ML100200131

Report No. 0900634.401, Revision 2, Updated Leak-Before-Break Evaluation for Several RCS Piping at Prairie Island Nuclear Generating Plant, Units 1 & 2.

ML100200131
Person / Time
Site:	Prairie Island
Issue date:	12/21/2009
From:	Jing P Structural Integrity Associates
To:	Office of Nuclear Reactor Regulation, Xcel Energy
References
0900634, L-PI-09-134 0900634.401, Rev 2
Download: ML100200131 (134)

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ENCLOSURE6 STRUCTURAL INTEGRITY ASSOCIATES, INC.

REPORT 0900634.401 REVISION 2 (NON-PROPRIETARY)

UPDATED LEAK-BEFORE-BREAK EVALUATION FOR SEVERAL RCS PIPING AT PRAIRIE ISLAND NUCLEAR GENERATING PLANT UNITS I AND 2 133 pages follow

Report No.: 0900634.401 Revision No.: 2 Project No.: 0900634 File No.: 0900634.401 December 2009 ZQ E] Non-Q Updated Leak-Before-Break Evaluation for Several RCS Piping at Prairie Island Nuclear Generating Plant Units 1 and 2 Preparedfor."

Xcel Energy Contract No. 1006, Release 9 Preparedby:

Structural Integrity Associates, Inc.

San Jose, California Preparedby: Date: Dec 21, 2009 P. Jing Reviewed by.. Date: Dec 21, 2009 H. Qian Approved by: Date: Dec 21, 2009 G. Angah Miessi Report No: 0900634.401 Revision: 2 V StructuralIntegrity Associates, Inc.

REVISION CONTROL SHEET Document Number: 0900634.401

Title:

Updated Leak-Before-Break Evaluation for Several RCS PipinR at Prairie Island Nuclear Generating Plant Units 1 and 2 Client: Xcel Energy Company SI Project Number: 0900634 Section Pages Revision Date Comments 1-8 All 0 Dec. 7, 2009 App. A A1-A4 1-8 All 1 Dec. 14, 2009 Addressed client comments.

App. A Al-A4 4 4-1, 2 Dec. 21,2009 Deleted Westinghouse Proprietary 4-21 -- 4-28 Information 6 6-1,6-6, Changed references per client comments 8 8-1, 8-2, 8-4 Report No: 0900634.401 Revision: 2 V StructuralIntegrityAssociates, Inc.

SUMMARY

This report presents a leak-before-break (LBB) evaluation for piping systems attached to the reactor coolant system (RCS) at Prairie Island Nuclear Generating Plant, Units 1 and 2 (operated by Xcel Energy). The evaluation includes portions of the safety injection (SI) and residual heat removal (RHR) systems.

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 through-wall flaw length which becomes unstable under a given set of applied load. 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 ,52 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 F2. 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.

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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 piping analyses, 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, Prairie Island 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 3.4 gpm under Originally Licensed Thermal Power (OLTP) considering only RHR Normal Thermal. With a margin of 10 on leakage suggested in NUREG-1061 Vol. 3, the leakage detection Report No: 0900634.401 StructuralIntegrity Associates, Inc.

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system at Prairie Island is capable of measuring leakage of 2.0 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 42 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).

6-n) No special testing (other than information in the CMTRs) was conducted to determine material properties for fracture mechanics evaluation. Instead, generic lower bound Revision: 20900634.401 StructuralIntegrity Associates, Inc.

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 could experience a large pipe break prior to leakage detection under Power Uprate Conditions considering RHR Thermal Stratification. Under Uprate Conditions considering RHR Thermal Stratification, it was determined that the leakage meet the LBB acceptance criteria. Additional leakage evaluation using Primary Water Stress Corrosion Cracking (PWSCC) morphology shows that leakage drops to as low as 22% of what is evaluated using fatigue morphology.

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Table of Contents Section Pag*e 1.0 IN T R OD UC T IO N ............................................................................................ ................. 1-1

1. 1 B ack grou n d ...................................................................................................................... 1-1 1.2 Leak-Before-Break Methodology ........................... ........................................................ 1-2 1.3 Leak Detection Capability at Prairie Island ..................................................................... 1-4 2.0 CRITERIA FOR APPLICATION OF LEAK-BEFORE-BREAK ...................................... 2-1 2.1 Criteria for Through-W all Flaw s .................................................................................... 2-1 2.2 Criteria for Part-Through-Wall Flaws ............................................................................. 2-2 2.3 Consideration of Piping Restraint Effects ........................................................................ 2-2 2.4 Consideration of Other Mechanisms ............................................................................... 2-2 3.0 CONSIDERATION OF WATER HAMMER, CORROSION AND FATIGUE ................ 3-1 3.1 W ater H amm er ................................................................................................ ..... 3-1 3 .2 C o rrosio n .......................................................................................................................... 3 -2 3 .3 F atigu e .............................................................................................................................. 3 -2 4.0 PIPING MATERIALS AND STRESSES ........................................................................... 4-1 4.1 Piping System D escription .............................................................................................. 4-1 4.2 M aterial Properties and Geom etry ................................................................................... 4-1 4.3 Piping Moments and Stresses for Originally Licensed Thermal Power (OLTP) considering only RHR Normal Thermal .................................................................................. 4-2 4.4 Piping Moments and Stresses for Uprate Conditions considering RHR Thermal S tratifi cation ............................................................................................................................. 4 -4 5.0 LEAK-BEFORE-BREAK EVALUATION ............................. .......................................... 5-1 5.1 Evaluation of C ritical Flaw Sizes .................................................................................... 5-1 5.1.1 CriticalFlaw Sizes DeterminedBy J-Integral/TearingModulus Analysis ............ 5-1 5.1.2 CriticalFlaw Sizes Determined by Limit Load Analysis ........................................ 5-5 5.2 L eak R ate Determ ination ................................................................................................ 5-7 5.3 Effect of Piping'Restraint on LBB Evaluation .............................................................. 5-12 5.4 LBB Evaluation Results and Discussions ...................................................................... 5-16 5.4.1 OriginallyLicensed Thermal Power (OLTP) considering only RHR Normal Th ermal ............................................................................................................................. 5 -1 6 5.4.2 Uprate Conditions consideringRHR Thermal Stratification............................... 5-17 6.0 EVALUATION OF FATIGUE CRACK GROWTH OF SURFACE FLAWS .................. 6-1 6.1 Plant Tran sients ............................................................................................................... 6-1 6.2 Stresses for Crack Growth Evaluation ............................................................................. 6-2 6.3 Model for Stress Intensity Factor ....................................... 6-3 6.4 Fatigue Crack Growth Analysis and Results ................................................................... 6-4 7.0

SUMMARY

AND CONCLUSIONS .................................................................................. 7-1 Report No: 0900634.401

• StructuralIntegrity Associates, Inc.

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8.0 RE FEREN C E S .................................................................................................................... 8-1 A P PEND IX A .................................................................................................................................

DETERMINATION OF RAMBERG-OSGOOD PARAMETERS AT 650°F ..................... A-i Report No: 0900634.401 Revision: 2 viii V StructuralIntegrityAssociates, Inc.

List of Tables Table Page Table 1-1. Summary of Response Time and Sensitivities for All Coolant Leakage Detection M ethods at Prairie Island ..................................................................................................... 1-5 Table 4-1a. Lower Bound SMAW Material Properties Used in the LBB Evaluation [15, 16] ... 4-8 Table 4-2. Moments for the 6-inch Safety Injection Piping Attached to Reactor Pressure ......... 4-9 Table 4-3. Moments for the 12-inch Safety Injection Piping Attached to Cold Leg (Unit 1) ... 4-10 Table 4-4. Moments for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Unit 1)4-11 Table 4-5. Moments for the 6-inch RCS Draindown Line Attached to Hot Leg (Unit 1) ......... 4-13 Table 4-6. Moments for the 6-inch Safety Injection Piping Attached to Reactor Pressure Vessel and C old L eg (U nit 2) ........................................................................................................ 4-14 Table 4-7. Moments for the 12-inch Safety Injection Piping Attached to Cold Leg (Unit 2)... 4-15 Table 4-8. Moments for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Unit 2)4-16 Table 4-9. Moments for the 6-inch RCS Draindown Line Attached to Hot Leg (Unit2) .......... 4-18 Table 4-10 Bounding Leakage Rates for the Originally Licensed Thermal Power (OLTP)

Considering Only RHR Normal Thermal ................................................... 4-19 Table 4-11 Loads for Uprate Conditions Considering RHR Thermal Stratification ................. 4-20 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) ............ i..................... 5-19 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) .................................. 5-20 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) ........................... 5-21 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) ........................... 5-22 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'F).................................. 5-23 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) .................................. 5-24 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) ......................................................... 5-25 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) ........................... 5-26 Table 5-9. Predicted Leakage Rates for 6-inch Safety Injection lines Attached to Reactor Pressure Vessel and RCS Cold Leg (Unit 1) .................................................................... 5-27 Table 5-10. Predicted Leakage Rates for 12-inch Safety Injection ......................................... 5-29 Table 5-11. Predicted Leakage Rates for 8-inch RHR Lines Attached ..................................... 5-30 Table 5-12. Predicted Leakage Rates for 6-inch Draindown Lines Attached to RCS Hot Leg (U n it 1) ............................................................................................................................... 5 -3 2 Table 5-13. Predicted Leakage Rates for 6-inch Safety Injection Lines Attached to Reactor Pressure Vessel and RCS Cold Leg (Unit 2) ..................................................................... 5-33 Table 5-14. Predicted Leakage Rates for 12-inch Safety Injection Lines Attached to RCS Cold L eg (U n it 2) ......................................................................................................................... 5-3 5 Table 5-15. Predicted Leakage Rates for 8-inch RHR Lines Attached to RCS Hot Leg (Unit 2)5-36 Revort No: 20900634.401 ix StructuralIntegrity Associates, Inc.

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Table 5-16. Predicted Leakage Rates for 6-inch Draindown Lines ........................................... 5-38 Table 5-17. Predicted Leakage Rates for 6-inch Nozzles Attached to RCS Hot Leg (Units 1 and

2) ........................................................................................................................................ 5 -3 8 Table 5-18. Moments Due to Kink Angle Restraint Effects for 6-inch Safety Injection Line Attached to RCS Cold Leg .................................................................. 5-39 Table 5-19. Moments Due to Kink Angle Restraint Effects for 6-inch Draindown Line Attached to R C S H ot L eg .................................................................................................................. 5-40 Table 5-20. Moments Due to Kink angle Restraint Effects for 8-inch RHR Lines Attached to R C S H ot L eg .............................................................................................................. 41

........ 5-4 Table 5-21. Leakage Flaw Size and Leakages for 6-inch Safety Injection Line Attached to RCS Cold Leg Considering R estraint Effect .............................................................................. 5-43 Table 5-22. Leakage Flaw Size and Leak Rates for 8-inch RHR Line Attached to RCS Hot Leg Considering Restraint E ffects ............................................................................................ 5-44 Table 5-23. Leakage Flaw Size and Leak Rates for 6-inch Draindown Line ............. 5-45 Table 5-24. Updated Leak Rates under Uprate Conditions Considering RHR Thermal Stratification using Fatigue Crack Morphology .......  :....................... 5-46 Table 5-25. Updated Leak Rates under Uprate Conditions Considering RHR Thermal Stratification using PWSCC Crack Morphology ............................................................... 5-47 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 ..................................................... 6-7 Table 6-4. Combined Transients for Crack Growth, Cold Leg ................................................... 6-8 T able 6-5. B ounding M om ents .................................................................................................... 6-8 Table 6-6. Maximum and Minimum Transient and Discontinuity Stress ................................... 6-9 Table 6-7. Maximum and Minimum Transient Stress ................................................................. 6-9 Table 6-8. Total Constant (ao) and Linear ((ai) Through-Wall Stresses, 6" Sch 160 Cold Leg S16-10 Table 6-9. Total Constant (ao0) and Linear ((al) Through-Wall Stresses, 12" Sch 160 SI A ccu mu lator ................................................................................................ I...................... 6-10 Table 6-10. Total Constant (ao) and Linear (a 1 ) Through-Wall Stresses, 8" Sch 140 RIIR S u ctio n ................................................................................................................................ 6-1 1 Table 6-11. Total Constant (ao) and Linear (a 1 ) Through-Wall Stresses, 6" Sch 160 Draindown6-11 Table 6-12. Initial Crack Depths for Various Locations ............................ 6-12 Table 6-13. Results of Fatigue Crack Growth Analysis ............................................................ 6-12 Report No: 0900634.401 StructuralIntegrity Associates, Inc.

