ML031320381

Westinghouse Topical Report WCAP-15628-NP, Rev 0, Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for the H. B. Robinson Unit 2 Nuclear Power Plant for the License Renewal Program

ML031320381
Person / Time
Site:	Robinson
Issue date:	04/30/2003
From:	Bhowmick D, Petsche J, Swamy S Westinghouse
To:	Office of Nuclear Reactor Regulation
References
FOIA/PA-2005-0108 WCAP-15628-NP, Rev 0
Download: ML031320381 (66)

Text

Westinghouse Non-Proprietary Class 3 WCAP-15628-NP Revision 0 Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for the H. B. Robinson Unit 2 Nuclear Power Plant for the License Renewal Program h Westinghouse April 2003

Westinghouse Non-Proprietary Class 3 WCAP-15628-NP Revision 0 Technical Justification for Eliminating Large Primary Loop Pipe Rupture as the Structural Design Basis for the H. B. Robinson Unit 2 Nuclear Power Plant for the License Renewal Program D. C. Bhowmick April 2003 V erifier: _ _ _ _ _ _ _ _ _ _

F. Petsche Approved:

62LI4'"

S. A. Syamy, Mana Structural Mechanics Technology Westinghouse Electric Company LLC P.O. Box 355 Piftsburgh, PA 15230-0355

©2003 Westinghouse Electric Company LLC All Rights Reserved

iii TABLE OF CONTENTS EXECUTIVE

SUMMARY

...................................................... ix

1.0 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..................................................... 2-2

2.4 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..............................

.............. 4-2

4.4 REFERENCES

4-4 5.0 CRITICAL LOCATIONS 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......................................... 7-1 7.3 RESULTS OF CRACK STABILITY EVALUATION......................................... 7-3

7.4 REFERENCES

7-4 8.0 FATIGUE CRACK GROWTH ANALYSIS 8-1

8.1 REFERENCES

8-4

9.0 ASSESSMENT

OF MARGINS..........................................

9-1

10.0 CONCLUSION

S.........................................

10-1 APPENDIX A LIMIT MOMENT.A-1 April 2003

V LIST OF TABLES Table Title Page Table 3-1 Dimensions, Normal Loads and Normal Stresses for H. B. Robinson Unit 2

............................................................................................................................ 3-4 Table 3-2 Faulted Loads and Stresses for H. B. Robinson Unit 2..........

............................. 3-5 Table 4-1 Measured Tensile Properties (psi) for H. B. Robinson Unit 2 Primary Loop Pipes.4-6 Table 4-2 Measured Tensile Properties (psi) for H. B. Robinson Unit 2 Primary Loop Elbows.4-7 Table 4-3 Mechanical Properties for H. B. Robinson Unit 2 Materials at Operating Temperatures.4-8 Table 4-4 Chemistry and Fracture Toughness Properties of the Cast Material Heats of H. B. Robinson Unit 2.4-9 Table 4-5 Fracture Toughness Properties for H. B. Robinson Unit 2 Primary Loops for Leak-Before-Break Evaluation at Critical Locations.......................................... 4-10 Table 6-1 Flaw Sizes Yielding a Leak Rate of 10 gpm at the Governing Locations............. 6-3 Table 7-1 Stability Results for H. B. Robinson Unit 2 Based on Elastic-Plastic J-lntegral Evaluations................................................

7-5 Table 7-2 Stability Results for H. B. Robinson Unit 2 Based on Limit Load.........

................ 7-5 Table 8-1 Summary of Reactor Vessel Transients................

................................ 8-5 Table 8-2 Fatigue Crack Growth at RPV Inlet Nozzle Safe-End Region (40 and 60 years).8-7 Table 8-3 Fatigue Crack Growth at RPV Outlet Nozzle Safe-End Region (40 and 60 years).8-7 Table 9-1 Leakage Flaw Sizes, Critical Flaw Sizes and Margins for H. B. Robinson Unit2.9-2 April 2003

vii LIST OF FIGURES Figure Title Page 3-1 Hot Leg Coolant Pipe.....................................................

