -16 275 -382 77 -296 489 1039A -274 9 -16 275 -382 77 -296 489 1039B -390 24 -229 453 -690 100 -943 1173 1040 -390 24 -229 453 -690 100 -943 1173 1045 -463 33 -388 605 -883 115 -1364 1629 1236 153 -226 59 279 269 -654 91 713 1238 202 -226 53 308 258 -654 107 711 1250 243 -226 48 335 287 -654 160 732 1259 284 -226 44 366 370 -654 218 782 1260A 284 -226 44 366 370 -654 218 782 1260B 499 -194 428 685 627 -566 660 1072 1265 499 -194 428 685 627 -566 660 1072 1270 764 -151 993 1262 888 -453 1235 1587 Notes: (1) SRSS= M* +MY +Mz (2) These nodes are on the safety injection lines attached to the reactor pressure vessel. SIR-00-045, Rev. 2 C-18 Structural IntegrityAssociates

Table D-2 Moments for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Prairie Island Unit 1) DW + TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs M I M, M" SRSS" Mx [M I M. SRSSO) 2000 2825 -4723 14998 15976 4159 -8507 15790 18412 2005 3689 -3859 11658 12822 4455 -6881 12044 14569 2010A 3689 -3859 11658 12822 4455 -6881 12044 14569 2010B 4094 -3691 11398 12661 4774 -6567 11562 14128 2015 4094 -3691 11398 12661 4774 -6567 11562 14128 2020A 4094 -3691 11398 12661 4774 -6567 11562 14128 2020B 3006 -3675 9359 10494 3728 -6105 9631 11997 2025 3006 -3675 9359 10494 3728 -6105 9631 11997 2030 -2945 -3625 -1597 4936 -3311 -5163 -2679 6693 2035 -9389 -3576 -13459 16795 -10227 -5490 -15835 19634 2040A -9389 -3576 -13459 16795 -10227 -5490 -15835 19634 2040B -10819 -3560 -16125 19742 -11669 -5604 -18253 22377 2045 -10819 -3560 -16125 19742 -11669 -5604 -18253 22377 2050 -9109 -3560 -13070 16324 -9963 -5622 -13542 17727 2055 -4834 -3560 -5432 8096 -6714. -5604 -10032 13309 2060 -487 -3560 2332 4284 -2839 -5604 10480 12219 2070A -487 -3560 2332 4284 -2839 -5604 10480 12219 2070B -4522 -1086 83 4651 -7000 -2554 9525 1.2093 2075 -4522 -1086 83 4651 -7000 -2554 9525 12093 2324 6686 -2680 -6842 9935 11788 -3530 -15364 19684 2326 7131 -4112 -6023 10200 12947 -5592 -13205 19320 (1) SRSS=,M' +V M M SIR-00-045, Rev. 2 C-19 V StructuralIntegrity Associates

Table D-2 (continued)Moments for the 8-inch Residual Heat Removal Piping'Attached to Hot Leg (Prairie Island Unit 1) DW + TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs M, M, Mý SRSS"' M,, MI Mz" SRSSO). 2328A 7131 -4112 -6023 10200 12947 -5592 -13205 19320 2328B 63 39 -5552 -4464 9536 11773 -9268 -7676 16835 2330 4841 -5552 -3700 8243 9023 -9268 -4256 13617 2332 506 -5552 -2689 6190 3582 -9268 -3957 10695 2334 -1470 -5552 -2227 6160 -3836 -9268 -3851 10744 2336 -5585 -5552 -1267 7976 -6523 -9268 -3689 11919 2338 -6902 -5552 -959 8910 -7350 -9268 -3471 12327 2340A -6902 -5552 -959 8910 -7350 -9268 -3471 12327 2340B -7331 -4900 -380 8826 -8029 -8378 -1524 11704 2342 -7331 -4900 -380 8826 -8029 -8378 -1524 11704 2344 -7040 -3780 155 7992 -9026 -6884 1497 11450 2346A -7040 -3780 .155 7992 -9026 -6884 1497 11450 2346B -7591. -3128 507 8226 -10607 -6048 3261 12638

.2348     -7591     -3128        507    8226       -10607    -6048     3261       12638 2350A      -7591      -3128       506    8226       -10607    -6048     3260       12638 2350B      -8059      -2933       642    8600       -11261   '-5801     3860       13242 2352     -8059      -2933     *642     8600       -11261    -5801     3860     ' 13242 2354     -8482      -2511       755    8878       -11856    -5271     5005        13907 (1) SRSS= M2 +M1 +M1 SIR-00-045, Rev.-2                      C-20 V. StructuralIntegrityAssociates

Table D-3 Moments for the 6-inch RCS draindown Line Attached to Hot Leg (Unit 1) DW+TE DW+TE+SSE Nodes Moment, ft-lbs Moment, ft-lbs

    -..... M      M,         Mz       SRSS'       M,      M:  I            SRSS' 730      -883     79        594       1067     -1117     631    1144       1719 720       883    -37       -269       924       1117    -579    -803       1493 (1) SRSS = VM' + MyM+M SIR-00-045, Rev. 2                    C-21 StructuralIntegrityAssociates