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List of Figures Figrure Page Figure 1-1. Representation of Postulated Cracks in Pipes for Fracture Mechanics Leak-Before-Break A nalysis ...................................................................................................... ... . ....... 1-6 Figure 1-2. Conceptual Illustration of ISI (UT)/Leak Detection Approach to Protection Against P ip e R up tu re ......................................................................................................................... 1-7 Figure 1-3. Leak-Before-Break Approach Based on Fracture Mechanics Analysis with In-service Inspection and Leak Detection ........................................................................... 1-8 Figure 4-1. Schematic of Piping Model and Selected Node Points for the 6-inch Safety Injection Piping Attached to Reactor Pressure Vessel and the Cold Leg (Unit 1 - Loops A and B) 4-22 Figure 4-2. Schematic of Piping Model and Selected Node Points for the 6-inch Safety Injection Piping Attached to Reactor Pressure Vessel and the Cold Leg (Unit 2 - Loops A an d B) ................................................................................................................................. 4 -2 3 Figure 4-3. Schematic of Piping Model and Selected Node Points for the 12-inch Safety Injection Piping Attached to the Cold Leg (Unit 1 - Loops A and B) ............................... 4-24 Figure 4-4. Schematic of Piping Model and Selected Node Points for the 12-inch Safety Injection Piping Attached to the Cold Leg (Unit 2 - Loops A and B) ............................... 4-25 Figure 4-5. Schematic of Piping Model and Selected Node Points for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Units 1 - Loops A and B) ................................. 4-26 Figure 4-6. Schematic of Piping Model and Selected Node Points for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Units 2 - Loops A and B) ..................................... 4-27 Figure 4-7. Schematic of Piping Model and Selected Node Points for the 6-inch RCS Draindown Line Attached to Hot Leg (Units 1 and 2) ...................................................... 4-28 Figure 5-1. J-Integral/Tearing Modulus Concept for Determination of Instability During D u ctile T earin g ................................................................................................................... 5-4 8 Figure 5-2. Leakage Flaw Size Versus Moment for 6-inch Schedule 160 Pipe Weld Determ ined by J/T and Lim it Load Analyses .................................................................... 5-49 Figure 5-3. Leakage Flaw Size Versus Moment for 6-inch Schedule 160 Nozzle/Draindown Weld Determined by J/T and Limit Load Analyses .......................................................... 5-50 Figure 5-4. Leakage Flaw Size Versus Moment for 8-inch Schedule 140 Pipe Weld Determ ined by J/T and Lim it Load Analyses .................................................................... 5-51 Figure 5-5. Leakage Flaw Size Versus Moment for 12-inch Schedule 160 Pipe Weld Determ ined by J/T and Lim it Load Analyses ................................................................... 5-52 Figure 5-6. Depiction of Restraint Effect on Cracked Piping ................................................... 5-53 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) ........................................ 5-54 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)....................................... 5-55 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) ..................... 5-56 Figure 5-10. Flow Path Deviation As Affected by Roughness and Crack Opening Displacement5-57 Figure 5-11. Roughness Depiction for Small and Large Crack Opening Displacements ........ 5-57 Report No: 0900634.401 xiStructural Integrity Associates, Inc.

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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 Prairie Island Units 1 and 2 under both Originally Licensed Thermal Power (OLTP) considering only Residual Heat Removal (RHR) Normal Thermal and Uprate Conditions considering RHR Thermal Stratification. These encompass portions of the safety injection (SI) system, including that from the SI accumulators, and the 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 original LBB evaluation in Reference 1 was performed for both Prairie Island and Kewaunee.

The current evaluation uses some of the design input data from Reference 1. The following lines are evaluated in this report for each unit at Prairie Island.

• 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 RHR 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 reactor vessel SI lines (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. Although these lines are included in the evaluation, the maximum break flow would be limited by the 4-inch piping.

• 6-inch RCS draindown line on the hot leg (Loop A on Unit 1 and Loop B on Unit 2). This line 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.

• 6-inch capped nozzle on the hot leg (Loop B on Unit 1 and Loop A on Unit 2).

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In addition, PI is planning for power uprate (Uprate) in 2010. Hence, the LBB evaluation is also performed under Uprate conditions. Available thermal stratification loads (STRAT) in the Units 1 and 2 residual heat removal (RHR) suction lines are considered under Uprate conditions.

1.2 Leak-Before-Break Methodology NRC SECY-87-213 [2] 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 of NUREG-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-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, 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 presented in Section 2 of this report, which summarizes NUREG-1061, Vol. 3 requirements.

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 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 detection, and service experience. In Figure 1-2, a limiting circumferential crack is modeled as having both a short through-wall component, or an axisymmetric part-through-wall crack component. Leak detection establishes an upper bound for the through-wall crack component while Report No: 0900634.401 Revision: 2 1-2 StructuralIntegrity Associates, Inc.

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 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 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.

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" 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.

1.3 Leak Detection Capability at Prairie Island Application of LBB evaluation methodology is predicated on having a very reliable leak detection system at the plant, capable of measuring 1/10 of the leakage determined in the evaluation. The various leak detection systems employed at Prairie Island are detailed in Reference 5. Table 1-1 taken from Reference 5 lists all the leak detection methods at Prairie Island, the minimum detectable leakage and the estimated response time for various leak rates.

As can be seen from this table, twelve separate leak detection methods are utilized at Prairie Island with minimum detectable leakage of as low as 0.1 gpm.

In summary, Prairie Island has a very redundant leak detection system capable of detecting leakage as low as 0.1 gpm. However, to be consistent with previous Westinghouse LBB report, which used the capability for Prairie Island Reactor Coolant System pressure boundary leak detection system [Section 5.2.3 of Reference 40], the minimum detectable leakage is set to 0.2gpm.

And since NUREG-1061, Vol. 3 requires that a margin of 10 be provided on leakage, the minimum allowable evaluated leakage rate is 2.Ogpm.

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Table 1-1. Summary of Response Time and Sensitivities for All Coolant Leakage Detection Methods at Prairie Island Minimum Detectable Estimated Response Time of Method (min) Control Room Method Leakage (gpm) 0.5 gpm Leak 1.0 gpm Leak 5.0 gpm Leak Alarm?

Operator Inspection 0.1 20160 20160 20160 No Volume Control Tank Makeup 0.5 260 150 35 Yes Charging Rate Monitoring 11 1 1 1 Yes Daily Coolant Inventory 0.1 1440 1440 1440 No Sump Pump Operating Time 0.21 1440 1440 1440 No Containment Temperature 0.5 180 120 72 No Monitoring Containment Pressure 0.5 180 120 72 No Monitoring Containment Relative 0.2 132 96 72 No Humidity Monitoring Containment Radioactive 0.1 60 30 6 Yes Particulate Monitor R- 11 Containment Radioactive Gas Note 1 Note 1 Note 1 Note 1 Yes Monitor R- 12 Containment Fan Coil Unit 2.73 Note 2 Note 2 0 - 120 Yes Condensate Measurement Acoustic Emission Monitoring Note 3 480 480 480 No Notes:

1. Low levels of fission products in reactor coolant cause containment gas monitor to be ineffective.

2. Below minimum sensitivity of method.

3. Minimum detectable leakage has yet to be determined.

Report No: 0900634.401 Revision: 2 1-5 V StructuralIntegrity Associates, Inc.

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

t 93369rW

b. Circumferential 360 Phrt-Through-Wall Crack of Depth a.

Figure 1-1. Representation of Postulated Cracks in Pipes for Fracture Mechanics Leak-Before-Break Analysis Report No: 0900634.401 Revision: 2 1-6 1 Structural IntegrityAssociates, Inc.

Depth a-

.=r r=*IO*i i iI.*__ l U-0LI-(I)

Critical Flaw Size Locus NDE Leak Detection 93370r0 THRU-WALL FLAW LENGTH Figure 1-2. Conceptual Illustration of ISI (UT)/Leak Detection Approach to Protection Against Pipe Rupture Report No: 0900634.401 Revision: 2 1-7

- StructuralIntegrityAssociates, Inc.

Figure 1-3. Leak-Before-Break Approach Based on Fracture Mechanics Analysis with In-service Inspection and Leak Detection Report No: 0900634.401 Revision: 2 1-8 1 StructuralIntegrityAssociates, Inc.

RF 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 NUJREG- 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:

1. 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 -52. 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.

Report No: 0900634.401 Revision: 2 2-1 StructuralIntegrityAssociates, Inc.

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 Reference 27 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 Prairie Island.

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.

Report No: 0900634.401 Revision: 2 2-2 2 StructuralIntegrity Associates, Inc.

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 Prairie Island 1 and 2, 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) condition. During normal plant operation, the portions of the system beyond the first isolation valve are expected to run at low temperature conditions. Thus, there should never be any Report No: 0900634.401 3-1 StructuralIntegrity Associates, Inc.

Revision: 2

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 Prairie Island.

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 Prairie Island.

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 NSP and submitted to the Nuclear Regulatory Commission have concluded that this does not apply to Prairie Island. 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 Thihange. 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. The potential for thermal fatigue cracking induced by swirl penetration in the 8" RHR piping is also considered. Using results from this project, the calculated cumulative usage factor considering swirl penetration is 0.00 for Unit 1 Loop A RHR Report No: 0900634.401 3-2 StructuralIntegrityAssociates, Inc.

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line and 0.23 for Unit 2 Loop B RHR line, based on 60 years of operation. This shows that thermal fatigue induced by swirl penetration is not significant; thus it is not considered as source for crack initiation.

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 Prairie Island.

Report No: 0900634.401 3-3 Revision: 2 V StructuralIntegrity Associates, Inc.

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 4-4. The lines are fabricated from Schedule 160 stainless steel piping. The most conservative normal operating pressure and temperature from the reactor pressure vessel specification [10], the reactor vessel Stress Report [11] and design bases document for the plant [12]

were used in the evaluation. From Reference 9, the RCS design operating pressure is 2235 psig while the design operating temperature for the cold leg is 544.5°F and that for the hot leg is 607.5°F.

From Reference 11, the corresponding values are M, and =and from Reference 12, they are 2235 psig, 535°F and 599.1F, respectively. For the purpose of evaluating Originally Licensed Thermal Power (OLTP) considering only RHR Normal Thermal, normal operating pressure of 2235 psig was used. In addition, a temperature of 550'F was used for the cold leg and 607.4°F was assumed forthe hot leg. The pressure and temperature used for Uprate Conditions considering RHR Thermal Stratification will be discussed in Section 4.2 "Piping Moments and Stresses for Uprate Conditions considering RHR Thermal Stratification".

4.2 Material Properties and Geometry The material properties of interest for fracture mechanics and leakage calculations are the Modulus of Elasticity (E), the yield stress (Sy), the ultimate stress (Su), the Ramberg-Osgood parameters for describing the stress strain curve (ax 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.

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The piping material is A-376, Type 316 stainless steel [13]. From Reference 14, 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 15 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 15 for SMAW weldments were compared with the lower bound curve provided in NUREG-6428 [16] 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 550°F temperature at which the material properties are determined for the cold leg is slightly different than the conservatively assumed operating temperature of 552 0 F. However, this difference is small and not expected to change the conclusions of the evaluation. The material properties at the hot leg temperature of 607.4°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 607.4°F were then interpolated from the values at 550TF 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 16 was also assumed at 607.4°F. The properties used for the SMAW weldments are shown in Table 4-la.

Geometry details of the piping system obtained from References 17 and 18 are reproduced in Table 4-1 b.

4.3 Piping Moments and Stresses for Originally Licensed Thermal Power (OLTP) considering only RHR Normal Thermal 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-Report No: 0900634.401 4-2 i StructuralIntegrity Associates, Inc.

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1061, other secondary stresses such as residual stresses and through-wall thermal stresses were not included in the evaluation.

Piping analysis was provided in References 17 and 18 and included moments for the nozzles, elbows and pipe-to-valve welds for all components. Summaries of the piping moments are shown in Tables 4-2 through 4-9, 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 ,/2. For leakage calculations, the moment and stress combination of pressure, deadweight and thermal expansion loads is used. These basic moment load combinations are shown in Tables 4-2 through 4-9 for the various nodal locations. Stresses were calculated directly from the piping analysis moments for the various lines considered in this evaluation [ 17, 18]. The resulting stresses used in the fracture mechanics analysis do not include the effects of stress indices.

The axial stress due to normal operating pressure is calculated from the expression:

pD2 (P-Do 2-Di where p is the internal pressure, Do is the outside diameter of the pipe and Di is the inside diameter.

For Originally Licensed Thermal Power (OLTP) considering only RHR Normal Thermal, 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. A later study showed that at one location on 8-inch RHR lines, axial load due to dead weight, thermal expansion and seismic was 7.6% of the axial load due to pressure. As a result, the leakage decreased 7.2% when these non-pressure axial loads, are included. Thus, the non-pressure axial load will be considered under Uprate Conditions considering RHR Thermal Stratification.

The axial stress due to dead weight, thermal expansion and seismic loads is calculated using the following equation:

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F.4

• (D. -_Di),

f where, F = the sum of axial forces from dead weight, thermal expansion and seismic loads.

