ML19095A605

Enclosure 5 - Topical Report WCAP-15550-NP, Rev 2, Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for Surry Units 1 and 2 Nuclear Power Plants for the Subsequent License Renewal Progra

ML19095A605
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Site:	Surry
Issue date:	03/31/2019
From:	Virginia Electric & Power Co (VEPCO), Westinghouse
To:	Office of Nuclear Reactor Regulation
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19-096 WCAP-15550-NP, Rev 2
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Change Notice 2 Serial No.: 19-096 SPS SLRA Docket Nos.: 50-280/281 Enclosure 5 TOPICAL REPORT WCAP-15550-NP, REV. 2 Virginia Electric and Power Company (Dominion Energy Virginia)

Surry Power Station Units 1 and 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 WCAP-15550-N P March 2019 Revision 2 Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for Surry Units 1 and 2 Nuclear Power Plants for the Subsequent License Renewal Program (80 Years) Leak-Before-Break Evaluation

WESTINGHOUSE NON-PROPRIETARY CLASS 3 WCAP-15550-NP Revision 2 Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for Surry Units 1 and 2 Nuclear Power Plants for the Subsequent License Renewal Program (80 Years)

Leak-Before-Break Evaluation March 2019 Authors: Mamo Wiratmo*

Structural Design & Analysis II Reviewer: Eric D. Johnson*

Structural Design & Analysis II Approved: Benjamin A. Leber*, Manager Structural Design & Analysis II

• Electronically approved records are authenticated in the electronic document management system.

Westinghouse Electric Company LLC 1000 Westinghouse Drive Cranberry Township, PA 16066, USA

© 2019 Westinghouse Electric Company LLC All Rights Reserved

WESTINGHOU SE NON-PROPRIETARY CLASS 3 iii RECORD OF REVISIONS Rev Date Revision Description August 0 Original Issue (WCAP-15550) 2000 Revised to include the LBB results from the Measured Uncertainty 1-A Recapture (MUR) Program.

(Draft for March customer 2017 This WCAP revision also includes LBB evaluation for subsequent review) license renewal for 80 years of operation for Surry Units 1 and 2.

June 1 Finalized Revision 1-A and incorporated customer's comments.

2017 Revised to address three chemical content errors in Tables 4-6 and 4-7 and to address the updated CMTR data from Surry Unit 1 that have not been considered in Revision 1. The updated CMTR data is March provided in Table 4-6.

2 2019 As shown in the revised Tables 4-6 and 4-7, the corrections of CMTR errors are shown in bold font and updates due to additional CMTRs are marked by grey-shaded color. Changes in the text of the document are shown with revision bars in the right margin.

WCAP-15550- N P March 2019 Revision 2

WESTINGH OUSE NON-PROPRIETARY CLASS 3 iv TABLE OF CONTENT S

1. O Introduction .................................................................................................................... 1-1 1.1 Purpose .............................................................................................................. 1-1 1.2 Background Information ...................................................................................... 1-1 1.3 Scope and Objectives ......................................................................................... 1-2 1.4 References ......................................................................................................... 1-3

2. 0 Operation and Stability of the Reactor Coolant System ..................................................* 2-1 2.1 Stress Corrosion Cracking .................................................................................. 2-1 2.2 Water Hammer.............................................. : ..................................................... 2-2 2.3 Low Cycle and High Cycle Fatigue ..................................................................... 2-3 2.4 Wall Thinning, Creep, and Cleavage ................................................................... 2-3

2. 5 References ......................................................................................................... 2-3 3.0 Pipe Geometry and Loading ...................................................................... :.................... 3-1 3.1 Introduction to Methodology ................................................................................ 3-1 3.2 Calculation of Loads and Stresses .................................................................. :... 3-1 3.3 Loads for Leak Rate Evaluation .......................................................................... 3-2 3.4 Load Combination for Crack Stability Analyses ................................................... 3-3 3.5 References ......................................................................................................... 3-3 4.0 Material Characterization ................................................................................................ 4-1 4.1 Primary Loop Pipe and Fittings Materials ............................................................ 4-1 4.2 Tensile Properties ............................................................................................... 4-1 4.3 Fracture Toughness Properties ........................................................................... 4-1 4.4 References ......................................................................................................... 4-4

5. 0 Critical Location and Evaluation Criteria ......................................................................... 5-1 5.1 Critical Locations ................................................................................................. 5-1 5.2 Fracture Criteria .................................................................................................. 5-1 6.0 Leak Rate Predictions .................................................................................................... 6-1 6.1 Introduction ......................................................................................................... 6-1

6. 2 General Considerations ...................................................................................... 6-1 6.3 Calculation Method ............................................................................................. 6-1 6.4 Leak Rate Calculations ....................................................................................... 6-2 6.5 References ......................................................................................................: .. 6-2

7. 0 Fracture Mechanics Evaluation ...................................................................................... 7-1 7.1 Local Failure Mechanism .................................................................................... 7-1 7.2 Global Failure Mechanism .................................................................................. 7-2 7.3 Crack Stability Evaluations .................................................................................. 7-3 7.4 References ......................................................................................................... 7-4 8.0 Fatigue Crack Growth Analysis ....................................................................................... 8-1 8.1 References ......................................................................................................... 8-2 9.0 Assessment of Margins .................................................................................................. 9-1 10.0 Conclusions .................................................................................................................. 10-1 Appendix A: Limit Moment. ......................................................................................................... A-1 WCAP-1555 0-N P March 2019 Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 V LIST OF TABLES Table 3-1 Dimensions, Normal Loads and Stresses for Surry Units 1 and 2 ............................... 3-4 Table 3-2 Faulted Loads and Stresses for Surry Units 1 and 2 ................................................... 3-5 Table 4-1 Measured Tensile Properties (psi) for Surry Unit 1 Primary Loop Pipes ...................... 4-5 Table 4-2 Measured Tensile Properties (psi) for Surry Unit 2 Primary Loop Pipes ...................... 4-6 Table 4-3 Measured Tensile Properties (psi) for Surry Unit 1 Primary Loop Elbows ................... .4-7 Table 4-4 Measured Tensile Properties (psi) for Surry Unit 2 Primary Loop Elbows ................... .4-8 Table 4-5 Mechanical Properties for Surry Units 1 and 2 Materials at Operating Temperatures ............................................................................................. 4-9 Table 4-6 Chemistry and Fracture Toughness Elbow Properties of the Material Heats of Surry Unit 1 ............................................................................................................. 4-10 Table 4-7 Chemistry and Fracture Toughness Elbow Properties of the Material Heats of Surry Unit 2 ............................................................................................................. 4-12 Table 4-8 Fracture Toughness Properties for Surry Units 1 and 2 Primary Loops for Leak-Before-Break Evaluation at Critical Locations ................................. 4-13 Table 6-1 Flaw Sizes Yielding a Leak Rate of 10 gpm at the Governing Locations .................... 6-3 Table 7-1 Stability Results for Surry Units 1 and 2 Based on Elastic-Plastic J-lntegral Evaluations ............................................................................................................... 7-5 Table 7-2 Stability Results for Surry Units 1 and 2 Based on Limit Load .................................... 7-5 Table 8-1 Summary of Reactor Vessel Transients ..................................................................... 8-3 Table 8-2 Typical Fatigue Crack Growth at [ rc,e (40, 60, and 80 years)****:****************************************************************************************** 8-4 Table 8-3 Summary of Reactor Vessel Transients for Surry Units 1 and 2 (40, 60, and 80 years) ............................................................................................... 8-5 Table 9-1 Leakage Flaw Size, Critical Flaw Sizes and Margins for Surry Units 1 and 2 .............................................................................................. 9-2 WCAP-15550-N P March 2019 Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 vi LIST OF FIGURES Figure 3-1 Hot Leg Coolant Pipe ............................................................................................. 3-6 Figure 3-2 Schematic Diagram of Surry Units 1 and 2 Primary Loop Showing Weld Locations ...................................................................................................... 3-7 Figure 4-1 Pre-Service J vs. ~a for SA351 CF8M Cast Stainless Steel at 600°F ................... 4-14 Figure 6-1 Analytical Predictions of Critical Flow Rates of Steam-Water Mixtures ................... 6-4 Figure 6-2 rc,e Pressure Ratio as a Function of UD ..................................... 6-5 Figure 6-3 Idealized Pressure Drop Profile Through a Postulated Crack ................................. 6-6 Figure 7-1 t,c,e Stress Distribution ................................................................... 7-6 Figure 7-2 Critical Flaw Size Prediction - Hot Leg at Location 1 ............................................. 7-7 Figure 7-3 Critical Flaw Size Prediction - Hot Leg at Location 3 ............................................. 7-8 Figure 7-4 Critical Flaw Size Prediction - Cross-over Leg at Location 6 ................................. 7-9 Figure 7-5 Critical Flaw Size Prediction - Cold Leg at Location 15 ....................................... 7-10 Figure 8-1 Typical Cross-Section of [ ]a,c,e ............................ .... 8-6 Figure 8-2 Reference Fatigue Crack Growth Curves for Carbon and Low Alloy Ferritic Steels ................................................................................................ 8-7 FigureA-1 Pipe with a Through-Wall Crack in Bending ........................................................... A-2 WCAP-15550-N P March 2019 Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 vii EXECUTIVE

SUMMARY

The original structural design basis of the reactor coolant system for the Surry Units 1 and 2 Nuclear Power Plants required consideration of dynamic effects resulting from pipe break and that protective measures for such breaks be incorporated into the design. Subsequent to the original Surry design, an additional concern of asymmetric blowdown loads was raised as described in Unresolved Safety Issue A-2 (Asymmetric Slowdown Loads on the Reactor Coolant System).