Table D-4 Moments for the 6-inch Safety Injection Piping Attached to Reactor Pressure Vessel and Cold Leg (Prairie Island Unit 2) Thermal + DW Thermal + DW + DBE Nodes Moment, ft-lbs Moment, ft-lbs M" MY M" SRSS(n) M" MY Mz SRSS(1) 695(2) 425 920 -703 1233 791 1144 -1593 2115 690(2) 822 2907 -1073 3206 1954 3513 -2679 4831 685B(') 822 2907 -1073 3206 1954 3513 -2679 4831 685A(2) 936 3012 -1114 3345 2212 3638 -2774 5082 680(2) 936 3012 -1114 3345 2212 3638 -2774 5082 675(2) 1146 2861 -1088 3268 2666 3485 -2740 5173 552(2) 2410 -555 -30 2473 2932 -1149 -114 3151 551(2) 2082 -555 -10 2155 2554 -1149 -182 2806 550B(2) 2082 -555 -10 2155 2554 -1149 -182 2806 550A(2) 2276 -837 -490 2474 2622 -1329 -938 3086 548(2) 2276 -837 -490 2474 2622 -1329 -938 3086 558 438 27 126 457 626 31 240 671 560 501 27 155 525 687 31 267 738 562 626 27 213 662 806 31 323 869 564 753 27 271 801 933 31 393 1013 566A 753 27 271 801 933 31 393 1013 566B 781 139 456 915 869 147 764 1166 568 781 139 456 915 869 147 764 1166 570 721 215 566 941 747 227 990 1261 826 -850 47 -251 888 -1002 69 -359 1067 828 -954 47 -279 995 -1130 69 -401 1201 830A -954 47 -279 995 -1130 69 -401 1201 830B -967 133 -437 1069 -1149 169 -581 1299 832 -967 133 -437 1069 -1149 169 -581 1299 834 -909 191 -545 1077 -1085 237 -703 1314 Notes: (1)SRSS= M +M +Mz (2) These nodes are on the safety injection lines attached to the reactor pressure vessel. SIR-00-045, Rev. 2 C-22 C StructuralIntegrity Associates

Table D-5 Moments for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Prairie Island Unit 2) DW + TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs M7 M, M,, SRSS(1) M, I M, Mz, SRSS(') 100 173 -1298 8580 8679 2321 -2920 12374 12924 101 920 -698 7381 7471 2010 -2848 12011 12507 105A 920 -698 7381 7471 2010 -2848 12011 12507 105B 1163 -566 6842 6963 2375 -2834 11540 12118 106 1163 -566 6842 6963 2375 -2834 11540 12118 llOA 1163 -566 6842 6963 2375 -2834 11540 12118 l10B 1377 -517 6263 6433 2095 -2425 9011 9564 111 1377 -517 6263 6433 2095* -2425 9011 9564 112 1382 -429 6247 6412 1974 -1685 6851 7326 l15A 1382 -429 12247 12332 1974 -1685 12851 13110 115B 1671 -380 5409 5674 2439 -1312 7777 8255 116 1671 -380 5409 5674 2439 -1312 7777 8255 117 3417 -380 510 3476 4659 -1312 4182 6397 118 5163 -380 -4388 6786 6553 -1312 -8290 10648 119 6111 -380 -7049 9337 6653 -1312 -10047 12121 120A 6111 -380 -7049 9337 6653 -1312 -10047 12121 120B 5442 -266 -6053 8144 5704 -930 -7881 9773 121 5442 -266 -6053 8144 5704 -930 -7881 9773 246 -2120 -6479 -310 6824 -11834 -9801 -30858' 34472 249A -2120 -6479 -310 6824 -11834 -9801 -30858 34472 249B -1536 -8376 2590 8901 -11768 -11156 32974 36745 250 -1536 -8376 2590 8901 -11768 -11156 32974 36745 251 -1190 -8376 3941 9333 -10978 -11156 32941 36470 (1)SRSS = VM' + M, + M, SIR-00-045, Rev. 2 C-23 StructuralIntegrity Associates

Table D-5 (continued) Moments for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Prairie Island Unit 2) DW + TE DW+TE+SSE Nodes Moment, ft-lbs _ Moment, ft-lbs MM [ ,] Mý I SRSS() M" M_ Mz J SRSS( 251 -1190 -8376 3941 9333 -10978 -11156 32941 36470 252 3655 -8376 22854 24613 7235 -11156 32492 35107 253 5730 -8376 30961 32582 6686 -11156 31831 34386 254 7517 -8376 33282 35133 8983 -11156 36458 39171 255A 7517 -8376 33282 35133 8983 -11156 36458 39171 255B 8278 -6990 30527 -32393 9932 -9582 35223 37830 256 8278 -6990 30527 32393 9932 -9582 35223 37830 257 1864 82 4066 4474 2366 1768 8294 8804 258 -3997 7153 -20112 21717 -6559 7299 -32834 34269 260A -3997 7153 -20112 21717 -6559 7299 -32834 34269 260B -2996 8540 -21871 23670 -5352 8806 -32447 34044 261 -2996 8540 -21871 23670 -5352 8806 -32447 34044 262 5324 8540 -11063 14955 5486 8806 -15809 18909 263 10402 8540 -4465 14180 12090 8806 -19119 24274 265A 10403 8540 -4465 14181 12091 8806 -19119 24275 265B 10926 7540 -1922 13414 12658 8888 -19746 25082 266 10926 7540 -1921 13413 12658 8888 -19745 25082 270 9494 3022 4393 10889 +10384 9356 28873 32078 (1) SRSS = M +My +MYz SIR-00-045, Rev. 2 C-24 OZ StructuralIntegrity Associates

Table D-6 Moments for the 6-inch RCS Draindown Line Attached to Hot Leg (Prairie Island Unit 2) DW + TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs M, M, M,. ISRSS"l) .... M, M M, SRSS() 10 288 -39 442 529 454 -361 542 794 _7 340 68 -409 536 -520 418 -521 847 (1) SRSS= vM* +M +M SIR-00-045, Rev. 2 C-25 C StructuralIntegrity Associates

APPENDIX D NRC SAFETY EVALUATION (Reference 34) SIR-00-045, Rev. 2 D-0

                                        &ý StructuralIntegrity Associates

September 5, 2002 Mr. Thomas Coutu Site Vice President and Interim Plant Manager Kewaunee Nuclear Power Plant Nuclear Management Company, LLC N490 State Highway 42 Kewaunee, WI 54216

SUBJECT:

KEWAUNEE NUCLEAR POWER PLANT - REVIEW OF LEAK-BEFORE-BREAK EVALUATION FOR THE RESIDUAL HEAT REMOVAL, ACCUMULATOR INJECTION LINE, AND SAFETY INJECTION SYSTEM (TAC NO. MB1301)

Dear Mr. Coutu:

By letter dated February 23, 2001, supplements dated February 28, and June 24, 2002, the Nuclear Management Company, LLC (NMC) submitted a request for the Nuclear Regulatory Commission (NRC) to review and approve the leak-before-break (LBB) evaluation at the Kewaunee Nuclear Power Plant (KNPP) for portions of the residual heat removal, accumulator injection line, and safety injection system piping. The submittal was made in accordance with the provisions of Title 10 of the Code of Federal Regulations, Part 50, Appendix A, General Design Criteria 4, which permits licensees to exclude the dynamic effects associated with postulated pipe ruptures from the facility's licensing basis if "analyses reviewed and approved by the Commission demonstrate that the probability of fluid system piping rupture is extremely low under conditions consistent with the design basis for the piping." The NRC has accepted the use of LBB evaluations consistent with the guidance provided in NRC NUREG-1061, Volume 3, "Report of the U.S. Nuclear Regulatory Commission Piping Review Committee, Evaluation of Potential for Pipe Breaks," and Draft Standard Review Plan Section 3.6.3, "Leak-Before-Break Evaluation Procedures," as providing such a demonstration. The NRC staff has completed its evaluation of the information submitted by NMC. The information provided by NMC was sufficient for the NRC staff to verify, through the use of independent NRC staff evaluations, that NMC's evaluation was consistent with the aforementioned NRC staff guidance and that the results of the NMC and NRC staff's evaluations support the approval of LBB for the KNPP piping segments addressed in the submittal. SIR-00-045, Rev. 2 D-1

• StructuralIntegrity Associates

T. Coutu The enclosed safety evaluation documents the NRC staff's conclusions. This completes our efforts for TAC No. MB13301. Sincerely, IRAI John G. Lamb, Project Manager, Section 1 Project Directorate III Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket No. 50-305

Enclosure:

Safety Evaluation cc w/encl: See next page SIR-00-045, Rev. 2 D-2 V StructuralIntegrity Associates

ML022400097 OFFICE PDIII-1/PM PDIII-1/LA EMCB/SC SPLB/SC PDIII-1/SC NAME JLamb THarris SCoffin SWeerakkody LRaghavan DATE 08/299/02 .08/29/02 09/04/02 08130102 09/05/02 SAFETY EVALUATION OF THE REQUEST TO APPLY LEAK-BEFORE-BREAK STATUS TO THE RESIDUAL HEAT REMOVAL (RHR), ACCUMULATOR INJECTION LINE, AND SAFETY INJECTION SYSTEM (SIS) PIPING AT KEWAUNEE NUCLEAR POWER PLANT

1.0 INTRODUCTION

By letter dated February 23, 2001, the Nuclear Management Company, LLC (NMC), the licensee for the Kewaunee Nuclear Power Plant (KNPP), submitted a request for the United States Nuclear Regulatory Commission (NRC) review and approval of their leak-before-break (LBB) evaluations for portions of the KNPP residual heat removal (RHR), accumulator injection, and safety injection system (SIS) piping.Y11 In their submittal, NMC included Structural Integrity Associates topical report SIR-00-045, "Leak-Before-Break Evaluation, 6-inch to 12-inch Safety Injection and Residual Heat Removal Piping Attached to the Reactor Coolant System (RCS), Kewaunee Nuclear Power Plant," which provided the technical basis for their request. The NRC issued requests for additional information (RAls) regarding the licensee's submittal on January 31, 2002, and May 23, 2002.12'3] NMC supplemented the information in their original submittal by letters dated February 28, 2002, and June 24, 2002, in response to the NRC staffs RAI.M5'] The June 24, 2002, NMC submittal also included Revision 1 to SIR-00-045. .The NMC submittal was made to support the exclusion of the dynamic effects of pipe rupture from the KNPP licensing basis.

2.0 REGULATORY EVALUATION

As addressed in Title 10 of the Code of Federal Regulations Part 50, Appendix A, General Design Criteria 4, nuclear power plant structures, systems, and components important to safety shall be appropriately protected against dynamic effects, including the effects of missiles, pipe whipping, and discharging fluids, that may result from equipment failures and from events and conditions outside the nuclear power unit. However, dynamic effects associated with postulated pipe ruptures may be excluded from the facility design (or licensing) basis when' analyses reviewed and approved by the Commission demonstrate that the probability of fluid system. piping rupture is extremely low under conditions consistent with the design basis for the piping. Formal, rigorous, LBB evaluations consistent with NRC staff guidance (e.g., NUREG-1061, Volume 3, draft Standard Review Plan 3.6.3) have been accepted by the staff as an acceptable demonstration of this extremely low probability of piping rupture. '6,7] LBB evaluations also rely in part on the capability of a facility's RCS leakage detection system. NRC Regulatory Guide 1.45 1 38 provides staff guidance on the design and evaluation of RCS leakage detection systems. SIR-00-045, Rev. 2 D-4 Struc8uCIInte'grJVLAssociates StruchN O.SU

• 1

3.0 TECHNICAL EVALUATION

3.1 Licensee's Evaluation This section of this safety evaluation (SE) describes: (1).the scope (i.e., piping segments evaluated) of the licensee's LBB evaluations, (2) the licensee's evaluation of the RCS leakage detection system capability, (3) the analysis methodology used by the licensee in their LBB evaluation, and (4) the results of the licensee's analysis and their conclusions regarding the application of LBB to the subject piping segments.