The bending stress due to dead weight, thermal expansion and SSE is calculated from the bending moments using the expression:

2 2 M2 +M +M z

where:

Z the section modulus and, Mx, My, Mz = the three orthogonal moments.

On occasions, furmanite clamps have been installed on the safety injection piping at Prairie Island to contain valve leakage. Evaluations were performed by Xcel Energy to assess the effect of the furmanite clamps on the stresses of the affected piping [19, 20]. The evaluations concluded that the change in stress is not significant (less than 5%). Hence, the piping loads without the furmanite clamps were used in the LBB evaluations. Consideration of the small stress changes due to furmanite clamps would not be expected to change the conclusions of the LBB evaluations.

4.4 Piping Moments and Stresses for Uprate Conditions considering RHR Thermal Stratification References 34 and 35 list the updated loadings for the Uprate Conditions considering RHR Thermal Stratification (which includes effects of Tave reconciliation, measurement uncertainty recapture (MUR) and transition to 422V+ fuel). Reference 36 reports a 1% increase in the normal operating pressure. Also, the updated cold leg temperature is reported as 527. °F or 527.4°F (conservatively considered 527.4°F for the purpose of the present evaluation as the Report No: 0900634.401 4-4 1 StructuralIntegrity Associates, Inc.

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difference is negligible) and the hot leg temperature is reported as 592.6°F (References 34 and 35).

The following describes the input for the LBB analysis under Uprate Conditions considering RHR Thermal Stratification.

1. Material properties are conservatively taken from Table 4-1, which are reported at higher temperatures than the updated temperatures reported in References 34 and 35.

2. Code minimum flow stress of 51 ksi [4] is used for the critical flaw size calculation except for the 8-inch RHR line in Unit 2 for which the actual material property is used per SRP 3.6.3.

3. Normal operating pressure is taken as 2235 psig x 1.01 = 2257.4 psig = 2258 psig for critical flaw size calculations and 2235 psig, the nominal normal operating pressure, for leakage calculations.

4. For the thermal-hydraulic model used to calculate leakage using EPRI program, PICEP

[24], cold leg temperature is taken as 527.4°F and hot leg temperature is taken as 592.6°F. The default inputs in PICEP are kept the same as those used in the existing LBB calculation that uses fatigue crack morphology.

5. Per SRP 3.6.3, Rev. 1 [4], loads for leakage are calculated as algebraic sums of P+DW+TH whereas, loads for critical flaw size are calculated using absolute sums of IPN+IDWI+ITHI+ ISSEI except for RHR lines for which the loads for leakage are calculated as algebraic sums of P+DW+TH+STRAT and the loads for critical flaw size are calculated as IPI+IDWI+ITHI+ ISSEI+ISTRATI.

6. Both the forces and moments are considered for the updated LBB analysis. For conservatism, the SRSS-e*d forces are assumed to be compressive for the leakage calculation. Table 4-11 lists the updated forces and moments used for the LBB evaluation.

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7. For Nodes 2000 and 2354 of 8-inch RHR line in Unit 1 and Nodes 100 and 270 of 8-inch RJIR line in Unit 2, References 34 and 35, respectively, reports thermal loads for both normal operating and hot functional conditions. Therefore, both conditions are evaluated to yield maximum and minimum moments for critical flaw size and leakage, respectively.

To comply with the fact that for leakage calculations a negative (compressive) force is conservatively considered, SRSS-ed forces from thermal load conditions are considered such that they are maximum for both critical flaw size and leakage.

8. 'Since not all the nodes reported in this report have updated loading data due to the Uprate Conditions considering RHR Thermal Stratification, the nodes reported in References 34 and 35 are analyzed for leakage. Table 4-10 is a summary of the nodes which have the limiting leakage on each piping line. It is based on the leakage results in Table 5-9 through Table 5-17. For a given line, if these nodes do not include the node(s) reported in Table 4-10 that gave critical leakage values, then the following heuristic scheme is adopted:

a) For a given line in a given unit, the maximum and minimum percentage increase in SRSS-ed moment due to the Uprate conditions is identified for critical flaw size and leakage evaluations, respectively, for all the nodes of that particular line in that particular unit for which the Uprate data is available. Similar calculations are performed for the SRSS-ed forces except that for leakage, the maximum percentage increase is also considered. This is to comply with the fact that for leakage calculation a negative (compressive) force is conservatively considered.

b) This percentage change is used to increase or decrease the existing SRSS-ed moment value for the Uprate conditions. Similar calculations are performed for the SRSS-ed forces.

c) There exist some lines (i.e., 6-inch RCS draindown lines for both Units 1 and 2) for which there is no data (for any node) given for the Uprate conditions. In that Report No: 0900634.401 4-6

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case, the worst possible changes (the most increase for critical flaw size evaluation and the most decrease for leakage calculation) in the SRSS-ed moment due to the Uprate conditions considering all nodes in all the lines for which the Uprate load data is available, is considered. For forces, the most increase is considered for both the critical flaw size and leakage calculations.

d) In general, the loop to which a node belongs is not considered to calculate the worst possible changes in the SRSS-ed moment due to the Uprate conditions except for the 8-inch RHR lines in Unit 2.

The nodes and corresponding loads for LBB evaluation under Uprate conditions are listed in Table 4-11.

Report No: 0900634.401 4-7 Revision: 2 V StructuralIntegrity Associates, Inc.

Table 4-1 a. Lower Bound SMAW Material Properties Used in the LBB Evaluation [ 15, 16]

Parameter Value Temp ('F) 550 607.4 (Cold Leg) (Hot Leg)

E (ksi) 25 x 103 24.72 x 10' Sy = ao (ksi) 49.4 48.137 Su (ksi) 61.4 61.4 Sf= 0.5 (Sy + Su) (ksi) 55.4 54.77 Ramberg-Osgood Parameter cc 9.0 9.130 Ramberg-Osgood Parameter n 9.8 9.636 Jjc (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 Table 4-lb. Geometry used in the LBB Evaluation [17, 18]

6" (Schedule 160) 8" (Schedule 140) 12" (Schedule 160)

Outside Radius (in) 3.3125 4.3125 6.375 Wall Thickness (in) 0.718 0.812 1.312 Area (in 2) 13.32 19.93 47.15 Moment of Inertia (in 4) 58.97 153.72 781.13 Report No: 0900634.401 4-8 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 4-2. Moments for the 6-inch Safety Injection Piping Attached to Reactor Pressure Vessel and Cold Leg (Unit 1)

Thermal + DW Thermal + DW + DBE Nodes Moment, ft-lbs Moment, ft-lbs Mx ] y ]Mý SRSS(') Mx My M, SRSS(')

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 1646(2) 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 = +M2 +M2 (2) These nodes are on the safety injection lines attached to the reactor pressure vessel.

(3) The moments are for OLTP w/ RHR Normal Thermal only.

Report No: 0900634.401 4-9 Revision: 2 r StructuralIntegrity Associates, Inc.

Table 4-3. Moments for the 12-inch Safety Injection Piping Attached to Cold Leg (Unit 1)

DW + TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs Mx M7 M, SRSS(1 ) Mx My Mz SRSS(1 )

175 -25496 6185 9427 27878 -27336 10635 11185 31392 180 -25204 10126 9965 28932 -26886 19990 11137 35306 185A -25201 12260 9971 29746 -26829 25428 10913 38542 185B -22918 15216 7981 28644 -26318 33000 11401 43722 190 -22918 15216 7981 28644 -26318 33000 11401 43722 855 48567 ,-11503 -21149 54207 58355 -13121 -31687 67687 860A 48567 -11503 -21148 54206 58355 -13121 -31686 67687 860B 51807 -10307 -21549 57049 62363 -11601 -30787 70509 865 51807 -10307 -21549 57049 62363 -11601 -30787 70509 870 35262 -10307 -8215 37645 43118 -11601 -15197 47167 875 18717 -10307 5120 21972 23949 -11601 10116 28469 880 -349 -10307 20487 22936 -2969 -11601 24147 26953 885 -19416 -10307 35853 42055 -23144 -11601 40307 47905 890A -19418 -10307 35854 42057 -23146 -11601 40308 47907 890B -30338 -16644 25218 42818 -36136 -17548 32120 51434 895 -30338 -16644 25218 42818 -36136 -17548 32120 51434 897 -35019 -21968 13129 43374 -41711 -23818 22651 53105 905A -35017 -21965 13134 43372 -41709 -23813 22654 53103 905B -35249 -28305 -5002 45483 -41893 -31545 -17344 55235 910 -35249 -28305 -5002 45483 -41893 -31545 -17344 55235 (1)SRSS aM2yM f +O M2 (2) The moments are for OLTP w/ RIIR Normal Thermal only.

Report No: 0900634.401 4-10 Revision: 2 V StructuralIntegrity Associates, Inc.

Table 4-4. Moments for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Unit 1)

DW + TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs M [ M, M, SRSS(1 ) Mx [T M, M, SRSS("'

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 12093 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 = +M2y +M2z (2) The moments are for OLTP w/ RHR Normal Thermal only.

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Table 4-4. Moments for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Unit 1)

(Continued)

DW + TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs M,, M M, SRSSI ) M, M, M, SRSS(1 )

2328A 7131 -4112 -6023 10200 12947 -5592 -13205 19320 2328B 6339 -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 + 2 (2) The moments are for OLTP w/ RHR Normal Thermal only.

Report No: 0900634.401 4-12 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 4-5. 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 Mx my M, SRSS[_) M,, M, M, SRSS(1 )

730 -883 79 594 1067 -1117 631 1144 1719 720 883 -37 -269 924 1117 -579 -803 1493 (1)SRS= M2x +My2 +M2z (1) SRSS a f O (2) The moments are for OLTP w/ RIIR Normal Thermal only.

Report No: 0900634.401 4-13 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 4-6. Moments for the 6-inch Safety Injection Piping Attached to Reactor Pressure Vessel and Cold Leg (Unit 2)

Thermal + DW Thermal + DW + DBE Nodes Moment, ft-lbs Moment, ft-lbs Mx M M, ]SRSS) M" M Mz SRSS(')

695(2) 425 920 -703 1233 791 1144 -1593 2115 690(2) 822 2907 -1073 3206 1954 3513 -2679 4831 685B(2) 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 y (2) These nodes are on the safety injection lines attached to the reactor pressure vessel.

(3) The moments are for OLTP w/ RHR Normal Thermal only.

Report No: 0900634.401 4-14 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 4-7. Moments for the 12-inch Safety Injection Piping Attached to Cold Leg (Unit 2)

DW+TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs M L My M, SRSS(1) M, My M, SRSS(1) 225 -51046 -4212 -16259 53738 -59760 -7946 -24339 65014 230A -51046 -4212 -16259 53738 -59760 -7946 -24339 65014 230B -43014 -9042 -20341 48433 -51324 -14140 -29261 60748 235 -43014 -9042 -20341 48433 -51324 -14140 -29261 60748 240 -35470 -9042 -19425 41439 -42984 -14140 -27905 53163 436 23987 -9308 -9247 27341 29369 -13550 -20149 38107 440A 23987 -9309 -9247 27341 29369 -13551 -20149 38107 440B 21619 -10987 -8404 25666 26501 -16233 -19258 36561 441 21619 -10987 -8404 25666 26501 -16233 -19258 36561 445 17692 -10987 -6525 21824 22510 -16233 -16495 32285 (1) SRSS = V M2x M2y +M2 (2) The moments are for OLTP w/ RR Normal Thermal only.

Report No: 0900634.401 4-15 Revision: 2 Ir StructuralIntegrity Associates, Inc.

Table 4-8. Moments for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Unit 2)

DW + TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs Mx My M, SRSS 1 ) M MMy M, SRSS(1 )

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 110A 1163 -566 6842 6963 2375 -2834 11540 12118 l0OB 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 = VMx M +

(2) The moments are for OLTP w/ RHR Normal Thermal only.

Report No: 0900634.401 4-16 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 4-8. Moments for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Unit 2)

(Continued)

DW + TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs Mx, M, M, SRSSI ) M I M, M, SRSS(1 )

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 = VMx y z (2) The moments are for OLTP w/ RI-IR Normal Thermal only.

Report No: 0900634.401 4-17 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 4-9. Moments for the 6-inch RCS Draindown Line Attached to Hot Leg (Unit2)

DW + TE DW + TE + SSE Nodes Moment, ft-lbs Moment, ft-lbs M- my_ I M, [SRSS() M,, M, M, SRSS.)

10 288 -39 442 529 454 -361 542 794 7 -340 68 -409 536 -520 418 -521 847 (1) SRSS = m M2 + M2+M2 (2) The moments are for OLTP w/ RHR Normal Thermal only.

Report No: 0900634.401 4-18 Revision: 2 V StructuralIntegrity Associates, Inc.