3-6 3-2 Schematic Diagram of H. B. Robinson Unit 2 Primary Loop Showing Weld Locations.3-7 4-1 Representative Lower Bound True Stress - True Strain Curve for A351 CF8M at 62 0 F.

4-11 4-2 Representative Lower Bound True Stress - True Strain Curve for A351 CF8M at 554 0F...................................................

4-12 4-3 Pre-Service J. vs. Aa for SA351 CF8M Cast Stainless Steel at 600°F......

........ 4-13 6-1 Analytical Predictions of Critical Flow Rates of Steam-Water Mixtures......

......... 6-4 6-2

[

a,c,e Pressure Ration as a Function of UD............................. 6-5 6-3 Idealized Pressure Drop Profile through a Postulated Crack..........

.................... 6-6 7-1

[

]a,C.e Stress Distribution....................................................

7-6 7-2 Critical Flaw Size Prediction - Hot Leg at Location 1........................................... 7-7 7-3 Critical Flaw Size Prediction - Hot Leg at Location 3........................................... 7-8 7-4 Critical Flaw Size Prediction - Cross-over Leg at Location 6............................... 7-9 7-5 Critical Flaw Size Prediction - Cold Leg at Location 13...............

...................... 7-10 8-1 Typical cross-section of RPV Inlet and outlet Nozzle Safe-End........................... 8-8 8-2 Reference Fatigue Crack Growth Curves for Carbon and Low Alloy Ferritic Steels.8-9 8-3 Reference Fatigue Crack Growth Curves for Stainless steel in Air Environments..................................................... 8-10 8-4 Crack Growth Model for Alloy in PWR Environments with Available Data.......... 8-11 A-1 Pipe with a Through-Wall Crack in Bending...................................................... A-2 April 2003

ix EXECUTIVE

SUMMARY

The original structural design basis of the reactor coolant system for the Carolina Power and Light Co. H. B. Robinson Unit 2 Nuclear Power Plant 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 H. B. Robinson Unit 2 design, an additional concern of Asymmetric Blowdown loads was raised as described in Unresolved Safety Issue A-2 (Asymmetric Blowdown Loads on the Reactor Coolant System). H. B. Robinson Unit 2 Nuclear Power Plant was 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 1-2).

The approved Westinghouse Generic Analyses were indicated to be directly applicable to H. B.

Robinson Unit 2 in Reference 1-2.

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 Reaister (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 1-3)." 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).

This report demonstrates compliance with LBB technology for the H. B. Robinson Unit 2 reactor coolant system piping based on a plant specific analysis for the License Renewal Program.

The report documents the plant specific geometry, loading, and material properties used in the fracture mechanics evaluation.

Mechanical properties were determined at operating temperatures.

Since the piping systems include cast stainless steel, fracture toughness considering thermal aging was determined for each heat of material.

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 postulated 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.

April 2003

x It is concluded that the Leak-Before-Break conditions are satisfied for the H. B. Robinson Unit 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 of the H. B. Robinson Unit 2 Nuclear Power Plant for the License Renewal Program.

April 2003

1-1

1.0 INTRODUCTION

1.1 PURPOSE This report applies to the H. B. Robinson Unit 2 Reactor Coolant System (RCS) primary loop piping. It is intended to demonstrate that for the specific parameters of the H. B. Robinson Unit 2 Nuclear Power Plant, RCS primary loop pipe breaks need not be considered in the structural design basis. The Nuclear Regulatory Commission (NRC) (Reference 1-3) has accepted the approach taken.

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 plant. The concept of eliminating pipe breaks in the RCS primary loop was first presented to the NRC in 1978 in WCAP-9283 (Reference 1-4). 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 1-5).