      .3.1.1 Scope of the Licensee's LBB Evaluation In Reference 5, NMC defined the scope of the piping within the RHR, accumulator injection, and SI system piping for which they sought to apply LBB. For the RHR system, the licensee's LBB Ievaluati      'on addressed the 8-inch diameter nominal pipe size (NPS) piping~in RHR Loop A from its connection to the Loop A hot leg outlet nozzle to RHR isolation valve RHR-1A and the 8-inch NPS piping in RHR Loop B from its connection to the Loop B hot leg outlet nozzle to RHR 3      ,isolation valve RHR-1B. For the SI system, the licensee's LBB evaluation addressed the 6-inch diameter NPS piping in SI Loop A from its connection to the Loop A cold leg inlet nozzle to SI
       -check valve SI-13A and the 6-inch NPS pipingin Sl Loop B from its connection to the Loop B I        cold leg inlet nozzle to SI check valve SI-13B. For the accumulator injection system, the licensee's LBB evaluation addressed the 12-inch diameter NPS piping in accumulator injection Loop A from its connection to'the Loop A cold leg to check valve SI-22A and the 12-inch NPS

• piping in accumulator Loop B from its connection to the LoopB cold leg to check Valve SI-22B.

Finally, the licensee's analysis addressed the application of LBB to one six-inch capped nozzle on each of the Loop A and Loop' B hot legs.. Each of the piping sections which were analyzed for LBB behavior in this application was constructed from either schedule 140 or 160 wrought austenitic A-376, Type 316 stainless steel. The piping welds were fabricated using a gas tungsten arc welding process for the root pass 3 and filled using a shielded metal arc welding (SMAW) process. No cast austenitic stainless steel (CASS) or Inconel Alloy 600 piping1 elbows, or safe ends were used to construct the analyzed piping sections. Further, no Inconel Alloy 82 or 182 material was used in the fabrication of any welds in the analyzed piping sections. 3.1.2 Licensee Evaluation of the RCS Leakage Detection System I The capability of the RCS leakage detection system was addressed in Section 1.3 of SIR .045. The licensee noted that detailed information on the RCS leakage detection system is provided in Section 6.5 of the facility's Final Safety Analysis Report (FSAR) and provided their assessment regarding the four most important detection instruments/methods which contribute to the overall sensitivity of the RCS leakage detection system: (1) the R-1 1 Containment System Air Particulate Monitor, (2) the R-12 Containment Radiogas Monitor, (3) humidity I detection instrumentation, and (4) monitoring of leakage into, and removal from, the, containment sumps. As an integrated system, the licensee concluded that the RCS leakage detection system was capable of detecting a leak rate of 0.25 gallons per minute (gpm), In addition, the licensee noted that the NRC had previously acknowledged a 0.25 gpm sensitivity for the R. E. Ginna RCS leakage detection system.191 NMC concluded that the R. E. SIR-00-045, Rev. 2 D-5 StructuralIntegrityAssociates e

Ginna RCS leakage detection system was sufficiently similar to the KNPP RCS leakage detection system to also support the use of a corresponding 0.25 gpm leakage detection capability in the NMC LBB evaluation. After reviewing the information in the licensee's submittal and the, FSAR information, the NRC staff requested additional information regarding the capability and availability of those leak detection systems based on the plant operating experience. In response to the RAI, the licensee provided additional information in Reference 4 about the capability of the R-1 1 Containment System Air Particulate monitor, the R-12 Containment Radiogas Monitor, and the R-21 Containment Vent Monitor, under various conditions of dispersion (from 100 percent to 1 percent for particulate) and reactor coolant radioactivity (from 1 percent to 0.1 percent fuel failure). The lower bound dispersion factor value of 1 percent was corresponding to the worst case dispersion of the particulate to account for entrapment in piping insulation, plateout on containment structures and components, and sensor location mismatches. The licensee verified the assumption of complete mixing based on the sensor location and the design and operation of the containment fan coil units. The piping from containment to R-11, R-12, and R-21 is not insulated; therefore, the plateout of radionuclides on the pipe is minimized. Under the condition of 0.1 percent fuel failure along with 1 percent dispersion, the licensee has determined that R-1 1 is able to detect a 0.25 gpm RCS leak within 90 minutes. In Reference 4, the licensee also determined the availability of the R-1 1 Containment System Air Particulate Monitor to be 98.5 percent, which was based on the data from its plant information system and plant process computer system for the period from 1997 - 2001. The licensee further discussed the redundancy and diversity of its leak detection systems as specified in its plant technical specifications. There are two RCS leak detection systems of different operating principles at the plant, and one of the two systems is sensitive to radioactivity. Either system may be out of operation for up to 12 hours provided at least one system is operational. If R-1 1 is found to be out-of-service (OOS), the plant can only continue to operate if within 12 hours another RCS leak detection system sensitive to radiation is placed in service. At the KNPP, this other leak detection system is a gaseous radiation monitor, R-12, or containment vent monitor, R-21. The plant operating procedures state that if R-1 1 is found OOS, the operators are directed to align R-21 to sample containment. The licensee also stated that both R-21 and R-12 are capable of detecting RCS leakage of 0.25 gpm within 20 minutes assuming 0.1 percent fuel failure and 100 percent dispersion. 3.1.3 Licensee's LBB Evaluation Methodology The licensee's LBB evaluation methodology is summarized in topical report SIR-00-045 and additional information regarding it was provided in Reference 5. The following description briefly addresses general aspects of the licensee's methodology which are consistent with 19 methodologies which have served as the basis for prior LBB submittals by other licensees. ] Specific aspects of the licensee's methodology, which are atypical when compared to the methodologies used to support a majority of prior NRC staff LBB approvals, are discussed in additional detail. The licensee's general methodology was constructed around analytical concepts consistent with the guidance provided in References 6 and 7. First, the licensee established that for the subject piping segments that no active degradation mechanisms (flow accelerated corrosion, stress corrosion cracking, fatigue) were expected in the subject piping. Further, the licensee SIR-00-045, Rev. 2 D-6 r Structural Integrity Associates