Table 4-10 Bounding Leakage Rates for the Originally Licensed Thermal Power (OLTP) considering only RHR Normal Thermal Moments Net Section Collapse Results Line Unit Node NOP 4 NOP+SSE Leakage Flaw (in-ibs) (in-Ibs) 1(inches)

Size, 2a Leakage Rate (gpm) 6" SI 1 1045 7260 19550 5.230 4.600 6" SI 2 558 5480 8050 5.342 4.909 6" Draindown 1 720 11090 17920 5.246 3.941 6" Draindown 2. 7 6430 10160 5.322 3.884 8" RHPT 1 2060 51410 146630 6.018 6.963 8" RHR 2 246 81890 413660 4.844 3.779 12" SI 1 185B/ 343730 524660 8.878 22.422 190 12" SI 2 445 261.890 387420 9.200 22.632 6" Capped 1,2 N/A1 02 02 5.420 3.740 NozzleII Notes:

1: Not applicable.

2: No loading except pressure (2235 psig) is considered.

3: Piping restraint effect not applicable.

4: NOP = Normal Operating Condition = DW+TH.

Report No: 0900634.401 4-19 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 4- 11 Loads for Uprate Conditions considering RIR Thermal Stratification Forces Moments Line Critical Critical Flaw Unit Node Leakage' Flaw Size 2 Leakage' Size2 (lbs) (lbs) (in-lbs) (in-lbs) 6" S16 1 1045 -368.68 1086.66 7180.23 21045.32 6" SI 1 1270 -659.43 736.19 15004.94 18968&52 12" S16 1 190 -1962.59 5243.32 327524.16 509258.64 12" SI 1 910 -10172.22 13731.91 520925.40 638922.48 8" RHR1 ° 1 2000 -17063.56 22010.32 198027.60 586646.64 8" RHR10 1 2354 -9676.03 13395.68 210368.04 384903.96 8" RHR6 '9 1 2060 -18937.3 12011.71 53102.08 389330.52 6" Draindown6'9 1 720 -2779.48 1886.99 10565.43 47571.04 6" SI 2 570 -316.20 1157.53 10833.93 20529.94 6" SI 2 834 -292.17 731.11 12336.26 20257.57 6" S17,9 2 558 -359.17 596.46 5234.93 10926.00 12" SI 2 240 -6803.46 15963.99 474323.88 675871.80 12" S179' 2 445 -2813.77 7791.14 249803.04 410449.32 8" RHR 10 2 100 -16059.03 17779.60 277176.84 379043.64 8" RHR'° 2 270 -23430.19 30200.73 291160.68 709515.60 8" RHR 7' 9 2 246 -13093.29 22536.71 182469.36 762461.88 6" Draindown 7' 9 2 7 -2477.97 2316.43 6135.19 24841.42 3

6" Capped 2 0

-oze458 4' 5', 1,2 N/A3 0 1 1 Nozzle 0 Notes:

1. DW+TH.

2. jDWjI+/-THI+jSSEI except for RHR lines for which it is IDWj+jTHI+ JSSEI+ ISTRATI.

3. Not applicable.

4. Piping restraint effect not applicable.

5. No loading except pressure (2258 psig for critical flaw size and 2235 psig for leakage) is considered.

6. Gave critical leakage values for corresponding lines for Unit 1.

7. Gave critical leakage values for corresponding lines for Unit 2.

Report No: 0900634.401 4-20 StructuralIntegrity Associates, Inc.

Revision: 2

8. Gave critical leakage value for capped nozzle for both Units 1 and 2.

9. No data available for the Uprate loads.

10. Thermal loads at hot functional condition and at operating condition are taken conservatively for critical flaw size (larger loads) and leakage (smaller loads) calculations.

Report No: 0900634.401 4-21 Revision: 2 V StructuralIntegrity Associates, Inc.

Figure 4-1. Schematic of Piping Model and Selected Node Points for the 6-inch Safety Injection Piping Attached to Reactor Pressure Vessel and the Cold Leg (Unit 1 - Loops A and B)

Report No: 0900634.401 4-22 Revision: 2 V StructuralIntegrityAssociates, Inc.

ire 4-2. Schematic of Piping Model and Selected Node Points for the 6-inch Safety Injection Piping Attached to Reactor Pressure Vessel and the Cold Leg (Unit 2 - Loops A and B)

Report No: 0900634.401 4-23 Revision: 2 Ir StructuralIntegrityAssociates, Inc.

Figure 4-3. Schematic of Piping Model and Selected Node Points for the 12-inch Safety Injection Piping Attached to the Cold Leg (Unit 1 - Loops A and B)

Report No: 0900634.401 4-24 Revision: 2 V StructuralIntegrityAssociates, Inc.

Figure 4-4. Schematic of Piping Model and Selected Node Points for the 12-inch Safety Injection Piping Attached to the Cold Leg (Unit 2 - Loops A and B)

Report No: 0900634.401 4-25 Revision: 2 V StructuralIntegrity Associates, Inc.

Figure 4-5. Schematic of Piping Model and Selected Node Points for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Units 1 - Loops A and B)

Report No: 0900634.401 4-26 Revision: 2 V StructuralIntegrity Associates, Inc.

Figure 4-6. Schematic of Piping Model and Selected Node Points for the 8-inch Residual Heat Removal Piping Attached to Hot Leg (Units 2 - Loops A and B)

Report No: 0900634.401 4-27 Revision: 2 V StructuralIntegrityAssociates, Inc.

Figure 4-7. Schematic of Piping Model and Selected Node Points for the 6-inch RCS Draindown Line Attached to Hot Leg (Units 1 and 2)

Report No: 0900634.401 4-28 Revision: 2 V StructuralIntegrityAssociates, Inc.

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 CriticalFlaw Sizes Determined By J-Integral/TearingModulus Analysis A fracture mechanics analysis for determining the stability of through-wall circumferential flawsin cylindrical geometries such as pipes using the J/T approach is presented in References 21 and 22.

This procedure was used for the determination of critical stresses and flaw sizes in the safety injection and RHR lines at Prairie Island, using computer program, pc-CRACKrM [23] 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 [21]

which is applied in this analysis is:

Report No: 0900634.401 5-1 i StructuralIntegrityAssociates, Inc.

Revision: 2

R) p2 R P l J= f (a,, 1,R p2- + 0 0 c*()hl (-,n, t)*o (5-1) where f(a,,, 2t 2

= aF2(b'R4R (5-2) ae = effective crack length including small scale yielding correction R nominal pipe radius t = pipe wall thickness F = elasticity factor [21, 22]

P= applied load = cy (27cRt); where cr is the remote tension stress in the uncracked section

.= Ramberg-Osgood material coefficient E = elastic modulus o= yield stress o= yield strain 2a = total crack length 2b = 27rR c = b-a hi= plasticity factor [21, 22]

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 [22] is given by:

Report No: 0900634.401 5-2

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J M2 R+n M j(-3)

The parameters in the above equations are the same as the tension loading case except M = applied moment = 7c, (n R2 t)

• o = 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 = oc (elastic-perfectly plastic case)

- M[CosX'2 2Sin(y)] (-4)

M'o = limit moment of the uncracked cylinder = 4ao R 2t The Tearing Modulus (T) is defined by the expression:

T W E (5-5) da (Tf 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, af, 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 using the tension and bending models separately. For the first case, the stress combination is Report No: 0900634.401 5-3 StructuralIntegrityAssociates, Inc.

Revision: 2

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 (aj)due to a combined tension and bending stress using linear interpolation, as described by the following equation:

aC =a t + ab (5-6)

Gb + at ab + aT Where at and Gb are 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 Prairie Island and Kewaunee. 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 (f 1) is equal to the half critical flaw length (aj). 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 (U2) is the total flaw length (2a,). The final leakage flaw length is the minimum of f I 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 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 Report No: 0900634.401 5-4

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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 NUR-EG-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 = 20R (5-8) where S = 2 af [2 sin3 - sin 0] (5-9) 71

= 0.5 [(7i -O)- 7 (Pro/oYf)], (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.

f = flow stress for austenitic steel pipe material categories. The value of 51 ksi recommended in Reference 4 was used in this case.

Report No: 0900634.401 5-5 StructuralIntegrityAssociates, Inc.

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If 0 + P3from Eqs. (5-9) and (5-10) is greater than 7t, then (5-11) where

=-IT (PM/Cr,) (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(Pm+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 ý M (Pm + Pb + Pe) Z (5-14) where Pe 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.

Report No: 0900634.401 5-6 Revision: 2 V StructuralIntegrityAssociates, Inc.

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.

5.2 Leak Rate Determination The determination of leak rate is performed using the EPRI program, PICEP [24]. The flow rate equations in PICEP are based on Henry's homogeneous nonequlibrium critical flow model [25].

The program accounts for nonequlibrium "flashing" mass transfer between liquid and vapor phases, fluid friction due to surface roughness and convergent flow paths.

Battelle Columbus and Engineering Mechanics Corporation of Columbus (Emc 2) have conducted research to assess the technology used in determining leakage through cracked piping with Stress Corrosion Cracking (SCC) morphology [38]. It has been determined that the crack morphology, characterized by the local roughness, number of flow path turns, and total leakage path length, is significantly different between fatigue cracking and SCC. For fatigue cracks, the flow path is relatively smooth and straight, whereas for SCC, the flow path is relatively rough and consists of many turns. A procedure has been proposed in NUREG/CR-6300 [37] that defines the surface roughness, effective flow path length and number of flow path turns as a function of the ratio of the crack opening displacement (COD, 6) to the global roughness (-to) of the flow path. For very tight cracks, there is a relatively longer flow path with many local turns, but the local roughness

(-LL)is relatively lower. For cracks with a larger opening, the roughness is better represented by the global roughness but the number of turns and effective flow path length decrease. Although not confirmed by testing or detailed fluid mechanics analysis, this model is a reasonable representation of the morphology effects on leakage flow due to SCC.

Report No: 0900634.401 5-7 1 StructuralIntegrityAssociates, Inc.

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For defining the crack morphology, the model proposed by Battelle is considered that takes into account both global roughness ýtG and the local roughness jiL as illustrated in Figure 5-11 [37].

These are then combined with 6, the COD, by the following set of equations to develop an effective roughness ýi.

L, 0.0 < < 0.1 t* = 9.9 AG

, > 10 MAG A similar set of equations is developed to determine the effective number of turns (NT), with the assumption that the number of turns decreases to about 0.1 of the local number of turns, (NL) when the crack opening displacement is equal to or greater than 10 times the global roughness.

rýL I 0.0 :9 6 < 0.1 YG fit =I OAJýLna > 10 Similarly, the total flow path length is increased due to the crack being skewed relative to the pipe wall and due to the turns within the material, as shown in Figure 5-10. Then, the ratio between the total flow path length La and the pipe wall thickness t is determined by:

Report No: 0900634.401 5-8 StructuralIntegrity Associates, Inc.

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Ko÷L, '0.0 < < O.I AG L. *.*KG--Kr, _a .1 1 T '- 9.9-1, [.*AG ,--

K0 ,

The EPRI-developed computer program PICEP [24] is not configured to directly include the methods for computing morphology using the interpolation method proposed in NUREG/CR-6300[37]. To determine the effects of crack morphology on leakage flaw sizes, additional calculations can be conducted using PICEP with input revised to simulate SCC morphology.

In PICEP, the number of turns can be' simulated by adding an equivalent L/D=26 for 45-degree turns and L/D=50 for 90-degree turns. These equivalent additional lengths are appropriate for use determining pressure drops through typical piping, components. However, when the roughness (r) is increased to be large comparable to the hydraulic diameter (DH), the effect of the number of turns is further amplified since it is multiplied by. an increased friction factor (f).

To determine input to PICEP to simulate a crack with both fatigue and Stress Corrosion Cracking morphologies, an equivalent number of turns and equivalent roughness are determined.

The method is based on the fact that the flow resistance along a flow path is made up of the friction resistance and the discontinuity (i.e., turns) resistance. The pressure differential is determined by multiplying the sum of the friction (fL/D) and discontinuity (K) loss factors by the velocity pressure in the flow path.

In PICEP, the turns and friction resistance are lumped together.

Loss Factor = f (t/Dh + 50N 9 0) for 90 degree turns

= f (t/Dh + 26N 45) for 45 degree turns

where, f = friction factor

= (2 log (DH/ 2 -) +4 1.74)-2 [24]

Report No: 0900634.401 5-9 StructuralIntegrityAssociates, Inc.

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= roughness (defined as [t by Battelle) t = pipe wall thickness N 90, N 45 = number of 90-degree or 45-degree turns in leak path Dn = hydraulic diameter = 4 A/Wp A = flow path cross-section area Wp = wetted perimeter of flow path cross-section area.