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 plant (References 1-6 and 1-7). The results from the LLNL study were released at a March 28, 1983, ACRS Subcommittee meeting. These studies, which are applicable to all Westinghouse plant east of the Rocky Mountains, determined the mean probability of a direct LOCA (RCS primary loop pipe break) to be 4.4 x 1012 per reactor year and the mean probability of an indirect LOCA to be 10-7 per reactor year. Thus, the results previously obtained by Westinghouse (Reference 1-4) were confirmed by an independent NRC research study.

Based on the studies by Westinghouse, LLNL, the ACRS, and the AlF, 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 1-2) concludes that an acceptable technical basis has been provided so that asymmetric blowdown loads need not be considered for those plant 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 (LBB) methodology applicability for PWRs, the NRC appropriately modified 10 CFR 50, General Design Criterion 4, Introduction April 2003 o:\\4438.doc:ib-040103 Revision 0

1-2

'Requirements for Protection Against Dynamic Effects for Postulated Pipe Rupture" (Reference 1-3).

1.3 SCOPE AND OBJECTIVES The general purpose of this investigation is to demonstrate leak-before-break for the primary loops in H. B. Robinson Unit 2 on a plant specific basis. The recommendations and criteria proposed in Reference 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 at least 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 H. B.

Robinson Unit 2 Plant consistent with the NRC position for exemption from consideration of dynamic effects.

Several computer codes are used in the evaluations. The computer programs are under Configuration Control, which has, requirements conforming to NRC's Standard Review Plan 3.9.1 (Reference 1-9). The fracture mechanics calculations are independently verified (benchmarked).

Introduction April 2003 o:\\4438.doc:1 b-040103 Revision 0

1-3

1.4 REFERENCES

1-1 WCAP-7211, Revision 4, "Proprietary Information and Intellectual Property Management Policies and Procedures," January 2001.

1-2 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.

1-3 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. 207/Tuesday, October 27, 1987/Rules and Regulations, pp. 41288-41295.

1-4 WCAP-9283, "The Integrity of Primary Piping Systems of Westinghouse Nuclear Power Plant During Postulated Seismic Events," March 1978.

1-5 Letter Report NS-EPR-2519, Westinghouse (E. P. Rahe) to NRC (D. G. Eisenhut),

Westinghouse Proprietary Class 2, November 10,1981.

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

1-7 Letter from Westinghouse (E. P. Rahe) to NRC (W. V. Johnston) dated July 25, 1983.

1-8 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.

1-9 Nuclear Regulatory Commission, Standard Review Plan Section 3.9.1, Special Topics for Mechanical Component," NUREG-0800, Revision 2, July 1981.

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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 950 reactor-years, including 13 plant each having over 25 years of operation, 12 other plant each with over 20 years of operation and 8 plant each 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 Plant." 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 piping 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 plant, there is no history of 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 corrosive environment. The material specifications consider compatibility with the system's operating environment (both internal and Operation and Stability of the Reactor Coolant System April 2003 o:\\4438.doc:lb-040103 Revision 0

2-2 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 pre-operational 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. Maintaining concentrations of chlorides and fluorides within the specified limits also stringently controls halogen concentrations. Thus during plant operation, the likelihood of stress corrosion cracking is minimized.

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 actuation is 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 by control rod position; pressurizer heaters and pressurizer spray also within a narrow range for steady-state conditions control pressure. The flow characteristics of the system remain constant during a fuel cycle because the only goveming 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. Pre-operational 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.

Operation and Stability of the Reactor Coolant System April 2003 o:14438.doc:1b-040103 Revision 0

2-3 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 exceedence of the vibration limits. Field measurements have been made on a number of plant during hot functional testing, including plant similar to H.

B. Robinson Unit 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 REFERENCES

2-1 Investigation and Evaluation of Stress-Corrosion Cracking in Piping of Light Water Reactor Plant, 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.

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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 2.40 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 H. B. Robinson Unit 2. 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. Location 1 is also the critical location for the stainless steel and Alloy 182 welds. 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 locations other than highest stressed pipe location were examined taking into consideration both fracture toughness and stress. The four most critical locations 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 Reference 3-1. Fatigue crack growth (Section 8.0) assessment and stability margins are also evaluated (Section 9.0).