established that no unanalyzable loading events (water hammer) would be expected to occur in the subject piping systems. The evaluation of these topics was provided in Section 3.0 of SIR-00-0145. Next, the licensee established material property parameters, operating conditions, and piping moments and membrane stresses for use in their LBB analyses. The material property parameters used in the licensee's analysis were given in Section 4.2 and summarized in Table 4-2 of SIR-00-145. The material property parameters used addressed both the tensile and fracture toughness properties of the SMAW welds. The licensee chose to only analyze the SMAW welds (and not the wrought austenitic base metal material) because of their potential for low initial toughness and susceptibility to loss of toughness through thermal aging, and the SMAW welds were expected to be the most limiting material with regard to achieving acceptable margins in the LBB analysis. The licensee concluded that the tensile and fracture toughness properties used in their analysis would bound the expected behavior for fully aged SMAW weld material. The operating conditions for which the subject piping was analyzed included 100 percent power operation at normal operating condition (NOP) and 100 percent power operation in conjunction with a safe shutdown earthquake (NOP+safe shutdown earthquake (SSE)). Although this submittal was initially made prior to the replacement of the KNPP stream generators (which occurred in Fall 2001), the pressure and temperature conditions assumed in the analysis were chosen to bound the post-steam generator replacement operating conditions. The piping moments (summed algebraically) considered in the licensee's LBB evaluation included those due to pressure, dead weight, and thermal expansion under NOP conditions and pressure, dead weight, thermal expansion, and SSE inertia under NOP+SSE conditions. The piping membrane stresses (as related to axial loads and summed. algebraically) used in the analyses were limited to the contribution from internal pressure since the "la]xial loads due to dead weight, thermal expansion, and seismic were not available from the piping stress analysis ....The stresses due to axial loads [from these sources] are not significant compared to those from pressure loads, so their exclusion does not significantly affect the results of the evaluation." Since the NRC staff guidance on LBB evaluations effectively requests that all axial loading sources be considered in an LBB evaluation, the NRC staff requested additional information from the licensee to support this assumption.16'7] NMC provided additional information to support their assumption in their response to NRC staff Question #5 in Reference 5.' Based on the material property, operation condition, and loading information noted above, the licensee implemented their LBB evaluation. Their process involved first defining the "critical crack lengths," the length of a throughwall circumferential crack at every SMAW weld (nodal) location in the analyzed piping which would be predicted to lead to gross piping failure under NOP+SSE loading conditions. The licensee analyzed each nodal location for its critical flaw length using both elastic-plastic fracture mechanics (EPFM) techniques and net section collapse techniques. The final "critical crack length" for each nodal location was then taken as the minimum of the EPFM and net section collapse results. The licensee then reduced the calculated critical crack lengths by a factor of 2 and defined this quantity to be the "leakage crack lengths" for each nodal location. This relationship between the critical crack length and leakage crack length results from the guidance in References 6 and 7 which specifies that a "margin" or "safety factor" of 2 should exist between the critical and leakage crack lengths in an acceptable LBB evaluation. SIR-00-045, Rev. 2 D-7

• StructuralIntegrity Associates

Having now defined the leakage crack length for each nodal location, the licensee then assessed the rate of leakage (in gpm) expected from the leakage crack length at each nodal location based on the NOP moments and stresses and assumed crack morphology parameters. The important crack morphology parameters required for an LBB evaluation are the surface roughness and number of turns (45 degree and/or 90 degree) along the plane of the crack. The crack morphology parameters are important because they define the impedance to fluid flow which occurs as a result of the crack not being a smooth throughwall slit in the piping. The licensee concluded that the crack morphology parameters assumed in their LBB analysis in Reference 1 were consistent with fatigue or corrosion-fatigue crack morphology observations. The licensee then determined the projected leakage at each nodal location through the use of the PICEP (Pipe Crack Evaluation Program), Revision 1 analytic code.11 01 The rate of leakage calculated for each nodal locations' leakage crack length was then compared to the established sensitivity of the KNPP RCS leakage detection system (see Section 3.1.2 of this SE). For an acceptable LBB evaluation, the rate of leakage from each nodal location's leakage crack length should be greater than the facility's leakage detection capability by a factor of 10 .16. Hence, for KNPP, the licensee demonstrated that each nodal location's leakage crack length would leak at a rate equal to, or greater than 2.5 gpm under NOP loading conditions. Two additional considerations, which were not addressed in prior LBB evaluations because they either did not apply or because a technical issue was not known to exist, were then addressed by the licensee. The first of these was addressed in the licensee's initial submittal and resulted from the licensee's request to apply LBB to unusually small diameter piping systems, in particular the 6-inch NPS lines. This consideration is termed "restraint of pressure-induced bending." Pressure-induced bending occurs when, due to the presence of a flaw at a specific location, the neutral bending axis of the pipe's cross-section becomes displaced from the pipe pressure center. This displacement causes a resultant bending moment at the flawed location. For large diameter, thick-walled piping, this effect is negligible. For small diameter piping which. may have a relatively thin wall thickness, the effect may be significant. Ifthe piping were perfectly free to rotate at the plane of a throughwall flaw, as is assumed in the computer codes used to evaluate leakage in the LBB analysis, the moment due to pressure-induced bending would increase the crack opening and increase the amount of leakage for a given leakage crack length. However, in general, facility piping systems are not perfectly free to rotate at any given location to due the presence of anchors attached to the piping system. These anchors provide a "restraint" to the pressure-induced bending and serve to reduce the crack opening area for a throughwall flaw. This restraint effect must be accounted for when LBB is applied to lines which may exhibit pressure-induced bending effects because, ifit were not, a non-conservative (i.e., greater than actual) evaluation of the leakage would result. Consistent with guidance provided in NUREG/CR-6443, the licensee evaluated the effect of the restraint of pressure-induced bending on both the 8-inch and 6-inch NPS lines in the KNPP LBB evaluation.["] To do this, NMC evaluated lines for both KNPP and Prairie Island Units I and 2 (at the time SIR-00-0145 and the KNPP LBB submittal were being developed, a similar LBB application was being prepared by NMC for the Prairie Island units) to determine which of the potentially affected lines exhibited the greatest degree of stiffness, with the stiffer lines exhibiting the greatest restraint to pressure-induced bending. The licensee assessed the inherent stiffness of the KNPP and Prairie Island piping systems by examining the thermal anchor stresses at anchor locations. Based on this assessment, the licensee took the SIR-00-045, Rev. 2 D-8

• StructuralIntegrity Associates

                                                "bounding" characteristics of the stiffest systems and determined what the maximum reduction in leakage rates would be expected to be for each of the subject piping systems due to restraint of pressure-induced bending.