(Dh = 7r/2 COD for an elliptical crack where COD is the center point crack opening displacement)

For flow through a complex crack consisting of a cracked weld followed by a cracked overlay, there will similarly be losses due to friction and turns. To simulate this in PICEP, an equivalent friction factor must be determined that will yield the same friction as for the complex crack case.

feq(t/Dh) = X fi (Lai/Dh) where, fi = friction factor for the revised roughness for each crack face Lai = revised flow path length for each crack face For input to PICEP, the equation above for the friction factor can be used to solve for an equivalent roughness that will produce the correct loss factor.

The equivalent number of turns can be similarly determined.

f (50N 90 ) = X N'i Lai Kg0 where, N'i = number of 90-degree turns per unit flow path length for each crack face K90 = loss coefficient (number of velocity heads) for each 90-degree turn Thus, the number of turns to be used in a PICEP analysis can be determined by:

Report No: 0900634.401 5-10 StructuralIntegrityAssociates, Inc.

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NpIcEP-90 = 0.02 (1 N'i Lai K9 0 ) / feq where, N' = number of 90' turns per inch predicted for a specific crack morphology L = total flow path length = t x KG+L (See flow path length equation earlier this Section)

Similarly, the number of 45-degree turns to input in a PICEP run can be determined as:

50 NPICEP-4 5 =NP1cEP_90 X -

26 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.

A sharp-edged entrance loss factor of 0.61 is used (PICEP default).

The default friction factors of PICEP are utilized.

The parameters used for fatigue morphology are listed below [39] and applied in leakage calculation in Originally Licensed Thermal Power (OLTP) considering only RHR Normal Thermal:

I-LL = 0.00197 S = 0.00197 N90 = 0 LG/t = 1.000 L/t = 1.000 where 91 = Local roughness, inches 9G = Global roughness, inches N90 = Number of 90 degree turns per inch L6 /t = Global flow path length to thickness ratio L/t = Global plus local flow path length to thickness ratio Stress Corrosion Cracking morphology are considered for sensitivity study under Uprate Conditions and RIR Thermal Stratification, even though the piping systems under consideration Report No: 0900634.401 5-11

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are not known to be susceptible to SCC in PWR environment. Normally intergranular stress corrosion cracking (IGSCC) has more adverse morphology, which produces more conservative leakage than transgranular stress corrosion cracking (TGSCC), thus, IGSCC crack morphology is chosen to study the sensitivity of leakage to crack morphology. And since Primary Water Stress Corrosion Cracking, or PWSCC, is a form of IGSCC that occurs in the PWR primary water environment. PWSCC crack morphology parameters [38], shown below, are used for the sensitivity study:

PL 0.00663778

-t 0.0044842 N 90 - 150.87 LG/t = 1.009 L/t = 1.243 The leakage was calculated at operating temperature and pressure for Originally Licensed Thermal Power (OLTP) considering only RHR Normal Thermal and Uprate Conditions considering RHR Thermal Stratification, 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.

5.3 Effect of Piping Restraint on LBB Evaluation In NUREG/CR-6443 [27], 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 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 Report No: 0900634.401 5-12

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Revision: 2

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.

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 Prairie Island and Kewaunee to determine the affect of restraint on the LBB evaluation results.

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 Report No: 0900634.401 5-13 *7j StructuralIntegrityAssociates, Inc.

Revision: 2

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.

Based on the criteria above, it was concluded that all six 8-inch RUR 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 [28]. 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 [29], and is given by:

=si [Sbb(9)+ Sjj(9) ][1 + ax(Sb + (5-17) where:

cyf = flow stress - 0.5(T,+ay) = Average of ultimate and yield strength of the material, ksi E = Young's modulus in ksi, Sb = b/(Tf = normalized bending stress, St = ct/af normalized tensile stress, lb and It are compliance functions given in Appendix B of Reference 29, 0, = effective half-crack angle corrected for plastic zone size, in radians, described below, Report No: 0900634.401 5-14

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Revision: 2

cc ' = (c(f/cro)n-I ax and n are Ramberg-Osgood parameters, described below.

The plastic stress-strain behavior is represented in the Ramberg-Osgood form (Eq. 2.18 in [29]),

k~c{2in C

60 Y (5-18) o where:

= ab+lat,

= reference stress used in determining the Ramberg-Osgood constants, usually ay, 60

= yo/E, ax and n are material parameters obtained from curve-fitting to tensile test results.

The effective half-crack angle (Oe) corrected for plastic zone size is (Eq. 2.8 in [29]):

2 K

0e __ 223 71rRaf + 00 (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 [29]), i.e.,

K = 7*--oO(o'tFt(0o.)+OCbFb(0o) (5-20)

Ft = geometry factor for tension (See Appendix A of Reference 29),

Fb = geometry factor for bending (See Appendix A of Reference 29),

Report No: 0900634.401 5-15

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2, for plane stress condition, parameter in Irwin plastic zone correction (Eq. 2.4 in [29])

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, 90', 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 5-18 through 5-20. 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 5-21 through 5-23. In comparing these results to those presented in Tables 5-9 through 5-17, 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 33.

5.4 LBB Evaluation Results and Discussions 5.4.1 OriginallyLicensed Thermal Power (OL TP) consideringonly RHR Normal Thermal Tables 5-9 through 5-17 show the predicted leakage for the leakage flaw length for each location under Originally Licensed Thermal Power (OLTP) considering only RHR Normal Thermal using fatigue morphology. In all cases, the leakage for cracks determined with net section collapse analyses was less than the leakage for cracks determined using J/T analysis. The leakage associated with net section collapse analyses is therefore conservatively used in the LBB evaluation.

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Revision: 2

It can be seen from Tables 5-9 through 5-17 that the limiting leakage is obtained from the limit load evaluation. 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 Attached to RPV and Cold Leg Unit 1 4.60 - 5.27 gpm Unit 2 4.91 - 5.71 gpm 6-inch Draindown Line Attached to Hot Leg Unit 1 3.94 - 3.97 gpm Unit 2 3.88 - 3.90 gpm 8-inch RHR Line Attached to Hot Leg Unit 1 6.96 - 11.20 gpm Unit 2 3.78- 11.73 gpm 12-inch Safety Injection Line Attached to Cold Leg Unit 1 22.42 - 26.98 gpm Unit 2 22.63 - 26.67 gpm 6-inch Hot Leg Capped Nozzles Units 1/2 3.74 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 3.78 gpm 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 3.4 gpm. This is well above the required leak detection of 2.0 gpm for Prairie Island as discussed in Section 1.3 of this report thereby justifying LBB for all the piping considered in this evaluation.

5.4.2 Uprate Conditions consideringRHR Thermal Stratification Table 5-24 and Table 5-25 show the predicted leakage under Uprate Conditions considering RIHR Thermal Stratification using fatigue morphology and PWSCC morphology, respectively. Note that the leak rates calculated by PICEP using fatigue crack morphology are given at a default pipe outlet temperature of 200'F whereas, in general the sump where the leaked fluid is collected temperature is at 120 'F. Therefore, the fluid collected at the sump will be slightly less than that exiting from the pipe. This is incorporated in Table 5-24. Also, a 13% reduction of the leak rate due to piping restraint is considered for all the lines for the leakage at the sump temperature.

Report No: 0900634.401 5-17 Revision: 2 V StructuralIntegrityAssociates, Inc.

As shown in Table 5-24, the minimum leakage is 2.44 gpm 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 2.12 gpm. This is well above the 2.0 gpm required leakage detection at Prairie Island. Therefore, LBB is still applicable under Uprate Conditions considering RHR Thermal Stratification load for all the piping considered in this report.

Hypothetical flaws due to PWSCC morphology have also been evaluated, with the leakage results reported in Table 5-25. Comparing Table 5-25 with Table 5-24, it shows that using the PWSCC morphology, leakage reduced to as low as 22% of the leakage using fatigue morphology. It is recognized that there have been some instances of SCC in recent PWR plant operations. However, it is highly unlikely that the RCS-attached piping systems at PI would be affected. There are no Alloy 82/182 weldments in the piping being evaluated for LBB in this report. The occurrence of TGSCC such as that which has occurred in CEDMs at Palisades is not expected at PI since the water in the RCS-attached lines is free to communicate with the RCS such that high levels of oxidants cannot 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. It was shown that the current Section XI ISI program at PI 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 a 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.

Report No: 0900634.401 5-18 1 StructuralIntegrityAssociates, Inc.

Revision: 2

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 0F)

Leakage Flaw Total Stress, Bending Stress, Tension Stress, Bending Moment, Size** (a),

aT, ksi Gb, 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.

Report No: 0900634.401 5-19 Revision: 2 V StructuralIntegrity Associates, Inc.

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 = 5507F)

Leakage Flaw Total Stress, Bending Stress, Tension Stress, Bending Moment, Size** (a),

UT, ksi Cjb, 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 5.14*

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.

Report No: 0900634.401 5-20 StructuralIntegrityAssociates, Inc.

Revision: 2

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),

aT, ksi Ub, 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 4.32 273.87 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.

Report No: 0900634.401 5-21 StructuralIntegrity Associates, Inc.

Revision: 2

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)

Leakage Flaw Total Stress, Bending Stress, Tension Stress, Bending Moment, Size** (a),

aT, ksi ab, ksi at, ksi j 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.

Report No: 0900634.401 5-22 Revision: 2 V StructuralIntegrity Associates, Inc.

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 0 F)

Moment, in-kips Leakage 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.

Report No: 0900634.401 5-23 Revision: 2 V StructuralIntegrity Associates, Inc.

Table 5-6. Leakage Flaw Size Versus Stress Determined by Limit Load for 12-inch Safety Injection Lines Attached to RCS Cold Leg (Temperature = 5500 F)

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.

Report No: 0900634.401 5-24 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 5-7. Leakage Flaw Size Versus Stress Determined by Limit Load for 8-inch RHR Lines Attached to RCS Hot Leg (Temperature = 607.47F)

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.

Report No: 0900634.401 5-25 Revision: 2 V StructuralIntegrity Associates, Inc.

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)

Moment, in-kips 1 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.

Report No: 0900634.401 5-26 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 5-9. Predicted Leakage Rates for 6-inch Safety Injection lines-Attached to Reactor Pressure Vessel and RCS Cold Leg (Unit 1)

Moments EPFM Results Net Section Collapse Results NOP. NOP+SSE Leakage Leakage Leakage Leakage de in-kips Flaw Size** Rate Flaw Size** Lekge Node in-kips in-kips (a), inches Rate, gpm (a), inches Rate, gpm 1621" 8.78. 19.87 2.730 5.733 2.613 4.714 1622* 8.27 16.55 2.743 5.810 2.629 4.801 1630' 17.34 28.18 2.696 6.217 2.575 5.104 1640A* 18.55 30.55 2.686 6.230 2.565 5.108 1640B* 17.88 33.78 2.672 6.038 2.550 4.929 1645" 16.33 32.52 2.678 5.945 2.556 4.858 1646* 17.46 34.03. 2.671 5.989 2.549 4.887 1045* 7.26 12.02 2.762 5.879 2.651 4.902 1040* 3.86 8.34 2.777 5.676 2.669 4.757 1025 2.64 3.95 2.795 5.722 2.691 4.819 1027 2.77 4.32 2.794 5.721 2.689 4.817 1030 3.02 5.04 2.791 5.718 2.685 4.812 1031 3.30 5.87 2.787 5.715 2.681 4.804 1039A 3.30 5.87 2.787 5.715 2.681 4.804 1039B 5.44 14.08 2.753 5.620 2.641 4.663 1040 5.44 14.08 2.753 5.620 2.641 4.663 1045 7.26 19.55 2.731 5.597 2.615 4.600 1236 3.35 8.56 2.776 5.616 2.668 4.704 1238 3.70 8.53 2.776 5.652 2.668 4.735 1250 4.02 8.78 2.775 5.675 2.667 4.753 1259 4.39 9.38 2.773 5.689 2.664 4.762 Report No: 0900634.401 5-27 Revision: 2 V StructuralIntegrity Associates, Inc.

Table 5-9. Predicted Leakage Rates for 6-inch Safety Injection lines Attached to Reactor Pressure Vessel and RCS Cold Leg (Unit 1)

(Continued)

Moments EPFM Results Net Section Collapse Results NOP NOP+SSE Leakage Leakage Leakage Leakage Flaw Size** Flaw Size** Rate, gpm Node in-kips in-kips (a), inches Rategpm (a), inches Rate, 1260A 4.39 9.38 2.773 5.689 2.664 4.762 1260B 8.22 12.86 2.758 5.945 2.647 4.951 1265 8.22 12.86 2.758 5.945 2.647 4.951 1270 15.14 19.04 2.733 6.392 2.617 5.272 Notes:

• These nodes are on the safety injection lines attached to the reactor pressure vessel.

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

• • • OLTP and RIR Normal Thermal Only.

Report No: 0900634.401 5-28 StructuralIntegrityAssociates, Inc.