Surry Units 1 and 2 Nuclear Power Plants were part of the utilities which sponsored Westinghouse to resolve the A-2 issue. Generic analyses by Westinghouse to resolve the A-2 issue was approved by the NRC and documented in Generic Letter 84-04 (Reference 1-1). Generic Letter 84-04 served as the original basis for the elimination of large primary loop pipe rupture from the structural design basis for Surry Units 1 and 2. As identified in Generic Letter 84-04, the primary technical references supporting the NRC's safety evaluation of eliminating postulated pipe breaks are documented in WCAP-9558 (Reference 1-9) and WCAP-9787 (Reference 1-10).

Research by the NRC and industry coupled with operating experience determined that safety could be negatively impacted by placement of pipe whip restraints on certain systems. As a result, NRC and industry initiatives resulted in demonstrating that Leak-before-break (LBB) criteria can be applied to reactor coolant system piping based on fracture mechanics technology and material toughness.

Subsequently, the NRC modified 10CFR50 General Design Criterion 4, and published in the Federal Register (Vol. 52, No. 207) on October 27, 1987 its final rule, "Modification of General Design Criterion 4 Requirements for Protection Against Dynamic Effects of Postulated Pipe Ruptures," (Reference 1-2). This change to the rule allows use of leak-before-break technology for excluding from the design basis the dynamic effects of postulated ruptures in primary coolant loop piping in pressurized water reactors (PWRs).

The LBB evaluation is performed based on loading, pipe geometry and fracture toughness considerations, enveloping critical locations were determined at which leak-before-break crack stability evaluations were made. Through-wall flaw sizes were found which would cause a leak at a rate of ten (10) times the leakage detection system capability of the plant. Large margins for such flaw sizes were demonstrated against flaw instability. Finally, fatigue crack growth was shown not to be an issue for the primary loops.

Revision O of this report had demonstrated compliance with LBB technology for the Surry reactor coolant system piping for the 60 year plant life based on a plant specific analysis. Subsequently, an LBB evaluation was performed for the MUR (Measurement Uncertainty Program), the results of that particular analysis are also incorporated in Revision 1 of this report. Lastly, based on the LBB evaluation in Revision 1 of this report herein, it also demonstrated that dynamic effects of reactor coolant system primary loop pipe breaks need not be considered in the structural design basis of the Surry Units 1 and 2 Nuclear Power Plants for the 80 year plant life (Subsequent License Renewal Program). The technical evaluations utilized in Revision O through Revision 2 of this report are consistent with the methodology and principles of WCAP-9558 and WCAP-9787.

Therefore, the justifications demonstrated herein are compliant with the original conclusions of Generic Letter 84-04.

The report documents the plant specific geometry, loading, and material properties used in the fracture mechanics evaluation. Mechanical properties were determined at operating temperatures.

WCAP-15550-NP March 2019 Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 viii Since the piping systems include cast austenitic stainless steel, fracture toughness considering thermal aging was determined for each heat of material. Fully aged fracture toughness properties were used for the LBB evaluation. The full aged condition is applicable for plants operating at beyond 15 EFPY (Effective Full Power Years) for the CF8M materials (elbows for Surry Units 1 and 2). As of January 2017, Surry Units 1 and 2 are operating at 33.78 and 33.69 EFPY, respectively. Thus, the LBB evaluation in this report has been demonstrated for the primary loops at Surry Units 1 and 2 for 80 years of plant operation.

WCAP-15550-N P March 2019 Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 1-1

1.0 INTRODUCTION

1.1 PURPOSE This report applies to the Surry Units 1 and 2 Reactor Coolant System (RCS) primary loop piping. It is intended to demonstrate that for the specific parameters of the Surry Units 1 and 2 Nuclear Power Plants, RCS primary loop pipe breaks need not be considered in the structural design basis for the 80 year plant life (Subsequent License Renewal Program). This report also includes the LBS evaluation results based on the Measurement Uncertainty Recapture (MUR)

Program.

1.2 BACKGROUND

INFORMATION Westinghouse has performed considerable testing and analysis to demonstrate that RCS primary loop pipe breaks can be eliminated from the structural design basis of all Westinghouse plants. The concept of eliminating pipe breaks in the RCS primary loop was first presented to the NRC in 1978 in WCAP-9283 (Reference 1-3). That topical report employed a deterministic fracture mechanics evaluation and a probabilistic analysis to support the elimination of RCS primary loop pipe breaks. That approach was then used as a means of addressing Generic Issue A-2 and Asymmetric LOCA Loads.

Westinghouse performed additional *testing and analysis to justify the elimination of RCS primary loop pipe breaks. This material was provided to the NRC along with Letter Report NS-EPR-2519 (Reference 1-4).

The NRC funded research through Lawrence Livermore National Laboratory (LLNL) to address this same issue using a probabilistic approach. As part of the LLNL research effort, Westinghouse performed extensive evaluations of specific plant loads, material properties, transients, and system geometries to demonstrate that the analysis and testing previously performed by Westinghouse and the research performed by LLNL applied to all Westinghouse plants (References 1-5 and 1-6). The results from the LLNL study were released at a March 28, 1983, ACRS Subcommittee meeting. These studies, which are applicable to all Westinghouse plants east of the Rocky Mountains, determined the mean probability of a direct LOCA (RCS 12 primary loop pipe break) to be 4.4 x 10- per reactor year and the mean probability of an 7

indirect LOCA to be 10- per reactor year. Thus, the results previously obtained by Westinghouse (Reference 1-3) were confirmed by an independent NRC research study.

Based on the studies by Westinghouse, LLNL, the ACRS, and the AIF, the NRC completed a safety review of the Westinghouse reports submitted to address asymmetric blowdown loads that result from a number of discrete break locations on the PWR primary systems. The NRC Staff evaluation (Reference 1-1) concludes that an acceptable technical basis has been provided so that asymmetric blowdown loads need not be considered for those plants that can demonstrate the applicability of the modeling and conclusions contained in the Westinghouse response or can provide an equivalent fracture mechanics demonstration of the primary coolant loop integrity. In a more formal recognition of Leak-Before-Break (LBS) methodology applicability for PWRs, the NRC appropriately modified 10 CFR 50, General Design Criterion 4, "Requirements for Protection Against Dynamic Effects for Postulated Pipe Rupture" (Reference 1-2).

Introduction March 2019 WCAP-15550-NP Revision 2

WESTING HOUSE NON-PROPRIETARY CLASS 3 1-2 1.3 SCOPE AND OBJECTIVES The general purpose of this investigation is to demonstrate leak-before-break for the primary loops in Surry Units 1 and 2 on a plant specific basis for the 80 year plant life. The recommendations and criteria proposed in References 1-7 and 1-8 are used in this evaluation.

These criteria and resulting steps of the evaluation procedure can be briefly summarized as follows:

1. Calculate the applied loads. Identify the locations at which the highest stress occurs.

2. Identify the materials and the associated material properties.

3. Postulate a surface flaw at the governing locations. Determine fatigue crack growth.

Show that a through-wall crack will not result.

4. Postulate a through-wall flaw at the governing locations. The size of the flaw should be large enough so that the leakage is assured of detection with margin using the installed leak detection equipment when the pipe is subjected to normal operating loads. A margin of 10 is demonstrated between the calculated leak rate and the leak detection capability.

5. Using faulted loads, demonstrate that there is a margin of 2 between the leakage flaw size and the critical flaw size.

6. Review the operating history to ascertain that operating experience has indicated no particular susceptibility to failure from the effects of corrosion, water hammer or low and high cycle fatigue.

7. For the materials actually used in the plant provide the properties including toughness and tensile test data .. Evaluate long term effects such as thermal aging.

8. Demonstrate margin on applied load.

This report provides a fracture mechanics demonstration of primary loop integrity for the Surry Units 1 and 2 plants consistent with the NRC position for exemption from consideration of dynamic effects.

It should be noted that the terms "flaw" and "crack" have the same meaning and are used interchangeably. "Governing location" and "critical location" are also used interchangeably throughout the report.

The computer codes used in this evaluation for leak rate and fracture mechanics calculations have been validated and used for all the LBB applications by Westinghouse.

March 2019 Introduction Revision 2 WCAP-15 550-NP

WESTINGHOU SE NON-PROPRIETARY CLASS 3 1-3

1.4 REFERENCES

1-1 USNRC Generic Letter 84-04,

Subject:

"Safety Evaluation of Westinghouse Topical Reports Dealing with Elimination of Postulated Pipe Breaks in PWR Primary Main Loops," February 1, 1984.

1-2 Nuclear Regulatory Commission, 10 CFR 50, Modification of General Design Criteria 4 Requirements for Protection Against Dynamic Effects of Postulated Pipe Ruptures, Final Rule, Federal RegisterNol. 52, No. 207fruesday, October 27, 1987/Rules and Regulations, pp. 41288-41295.

1-3 WCAP-9283, "The Integrity of Primary Piping Systems of Westinghouse Nuclear Power Plants During Postulated Seismic Events," March, 1978.

1-4 Letter Report NS-EPR-2519, Westinghouse (E. P. Rahe) to NRC (D. G. Eisenhut),

Westinghouse Proprietary Class 2, November 10, 1981.

1-5 Letter from Westinghouse (E. P. Rahe) to NRC (W. V. Johnston) dated April 25, 1983.

1-6 Letter from Westinghouse (E. P. Rahe) to NRC (W. V. Johnston) dated July 25, 1983.

1-7 Standard Review Plan: Public Comments Solicited; 3.6.3 Leak-Before-Break Evaluation Procedures; Federal RegisterNol. 52, No. 167/Friday August 28, 1987/Notices, pp.

32626-32633.

1-8 NUREG-0800 Revision 1, March 2007, Standard Review Plan: 3.6.3 Leak-Before-Break Evaluation Procedures.

1-9 WCAP-9558, Revision 2, "Mechanistic Fracture Evaluation of Reactor Coolant Pipe Containing a Postulated Circumferential Throughwall Crack," May, 1981.