All the weld locations for evaluation are those shown in Figure 3-2.

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

a = (F/A)+(M/Z')

(3-1)

where, a

=

stress F

=

axial load M

=

moment A

=

pipe cross-sectional area Z'

=

section modulus Pipe Geometry and Loading April 2003 o:\\4438non.doc:lb-040103 Revision 0

3-2 The bending moments for the desired loading combinations are calculated by the following equation:

M= (M 2+M 2+M~ 2)0.5 (3-2)

where, M

=

moment for required loading x

=

x component of bending moment M

=

y component of bending moment Mz

=

z component of bending moment 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

=

FDW +FTH+

Fp (3-3)

MX

=

(MX)DW + (MX)TH + (MX)P (3-4)

MY

=

(MY)DW + (MY)TH + (MY)P (3-5)

MZ

=

(MZ)Dw + (MZ)H + (MZ)P (3-6)

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

DW

=

deadweight TH

=

normal thermal expansion P

=

load due to internal pressure This method of combining loads is often referred as the algebraic sum method (Reference 3-1).

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

Pipe Geometry and Loading April 2003 o:\\4438non.doc:lb-040103 Revision 0

3-3 3.4 LOAD COMBINATION FOR CRACK STABILITY ANALYSES In accordance with Standard Review Plan 3.6.3 (Reference 3-1), the absolute sum of loading components can be applied which results in higher magnitude of combined loads. If crack stability is demonstrated using these loads, the LBB margin on loads can be reduced from /2 to 1.0. The absolute summation of loads are shown in the following equations:

F = I FDW I + I FTH I + I Fp I + I FSSEINERTIA I + I FSSEAM I (3-6)

Mx = I (MX)DW I + I (MX)TH I + I (MO)P I + I (MX)SSEINERTIA I + I (MXSSEAM I My = I (My)DW I + I (MY)TH I + I (My)p I + I (MY)SSEINERTIA I + I (My)SSEAM I Mz = I (MZ)DW I + I (MZ)TH I + I (Mz I + I (MZ)SSEINERTIA I + I (MZ)ssrEp I

(3-7)

(3-8)

(3-9) where subscripts SSE, INERTIA and AM mean safe shutdown earthquake, inertia and 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 locations of interest (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.

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Table 3-1 Dimensions, Normal Loads and Normal Stresses for H. B. Robinson Unit 2 Minimum Outside Diameter Thickness Axial Load b Moment Locationa (in)

(in)

(kips)

(in-kips)

Total Stress (ksi) 1 34.00 2.400 1492 22386 18.99 2

34.00 2.400 1492 4327 8.72 3

34.00 2.400 1492 9062 11.41 4

37.75 3.275 1849 16204 10.97 5

37.62 3.210 1665 4563 6.46 6

36.32 2.560 1654 4273 8.09 7

36.32 2.560 1651 4351 8.11 8

36.32 2.560 1706 1084 6.79 9

36.32 2.560 1706 2779 7.58 10 37.62 3.210 1801 7465 7.90 11 32.26 2.280 1354 7526 11.31 12 32.26 2.280 1354 4968 9.61 13 32.26 2.280 1354 5841 10.19 14 33.60 2.950 1339 7260 8.34

a.

See Figure 3-2

b.

Includes Pressure Pipe Geometry and Loading o:\\4438non.doc:1 b-0401 03 April 2003 Revision 0 3-4

Table 3-2 Faulted Loads and Stresses for H. B. Robinson Unit 2 Location' Axial Load' (kips)

Moment (in-kips)

Total Stress (ksi) 1 1639 22824 19.85 2

1638 5076 9.76 3

1638 9714 12.40 4

1956 18794 12.19 5

1882 14302 10.62 6

1840 9572 11.25 7

1837 6079 9.60 8

1841 6355 9.75 9

1839 7233 10.15 10 1846 15456 10.93 11 1405 13288 15.38 12 1405 10660 13.63 13 1406 9465 12.84 14 1401 11305 10.57

a.