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Table 5-10. Predicted Leakage Rates for 12-inch Safety Injection Lines Attached to RCS Cold Leg (Unit 1)

Moments EPFM Results Net Section Co lapse 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 175 334.54 376.70 4.930 33.189 4.613 25.643 180 347.18 423.67 4.874 32.289 4.558 24.946 185A 356.95 462.50 4.827 31.532 4.512 24.360 185B 343.73 524.66 4.752 29.113 4.439 22.422 190 343.73 524.66 4.752 29.113 4.439 22.422 855 650.48 812.24 4.405 32.866 4.129 26.124 860A 650.47 812.24 4.405 32.865 4.129 26.124 860B 684.59 846.11 4.364 33.023 4.095 26.378 865 684.59 846.11 4.364 33.023 4.095 26.378 870 451.74 566.00 4.702 32.569 4.393 25.254 875 263.66 341.63 4.973 30.841 4.656 23.810 880 275.23 323.44 4.995 31.966 4.678 24.712 885 504.66 574.86 4.691 34.705 4.383 26.985 890A 504.68 574.88 4.691 34.706 4.383 26.985 890B 513.82 617.21 4.640 33.707 4.336 26.270 895 513.82 617.21 4.640 33.707 4.336 26.270 897 520.49 637.26 4.616 33.353 4.314 26.005 905A 520.46 637.24 4.616 14.995 4.314 26.005 905B 545.80 662.82 4.585 33.600 4.286 26.252 910 545.80 662.82 4.585 33.600 4.286 26.252

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

• • • OLTP and RHR Normal Thermal only.

Report No: 0900634.401 5-29 Revision: 2 V StructuralIntegrityAssociates,.Inc.

Table 5-11. Predicted Leakage Rates for 8-inch RHR Lines Attached to RCS Hot Leg (Unit 1)

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 2000 191.71 220.94 2.983 12.963 .2.832 10.770 2005 153.86 174.83 3.118 13.178 2.940 10.640 2010A 153.86 174.83 3.118 13.178 2.940 10.640 2010B 151.93 169.54 3.133 13.306 2.953 10.730 2015 151.93 169.54 3.133 13.306 2.953 10.730 2020A 151.93 169.54 3.133 13.306 2.953 10.730 2020B 125.93 143.96 3.208 13.037 3.016 10.345 2025 125.93 143.96 3.208 13.037 3.016 10.345 2030 59.23 80.32 3.395 11.758 3.183 9.099 2035 201.54 235.61 2.940 12.742 2.798 10.702 2040A 201.54 235.61 2.940 12.742 2.798 10.702 2040B 236.90 268.52 2.844 12.791 2.725 11.066 2045 236.90 268.52 2.844 12.791 2.725 11.066 2050 195.89 212.72 3.007 13.547 2.850 11.200 2055 97.15 159.71 3.162 10.817 2.977 8.627 2060 51.41 146.63 3.200 8.866 3.009 6.963 2070A 51.41 146.63 3.200 8.866 3.009 6.963 2070B 55.81 145.12 3.205 9.153 3.013 7.189 2075 55.81 145.12 3.205 9.153 3.013 7.189 2324 119.22 236.21 2.938 9.104 2.797 7.600 Report No: 0900634.401 5-30 Revision: 2 V StructuralIntegrity Associates, Inc.

Table 5-11. Predicted Leakage Rates for 8-inch RHR Lines Attached to RCS Hot Leg (Unit 1)

(Continued)

Moments EPFM Results Net Section Collapse Results Leakage Leakagee NOP NOP+SSE Flaw Sae* Leakage Flaw Size* Leakage Node in-kips in-kips (a), inches Rate, gpm (a), inches Rate, gpm 2326 122.40 231.84 2.951 9.398 2.807 7.823 2328A 122.40 231.84 2.951 9.398 2.807 7.823 2328B 114.43 202.02 3.039 10.085 2.875 8.222 2330 98.92 163.40 3.151 10.762 2.968 8.603 2332 74.28 128.34 3.254 10.769 3.056 8.460 2334 73.92 128.93 3.252 10.724 3.054 8.427 2336 95.71 143.03 3.211 11.397 3.018 9.003 2338 106.92 147.92 3.196 11.807 3.006 9.365 2340A 106.92 147.92 3.196 11.807 3.006 9.365 2340B 105.91 140.45 3.218 12.059 3.025 9.535 2342 105.91 140.45 3.218 12.059 3.025 9.535 2344 95.90 137.40 3.227 11.628 3.033 9.181 2346A 95.90 137.40 3.227 11.628 3.033 9.181 2346B 98.71 151.66 3.186 11.218 2.997 8.907 2348 98.71 151.66 3.186 11.218 2.997 8.907 2350A 98.71 151.66 3.186 11.218 2.997 8.907 2350B 103.20 158.90 3.164 11.163 2.979 8.905 2352 103.20 158.90 3.164 11.163 2.979 8.905 2354 106.54 166.88 3.141 11.009 2.959 8.827

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

• • • OLTP and RHR Normal Thermal only.

Report No: 0900634.401 5-31 Revision: 2 V StructuralIntegrity Associates, Inc.

Table 5-12. Predicted Leakage Rates for 6-inch Draindown Lines Attached to RCS Hot Leg (Unit 1)

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 730 12.80 20.63 2.794 5.367 2.610 3.970 720 11.09 17.92 2.808 5.336 2.623 3.941

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

• • • OLTP and RHR Normal Thermal only.

Report No: 0900634.401 5-32 Revision: 2 V StructuralIntegrity Associates, Inc.

Table 5-13. Predicted Leakage Rates for 6-inch Safety Injection Lines Attached to Reactor Pressure Vessel and RCS Cold Leg (Unit 2)

Moments EPFM Results Net Section Coliapse Results Leakage Flaw Leakage NOP NOP+SSE Size** (a), Leakage Flaw Size** Leakage Node in-kips. in-kips inches Rate, gpm (a), inches Rate, gpm 695* 14.80 25.38 2.707 6.092 2.588 5.005 690* 38.47 57.97 2.572 6.815 2.443 5.511 68590 38.47 57.97 2.572 6.815 2.443 5.511 685A* 40.14 60.987 2.559 6.823 2.431 5.521 680* 40.14 60.98 2.559 6.823 2.431 5.521 670* 39.29 62.20 2.554 6.695 2.426 5.416 552* 29.68 37.81 2.656 6.958 2.531 5.675 551* 25.86 33.67 2.673 6.788 2.550 5.557 550B* 25.86 33.67 2.673 6.788 2.550 5.557 550A* 29.69 37.03 2.659 6.995 2.535 5.708 548* 29.69 37.03 2.659 6.995 2.535 5.708 558 5.48 8.05 2.778 5.852 2.671 4.909 560 6.30 8.86 2.775 5.902 2.667 4.947 562 7.94 10.43 2.768 6.010 2.659 5.029 564 9.61 12.16 2.761 6.114 2.651 5.102 566A 9.61 12.16 2.761 6.114 2.651 5.102 566B 10.98 13.99 2.754 6.181 2.642 5.141 568 10.98 13.99 2.754 6.181 2.642 5.141 570 11.29 15.13 2.749 6.167 2.636 5.118 826 10.66 12.80 2.759 6.195 2.647 5.165 828 11.94 14.41 2.752 6.261 2.640 5.205 Report No: 0900634.401 5-33 StructuralIntegrity Associates, Inc.

Revision: 2

Table 5-13. Predicted Leakage Rates for 6-inch Safety Injection Lines Attached to Reactor Pressure Vessel and RCS Cold Leg (Unit 2)

(Continued)

Moments EPFM Results Net Section Collapse Results Leakage Flaw Leakage NOP NOP+SSE Size** (a), Leakage Flaw Size** Leakage Node in-kips in-kips inches Rate, gpm (a), inches Rate, gpm 830A 11.94 14.41 2.752 6.261 2.640 5.205 830B 12.83 15.59 2.747 6.303 2.634 5.228 832 12.83 15.59 2.747 6.303 2.634 5.228 834 12.92 15.77 2.746 6.305 2.633 5.229 Notes:

• These nodes are on the safety injection lines attached to the reactor pressure vessel.

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

• • • OLTP and RHR Normal Thermal only.

Report No: 0900634.401 5-34 Revision: 2 V StructuralIntegrityAssociates, inc.

Table 5-14. Predicted Leakage Rates for 12-inch Safety Injection Lines Attached to RCS Cold Leg (Unit 2)

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 225 644.86 780.17 4.444 33.713 4.162 26.673 230A 644.86 780.17 4.444 33.713 4.162 26.673 230B 581.20 728.98 4.505 32.898 4.216 25.906 235 581.20 728.98 4.505 32.898 4.216 25.906 240 497.27 637.96 4.615 32.325 4.313 25.182 436 328.09 457.28 4.833 30.406 4.518 23.470 440A 328.09 457.28 4.833 30.406 4.518 23.470 440B 307.99 438.73 4.856 30.048 4.540 23.182 441 307.99 438.73 4.856 30.048 4.540 23.182 445 261.89 387.42 4.917 29.388 4.600 22.632

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

OLTP and RHR Normal Thermal only.

Report No: 0900634.401 5-35 Revision: 2 10 StructuralIntegrity Associates, Inc.

Table 5-15. Predicted Leakage Rates for 8-inch RHR Lines Attached to RCS Hot Leg (Unit 2)

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 100 104.15 155.09 3.176 11.367 2.989 9.053 101 89.65 150.08 3.190 10.797 3.001 8.558 105A 89.65 150.08 3.190 10.797 3.001 8.558 105B 83.56 145.42 3.204 10.645 3.012 8.408 106 83.56 145.42 3.204 10.645 3.012 8.408 110A 83.56 145.42 3.204 10.645 3.012 8.408 lIOB 77.20 114.77 3.294 11.502 3.092 8.983 111 77.20 114.77 3.294 11.502 3.092 8.983 112 76.94 87.91 3.372 12.609 3.162 9.775 115A 147.98 157.32 3.169 13.669 2.983 10.956 115B 68.09 99.06 3.340 11.590 3.132. 8.971 116 68.09 99.06 3.340 11.590 3.132 8.971 117 41.71 76.76 3.405 10.745 3.193 8.288 118 81.43 127.78 3.255 11.201 3.058 8.811 119 112.04 145.45 3.204 12.186 3.012 9.663 120A 112.04 145.45 3.204 12.186 3.012 9.663 120B 97.73 117.28 3.286 12.611 3.085 9.892 121 97.73 117.28 3.286 12.611 3.085 9.892 246 81.89 413.66 2.459 3.994 2.422 3.779 249A 81.89 413.66 2.459 3.994 2.422 3.779 249B 106.81 440.94 2.392 4.139 2.369 4.006 250 106.81 440.94 2.392 4.139 2.369 4.006 251 112.00 437.64 2.400 4.292 2.375 4.146 Report No: 0900634.401 5-36 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 5-15. Predicted Leakage Rates for 8-inch RHR Lines Attached to RCS Hot Leg (Unit 2)

(Continued)

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 251 112.00 437.64 2.400 4.292 2.375 4.146 252 295.36 421.28 2.440 9.245 2.407 8.829 253 390.98 412.63 2.462 12.338 2.424 11.728 254 421.60 470.05 2.324 11.079 2.313 10.930 255A 421.60 470.05 2.324 11.079 2.313 10.930 255B 388.72 453.96 2.362 10.747 2.344 10.501 256 388.72 453.96 2.362 10.747 2.344 10.501 257 53.69 105.65 3.320 10.444 3.115 8.083 258 260.60 411.23 2.465 8.573 2.427 8.131 260A 260.60 411.23 2.465 8.573 2.427 8.131 260B 284.04 408.53 2.472 9.322 2.432 8.829 261 284.04 408.53 2.472 9.322 2.432 8.829 262 179.46 226.91 2.965 12.125 2.818 10.105 263 170.16 291.29 2.779 9.279 2.675 8.134 265A 170.16 291.30 2.779 9.279 2.675 8.133 265B 160.97 300.98 2.753 8.669 2.654 7.635 266 160.96 300.98 2.753 8.669 2.654 7.634 270 130.67 384.94 2.531 5.652 2.480 5.262

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

• OLTP and RHR Normal Thermal only.

Report No: 0900634.401 5-37 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 5-16. Predicted Leakage Rates for 6-inch Draindown Lines Attached to RCS Hot Leg (Unit 2)

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 10 6.35 9.53 2.848 5.264 2.664 3.899 7 6.43 10.16 2.845 5.245 2.661 3.884

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

• • OLTP and RHR Normal Thermal only.

Table 5-17. Predicted Leakage Rates for 6-inch Nozzles Attached to RCS Hot Leg (Units 1 and 2)'

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 0 2.894 5.073 2.710 3.740

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

• • • OLTP and RHR Normal Thermal only.

Report No: 0900634.401 5-38 Revision: 2 V StructuralIntegrity Associates, Inc.