1-10 WCAP-9787, "Tensile and Toughness Properties of Primary Piping Weld Metal for Use in Mechanistic Fracture Evaluation," May, 1981.

Introduction March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 2-1 2.0 OPERATION AND STABILITY OF THE REACTOR COOLANT SYSTEM 2.1 STRESS CORROSION CRACKING The Westinghouse reactor coolant system primary loops have an operating history that demonstrates the inherent operating stability characteristics of the design. This includes a low susceptibility to cracking failure from the effects of corrosion (e.g., intergranular stress corrosion cracking (IGSCC)). This operating history totals over 1400 reactor-years, including 16 plants each having over 30 years of operation, 10 other plants each with over 25 years of operation, 11 plants each with over 20 years of operation, and 12 plants each with over 15 years of operation.

In 1978, the United States Nuclear Regulatory Commission (USNRC) formed the second Pipe Crack Study Group. (The first Pipe Crack Study Group (PCSG) established in 1975, addressed cracking in boiling water reactors only.) One of the objectives of the second PCSG was to include a review of the potential for stress corrosion cracking in Pressurized Water Reactors (PWR's). The results of the study performed by the PCSG were presented in NUREG-0531 (Reference 2-1) entitled "Investigation and Evaluation of Stress Corrosion Cracking in Piping of Light Water Reactor Plants." In that report the PCSG stated:

"The PCSG has determined that the potential for stress-corrosion cracking in PWR primary system piping is extremely low because the ingredients that produce IGSCC are not all present. The use of hydrazine additives and a hydrogen overpressure limit the oxygen in the coolant to very low levels. Other impurities that might cause stress-corrosion cracking, such as halides or caustic, are also rigidly controlled. Only for brief periods during reactor shutdown when the coolant is exposed to the air and during the subsequent startup are conditions even marginally capable of producing stress-corrosion cracking in the primary systems of PWRs. Operating experience in PWRs supports this determination. To date, no stress corrosion cracking has been reported in the primary piping or safe ends of any PWR."

During 1979, several instances of cracking in PWR feedwater p1pmg led to the establishment of the third PCSG. The investigations of the PCSG reported in NUREG-0691 (Reference 2-2) further confirmed that no occurrences of IGSCC have been reported for PWR primary coolant systems.

As stated above, for the Westinghouse plants there is no history of cracking failure in the reactor coolant system loop. The discussion below further qualifies the PCSG's findings.

For stress corrosion cracking (SCC) to occur in piping, the following three conditions must exist simultaneously: high tensile stresses, susceptible material, and a corrosive environment. Since some residual stresses and some degree of material susceptibility exist in any stainless steel piping, the potential for stress corrosion is minimized by properly selecting a material immune to SCC as well as preventing the occurrence of a Operation and Stability of the Reactor Coolant System March 2019 WCAP-15550-NP . Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 2-2 corrosive environment. The material specifications consider compatibility with the system's operating environment (both internal and external) as well as other material in the system, applicable ASME Code rules, fracture toughness, welding, fabrication, and processing.

The elements of a water environment known to increase the susceptibility of austenitic stainless steel to stress corrosion are: oxygen, fluorides, chlorides, hydroxides, hydrogen peroxide, and reduced forms of sulfur (e.g., sulfides, sulfites, and thionates). Strict pipe cleaning standards prior to operation and careful control of water chemistry during plant operation are used to prevent the occurrence of a corrosive environment. Prior to being put into service, the piping is cleaned internally and externally. During flushes and preoperational testing, water chemistry is controlled in accordance with written specifications. Requirements on chlorides, fluorides, conductivity, and pH are included in the acceptance criteria for the piping.

During plant operation, the reactor coolant water chemistry is monitored and maintained within very specific limits. Contaminant concentrations are kept below the thresholds known to be conducive to stress corrosion cracking with the major water chemistry control standards being included in the plant operating procedures as a condition for plant operation. For example, during normal power operation, oxygen concentration in the RCS is expected to be in the ppb range by controlling charging flow chemistry and maintaining hydrogen in the reactor coolant at specified concentrations. Halogen concentrations are also stringently controlled by maintaining concentrations of chlorides and fluorides within the specified limits. Thus during plant operation, the likelihood of stress corrosion cracking is minimized.

It should be noted that there are no primary water stress corrosion cracking material such as Alloy 82/182 in the dissimilar metal welds in the Surry Units 1 and 2 Reactor Coolant System (RCS) primary loop piping.

2.2 WATER HAMMER Overall, there is a low potential for water hammer in the RCS since it is designed and operated to preclude the voiding condition in normally filled lines. The reactor coolant system, including piping and primary components, is designed for normal, upset, emergency, and faulted condition transients. The design requirements are conservative relative to both the number of transients and their severity. Relief valve actuation and the associated hydraulic transients following valve opening are considered in the system design. Other valve and pump actuations are relatively slow transients with no significant effect on the system dynamic loads. To ensure dynamic system stability, reactor coolant parameters are stringently controlled. Temperature during normal operation is maintained within a narrow range; pressure is controlled by pressurizer heaters and pressurizer spray also within a narrow range for steady-state conditions. The flow characteristics of the system remain constant during a fuel cycle because the only governing parameters, namely system resistance and the reactor coolant pump characteristics, are controlled in the design process. Additionally, Westinghouse has instrumented typical reactor coolant systems to verify the flow and vibration characteristics of the system. Preoperational Operation and Stability of the Reactor Coolant System March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 2-3 testing and operating experience have verified the Westinghouse approach. The operating transients of the RCS primary piping are such that no significant water hammer can occur.

2.3 LOW CYCLE AND HIGH CYCLE FATIGUE An assessment of the low cycle fatigue loadings was carried out as part of this study in the form of a fatigue crack growth analysis, as discussed in Section 8.0.

High cycle fatigue loads in the system would result primarily from pump vibrations. These are minimized by restrictions placed on shaft vibrations during hot functional testing and operation. During operation, an alarm signals the exceedance of the vibration limits. Field measurements have been made on a number of plants during hot functional testing, including plants similar to Surry Units 1 and 2. Stresses in the elbow below the reactor coolant pump resulting from system vibration have been found to be very small, between 2 and 3 ksi at the highest. These stresses are well below the fatigue endurance limit for the material and would also result in an applied stress intensity factor below the threshold for fatigue crack growth.

2.4 WALL THINNING, CREEP, AND CLEAVAGE Wall thinning by erosion and erosion-corrosion effects should not occur in the primary loop piping due to the low velocity, typically less than 1.0 ft/sec and the stainless steel material, which is highly resistant to these degradation mechanisms. The cause of wall thinning is related to high water velocity and is therefore clearly not a mechanism that would affect the primary loop piping.

Creep is typical experienced for temperatures over 700°F for stainless steel material, and the maximum operating temperature of the primary loop piping is well below this temperature value; therefore, there would be no significant mechanical creep damage in stainless steel piping.

Cleavage type failures are not a concern for the operating temperatures and the stainless steel material used in the primary loop piping.

2.5 REFERENCES

2-1 Investigation and Evaluation of Stress-Corrosion Cracking in Piping of Light Water Reactor Plants, NUREG-0531, U.S. Nuclear Regulatory Commission, February 1979.

2-2 Investigation and Evaluation of Cracking Incidents in Piping in Pressurized Water Reactors, NUREG-0691, U.S. Nuclear Regulatory Commission, September 1980.

Operation and Stability of the Reactor Coolant System March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-1 3.0 PIPE GEOMETRY AND LOADING

3.1 INTRODUCTION

TO METHODOLOGY The general approach is discussed first. As an example a segment of the primary coolant hot leg pipe is shown in Figure 3-1. The as-built outside diameter and minimum wall thickness of the pipe are 34.00 in. and 2.395 in., respectively, as shown in the figure. The normal stresses at the weld locations are from the load combination procedure discussed in Section 3.3 whereas the faulted loads are as described in Section 3.4. The components for normal loads are pressure, dead weight and thermal expansion. An additional component, Safe Shutdown Earthquake (SSE), is considered for faulted loads. Tables 3-1 and 3-2 show the enveloping loads for Surry Units 1 and 2; these loads were determined as part of the MUR project. As seen from Table 3-2, the highest stressed location in the entire loop is at Location 1 at the reactor vessel outlet nozzle to pipe weld. This is one of the locations at which, as an enveloping location, leak-before-break is to be established. Essentially a circumferential flaw is postulated to exist at this location which is subjected to both the normal loads and faulted loads to assess leakage and stability, respectively. The loads (developed below) at this location are also given in Figure 3-1.

Since the elbows are made of different materials than the pipe, locations other than the highest stressed pipe location were examined taking into consideration both fracture toughness and stress. The four most critical locations among the entire primary loop are identified after the full analysis is completed. Once loads (this section) and fracture toughnesses (Section 4.0) are obtained, the critical locations are determined (Section 5.0). At these locations, leak rate evaluations (Section 6.0) and fracture mechanics evaluations (Section 7.0) are performed per the guidance of References 3-1 and 3-2. Fatigue crack growth (Section 8.0) assessment and stability margins are also evaluated (Section 9.0). All the weld locations considered for the LBB evaluation are those shown in Figure 3-2.

Please note that the piping loads and stresses based on the MUR Program were considered in the LBB evaluation as part of Revision 1 of this WCAP report.

3.2 CALCULATION OF LOADS AND STRESSES The stresses due to axial loads and bending moments are calculated by the following equation:

F M (3-1) a=-+ -

A Z

where, cr = stress, ksi F = axial load, kips M = bending moment, in-kips 2

A = pipe cross-sectional area, in z = section modulus, in 3 Pipe Geometry and Loading March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-2 The total moments for the desired loading combinations are calculated by the following equation:

(3-2)

where, M = total moment for required loading Mx = X component of moment (torsion)

Mv = Y component of bending moment Mz = Z component of bending moment NOTE: X-axis is along the center line of the pipe.