The second additional consideration which the licensee addressed concerned the assumed crack morphology parameters in their leakage assessment. The licensee's use of crack morphology parameters associated with fatigue or corrosion-fatigue flaws was consistent with prior LBB evaluations which have been found to be acceptable by the NRC staff. However, in Question #6 of Reference 3, the NRC staff noted that due to recent stress corrosion cracking (SCC) events in pressurized water reactor environments, some concern exists over the continued acceptability of the fatigue or corrosion-fatigue flaw assumption for LBB evaluations. However, since the materials and specific environmental conditions associated with the lines for which NMC is requesting LBB approval have not been demonstrated to be subject to any active SCC mechanisms, the NRC staff requested only that NMC perform a leakage rate sensitivity study to further investigate how assuming different crack morphology parameters, for example ones consistent with transgranular SCC of stainless steel, would affect the margins in their LBB analysis. Using data on stainless steel SCC from several sources, the licensee developed flaw morphology parameters which were consistent with both intergranular and transgranular SCC and provided the requested sensitivity study results in Reference 5.[12"13 The licensee then completed their LBB analysis by demonstrating that the leakage crack size defined for each nodal location would be stable under loading conditions greater than the NOP+SSE conditions. References 6 and 7 note that the leakage crack size for each location should be demonstrated to be stable under moments and stresses which a factor of4/2 greater than the NOP+SSE loads when those loads are summed algebraically. The licensee chose to perform this analysis by determining the throughwa!l flaw size which would fail under 42 * (NOP+SSE) loads and demonstrate that it was consistently larger than the leakage flaw size. 3.1.4 Results/Conclusions from the Licensee's LBB Analysis The result of the licensee's LBB analysis for all nodal locations in the KNPP 6-inch SI system lines, 12-inch accumulator injection system lines, 8-inch RHR system lines, and 6-inch nozzles attached to the RCS hot legs are given in Tables 5-10 through 5-12 of SIR-00-0145. Given the way in which the licensee's analysis was conducted (as noted in Section 3.1.3 of this SE), an acceptable LBB analysis result was achieved if, for each nodal location, the leakage flaw size produced a leakage rate under NOP conditions of 2.5 gpm or greater (that is, a leakage rate which is a factor of 10 greater than the 0.25 gpm RCS leakage detection system sensitivity assumed by the licensee). For the 6-inch SI system piping, the minimum leakage rate from any nodal location was 5.189 gpm. For the 12-inch accumulator injections system piping, the minimum leakage rate from any nodal location was 30.128 gpm. For the 8-inch RHR system piping, the minimum leakage rate from any nodal location was 7.480 gpm. Finally, for the 6-inch nozzles attached to the RCS hot legs, the leakage rate for the single analyzed nodal location was 3.740 gpm. The leakage rate information cited above does not include leakage rate modifications to address the issue of restraint of pressure-induced bending. The licensee provided separate information SIR-00-045, Rev. 2 D-9

• Structural Integrity Associates

in Tables 5-16 and 5-17 of SIR-00-0145 which indicated that the maximum leakage rate reduction due to the restraint of pressure-induced bending would be expected to be less than 0.05 gpm for nodal locations in the 6-inch KNPP SI system piping and less than 1.7 gpm for nodal locations in the 8-inch KNPP RHR system piping. The 12-inch accumulator system piping was not analyzed since its diameter and wall thickness was judged to make the effects of pressure-induced bending negligible. The 6-inch nozzles attached to the RCS hot legs were not analyzed since their capped ends were unrestrained and free to rotate. Considering these adjustments, all nodal locations in each of the analyzed piping sections would still exceed the 2.5 gpm limit established by the licensee for an acceptable LBB evaluation. Finally, as requested by the NRC. staff, the licensee presented the results of their leakage rate sensitivity study in Reference 5. For their sensitivity analysis, the licensee focused on the 6-inch nozzles attached to the RCS hot legs, which their prior results indicated had the smallest

'margin" in the baseline LBB analysis. As noted in Section 3.1.3 above, the license developed flaw morphology parameters consistent with both intergranular and transgranular SCC and determined what the leakage rate would be from the leakage size flaw (5.42 inches in length) and from a flaw 1.5 times the size of the leakage size flaw (8.13 inches in length). Based on their range of credible flaw morphology parameters, the licensee concluded that the leakage rate from the leakage flaw size, if it were a SCC-type flaw, could range from 0.33 to 0.60 gpm.