See Figure 3-2

b.

See Table 3-1 for dimensions

c.

Includes Pressure Pipe Geometry and Loading o:\\4438non.doc:1 b-040103 April 2003 Revision 0 3-5

t Fa M

OD2 = 34.00 in ta

=2.40in Normal Loadsa forceC:

1492 kips Faulted Loadsb forcec:

22386 in-kips moment:

22824 in-kips a See Table 3-1 b See Table 3-3 C Includes the force due to a pressure of 2250 psia Figure 3-1 Hot Leg Coolant Pipe Pipe Geometry and Loading o:4438non.doc:1 b-040103 3-6 LI.

L moment:

1639 kips April 2003 Revision 0

3-7

\\-R Reactor Coolant Pump

\\-

Steam Generator CROSSOVER LEG HOT LEG Temperature 612°F, Pressure:

CROSSOVER LEG Temperature 554°F, Pressure:

COLD LEG Temperature 554°F, Pressure:

2250 psia 2250 psia 2250 psia Figure 3-2 Schematic Diagram of H. B. Robinson Unit 2 Primary Loop Showing Weld Locations Pipe Geometry and Loading o:\\4438non.doc:1 b-031 803 March 2003 Revision 0

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 the H. B.

Robinson Unit 2. Field weld process type used in the analysis is assumed as GTAW and SMAW combination and for the shop weld process type is GTAW, SMAW and SAW combination.

4.2 TENSILE PROPERTIES The Pipe Certified Materials Test Reports (CMTRs) for H. B. Robinson Unit 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 H. B. Robinson Unit 2 pipes, Table 4-2 for the H. B.

Robinson Unit 2 elbows.

The representative properties at 612°F for the pipe were established from the tensile properties at 650°F given in Table 4-1 by utilizing Section III of the 1989 ASME Boiler and Pressure Vessel Code (Reference 4-1). Code tensile properties at 612°F was obtained by interpolating between the 600°F and 650°F tensile properties. Ratios of the code tensile properties at 612°F to the corresponding tensile properties at 650°F were then applied to the 650°F tensile properties given in Table 4-1 to obtain the plant specific properties for the forged material A376 TP316 at 6120F.

The representative properties at 612°F and 554°F for the elbows were established from the tensile properties at room temperature properties given in Table 4-2 by utilizing Section III of the 1989 ASME Boiler and Pressure Vessel Code (Reference 4-1). Code tensile properties at 612°F and 554°F were obtained by interpolating between the 500°F, 600°F and 650°F tensile properties. Ratios of the code tensile properties at 612°F and 554°F to the corresponding tensile properties at room temperature were then applied to the room temperature tensile properties given in Table 4-2 to obtain the plant specific properties for the cast material A351 CF8M at-612°F and 5540F.

The average and lower bound yield strengths and ultimate strengths are given in Table 4-3.

The ASME Code moduli of elasticity values are also given, and Poisson's ratio was taken as 0.3.

For leak-before-break fracture evaluations at the critical locations the true stress-true strain curves for A351 CF8M at 612°F and 554°F must be available. These curves were obtained using the Nuclear Systems Materials Handbook (Reference 4-2). The lower bound true stress-true strain curves are given in Figures 4-1 and 4-2.

Material Characterization April 2003 o:A4438non.do1lb-040103 Revision 0

4-2 4.3 FRACTURE TOUGHNESS PROPERTIES Forged stainless steel piping such as A376 TP316 does not degrade due to thermal aging.

Thus fracture toughness values well in excess of that established in the following paragraphs for the cast material and welds exist for the material throughout service life and therefore, forged material is not limiting.