I The axial load and bending moments for leak rate predictions and crack stability analyses are computed by the methods to be explained in Sections 3.3 and 3.4.

3.3 LOADS FOR LEAK RATE EVALUATION The normal operating loads for leak rate predictions are calculated by the following equations:

F = Fow + FTH + Fp (3-3)

Mx = (Mx)ow + (Mx)TH (3-4)

Mv = (Mv)ow + (MvhH (3-5)

Mz = (Mz)ow + (MzhH (3-6)

The subscripts of the above equations represent the following loading cases:

ow = deadweight TH = normal thermal expansion p = load due to internal pressure This method of combining loads is often referred to as the algebraic sum method (References 3-1 and 3-2).

The loads based on this method of combination are provided in Table 3-1 at all the weld locations identified in Figure 3-2. The as-built dimensions are also given in Table 3-1.

Pipe Geometry and Loading March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-3 3.4 LOAD COMBINATION FOR CRACK STABILITY ANALYSES In accordance with Standard Review Plan 3.6.3 (References 3-1 and 3-2), the margin in terms of applied loads needs to be demonstrated by crack stability analysis. Margin on loads of 1.4

(../2) can be demonstrated if normal plus Safe Shutdown Earthquake (SSE) are applied. The 1.4

(../2) margin should be reduced to 1.0 if the deadweight, thermal expansion, internal pressure, pressure expansion, SSE INERTIA and seismic anchor motion (SAM) loads are combined based on individual absolute values as shown below.

The absolute sum of loading components is used for the LBB analysis which results in higher magnitude of combined loads and thus satisfies a margin on loads of 1.0. The absolute summation of loads is shown in the following equations:

F = I Fow I + I FTH I + I Fp I + I FssEINERTIA I + I FssEAM I (3-7)

Mx = I (Mx)ow I + I (MxhH I + I (Mx)ssEINERTIA I + I (Mx)ssEAM I (3-8)

Mv = I (Mv)ow I+ I (MvhH I+ I (Mv)ssEINERTIAI + I (Mv)ssEAM I (3-9)

Mz = I (Mz)ow I + I (Mz)TH I + I (Mz)ssEINERTIA I + I (Mz)ssEAM I (3-10) where subscript SSEINERTIA refers to safe shutdown earthquake inertia, SSEAM is safe shutdown earthquake anchor motion, respectively.

The loads so determined are used in the fracture mechanics evaluations (Section 7.0) to demonstrate the LBB margins at the locations established to be the governing locations. These loads at all the weld locations (see Figure 3-2) are given in Table 3-2.

3.5 REFERENCES

3-1 Standard Review Plan: Public Comments Solicited; 3.6.3 Leak-Before-Break Evaluation Procedures; Federal RegisterNol. 52, No. 167/Friday, August 28, 1987/Notices, pp. 32626-32633.

3-2 NUREG-0800 Revision 1, March 2007, Standard Review Plan: 3.6.3 Leak-Before-Break Evaluation Procedures.

Pipe Geometry and Loading March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-4 Table 3-1 Dimensions, Normal Loads and Stresses for Surry Units 1 and 2 3 Outside Minimum Axial Loadb Moment Total Stress Location Diameter (in) Thickness (in) (kips) (in-kips) (ksi) 1 34.00 2.395 1482 19815 17.51 2 34.00 2.395 1482 837 6.71 3 34.00 2.395 1482 9661 11.73 4 37.75 3.270 1614 14956 9.87 5 37.625 3.208 1628 7852 7.55 6 36.32 2.555 1605 6815 9.11 7 36.32 2.555 1599 6786 9.07 8 36.32 2.555 1709 1071 6.81 9 37.625 3.208 1709 2666 5.90 10 37.625 3.208 1844 9466 8.76 11 32.26 2.270 1365 2588 8.11 12 32.26 2.270 1365 2927 8.33 13 32.26 2.270 1366 2373 7.97 14 33.60 2.940 1366 3636 6.64 15 33.60 2.940 1363 4955 7.29 Notes:

a. See Figure 3-2

b. Included Pressure

_Pipe Geometry and Loading March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-5 Table 3-2 Faulted Loads and Stresses for Surry Units 1 and 2 Locationa,b Axial Loadc Moment Total Stress (kips) (in-kips) (ksi) 1 1640 24646 20.93 2 1640 2652 8.41 3 1639 12918 14.25 4 1941 20101 12.62 5 1927 22956 13.89 6 1870 15673 14.23 7 1864 9928 11.52 8 1839 8475 10.75 9 1839 11375 9.43 10 1885 14032 10.53 11 1413 7850 11.84 12 1413 7390 11.54 13 1420 6032 10.66 14 1422 7923 8.99 15 1418 10829 10.42 Notes:

a. See Figure 3-2

b. See Table 3-1 for dimensions

c. Included Pressure Pipe Geometry and Loading March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-6 Crack

'

(-

---

• ) M

1. OD

.1 ooa = 34.00 in Location 1 ta = 2.395 in Normal Loadsa Faulted Loadsb Forcec: 1482 kips Forcec: 1640 kips Bending Moment: 19815 in-kips Bending Moment: 24646 in-kips a See Table 3-1 b See Table 3-2 c Includes the force due to a pressure of 2250 psia Figure 3-1 Hot Leg Coolant Pipe Pipe Geometry and Loading March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 3-7

• Reactor Pressure Vessel

.....-coLDLEG

...--@

...--@

\ _ Reactor Coolant Pump

\....__ _ Steam Generator CROSSOVER LEG HOT LEG Temperature 609.1 °F Pressure: 2250 psia CROSS-OVER LEG Temperature 542.6°F Pressure: 2250 psia COLD LEG Temperature 542.9°F Pressure: 2250 psia Figure 3-2 Schematic Diagram of Surry Units 1 and 2 Primary Loop Showing Weld Locations Pipe Geometry and Loading March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-1 4.0 MATERIAL CHARACTERIZATION 4.1 PRIMARY LOOP PIPE AND FITTINGS MATERIALS The primary loop pipe is A376-TP316 and the elbow fittings are A351-CF8M for Surry Units 1 and 2.

4.2 TENSILE PROPERTIES The Pipe Certified Materials Test Reports (CMTRs) for Surry Units 1 and 2 were used to establish the tensile properties for the leak-before-break analyses. The CMTRs include tensile properties at room temperature and/or at 650°F for each of the heats of material. These properties are given in Table 4-1 for the Surry Unit 1 pipe, Table 4-2 for the Surry Unit 2 pipe, Table 4-3 for Unit 1 elbows and in Table 4-4 for Unit 2 elbows.

The representative properties at 609°F (represents actual 609.1 °F for Hot Leg) for the pipe were established from the tensile properties at 650°F given in Tables 4-1 and 4-2 by utilizing Section II of the 1999ASME Boiler and Pressure Vessel Code (Reference 4-1). Code tensile properties at 609°F were obtained by interpolating between the 600°F and 650°F tensile properties. Ratios of the code tensile properties at 609°F to the corresponding tensile properties at 650°F were then applied to the 650°F tensile properties given in Tables 4-1 and 4-2 to obtain the plant specific properties for A376-TP316 at 609°F. It should be noted that there is no significant impact by using the 1999 ASME Code Section II edition for material properties for the LBB analysis, as compared to the Surry ASME code of record.

The representative properties at 609°F (represents actual 609.1 °F for Hot Leg) and 543°F (represents actual 542.9°F for Cold Leg and 542.6°F for Crossover Leg) for the elbows were established from the tensile properties at room temperature properties given in Tables 4-3 and 4-4 by utilizing Section II of the 1999 ASME Boiler and Pressure Vessel Code (Reference 4-1).

Code tensile properties at 609°F and 543°F were obtained by interpolating between the 500°F, 600°F and 650°F tensile properties. Ratios of the code tensile properties at 609°F and 543°F to the corresponding tensile properties at room temperature were then applied to the room temperature tensile properties given in Tables 4-3 and 4-4 to obtain the plant specific properties for A351-CF8M at 609°F and 543°F.

The average and lower bound yield strengths and ultimate strengths are given in Table 4-5. The ASME Code moduli of elasticity values are also given, and Poisson's ratio was taken as 0.3.

Updated CMTRs from Replacement Steam Generator (RSG) replacement elbows on Surry Unit 1 are also considered. The added tensile properties are shown in Table 4-3 (marked by grey-shaded color). Of these added properties, the minimum Yield Strength is 38350 psi and the minimum Ultimate Strength is 81200 psi. These values are bounded by lower bound values in Table 4-5. It has also been reviewed that the updated tensile data has negligible impact to the average Yield Strength in Table 4-5.

4.3 FRACTURE TOUGHNESS PROPERTIES The pre-service fracture toughness (J) of cast stainless steels that are of interest are in terms of J 1c (J at Crack Initiation) and have been found to be very high at 600°F. [

]a,c,e However, cast Material Characterization March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-2 stainless steel is susceptible to thermal aging at the reactor operating temperature, that is, about 290°C (550°F). Thermal aging of cast stainless steel results in embrittlement, that is, a decrease in the ductility, impact strength, and fracture toughness of the material. Depending on the material composition, the Charpy impact energy of a cast stainless steel component could decrease to a small fraction of its original value after exposure to reactor temperatures during service.

The susceptibility of the material to thermal aging increases with increasing ferrite contents. The molybdenum bearing CF8M shows increased susceptibility to thermal aging.

The method described below was used to calculate the end of life toughness properties for the cast material of the Surry Units 1 and 2 primary coolant loop piping and elbows.