Table 5-18. Moments Due to Kink Angle Restraint Effects for 6-inch Safety Injection Line Attached to RCS Cold Leg Crack T Limiting Load Node Orientation Mx My [k SRSS Reduction Moment (Degrees) [in-kips] [in-kips] [in-kips] [in-kips] [in-kips]

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 0.210 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 1 Note: Based on Kewaunee Loop B line.

Report No: 0900634.401 5-39 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 5-19. Moments Due to Kink Angle Restraint Effects for 6-inch Draindown Line Attached to RCS Hot Leg Crack M Limiting Load Node Orientation MI My SRSS Reduction Moment (Degrees) [in-kips] [in-kips] [in-kips] [in-kips] [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.

OLTP and RHR Normal Thermal only.

Report No: 0900634.401 5-40 Revision: 2 V StructuralIntegrity Associates, Inc.

Table 5-20. 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-kips] [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 1 135 -0.32 -13.57 -6.39 15.00 Report No: 0900634.401 5-41 StructuralIntegrityAssociates, Inc.

Revision: 2

Table 5-20. 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 Mz 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 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 Note: Based on Prairie Island Unit 1 Loop A line.

OLTP and RHR Normal Thermal only.

Report No: 0900634.401 5-42 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 5-21. 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 Leakage Leakage Leakage Leakage Leakage Node 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 Note: Based on evaluating Kewaunee Loop B line.

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

Report No: 0900634.401 5-43 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 5-22. 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) (gpm) (in) (gpm) (in) (gpm) (in) (gpm) 2000 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 Note:

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

• • Based on Prairie Island Loop A line.

• OLTP and RHR Normal Thermal only.

Report No: 0900634.401 5-44 Revision: 2 V StructuralIntegrity Associates, Inc.

Table 5-23. 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 Note:

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

• • Based on Prairie Island Unit 2 line.

• OLTP and RHR Normal Thermal only.

Report No: 0900634.401 5-45 Revision: 2 V StructuralIntegrityAssociates, Inc.

Table 5-24. Updated Leak Rates under Uprate Conditions with RHR Thermal Stratification using Fatigue Crack Morphology Leak Rate (gpm) at Adjusted Leak Rate Line Unit Node 200°F 1 12001F (gpm) at 1200F 3 6" SI 1 1045 4.580 4.463 3.882 6" SI 1 1270 5.325 5.188 4.514 12" SI 1 190 22.494 21.916 19.067 12" SI 1 910 24.750 24.114 20.979 8" R1IR 1 2000 3.442 3.354 2.918 8" RIJLR 1 2354 6.862 6.685 5.816 8" RHIR 1 2060 2.673 2.604 2.265 6" Draindown 1 720 3.158 3.077 2.677 6" SI 2 570 4.911 4.785 4.163 6" SI 2 834 5.094 4.963 4.318 6" SI 2 558 4.858 4.734 4.118 12" SI 2 240 22.584 22.003 19.143 12" SI 2 445 21.353 20.804 18.099 8" R1R 2 100 9.247 9.009 7.838 8" RHR 2 270 3.866 3.767 3.277 8" RIR 2 246 2.504 2.440 2.123 6" Draindown 2 7 3.446 3.358 2.921 6" Capped Nozzle 1,2 N/A4 4.217 4.109 3.575 Notes:

1. PICEP default outlet fluid temperature.

2. Sump temperature at which the fluid from the cracked pipe is collected.

3. Includes a 13 % decrease (maximum decrease as calculated in Reference 1) in leak rate due to the effect of piping restraint.

4. Uprate Conditions with RHR Thermal Stratification.

Report No: 0900634.401 5-46 Revision: 2 V StructuralIntegrity Associates, Inc.

Table 5-25. Updated Leak Rates under Uprate Conditions with RHR Thermal Stratification using PWSCC Crack Morphology Leak Rate (gpm) at Adjusted Leak Rate Line Unit Node 200°F 1 120°F2 (gpm) at 120°F3 6" SI 1 1045 1.454 .1.416 1.232 6" SI 1 1270 1.630 1.588 1.382 12" SI 1 190 4.945 4.817 4.191 12" SI 1 910 5.293 5.157 4.487 8" RHR 1 2000 0.971 0.946 0.823 8" RHR 1 2354 1.751 1.706 1.484 8" RHR 1 2060 0.816 0.795 0.691 6" Draindown 1 720 0.971 0.946 0.823 6" SI 2 570 1.521 1.482 1.290 6" SI 2 834 1.570 1.529 1.330 6" SJ 2 558 1.513 1.474 1.282 12" SI 2 240 4.899 4.773 4.152 12" SI 2 445 4.775 4.652 4.047 8" RHR 2 100 2.268 2.210 1.922 8" RHIR 2 270 1.045 1.018 0.886 8" RHR 2 246 0.732 0.713 0.621 6" Draindown 2 7 1.041 1.014 0.882 6" Capped Nozzle 1,2 N/A 4 1.239 1.207 1.050 Notes:

1. PICEP default outlet fluid temperature.

2. Sump temperature at which the fluid from the cracked pipe is collected.

3. Includes a 13% decrease (maximum decrease as calculated in Reference 1) in leak rate due to the effect of piping restraint.

4. Uprate Conditions with RHR Thermal Stratification.

Report No: 0900634.401 5-47 Revision: 2 V StructuralIntegrityAssociates, Inc.

J 2J1 c

\-SLOPE dda T=-d ( E) 93220r0 Note: Linear extrapolation used to determine Tmaterial for J values greater than 2 JIc Figure 5-1. J-Integral/Tearing Modulus Concept for Determination of Instability During Ductile Tearing Report No: 0900634.401 5-48 Revision: 2 V StructuralIntegrity Associates, Inc.

Leakage Flaw Size vs. Moment, 6-inch Sch 160 Pipe Weld 5.0 4.5 4.0 3.5 U*

.* 3.0 ig 1.5

_j N.S.C. Results 1'0 EPFM Results 0.5 Extrapolated EPFM 0.0 0.0 20.0 40.0 60.0 80.0 100.0 1220.0 140.0 160.0 180.0 Moment (NOP+SSE), in-kips Note: Leakage flaw size (a) is one half the total flaw length.

Figure 5-2. Le*akage Flaw Size Versus Moment for 6-inch Schedule 160 Pipe

[eld Determined by J/T and Limit Load Analyses Report No: 0900634.401 5-49 Revision: 2 V StructuralIntegrityAssociates, Inc.

Leakage Flaw Size vs. Moment, 6-inch Sch 160 Nozzle/Draindown Weld 3.5 3.0 2.5

. 2.0

5. 1.5 C,

- NSC Results

-J D 1.0

• -- EPFM Results 0.5 _Extrapolated EPFM 0.0 0.0 20.0 40.0 60.0 80.0 100.0 120.0 140.0 160.0 Moment (NOP+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 Report No: 0900634.401 5-50 Revision: 2 V StructuralIntegrityAssociates, Inc.

Leakage Flaw Size vs. Moment, 8-inch Sch 140 Pipe Weld 4.0 2.5 2.0 U, N.

15 _* EPFMReut -

a - 1Extrapolated EPFM 1.0 0.5 00 0.0 20.0 40.0 60,0 8000 100.0 120,0 140.0 160.0 180.0 2000 220.0 240.0 260.0 28 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 Report No: 0900634.401 5-51 Revision: 2 V StructuralIntegrityAssociates, Inc.

Leakage Flaw Size vs. Moment, 12-inch Sch 160 Pipe Weld 6.0 5.0 U 4.0 CS3.0 01 LL

- NSC Results A 2.0

- EPFM Results

_101. -- Extrapolated EPFM 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 Report No: 0900634.401 5-52 Revision: 2 V StructuralIntegrity Associates, Inc.

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 Moment induced due to restraint T

PIPE RESTRAINT 00034r0 c) Cracked pipe with restraint.

Figure 5-6. Depiction of Restraint Effect on Cracked Piping Report No: 0900634.401 5-53 Revision: 2 V StructuralIntegrityAssociates, Inc.

LI

@0 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 (8-inch RI-IR Line - Prairie Island Unit 1, Loop A)

Report No: 0900634.401 5-54 Revision: 2 V StructuralIntegrity Associates, Inc.

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)

Report No: 0900634.401 5-55 StructuralIntegrityAssociates, Inc.

Revision: 2

62 20 15 so WDPR 95 too 11110S*

165 WOMO- 71 Is?

170 W6,R it -13 217

-60) 280

'10 31S 250 Z55 230

-4C itel 71WK 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)

Report No: 0900634.401 5-56 Revision: 2 V StructuralIntegrityAssociates, Inc.

MK4+Lt Tt Small COD Figure 5-10. Flow Path Deviation As Affected by Roughness and Crack Opening Displacement PC; _

Large COD Small COD Figure 5-11. Roughness Depiction for Small and Large Crack Opening Displacements Report No: 0900634.401 5-57 Revision: 2 V StructuralIntegrityAssociates, Inc.

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 1WB-3514 acceptance standards [30]

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.

6.1 Plant Transients Since Prairie Island 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 for the reactor pressure vessel [!i ýI[Pil))

(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 the original design of the reactor pressure vessel [ 11] except that the number of heatup/cooldown cycles was modified from 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. Accumulator blowdown transient was not evaluated, since this transient has never occurred at Prairie Island and hence is considered as a very unlikely event. Although there was a safety injection transient in Unit 1 due to tube rupture in 1979, there have been no inadvertent safety injections since. This transient is therefore also considered unlikely and was not evaluated. There are no local piping system transients for the 6-inch draindown line and 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 Report No: 0900634.401 Revision: 2 6-1 V StructuralIntegrity Associates, Inc.

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.

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:

c~ =pP D i2 Do 2 -Do 2 where Do is the outside diameter and Di is the inside diameter of the pipe.

Bending stress is given by ab Do(M)/21, where M - bending moment I = moment of inertia

= (7i/64)*(Do4-Di 4)

For thermal expansion moments, the maximum operating thermal moments (Mmax oper), from Section 4, are scaled by the ratio of the transient temperature ranged (AT) to the operating temperature range (AToper):

Mt Mmax oper (AT/AToper),

where AToper is based on the temperatures at which the thermal expansion moments were calculated. AToper = 607.4 - 70 = 537.4 0 F for the hot leg and 552 - 70 = 482°F for the cold leg.

Report No: 0900634.401 Revision: 2 6-2 V StructuralIntegrity Associates, Inc.

Table 6-5 gives the bounding non-scaled moments, based on the Section 4 tables. The operating conditions used for this evaluation have been provided 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 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 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°F was used.

Thermal transient stresses (OTT) and thermal stresses associated with material discontinuities (uTD) are also included in this evaluation and are presented in Tables 6-6 and 6-7. The computer program PIPETRAN [31 ] 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 6-11 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 15. The stress intensity factors are determined for a conservative aspect ratio (a/f) of 0.1.

The stress intensity factor for the deepest point on the semi-elliptical flaw from Reference 15 is given as:

Report No: 0900634.401 Revision: 2 6-3 StructuralIntegrityAssociates, Inc.

5 K1 = (itt)' ° i z[0i(a/t)Gi where ai are the coefficients of the stress polynomial describing the axial stress (a) variation through the cylinder wall and are defined below.

CY = GO + a1 (z/t) + a 2 (z/t) 2 + Ca 3 3 (z/t) ,

z is the distance measured from the inner surface of the cylinder wall and t is the cylinder wall thickness. The Gi are the influence coefficients associated with the coefficients of the stress polynomial ai and are expressed by the following general form:

2 Gi =Ac(i +A 2 ci + A 3 ti 3 +A 4ci4 +A 50i5 + A 6 Ci(R/t-5) oci= (a / t)/(a / c)m The values of A, through A6 and m are provided in Reference 15 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 [32], the fatigue crack growth law for stainless steel is given as:

da

- =CES (AKI)n dN Report No: 0900634.401 Revision: 2 6-4 4 StructuralIntegrity Associates, Inc.

where n equals 3.3, C = 2 x 10-19 (in/cycle) (psi/'Hn), 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 (Kmin/Kmax), and is given by:

R2)-4 S = (1.0 - 0.5 The R ratio was calculated for each Km&a 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/!

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 6-12.

The results of the fatigue crack growth analysis are presented in Table 6-13. The results show that for the 6-inch cold leg safety injection and draindown 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, and 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 RHR and 12" safety injection accumulator piping can be attributed to the RHR transients listed in Table 6-2. For the last ten years, Prairie Island 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 Report No: 0900634.401 Revision: 2 6-5 StructuralIntegrity Associates, Inc.

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 Prairie Island.

Table 6-1. Plant Design Transients Used for LBB Evaluations Event Cce Plant Heatup/Cooldown (HU/CD) 250 Plant Loading/Unloading 18,300 10% Step Load Decrease 2,000 10% Step Load Increase 2,000 Large Step Decrease 200 Loss of Load 80 Loss of Power 40 Loss of Flow 80 Reactor Trip from Full Power 400 Turbine Roll Test 10 Primary Side Hydro Test 5 Primary Side Leak Test 50 Operating Basis Earthquake + 200 Report No: 0900634.401 Revision: 2 6-6

- StructuralIntegrityAssociates, Inc.