The pre-service fracture toughnesses of cast stainless steels in terms of Jlc have been found to be very high at 6000F. Typical results for a cast material are given in Figure 4-3. Jlc is observed to be over 2500 in-lbs/in2. However, cast stainless steel is susceptible to thermal aging at the reactor operating temperature, that is, about 2900C (5500F). Thermal aging of cast stainless steel results in embrittlement, that is, a decrease in the ductility, impacts strength, and fractures 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.

In 1994, the Argonne National Laboratory (ANL) completed an extensive research program in assessing the extent of thermal aging of cast stainless steel materials. The ANL research program measured mechanical properties of cast stainless steel materials after they have 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 290W4000C (550-7500F) for up to 58,000 hours0 days <br />0 hours <br />0 weeks <br />0 months <br /> (6.5 years).

From this database, ANL developed correlations for estimating the extent of thermal aging of cast stainless steel (References 4-3 and 4-4).

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 ANL procedures produced conservative estimates that were about 30 to 50 percent less than actual measured values. The procedure developed by ANL in Reference 4-4 was used to calculate the fracture toughness values for this analysis. ANL research program was sponsored and the procedure was accepted (Reference 4-5) by the NRC.

Material Characterization April 2003 o:\\4438non.doc:1 b-040703 Revision 0

4-3 I

Ia,r-e Material Characterization April 2003 o:\\4438non.doc:1 b-040703 Revision 0

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

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

In fracture mechanics analyses that follow, the fracture toughness properties given in Table 4-5 will be used as the criteria against which the applied fracture toughness values will be compared.

4.4 REFERENCES

4-1 ASME Boiler and Pressure Vessel Code Section 1II, "Rules for construction of Nuclear Power plant Components," Appendices, July 1, 1989.

4-2 Nuclear Systems Materials Handbook, Part 1 - Structural Materials, Group 1 - High Alloy Steels, Section 2, ERDA Report TID 26666, November, 1975.

4-3

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.

4-4

0. K. Chopra, "Estimation of Fracture Toughness of Cast Stainless Steels During Thermal Aging in LWR Systems," NUREG-CR-4513, Revision 1, U. S. Nuclear Regulatory Commission, Washington, DC, August 1994.

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

Material Characterization April 2003 o:\\4438non.doc:1 b-040703 Revision 0

4-5 REFERENCES (Cont'd) 4-5 "Flaw Evaluation of Thermally aged Cast Stainless Steel in Light-Water Reactor Applications," Lee, S.; Kuo, P. T.; Wichman, K.; Chopra, O.; Published in Intemational Journal of Pressure Vessel and Piping, June 1997.

Material Characterization o:\\4438non.doc: b-0401 03 April 2003 Revision 0

Table 4-1 Measured Tensile Pronartias (sil for H. B. Robinson Unit 2

__l___l_

At Room Temperature At 650°F HEAT YIELD ULTIMATE YIELD ULTIMATE NO.

LOCATION STRENGTH STRENGTH STRENGTH STRENGTH F0190 Hot Lea 42000 88800 21300 58200 FO190 Hot Lea 43000 86000 N/A N/A V0126 Hot Lea 40500 83000 23400 65200 V0126 Hot Lea 46100 90200 N/A N/A D8774 Hot Lea 36000 79200 24000 67400 D8774 Hot Lea 37000 79700 N/A N/A 52152 Hot Lea 37100 77400 20800 61400 52152 Hot Lea 36500 78600 N/A N/A F0214 Hot Lea 42500 82300 22400 62300 F0214 Hot Lea 44500 77300 N/A N/A D8777 X-Over Leg 36100 78200 20800 63700 D8777 X-Over Lea 38500 77800 N/A N/A D8915 X-Over Lea 38500 77400 24200 62300 D8915 X-Over Lea 38600 77200 N/A N/A D8785 X-Over Lea 36100 74200 20400 57200 D8785 X-Over Lea 39700 79800 N/A N/A F0189 X-Over Lea 37700 80600 25200 70000 F0189 X-Over Lea 44100 91000 N/A N/A D8775 X-Over Lea 36100 77800 20500 64100 D8775 X-Over Lea 39300 79000 N/A N/A D8915 X-Over Lea 37700 79600 22800 62400 D8915 X-Over Lea 39300 80200 N/A N/A F0216 Cold Lea 40900 83000 21300 66600 F0216 Cold Lea 42500 83500 N/A N/A 52263 Cold Lea 34200 75100 23100 63700 52263 Cold Lea 37800 75200 N/A N/A 08768 Cold Lea 36000 83000 23800 71700 D8768 Cold Lea 39300 82700 N/A N/A 52152 Cold Lea 44400 89700 21600 58800 52152 Cold Lea 34899 75200 N/A N/A V0342 Cold Lea 35100 75200 25600 52500 V0342 Cold Lea 36100 75100 N/A N/A D8913 C