In 1994, the Argonne National Laboratory (ANL) completed an extensive research program in assessing the extent of thermal aging of cast stainless steel materials (Reference 4-2). The ANL research program measured mechanical properties of cast stainless steel materials after they had been heated in controlled ovens for long periods of time. ANL compiled a data base, both from data within ANL and from international sources, of about 85 compositions of cast stainless steel exposed to a temperature range of 290-400°C (550-750°F) for up to 58,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> (6.5 years). In 2015 the work done by ANL was augmented, and the fracture toughness database for CASS materials was aged to 100,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> at 290-350°C (554-633°F). The methodology for estimating fracture properties has been extended to cover CASS materials with a ferrite content of up to 40%. From this database (NUREG/CR-4513, Revision 2), ANL developed correlations for estimating the extent of thermal aging of cast stainless steel (Reference 4-3).

ANL developed the fracture toughness estimation procedures by correlating data in the database conservatively. After developing the* correlations, ANL validated the estimation procedures by comparing the estimated fracture toughness with the measured value for several cast stainless steel plant components removed from actual plant service. The procedure developed by ANL in Reference 4-3 was used to calculate the end of life fracture toughness values for this analysis. The ANL research program was sponsored and the procedure was accepted by the NRC.

Based on NUREG/CR-4513, Revision 2, the fracture toughness correlations used for the full aged condition is applicable for plants operating at and beyond 15 EFPY (Effective Full Power Years) for the CF8M materials (elbows for Surry Units 1 and 2). As of January 2017, Surry Units 1 and 2 are operating at 33. 78 and 33.69 EFPY, respectively. Therefore, the use of the fracture toughness correlations described below is applicable for the fully aged or saturated condition of the Surry Units 1 and 2 elbow materials made of CF8M.

The chemical compositions of the Surry Units 1 and 2 primary loop elbow fitting material are available from CMTRs and are provided in Table 4-6 and Table 4-7 of this report. The following equations are taken from Reference 4-3 and applicable for CF8M type material:

Creq = Cr+ 1.21 (Mo) + 0.48(Si) - 4.99 = (Chromium equivalent) (4-1) 2 Nieq =(Ni)+ 0.11(Mn)- 0.0086(Mn) + 18.4(N) + 24.5(C) + 2.77 = (Nickel equivalent) (4-2)

Oc =100.3(Creq I Nieq )2-170.72(Creq I Nieq )+74.22 = (Ferrite Content) (4-3)

Material Characterization March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-3 where the elements are in percent weight and oc is ferrite in percent volume.

The saturation room temperature (RT) impact energies of the cast stainless steel materials were determined from the chemical compositions available from CMTRs and provided in Tables 4-6 and 4-7.

For CF8M steel with < 10% Ni, the saturation value of RT impact energy CVsat (J/cm 2 ) is the lower value determined from log10CVsat = 0.27 + 2.81 exp (-0.022$) (4-4) where the material parameter $ is expressed as

$ = oc (Ni + Si + Mn)2(C + 0.4N)/5.0 (4-5) and from log 10CVsat = 7.28 - 0.011oc - 0.185Cr - 0.369Mo - 0.451 Si - 0.007Ni - 4.71 (C + 0.4N) (4-6)

For CF8M steel with ~ 10% Ni, the saturation value of RT impact energy Cvsat (J/cm 2

) is the lower value determined from log10CVsat = 0.84 + 2.54 exp (-0.047$) (4-7) where the material parameter $ is expressed as

$ = oc (Ni + Si + Mn)2(C + 0.4N)/5.0 (4-8) and from log10CVsat = 7 .28 - 0.011 oc - 0.185Cr - 0.369Mo - 0.451 Si - 0.007Ni - 4. 71 (C + 0.4N) (4-9)

The saturation J-R curve at RT, for static-cast CF8M steel is given by 135 2 (4-10)

Jd = 1.44 (CVsat) ' (.!iat for CVsat < 35 J/cm for CVsat ~ 35 J/cm 2

(4-11) n = 0.20 + 0.08 log10 (CVsat) (4-12) where Jct is the "deformation J" in kJ/m 2 and Lia is the crack extension in mm.

The saturation J-R curve at 290-320°C (554-608°F), for static-cast CF8M steel is given by 98 2 Jd = 5.5 (CVsal' (Liat for CVsat < 46 J/cm (4-13) 41 for CVsat ~ 46 J/cm 2

Jd = 49 (CVsal' (Lia)" (4-14) n = 0.19 + 0.07 log10 (CVsat) (4-15) where Jct is the "deformation J" in kJ/m 2 and Lia is the crack extension in mm.

Material Characterization March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-4 The results from the ANL Research Program indicate that the lower-bound fracture toughness of thermally aged cast stainless steel is similar to that of submerged arc welds (SAWs). The applied value of the J-integral for a flaw in the weld regions will be lower than that in the base 1

metal because the yield stress for the weld materials is much higher at the temperature.

Therefore, weld regions are less limiting than the cast material.

In the fracture mechanics analyses that follow, the fracture toughness properties given in Table 4-8 will be used as the criteria against which the applied fracture toughness values will be compared.

As indicated in the record of revisions table, this stress report is revised to address CMTR errors and to address updated CMTRs from RSG replacement elbows on Unit 1.

As shown in the revised Tables 4-6 and 4-7, the corrections of CMTR errors (shown in bold font) and updates due to additional CMTR's (marked by grey-shaded color) have been included in this stress report. It has been reviewed that the revisions do not impact the evaluation results in this Section 4 material characterization. The summary of limiting fracture toughness properties provided in Table 4-8 remains valid and applicable. The revisions also do not affect the conclusions of this stress report.

4.4 REFERENCES

4-1 ASME Boiler and Pressure Vessel Code, An International Code,Section II, Materials, Part D-Properties, 1999 Addenda, July 1, 1999.

4-2 0. K. Chopra and W. J. Shack, "Assessment of Thermal Embrittlement of Cast Stainless Steels," NUREG/CR-6177, U.S. Nuclear Regulatory Commission, Washington, DC, May 1994.

4-3 0. K. Chopra, "Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems," NUREG/CR-4513, Revision 2, U.S. Nuclear Regulatory Commission, Washington, DC, May 2016.

1 In the report all the applied J values were conservatively determined by using base metal strength properties.

Material Characterization March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-5 Table 4-1 Measured Tensile Properties (psi) for Surry Unit 1 Primary Loop Pipes At Room Temp. At 650°F Heat No./Serial Yield Ultimate Yield Ultimate Location Strength Strength Strength No. Strength F021212867Z X-over Leg 43500 84200 26400 67000 F021212867Z X-over Leg 43900 82500 NIA NIA F021512894Y X-over Leg 40000 84800 21700 66800 F021512894Y X-over Leg 41900 87700 NIA NIA F022212900Y X-over Leg 44000 86500 21500 66200 F022212900Y X-over Leg 41500 83200 NIA NIA 877712883X X-over Leg 36100 78200 21000 62000 877712883X X-over Leg 38500 77800 NIA NIA 878512881X X-over Leg 36100 74200 20400 57200 878512881X X-over Leg 39700 79800 NIA NIA 891512885X X-over Leg 38500 77400 24200 62300 891512885X X-over Leg 38600 77200 NIA NIA 877712874Y Cold Leg 35300 79200 24100 65600 877712874Y Cold Leg 34900 78200 NIA NIA 891312875Y Cold Leg 35100 78400 24300 68500 891312875Y Cold Leg 41100 84800 NIA NIA F022812996 Cold Leg 45100 88600 24700 69800 F022812996 Cold Leg 43900 87400 NIA NIA F022912952 Cold Leg 42200 85300 24500 68200 F022912952 Cold Leg 39700 83400 NIA NIA F016212859 Cold Leg 46000 83500 27600 69400 F016212859 Cold Leg 52900 87900 NIA NIA F016212860 Cold Leg 43700 83900 NIA NIA F016212860 Cold Leg 47400 90400 NIA NIA F021612861 Cold Leg 40600 83400 21300 66600 F021612861 Cold Leg 40000 80500 NIA NIA F022712947 Cold Leg 42500 83700 20900 66600 F022712947 Cold Leg 43200 87100 NIA NIA F022912951 Cold Leg 42000 84400 24500 68200 F022912951 Cold Leg 44500 86800 NIA NIA 878512963X Hot Leg 33400 75700 22000 61000 878512963X Hot Leg 33600 75300 NIA NIA FO 19012847Y Hot Leg 42000 88800 21300 58200 F019012847Y Hot Leg 43000 86000 NIA NIA F005812629 Hot Leg 41200 85200 27000 74000 F005812629 Hot Leg 44300 89500 NIA NIA F018812845 Hot Leg 40900 83000 26100 67000 F018812845 Hot Leg 43000 84000 NIA NIA E148213353 Hot Leg 41800 84400 24500 66200 E148213353 Hot Leg 41700 84600 NIA NIA Note: NIA= Not Applicable Material Characterization March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-6 Table 4-2 Measured Tensile Properties (psi) for Surry Unit 2 Primary Loop Pipes At Room Temperature At 650°F Heat No./Serial Yield Ultimate Yield Ultimate Location Strength Strength No. Strength Strength F0213/2889 Hot Leg 43200 84800 23700 69800 F0213/2889 Hot Leg 44000 88400 N/A N/A F0213/2890X Hot Leg 41900 82500 N/A N/A F0213/2890X Hot Leg 46500 84500 N/A N/A F0213/2891X Hot Leg 44000 86000 N/A N/A F0213/2891X Hot Leg 41000 83000 N/A N/A F0227/2897X Hot Leg 41800 86800 N/A N/A F0227/2897X Hot Leg 42500 85500 N/A N/A F0373/3169 Cold Leg 41400 85800 25600 71900 F0373/3169 Cold Leg 44800 89700 N/A N/A F0221 /2866X X-over Leg 44000 83800 N/A N/A F0221/2866Y X-over Leg 42700 86000 21600 65200 F0222/2900X X-over Leg 44000 86500 21500 66200 F0222/2900X X-over Leg 41500 83200 N/A N/A 52154/2843 Cold Leg 43500 86500 23100 57400 52154/2843 Cold Leg 33300 75600 N/A N/A F0228/2948 Cold Leg 42500 87400 24700 69800 F0228/2948 Cold Leg 45000 87500 N/A N/A F0229/2994 Cold Leg 41000 82800 24500 68200 F0229/2994 Cold Leg 45000 87900 N/A N/A E1490/3347Y Hot Leg 43100 86000 23700 68000 E1490/3347Y Hot Leg 43000 82700 N/A N/A F0189/2869Y X-over Leg 37700 80600 N/A N/A F0189/2869Z X-over Leg 44100 91000 N/A N/A F0189/2868X X-over Leg 37700 80600 25200 70000 F0189/2868X X-over Leg 44100 91000 N/A N/A F0226/2946 Cold Leg 43000 85000 21500 66400 F0226/2946 Cold Leg 42100 86000 N/A N/A K2011/3683X Cold Leg 32100 75900 20600 56200 1<2011 /3683X Cold Leg 38400 81900 N/A N/A E1478/3257 Cold Leg 38000 82900 25300 72400 E1478/3257 Cold Leg 42400 84900 N/A N/A V0629/3262 Cold Leg 48400 88800 21100 67400 V0629/3262 Cold Leg 41300 82200 N/A N/A F0229/2953 Cold Leg 41000 84900 24500 68200 F0229/2953 Cold Leg 45000 86200 N/A N/A l