Table 6-2. Additional System Transients Used Specifically for LBB Evaluations

[Piping ITransient I Cycles ITmin, OFiTmax, OFI 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" RHIR Suction RRHR Initiation (away from RC nozzle) 250 100 400 300 Table 6-3. Combined Transients for Crack Growth, Hot Leg I I Tmin, Tmax, OF Pmin, Pmax' AP, No. Load Set Pair Cycles OF OF JAT, OFI psig psig 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 TRTest & 10% Load Increase 10 480 606 126 1935 2335 400 6 Loss of Flow & 10% Load Increase 80 486 606 120 1855 2235 380 7 Step Deer. & 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 Side Hydro Test 5 120 120 0 0 3105 3105 13 Primary Side LeakTest 50 120 547 427 0 2485 2485 Report No: 0900634.401 Revision: 2 6-7 7 StructuralIntegrityAssociates, Inc.

Table 6-4. Combined Transients for Crack Growth, Cold Leg II ITmfin, Tmax, Pm~i., IP..x, AP, No. C Load Set Pair I 5 OF AT, 0Cycles2

.F Psig

-F psig 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% LoadIncr. & 10% LoadDecr. 1920 517.2 547.2 30 2135 2335 200 7 10% Load Incr & Load/Unload 80 51.7.2 547 *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 LeakTest 50 120 547 427 0 2485 2485 Table 6-5. Bounding Moments

[DW Moment, ft-lb JOBE Moment, ft-lb Plant Node M MLine ]M I ft-lb TE Moment, Mz MIIM I Mz M M. I M, I n_

6" Sch 160 Cold Leg SI 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 PIUnit 1 855 46008 -11027 -18203 2559 -476 -2946 4894 809 5269 PIUnit 1 910 -34147 -27905 -1668 -1102 -400 -3334 3322 1620 6171 8" Sch 140 RHR Suction PIUnit1 2000 2967 -4507 16159 -142 -216 -1161 667 1892 396 PIUnit 1 2324 7449 -2958 -4764 -763 278 -2078 2551 425 4261 PIUnit2 246 --1295 -6489 -1932 -825 10 1622 4857 1661 15274 PIUnit2 P 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 Report No: 0900634.401 Revision: 2 6-8 8 StructuralIntegrity Associates, Inc.

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" S1 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 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 RJJR Initiation -36.13 Report No: 0900634.401 Revision: 2 6-9 6 StructuralIntegrityAssociates, Inc.

Table 6-8. Total Constant (ao) and Linear ((a 1 ) Through-Wall Stresses, 6" Sch 160 Cold Leg SI Stresses (psi)

Minimum Maximum Load Set Pair Cycles (O a1 C0 01 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 Decr. 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 Table 6-9. Total Constant (ao) and Linear ((cyl) Through-Wall Stresses, 12" Sch 160 SI Accumulator Stresses (psi)

Minimum Maximum Load Set Pair Cycles O 0 al (0 al 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 Report No: 0900634.401 Revision: 2 6-10 6 StructuralIntegrity Associates, Inc.

Table 6-10. Total Constant (ao) and Linear (a1 ) Through-Wall Stresses, 8" Sch 140 RHR Suction Stresses (psi)

Minimum Maximum Load Set Pair Cycles G0 a1 G0 Ca CD & HU/Loss of Load/OBE 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/10% 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/10% 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 RRHR Operation at Cooldown 250 -37688 66943.1 22639 -47537 Table 6-11. Total Constant (ao) and Linear (a1 ) Through-Wall Stresses, 6" Sch 160 Draindown Stresses (psi)

Minimum Maximum Load Set Pair Cycles (O Cl (O al CD & HU/Loss of Load/OBE 20 19694 -53760 23973 -53760 CD & HU/Loss of Load 60 19744 -53760 23872 -53760 CD & HU/Loss of Power 40 19744 -53760 23714 -53760 CD & HU/10% Load Increase 130 22815 -53760 23725 -53760 TR Test & 10% Load Increase 10 22898 -53760 23725 -53760 Loss of Flow & 10% Load Increase 80 23346 -53760 23725 -53760 Step Decr. & 10% Load Increase 200 23361 -53760 23725 -53760 Rx Trip & 10% Load Increase 400 23363 -53760 23725 -53760 Unload & Load/10% Load Increase 1180 23377 -53760 23725 -53760 Unload & Load/10% Load Decrease 2000 23377 -53760 23722 -53760 Loading/Unloading 15120 23377 -53760 23720 -53760 Primary Side Hydro Test 5 19775 -53760 24703 -53760 Primary Side Leak Test 50 19770 -53760 23933 -53760 Report No: 0900634.401 Revision: 2 6-11 6 StructuralIntegrity Associates, Inc.

Table 6-12. Initial Crack Depths for Various Locations It(in.) I a/t a (in.)

6" Sch 160 Cold Leg SI 0.718 0.1163 0.0835 12" Sch 160 SIAccumulator 1.312 0.1091 0.1432 8" Sch 140 RIIR Suction 0.812 0.1146 0.0930 6" Sch 160 Draindown 0.718 0.1163 0.0835 Table 6-13. 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 0.1432 0.984 0.984 38 8" Sch 160 RHR 0.0930 0.609 0.609 123 6" Sch 160 Draindown 0.0835 0.0837 0.5385 > 250 Report No: 0900634.401 Revision: 2 6-12 61 StructuralIntegrity Associates, Inc.

7.0

SUMMARY

AND CONCLUSIONS Leak-before-break (LBB) evaluations are performed for the RCS attached piping at Prairie Island Units 1 and 2 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 from both Originally Licensed Thermal Power (OLTP) considering only RHR.Normal Thermal & Uprate Conditions considering RHR Thermal Stratification. 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 J2_ 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.

For Originally Licensed Thermal Power (OLTP) conditions, considering only RHR Normal Thermal, 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 Attached to RPV and Cold Leg Unit 1 4.60 - 5.27 gpm Unit 2 4.91 - 5.71 gpm 6-inch Draindown Line Attached to Hot Leg Unit 1 3.94 - 3.97 gpm Unit 2 3.88 - 3.90 gpm 8-inch RHR Line Attached to Hot Leg Unit 1 6.96 - 11.20 gpm Unit 2 3.78 - 11.73 gpm Report No: 0900634.401 Revision: 2 7-1 StructuralIntegrity Associates, Inc.

12-inch Safety Injection Line Attached to Cold Leg - Unit 1 22.42 - 26.98 gpm Unit 2 22.63 - 26.67 gpm 6-inch Hot Leg Capped Nozzles Units 1/2 3.74 gpm

" The 'piping restraint effects have no significant impact on the predicted leakages for the 6-inch safety injection and draindown 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 3.78 gpm without consideration of the piping restraint effect. When the restraint effect is considered, the minimum leakage for all the piping systems considered is 3.4 gpm.

" Based on the capability of all the available leak detection systems, Prairie Island is capable of detecting leak rates as low as 0.1 gpm. However, for this evaluation a detectable leak rate of 0.2 gpm is assumed based on previous NRC approval for a sister plant. When the NUREG- 1061 margin of 10 is applied to this rate, Prairie Island leak detection capability is 2.0 gpm. The minimum predicted leakage under Originally Licensed Thermal Power (OLTP) considering only RHR Normal Thermal, 3.4 gpm is greater than the leak detection at Prairie Island 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 Prairie Island 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.

Report No: 0900634.401 Revision: 2 7-2 V StructuralIntegrity Associates, Inc.

For Uprate Conditions considering RHR Thermal Stratification, the following conclusion can be made:

The LBB evaluation due under Uprate conditions considering RHR Thermal Stratification demonstrates that LBB is still applicable for all the piping considered if fatigue crack morphology is used. The minimum leakage under uprate conditions considering RHR Thermal Stratification is 2.12 gpm associated with the 8-inch RHR piping in Unit 2 considering the maximum 13% reduction of the leak rate due to piping restraint. This is above the required leak detection of capability of 2.0 gpm for Prairie Island.

Report No: 0900634.401 Revision: 2 7-3 7- StructuralIntegrity Associates, Inc.

8.0 REFERENCES

1. Structural Integrity Associates Report No. SIR-00-045, Rev. 0, "Leak-Before-Break Evaluation, 6-inch to 12-inch Safety Injection and Residual Heat Removal Piping Attached to the RCS, Kewaunee Nuclear Power Plant."

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Excerpts from "Northern States Power Company Prairie Island Nuclear Generating Plant Design Basis Document," Revision 2, Pages 131, 132 and 134 of 308 "Reactor Coolant System."

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Report No: 0900634.401 Revision: 2 8-1 V StructuralIntegrityAssociates, Inc.

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Report No: 0900634.401 Revision: 2 8-2 StructuralIntegrity Associates, Inc.

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32. 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. 352-366.

33. 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.

34. ENG-CS-378, Rev. 0, "Evaluation of The Effects of Tave Reconciliation, MUR And Transition to 422V+ Fuel On The Unit 1 Branch Lines And Nozzles Connected to The RCS Loop Piping and Components,".

35. ENG-CS-376, Rev. 0, "Evaluation of The Effects of Tave Reconciliation, MUR And Transition to 422V+ Fuel On The Unit 2 Branch Lines And Nozzles Connected to The RCS Loop Piping and Components,".

36. Design Information Transmittal 1006-4, "Unit 2 Pressurizer Surge Nozzle Design Data; Surge Line Data; Engineering Manual Data; Actual Operating Data", October 12, 2009.

37. NUREG/CR-6300, "Refinement and Evaluation of Crack-Opening Analyses for Short Circumferential Through-Wall Cracks in Pipes," U.S. Nuclear Regulation Commission, April 1995.

38. D. Ruland, R. Wolterman, G. Wilkowski, R. Tregoning, "Impact of PWSCC and Current Leak Detection on Leak-Before-Break," Proceedings of Conference on Vessel Head Penetration, Inspection, Cracking, and Repairs, Sponsored by USNRC, Marriot Washingtonian Center, Gaithersburg, MD, September 29 to October 2,2003.

39. D. Abdollahian and B. Chexal, "Calculation of Leak Rates Through Cracks in Pipes and Tubes," EPRI NP-3395, Electric Power Research Institute, Palo Alto, CA, December 1983.

40.

Report No: 0900634.401 Revision: 2 8-4 8 StructuralIntegrityAssociates, Inc.

APPENDIX A DETERMINATION OF RAMBERG-OSGOOD PARAMETERS AT 650OF Report No: 0900634.401 StructuralIntegrityAssociates, Inc.

Revision: 2 A-0

A.1 INTRODUCTION The Ramberg-Osgood stress-strain parameters (cc 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 parameters for another temperature are known. In this case, the Ramberg-Osgood parameters are derived for at 650'F for given values at 550 0 F for the Type 316 stainless steel piping SMAW welds at Prairie Island.

A.2 METHODOLOGY The Ramberg-Osgood model is in the form:

1(1) 1+

Where c and , are the true stress and true strain, cro and co are the reference stress and reference strain (in general yield stress and yield strain) and ac 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 (2) ey Report No: 0900634.401 StructuralIntegrity Associates, Inc.

Revision: 2 A-11

[l _fn_+_ey Sy +e,1 o n Su(1 + e,) S 1 +e)(3)

IS, (1+ey)]

where Su and Sy represent ultimate stiess 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:

ey =- - (4)

E where E (modulus of elasticity) can also be obtained from the ASME Code. The ultimate strain (eu) 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 I and n by using equation (2) and (3).

It is obvious that cc is a function of ey, n is a function of ca, eu1, ey, Su, and Sy , 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 predicted properties from Equations (2) and (3) using Code minimum properties:

(CC)65m-F =(O)Base,550mF XEquation(2)

- 5 5 0oF Code min.property Equation (2) m-, Code min.property 65 (5)

Equation (3) 655 F,Code min.property n)6mF=

()Be 5~FEquation (3) 6 5 mr Code min~property Report No: 0900634.401 A-' StructuralIntegrity Associates, Inc.

Revision: 2 A-2V

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 input and results of the analysis 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.

Report No: 0900634.401 Revision: 2 A-3 V StructuralIntegrity Associates, Inc.

Table A- I Determination of Ramberg-Osgood Parameters for SMAW at 650'F a, 550'F 9 n, 550'F 9.8 Temperature (°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 s,= fn (l+ey) 0.0007571 0.0007383 Fu= ýn (l+eu) 0.2623643 0.2623643 2.6408269 2.7081081 n' 3.2348215 3.1407678 a 9.0 9.227 n 9.8 9.515 Report No: 0900634.401 Revision: 2 A-4 V StructuralIntegrity Associates, Inc.