For a flaw 1.5 times the size of the leakage size flaw, the range of leakage rates was 3.43 to 6.63 gpm. Based on these results, the licensee concluded that, when SCC flaw morphology parameters were considered: (1) the leakage rate from the leakage flaw size would still exceed the KNPP RCS leakage detection system capability and a margin of 2 between the leakage and critical size flaw would be maintained, or (2),a larger flaw (1.5 times the leakage size flaw) would produce sufficient leakage to maintain the prescribed margin of 10 on leakage detection while still maintaining some margin (in this case 1.33) on flaw size when compared to the critical size flaw. 3.2 NRC Staff Evaluation 3.2.1 Scope of the Licensee's LBB Evaluation The NRC staff~reviewed the scope of the NMC LBB evaluation and concluded that the licensee adequately defined the analyzable portions of the piping systems (as given in Section 3.1.1 of this SE) for which they sought LBB approval. The staff concluded that since the defined piping segments do not include any Inconel Alloy 600 components or Inconel Alloy 82/182 welds, they are candidates for LBB approval at this time. Inconel Alloy 600 components and Inconel Alloy 82/182 welds may be degraded by primary water SCC and are the ongoing topic of interactions between the NRC and the industry regarding actions necessary to support LBB approval on lines containing such materials. Since no CASS piping, elbows, or safe ends were present in the piping sections that the licensee analyzed, the NRC staff agrees with the licensee's conclusion that the SMAW welds would be limiting with respect to LBB analyses when compared to the wrought austenitic base metal from which the piping was fabricated. In addition, the NRC staff reviewed the tensile and fracture toughness material property parameters provided in the licensee's analysis for aged SIR-00-045, Rev. 2 D-10

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SMAW welds. The NRC staff concluded that the material property parameters used by the licensee were consistent with, or more conservative than, those used by the NRC staff for independent analyses in prior LBB applications. 3.2.2 NRC Staff Evaluation of the KNPP RCS Leakage Detection System Based on the evaluation provided by the licensee regarding the KNPP RCS leakage detection system capability, availability, diversity, and redundancy, the NRC staff concluded that the KNPP leakage detection systems may be credited with the sensitivity to detect a leakage rate of 0.25 gpm in support of the requested LBB approval. 3.2.3 NRC Staff Independent LBB Evaluation Methodology The NRC staff conducted an independent LBB analysis of limiting nodal locations in the subject piping segments as part of the review of the licencee's submittal. In this case, "limiting" nodal locations were defined as those locations for which the licensee's analysis demonstrated that the minimum margins existed for LBB approval. The NRC staff's analysis was performed in accordance with the guidance provided in NUREG-1061, Vol. 3. Based on the information submitted by the licensee, the NRC staff determined the critical flaw size at selected nodal locations for each piping system using the codes compiled in the NRC's Pipe Fracture Encyclopedia. 1 141 For evaluating the limiting SMAW pipe welds, the NRC staff used the LBB.ENG3 code developed by Battelle for that express purpose. 115' The LBB.ENG3 methodology is significantly different from the other codes in the Reference 13 and from the licensee's analysis in that LBB.ENG3 explicitly accounts for the differences in the stress-strain properties of the weld and an adjoining base material when determining the effective energy release from the structure with crack extension. The NRC staff then compared the critical flaw size at the selected nodal locations to the leakage flaw size which provided 2.5 gpm of leakage under NOP conditions to determine whether the margin of 2 defined in NUREG-1 061, Vol. 3 was achieved. The leakage flaw size calculation was carried out using the PICEP Program, Revision 1 analytic code. 10 1

                                                                         ° The 2.5 gpm value was defined based upon the licensee's demonstration, and the NRC staff acceptance, of a 0.25 gpm leak rate detection sensitivity for the KNPP RCS leakage detection system and a factor of 10 applied to this 0.25 gpm detection capability to account for thermohydraulic uncertainties in calculating the leakage through small cracks. The stability of the leakage flaw size under loadings a factor of q2 greater than the combination of SSE+NOP loads was subsequently evaluated to check the final acceptance criteria of NUREG-1061, Vol. 3.

'It should be noted that the NRC staff's evaluation did not independently address the leakage rate sensitivity study documented by the licensee in Reference 5, nor did it attempt to independently address'the effect of the restraint of pressure-induced bending on the LBB analysis. Rather, concerning these issues, the NRC staff's review and conclusions were based on information provided by the licensee's analyses. SIR-00-045, Rev. 2 D-1 1

• StructuralIntegrityAssociates

3.2.4 NRC Staff Results and Conclusions The results of the NRC staffs independent LBB evaluation confirmed the licensee's conclusion that the subject piping sections can be shown to exhibit LBB behavior consistent with the guidance in References 6 and 7. The NRC staffs conclusion was based on the NRC staffs calculations (which used flaw morphology parameters consistent with fatigue or corrosion-fatigue flaws for the leakage evaluation) as modified by the information provided by the licensee regarding reductions in leakage rates for each which would result from the restraint of pressure-induced bending. For the portion of each system covered under the NMC submittal, the NRC staff was able to show that a margin of 2 on flaw size between the critical size flaw and leakage size flaw existed, while a margin of 10 existed between the projected leakage rate and the sensitivity of the KNPP RCS leakage detection system. Based upon this information, the NRC staff concluded that LBB had been demonstrated for the analyzed portions of the KNPP' RHR, SI, and accumulator injection systems. As supplemental information, the NRC staff also evaluated the information provided by the licensee in Reference 5 regarding the sensitivity of their LBB analysis to changing flaw. morphology parameters. The changes in leakage identified in the licensee's analysis when going from fatigue flaw morphology to a SCC flaw morphology were consistent with NRC staff -expectations. The NRC staff concluded that, although the licensee's'analysis.did not demonstrate that the standard margins of 2 and 10 on flaw size and leakage, respectively, would be met if a SCC-type flaw were assumed, the licensee's analysis did confirm that some lesser margins would be maintained. Considering the types of material from which the subject KNPP piping segments were constructed and their operating environment, no operating experience exists which would indicate the presence of any active SCC mechanism in these lines. Based on this experience, the NRC staff concluded that there is a lower likelihood of SCC in these lines, when compared to traditional fatigue or corrosion-fatigue cracking mechanisms, such that the NRC staff can accept that the lesser margins demonstrated by the licensee's analysis were sufficient to confirm that LBB may still be granted on the portions of the piping systems for which it was requested.'