F0215/2892Y Hot Leg 43000 83000 21700 66800 F0215/2892Y Hot Leg 42000 84600 N/A N/A Note: N/A = Not Applicable Material Characterization March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-7 Table 4-3 Measured Tensile Properties (psi) for Surry Unit 1 Primary Loop Elbows At Room Temperature Heat No. Location Yield Strength Ultimate Strength 10360-1 X-over Leg 46500 88000 10844-1 X-over Leg 39000 78000 11046-1 X-over Leg 43500 87000 11246-1 X-over Leg 42000 82500 11441-1 X-over Leg 48000 88500 11937-1 X-over Leg 45000 88500 10442-1 X-over Leg 48000 88500 11168-1 X-over Leg 46500 88000 12198-1 X-over Leg 45000 85000 12623-1 X-over Leg 42000 80000 10482-1 X-over Leg 45750 80250 10723-1 X-over Leg 46200 88600 29943-2 Cold Leg 39300 77300 30690-1 Cold Leg 39700 80200 29943-1 Hot Leg 38400 74900 31011-5 Hot Leg 43000 84800 28387-2 Hot Leg 42300 85800 28387-1 Cold Leg 42300 85800 30597-2 X-over Leg 42300 84800 10128-2 X-over Leg 46500 89000 10243-2 X-over Leg 48000 90000 Note:

• tensile properties from the added heats are not included in the average tensile property calculations in Table 4-5, but the impact of the added tensile data are negligible.

Material Characterization March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-8 Table 4-4 Measured Tensile Properties (psi) for Surry Unit 2 Primary Loop Elbows At Room Temperature Heat No. Location Yield Strength Ultimate Strength 30080-2 Hot Leg 42400 82400 32535-2 Cold Leg 44100 87500 31571-6 Cold Leg 42800 85600 14008-1 X-over Leg 48000 87000 14085-1 X-over Leg 45000 86000 14165-1 X-over Leg 48000 89000 12709-1 X-over Leg 48000 85500 14507-1 X-over Leg 40500 82000 13579-1 X-over Leg 48000 85500 13781-5 X-over Leg 4500 89500 13826-2 X-over Leg 48000 87500 30690-2 Hot Leg 38100 82200 31427-2 Hot Leg 41250 86250 14786-3 X-over Leg 42000 84500 14990-1 X-over Leg 43500 84500 15384-1 X-over Leg 45000 88500 15769-1 X-over Leg 46500 85500 30080-1 Cold Leg 45100 84200 12087-3 X-over Leg 42000 80500 12547-2 X-over Leg 40500 83500 13051-4 X-over Leg 40500 83500 Material Characterization March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-9 Table 4-5 Mechanical Properties for Surry Units 1 and 2 Materials at Operating Temperatures Lower Bound Average Yield Modulus of Temperature* Yield Ultimate Material Strength Elasticity (OF) Strength Strength (psi) (psi)

- (psi) (psi) 6 A376 TP316 609 23835 25.255 X 10 20,762 56,200 6

609 27468 25.255 X 10 23,785 71,904 A351 CF8M 6 543 28493 25.585 X 10 24,672 71,904 Poisson's ratio: 0.3 Note: Representative temperature. The actual temperatures are provided in Figure 3-2.

Material Characterization March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-10 Table 4-6 Chemistry and Fracture Toughness Elbow Properties of the Material Heats of Surry Unit 1 a,c,e Material Characterization March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-11 Table 4-6 Chemistry and Fracture Toughness Elbow Properties of the Material Heats of Surry Unit 1 a,c,e Material Characterization March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-12 Table 4-7 Chemistry and Fracture Toughness Elbow Properties of the Material l:feats of Surry Unit 2 a,c,e Material Characterization March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-13 Table 4-8 Fracture Toughness Properties for Surry Units 1 and 2 Primary Loops for Leak-Before-Break Evaluation at Critical Locations a,c,e Material Characterization March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 4-14 a .. c .. e Figure 4-1 Pre-Service J vs. ~a for SA351-CF8M Cast Stainless Steel at 600°F Material Characterization March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 5-1 5.0 CRITICAL LOCATION AND EVALUATION CRITERIA 5.1 CRITICAL LOCATIONS The leak-before-break (LBB) evaluation margins are to be demonstrated for the limiting locations (governing locations). Such locations are established based on the loads (Section 3.0) and the material properties established in Section 4.0. These locations are defined below for Surry Units 1 and 2. Table 3-2 as well as Figure 3-2 are used for this evaluation.

Critical Locations The highest stressed location for the entire primary loop is at Location 1 (in the Hot Leg) (See Figure 3-2) at the reactor vessel outlet nozzle to pipe weld. Location 1 is critical for all the weld locations of pipe.

Since the elbows are made of cast materials, the critical locations for the elbows are: for the hot leg, the highest stressed location is at weld location 3; for the cross-over leg, the highest stressed location is at weld location 6; and for the cold leg; the highest stressed location is at weld location 15. It is thus concluded that the enveloping locations in Surry Units 1 and 2 for which LBB methodology is to be applied are locations 1, 3, 6 and 15. The tensile properties and the allowable toughness for the critical locations are shown in Tables 4-5 and 4-8.

5.2 FRACTURE CRITERIA As will be discussed later, fracture mechanics analyses are made based on loads and postulated flaw sizes related to leakage. The stability criteria against which the calculated J and tearing modulus are compared are:

(1) If Japp < J 1c, then the crack will not initiate and the crack is stable; (2) If Japp~ J1c; and Tapp< T mat and Japp< Jmax, then the crack is stable.

Where:

Japp = Applied J J1c = J at Crack Initiation Tapp = Applied Tearing Modulus Tmat = Material Tearing Modulus Jmax = Maximum J value of the material For critical locations, the limit load method discussed in Section 7.0 was also used.

Critical Location and Evaluation Criteria March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 6-1 6.0 LEAK RATE PREDICTIONS

6.1 INTRODUCTION

The purpose of this section is to discuss the method which is used to predict the flow through postulated through-wall cracks and present the leak rate calculation results for through-wall circumferential cracks.

6.2 GENERAL CONSIDERATIONS The flow of hot pressurized water through an opening to a lower back pressure causes flashing which can result in choking. For long channels where the ratio of the channel length, L, to hydraulic diameter, DH, (UDH) is greater than [

6.3 CALCULATION METHOD The basic method used in the leak rate calculations is the method developed by [

The flow rate through a crack was calculated in the following manner. Figure 6-1 from Reference 6-2 was used to estimate the critical pressure, Pc, for the primary loop enthalpy condition and an assumed flow. Once Pc was found for a given mass flow, the [

]8-c,e was found from Figure 6-2 (taken from Reference 6-2). For all cases considered, since [ ]8-c,e Therefore, this method will yield the two-phase pressure drop due to momentum effects as illustrated in Figure 6-3, where PO is the operating pressure. Now using the assumed flow rate, G, the frictional pressure drop can be calculated using (6-1) where the friction factor f is determined using the [ ]a,c,e The crack relative roughness, c, was obtained from fatigue crack data on stainless steel samples. The relative roughness value used in these calculations was [ ]a,c,e The frictional pressure drop using equation 6-1 is then calculated for the assumed flow rate and added to the [ ]a,c,e to obtain the total pressure drop from the primary system to the atmosphere. That is, for the primary loop:

Ab~olute Pressure - 14. 7 = [ (6-2)

Leak Rate Predictions March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 6-2 for a given assumed flow rate G. If the right-hand side of equation 6-2 does not agree with the pressure difference between the primary loop and the atmosphere, then the procedure is repeated until equation 6-2 is satisfied to within an acceptable tolerance which in turn leads to flow rate value for a given crack size.

6.4 LEAK RATE CALCULATIONS Leak rate calculations were made as a function of crack length at the governing locations previously identified in Section 5.1. The normal operating loads of Table 3-1 were applied in these calculations. The crack opening areas were estimated using the method of Reference 6-3, and the leak rates were calculated using the two-phase flow formulation described above. The average material properties of Section 4.0 (see Table 4-5) were used for these calculations.

The flaw sizes to yield a leak rate of 10 gpm were calculated at the governing locations and are given in Table 6-1 for Surry Units 1 and 2. The flaw sizes so determined are called leakage flaw sizes.

The Surry Units 1 and 2 RCS pressure boundary leak detection system meets the intent of Regulatory Guide 1.45, and the plant leak detection capability is 1 gpm. Thus, to satisfy the margin of 10 on the leak rate, the flaw sizes (leakage flaw sizes) are determined which yield a leak rate of 10 gpm.

6.5 REFERENCES

6-1 6-2 M. M, EI-Wakil, "Nuclear Heat Transport, International Textbook Company," New York, N.Y, 1971.

6-3 Tada, H., "The Effects of Shell Corrections on Stress Intensity Factors and the Crack Opening Area of Circumferential and a Longitudinal Through-Crack in a Pipe,"

Section 11-1, NUREG/CR-3464, September 1983.

Leak Rate Predictions March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 6-3 Table 6-1 Flaw Sizes Yielding a Leak Rate of 10 gpm at the Governing Locations Location Leakage Flaw Size (in) 1 4.02 3 5.85 6 6.84 15 7.96 Note: The flaw size in the above table refers to the flaw length of through-wall circumferential crack.

Leak Rate Predictions March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 6-4 a,c,e

-

-=i

-&

...-

>

u

...0

"'>

ti C

2 STAGNATION ENTHALPY no2 Btu/lb)

Figure 6-1 Analytical Predictions of Critical Flow Rates of Steam-Water Mixtures Leak Rate Predictions March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 6-5 a,c,e LENGTH/OIAMET'EA RATIO (L/D)

Figure 6-2 [ ia,c,e Pressure Ratio as a Function of UD Leak Rate Predictions March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 6-6

[

Figure 6-3 Idealized Pressure Drop Profile Through a Postulated Crack Leak Rate Predictions March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-1 7.0 FRACTURE MECHANICS EVALUATION 7.1 LOCAL FAILURE MECHANISM The local mechanism of failure is primarily dominated by the crack tip behavior in terms of crack-tip blunting, initiation, extension and final crack instability. The local stability will be assumed if the crack does not initiate at all. It has been accepted that the initiation toughness measured in terms of J1c from a J-integral resistance curve is a material parameter defining the crack initiation. If, for a given load, the calculated J-integral value is shown to be *less than the J 1c of the material, then the crack will not initiate. If the initiation criterion is not met, one can calculate the tearing modulus as defined by the following relation:

dJ E Tapp= -d Xz a at where:

Tapp = applied tearing modulus E = modulus of elasticity

= 0.5 (cry+ cru) = flow stress a = crack length cry, cru = yield and ultimate strength of the material, respectively Stability is. said to exist when ductile tearing does not occur if Tapp is less than T mat, the experimentally determined tearing modulus. Since a constant T mat is assumed a further restriction is placed in Japp* Japp must be less than Jmax where Jmax is the maximum value of J for which the experimental T mat is greater than or equal to the Tapp used.

As discussed in Section 5.2 the local crack stability criteria is a two-step process:

( 1) If Japp < J 1c, then the crack will not initiate and the crack is stable; (2) If Japp ~ J1c; and Tapp < T mat and Japp < Jmax, then the crack is stable.,

Fracture Mechanics Evaluation March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-2 7 .2 GLOBAL FAILURE MECHANISM Determination of the conditions which lead to failure in stainless steel should be done with plastic fracture methodology because of the large amount of deformation accompanying fracture. One method for predicting the failure of ductile material is the plastic instability method, based on traditional plastic limit load concepts, but accounting for strain hardening and taking into account the presence of a flaw. The flawed pipe is predicted to fail when the remaining net section reaches a stress level at which a plastic hinge is formed. The stress level at which this occurs is termed as the flow stress. The flow stress is generally taken as the average of the yield and ultimate tensile strength of the material at the temperature of interest.

This methodology has been shown to be applicable to ductile piping through a large number of experiments and will be used here to predict the critical flaw size in the primary coolant piping.

The failure criterion has been obtained by requiring equilibrium of the section containing the flaw (Figure 7-1) when loads are applied. The detailed development is provided in Appendix A for a through-wall circumferential flaw in a pipe with internal pressure, axial force, and imposed bending moments. The limit moment for such a pipe is given by:

r,c,e

= 0.5 (cry+ cru) = flow stress, psi The analytical model described above accurately accounts for the piping internal pressure as well as imposed axial force as they affect the limit moment. Good agreement was found between the analytical predictions and the experimental results (Reference 7-1). For application of the limit load methodology, the material, including consideration of the configuration, must have a sufficient ductility and ductile tearing resistance to sustain the limit load.

Fracture Mechanics Evaluation March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-3 7.3 CRACK STABILITY EVALUATIONS Local Failure Mechanism:

Fracture Mechanics Evaluation March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-4 Global failure mechanism:

A stability analysis based on limit load was performed for all the critical locations (locations 1, 3, 6 and 15) as described in Section 7.2. The field welds are made of GTAW and SMAW combination weld. The shop welds are made of GTAW, SMAW or SAW combination weld.

Field welds are at the Critical locations 1, 3 and 15. Shop weld is at critical location 6. The "Z" factor correction for SMAW was applied (References 7-5 and 7-6) at the field weld critical locations (locations 1, 3 and 15) and the "Z" factor correction for SAW was applied (References 7-5 and 7-6) at the shop weld location (location 6) and the equations as follows:

Z = 1.15 [1.0 + 0.013 (OD-4)] for SMAW Z = 1.30 [1.0 + 0.01 (OD-4)] for SAW where OD is the outer diameter of the pipe in inches.

The Z-factors were calculated for the critical locations, using the dimensions given in Table 3-1.

The Z factor was 1.599 for locations 1 and 3, 1. 72 for location 6 and 1.592 for location 15. The applied loads were increased by the Z factors and plots of limit load versus crack length were generated as shown in Figures 7-2, 7-3, 7-4 and 7-5. Table 7-2 summarizes the results of the stability analyses based on limit load. The leakage flaw sizes are also presented on the same table.

7.4 REFERENCES

7-1 Kanninen, M. F., et. al., "Mechanical Fracture Predictions for Sensitized Stainless Steel Piping with Circumferential Cracks," EPRI NP-192, September 1976.

7-2 Johnson, W. and Mellor, P. B., Engineering Plasticity, Van Nostrand Relmhold Company, New York, (1973), pp. 83-86.

7-3 Tada, H., "The Effects of Shell Corrections on Stress Intensity Factors and the Crack Opening Area of Circumferential and a Longitudinal Through-Crack in a Pipe," Section 11-1, NUREG/CR-3464, September 1983.

7-4 Irwin, G. R., "Plastic Zone near a Crack and Fracture Toughness," Proc.ih Sagamore Conference, P. IV-63 (1960).

7-5 Standard Review Plan; Public Comment Solicited; 3.6.3 Leak-Before-Break Evaluation Procedures; Federal RegisterNol. 52, No. 167/Friday, August 28, 1987/Notices, pp.

32626-32633.

7-6 NUREG-0800 Revision 1, March 2007, Standard Review Plan: 3.6.3 Leak-Before-Break Evaluation Procedures.

Fracture Mechanics Evaluation March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-5 Table 7-1 Stability Results for Surry Units 1 and 2 Based on Elastic-Plastic J-lntegral Evaluations a,c,e Table 7-2 Stability Results for Surry Units 1 and 2 Based on Limit Load Critical Location Critical Flaw Size (in) Leakage Flaw Size (in) 1 19.87 4.02 3 34.08 5.85 6 34.81 6.84 15 40.07 7.96 Fracture Mechanics Evaluation March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-6 Neutral Axis Figure 7-1 [ ]a,c,e Stress Distribution Fracture Mechanics Evaluation March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-7 80000 70000 60000

- I I) 0.

SC:I 50000

--C C

Q) 40000 E

0 30000

1E

.:==

E 20000

J 10000 0

0 10 20 30 40 50 Flaw Length (inches)

OD = 34.00 in. cry = 20. 76 ksi F = 1640 kips t = 2.395 in. cru = 56.20 ksi M = 24646 in-kips A376-TP316 Material with SMAW Weld Figure 7-2 Critical Flaw Size Prediction - Hot Leg at Location 1 Fracture Mechanics Evaluation March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-8.

100000 90000 80000

-0 Q.

i..

70000 60000

-

C:

,:..

C:

50000 Q)

E 40000 0

!2E

t: 30000 E

J 20000 ------------****---------------------- -----------------*----------------- (34_080 in_, 20650 in-kips) 10000 0

0 10 20 30 40 50 Flaw Length (inches)

OD= 34.00 in. cry = 23. 78 ksi F = 1639 kips t= 2.395 in. cru = 71.90 ksi M = 12918 in-kips A351-CF8M Material with SMAW Weld Figure 7-3 Critical Flaw Size Prediction - Hot Leg at Location 3 Fracture Mechanics Evaluation March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-9 140000 120000

- II)

Q.

ii:I 100000

-....

.5 C

Cl) 80000 E

0 60000

E

t::

E

i 40000 (34.814 in., 26960 in-kips) 20000 0

0 10 20 30 40 50 Flaw Length (inches)

OD = 36.32 in. cry = 24.67 ksi F = 1870 kips t = 2.555 in. cru = 71.90 ksi M = 15673 in-kips A351-CF8M material with SAW Weld Figure 7-4 Critical Flaw Size Prediction - Crossover Leg at Location 6 Fracture Mechanics Evaluation March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 7-10 100000

- Cl)

Q.

.i:I 80000

-....

.5 C:

G) 60000 E

0

IS

!::

E 40000

J 20000 0 ......- .............-+__.______+-_.............-+__.______+-_..............-+.....____--...