4.0 CONCLUSION

The NRC concludes that based on the licensee's submittal and independent NRC staff evaluation that LBB behavior has been demonstrated for the portions of the KNPP RHR, SI, and accumulator ir-Jection systems defined in Section 3.1.1 of this SE. Based on this conclusion and consistent with 10 CFR Part 50, Appendix A, General Design Criteria 4, the licensee shall be permitted to exclude consideration of the dynamic effects associated with the postulated rupture of the analyzed portions of these KNPP systems from the- KNPP design andlor licensing basis. SIR-00-045, Rev. 2 D-12

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5.0 REFERENCES

[i] M. E. Reddemann (NMC) to U.S. Nuclear Regulatory Commission Document Control Desk, "Request to Exclude Dynamic Effects Associated with Postulated Pipe Ruptures From Licensing Basis For Residual Heat Removal, Accumulator Injection, and Safety Injection System Piping Based Upon Leak Before Break Analysis," February 23, 2001. 12] J. G. Lamb (USNRC) to M. Reddemann (NMC), "Kewaunee Nuclear Power Plant - Request For Additional Information Related To Request To Exclude Dynamic Effects Associated With Postulated Pipe Ruptures From Licensing Basis For Residual Heat Removal, Accumulator Injection, and Safety Injection System Piping Based On Leak Before Break Analysis (TAC No. MB1301)," January 31, 2002. [3] J. G. Lamb (USNRC) to M. Warner (NMC), "Kewaunee Nuclear Power Plant - Request For Additional Information Related To Request To Exclude Dynamic Effects Associated With Postulated-Pipe Ruptures From Licensing Basis For Residual Heat Removal, Accumulator Injection, and Safety- Injection System Piping Based On Leak Before Break Analysis (TAC No. MBI 301)," May 23, 2002. [4] M. E. Warner (NMC) to U.S. Nuclear Regulatory Commission Document Control Desk, "Response to NRC Request For Additional Information Concerning Leak Before Break Analysis For Kewaunee Nuclear Power Plant," February 28, 2002. [51 M. E. Warner (NMC) to U.S. Nuclear Regulatory Commission Document Control Desk, "Response to NRC Request For Additional Information Concerning Leak Before Break Analysis For, Kewaunee Nuclear Power Plant," June 24, 2002. [6] United States Nuclear Regulatory Commission NUREG-1061, Volume 3, "Report of the U.S. Nuclear Regulatory Commission Piping Review Committee, Evaluation of Potential for Pipe Breaks," November 1984. [7] United States Nuclear Regulatory Commission, Draft Standard Review, Plan Section 3.6.3, "Leak-Before-Break Evaluation Procedures," published for comment at 52 Federal Register 32626, August 28,1987. [8] United States Nuclear Regulatory Commission Regulatory Guide 1.45, "Reactor Coolant Pressure Boundary Leakage Detection Systems," 1973. [9] G. S. Vissing (USNRC) to R. C. Mecready (RG&E), "Staff Review of the Submittal by Rochester Gas and Electric Company to Apply Leak-Before-Break Status to Portions of

      ,the R. E. Ginna Nuclear Power Plant Residual Heat Removal System Piping (TAC No.

MA0389)," February 25, 1999. [10] ERPI Report NP-3596-SR, Revision 1, "PICEP: Pipe Crack Evaluation Program (Revision 1)," December 1987. [11] NUREG/CR-6443, "Deterministic and Probabilistic Evaluations for Uncertainty in Pipe Fracture Parameters in Leak-Before-Break and In-Service Flaw Evaluations," N. Ghadiali, et. al., June, 1996. SIR-00-045, Rev. 2 D-13 SStructural Integrity Associates

[12] B. Lisowyj, 'Evaluation of Cracking in Type 348 Stainless Steel Control Element Drive Mechanism Housings," Sixth International Symposium on Environmental Degradation of Materials in Nuclear Power Systems-Water Reactors, August 1-5, 1993, San Diego, CA pp. 343-350. [13] EPRI NP-2671-LD, "Alternative Alloys for BWR Pipe Applications," Final Report, October 1982, pp. 4-55, 4-56. [14] Pipe Fracture Encyclopedia, produced on CD-ROM by Battelle-Columbus Laboratory for the U.S. Nuclear Regulatory Commission, 1997. [15] Brust, F.W., et. al., "Assessment of Short Througfi-Wall Circumferential Cracks in Pipes," NUREGICR-6235, BMI-2179. SIR-00-045, Rev. 2 D-14 StructuralIntegrity Associates

Kewaunee Nuclear Power Plant cc: John H. O'Neill, Jr. David Molzahn Shaw Pittman, Potts & Trowbridge Nuclear Asset Manager 2300 N. Street, NW 600 North Adams Street Washington, DC 20037-1128 Green Bay, Wl 54307-9002 David Zellner Thomas Couto, Site Vice President Town Chairman - Town of Carlton Kewaunee Nuclear Plant and Interim N2164 County B Plant Manager Kewaunee, WI 54216 N490, Highway 42 Kewaunee, WI 54216 Larry L. Weyers Chairman, President, and CEO Sarah Jenkins Wisconsin Public Service Corporation Electric Division 600 North Adams Street Public Service Commission of Wisconsin Green Bay, WI 54307-9002 PO Box 7854 Madison, WI 53707-7854 Resident Inspectors Office U.S. Nuclear Regulatory Commission NRC NRR Project Manager N490 Hwy 42 Mail Stop O-8-H-4A Kewaunee, WI 54216-9510 U. S. Nuclear Regulatory Commission Washington, DC 20555 Regional Administrator Region III U.S. Nuclear Regulatory Commission 801 Warrenville Road Lisle, IL 60532-4351 Ave M. Bie, Chairperson Public Service Commission of Wisconsin PO Box 7854 Madison, WI 53707-7854 Roy Anderson Chief Nuclear Officer Nuclear Management Company, LLC 700 First Street Hudson, WI 54016 SIR-00-045, Rev. 2 D-15

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