0 10 20 30 40 50 60 Flaw Length (inches)

OD = 33.60 in. cry =24.67ksi F=1418kips t = 2.940 in. cru = 71.90 ksi M = 10829 in-kips A351-CF8M material with SMAW Weld Figure 7-5 Critical Flaw Size Prediction - Cold Leg at Location 15 Fracture Mechanics Evaluation March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-1 8.0 FATIGUE CRACK GROWTH ANALYSIS To determine the sensitivity of the primary coolant system to the presence of small cracks, a fatigue crack growth analysis was carried out for the [ rc,e region of a typical system (see Location [ ]8,c,e of Figure 3-2). This region was selected because crack growth calculated here will be typical of that in the entire primary loop. Crack growths calculated at other locations can be expected to show less than 10% variation.

A[ ]a,c,e of a plant typical in geometry and operational characteristics to any Westinghouse PWR System.

[

]a,c,e The normal, upset, and test conditions were considered. A summary of generic applied transients is provided in Table 8-1. Circumferentially oriented surface flaws were postulated in the region, assuming the flaw was located in two different locations, as shown in Figure 8-1. Specifically, these were:

Cross Section A: Stainless Steel Cross Section B: SA 508 Cl. 2 or 3 Low Alloy Steel Fatigue crack growth rate laws were used [

]8,c,e The law for stainless steel was derived from Reference 8-1, a compilation of data for austenitic stainless steel in a PWR water environment was presented in Reference 8-2, and it was found that the effect of the environment on the crack growth rate was very small. From this information it was estimated that the environmental factor should be conservatively set at [ rc,e in the crack growth rate equation from Reference 8-1.

For stainless steel, the fatigue crack growth formula is:

Fatigue Crack Growth Analysis March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-2 The calculated fatigue crack growth for semi-elliptic surface flaws of circumferential orientation and various depths is summarized in Table 8-2, and shows that the crack growth is very small, regardless of which material is assumed.

The reactor vessel transients and cycles for Surry Units 1 and 2 are shown in Table 8-3. By comparing the transients and cycles for the generic analysis shown in Table 8-1 and the Surry plant specific transients and cycles shown in Table 8-3, it is concluded that the generic transients and cycles used for the fatigue crack growth analysis enveloped the Surry transients and cycles. The transients and cycles (shown in Table 8-3) for the Surry plants for 60 years are the same as those of 40 years, and remain applicable for 80 years of operation as well. Also any changes in the cycles for the 80 year design transients will not have a significant impact on the fatigue crack growth conclusions, since there is insignificant growth of small surface flaws as shown in Table 8-2.

It is therefore, concluded that the generic fatigue crack growth analysis shown in Table 8-2 is representative of the Surry plants fatigue crack growth and also applicable for 80 years.

8.1 REFERENCES

8-1 James, L.A. and Jones, D.P., "Fatigue Crack Growth Correlations for Austenitic Stainless Steel in Air, Predictive Capabilities in Environmentally Assisted Cracking," ASME Publication PVP-99, December 1985.

8-2 Bamford, W. H., "Fatigue Crack Growth of Stainless Steel Piping in a Pressurized Water Reactor Environment," Trans. ASME Journal of Pressure Vessel Technology, Vol. 101, Feb. 1.979.

Fatigue Crack Growth Analysis March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-3 Table 8-1 Summary of Reactor Vessel Transients Number of Number Typical Transient Identification Cycles 1 Turbine Roll 10 2 Cold Hydro 10 3 Heatup/Cooldown 200 4 Loading and Unloading 18300 5 10% Step Load Decrease/Increase 2000 6 Large Step Decrease 200 7 Steady State Fluctuation 1000000 8 Loss of Load from Full Power 80 9 Loss of Power 40 10 Partial Loss of Flow 80 11 Reactor Trip from Full Power 400 12 Hot Hydro Test 50 Fatigue Crack Growth Analysis March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-4 a,c,e Table 8-2 Typical Fatigue Crack Growth at [ 1 (40, 60, and 80 years)

FINAL FLAW ( in.) a,c,e Fatigue Crack Growth Analysis March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-5 Table 8-3 Summary of Reactor Vessel Transients For Surry Units 1 and 2 (40, 60, 80 years)

Number Typical Transient Identification Number of Cycles 1 Heatu p/Cooldown 200 2 Loading and Unloading 18300 3 10% Step Load Decrease/Increase 2000 4 ' Large Step Decrease 200 5 Reactor Trip from Full Power 400 6 Hot Hydro Test 45 Fatigue Crack Growth Analysis March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-6

]a,c,e Figure 8-1 Typical Cross-Section of [

Fatigue Crack Growth Analysis March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 8-7 1000 - - - - - - - - - - - - - - - - - - - - - - - - - - - - ~

• Linear interpolation is recom-700 mended to account for ratio dependence of water environment 500 curves, for 0.25 <R< 0.65 for shallow slope:

~ = (1.01 X 10*11 o ti. K1 .95 dN 2 02 = 3.75 R +0.06 R = /(min /Kmax 200 Subsurface fla\NS

.!!

u 100 lair environment)

.

>

u J::

u 70 C

• eu Determine the ti.K at which the 50 i law changes by calculation of the intersection of the two

§ curves.

""~

e a:'" Surface flaws J:: (water reactor j environment) 20 e

t.7 applicable for

"'I!

u R < 0.25 u "0.25 < R < 0.65 R;, 0.65 10 R = Kmin /Krnax 7

5

• Linear interpolation is recommended to account for R ratio dependence of water environment curves, for 0.25 < R < 0.65 fer steep s!ope:

da = (1.02 X 10-61 01 ti.K5 *95 dN 01 = 26.9R

• 5.725 R = Kmin /Kmax 2 5 7 10 20 50 70 100 Stress lntensitv Factor Range (ti.K1 ksi ~.I Figure 8-2 Reference Fatigue Crack Growth Curves for Carbon & Low Alloy Ferritic Steels Fatigue Crack Growth Analysis March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 9-1 9.0 ASSESSMENT OF MARGINS The results of the leak rates of Section 6.4 and the corresponding stability and fracture toughness evaluations of Sections 7.1, 7.2 and 7.3 are used in performing the assessment of margins. Margins are shown in Table 9-1. All of the LBB recommended margins are satisfied.

In summary, at all the critical locations relative to:

1. Flaw Size - Using faulted loads obtained by the absolute sum method, a margin of 2 or more exists between the critical flaw and the flaw having a leak rate of 10 gpm (the leakage flaw).

2. Leak Rate - A margin of 10 exists between the calculated leak rate from the leakage flaw and the plant leak detection capability of 1 gpm.

3. Loads - At the critical locations the leakage flaw was shown to be stable using the faulted loads obtained by the absolute sum method (i.e., a flaw twice the leakage flaw size is shown to be stable; hence the leakage flaw size is stable). A margin of 1 on loads using the absolute summation of faulted load combinations is satisfied.

Assesment of Margins March 2019 WCAP-15550-N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 9-2 Table 9-1 Leakage Flaw Sizes, Critical Flaw Sizes and Margins for Surry Units 1 and 2 Location Leakage Flaw Size Critical Flaw Size Margin 8 8 1 4.02 in. 19.87 in. 4.9 8 8 3 5.85 in. 34.08 in. 5.8 3 5.85 in. 11.70bin. >2.0b 8 8 6 6.84 in. 34.81 in. 5.1 6 6.84 in. 13.68b in. >2.0b 8 8 15 7.96 in. 40.07 in. 5.0 15 7.96 in. 15.92b in. >2.0b "based on limit load bbased on J integral evaluation Assesment of Margins March 2019 WCAP-15550-NP Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 10-1

10.0 CONCLUSION

S This report justifies the elimination of RCS primary loop pipe breaks from the structural design basis for the 80 year plant life of Surry Units 1 and 2 as follows:

a. Stress corrosion cracking is precluded by use of fracture resistant materials in the piping system and controls on reactor coolant chemistry, temperature, pressure, and flow during normal operation. There is no Alloy 82/182 material present in the welds for the Surry Units 1 and 2 Reactor Coolant System (RCS) primary loop piping.

• b. Water hammer should not occur in the RCS piping because of system design, testing, and operational considerations.

c. The effects of low and high cycle fatigue on the integrity of the primary piping are negligible.

d. Ample margin exists between the leak rate of small stable flaws and the capability of the Surry Units 1 and 2 reactor coolant system pressure boundary Leakage Detection System.

e. Ample margin exists between the small stable flaw sizes of item (d) and larger stable flaws.

f. Ample margin exists in the material properties used to demonstrate end-of-service life (fully aged) stability of the critical flaws.

For the critical locations, flaws are identified that will be stable because of the ample margins described in d, e, and f above.

Based on the above, the Leak-Before-Break conditions and margins are satisfied for the Surry Units 1 and 2 primary loop piping. All the recommended margins are satisfied. It is therefore concluded that dynamic effects of RCS primary loop pipe breaks need not be considered in the structural design basis for Surry Units 1 and 2 Nuclear Power Plants for the 80 year plant life (subsequent license renewal program).

Conclusions March 2019 WCAP-15550-NP Revision 2

WESTINGHOU SE NON-PROPRIETARY CLASS 3 A-1 APPENDIX A: LIMIT MOMENT

]a,c,e Appendix A: Limit Moment March 2019 WCAP-15550- N P Revision 2

WESTINGHOUSE NON-PROPRIETARY CLASS 3 A-2 a,

0.-------------------

ca ----

Figure A-1 Pipe with a Through-Wall Crack in Bending Appendix A: Limit Moment March 2019 WCAP-15550-NP Revision 2

WCAP-15550-NP Revision 2 Proprietary Class 3

• • This page was added to the quality record by the PRIME system upon its validation and shall not be considered in the page numbering of this document.**

Author Approval Wiratmo Mamo Mar-14-2019 12:06:23 Reviewer Approval Johnson Eric D Mar-14-2019 12:16:52 Manager Approval Leber Benjamin A Mar-14-2019 12:27:28 Files approved on Mar-14-2019