35100 78400 24300 68500 D8913 Cold Lea 41100 84800 N/A N/A Material Characterization o:\\4438non.doc:lb-040103 4-6 April 2003 Revision 0

l______________

l At Room Temperature HEAT YIELD ULTIMATE NO.

LOCATION STRENGTH STRENGTH 4204 Hot Leg 43500 87500 7896 Hot Leg 43500 87500 8066 Hot Leg 49500 88500 3327 X-over Leg 51000 90000 6079 X-over Leg 54000 93800 6185 X-over Leg 43500 87500 9390A X-over Leg 45000 88500 9517 X-over Leg 48000 89000 9436 X-over Leg 45000 88500 9476 X-over Leg 43500 85500 9964 X-over Leg 48000 90000 10165 X-over Leg 55500 96500 9305A X-over Leg 51000 91500 9640 X-over Leg 48000 88000 9720 X-over Leg 45750 88000 9760 X-over Leg 45500 89500 9841 X-over Leg 45000 88500 9882 X-over Leg 45000 85500 4589 Cold Leg 45000 89000 5065 Cold Leg 45000 87500 5529 Cold Leg 54000 96000 Material Characterization o:I4438non.doc:1 b-0401 03 4-7 Table 4-2 Measured Tensile Properties (psi) for H. B. Robinson Unit 2 Primary Loop Elbows April 2003 Revision 0

Material Characterization o:\\4438non.doc:1 b-040103 4-8 Table 4-3 Mechanical Properties for H. B. Robinson Unit 2 Materials at Operating Temperatures Lower Bound Average Yield Yield Stress Ultimate Strength Material Temperature (F)

Strength (psi)

(psi)

(psi)

A376 TP316 612 22,955 20,651 52,500 A351 CF8M 612 29,556 27,156 81,836 554 30,468 27,994 81,836 Modulus of Elasticity E = 25.24x 106 psi, at 612°F E = 25.53 x 106 psi, at 554°F Poisson's ratio: 0.3 April 2003 Revision 0

4-9 a,c,e Material Characterization April 2003 oA4438non.doc:ib-040103 Revision 0

4-10 a,c,e Material Characterization April 2003 o:\\4438non.doc:1 b-040103 Revision 0

4-11 a,c,e Figure 4-1 Representative Lower Bound True Stress - True Strain Curve for A351 CF8M at 612 0 F Material Characterization o:\\4438non.doc:1 b-040103 April 2003 Revision 0

4-12 a,c,e Figure 4-2Representative Lower Bound True Stress - True Strain Curve for A351 CF8M at 5540F Material Characterization o:\\4438non.doc: b-0401 03 April 2003 Revision 0

4-13 a,c,e Figure 4-3 Pre-Service J vs. Aa for SA351 CF8M Cast Stainless Steel at 600°F Material Characterization o:\\4438non.doc:1 b-0401 03 April 2003 Revision 0

5-1 5.0 CRITICAL LOCATIONS AND EVALUATION CRITERIA 5.1 CRITICAL LOCATIONS The leak-before-break (LBB) evaluation margins are to be demonstrated for the limiting locations (goveming 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 H.

B. Robinson Unit 2. Table 3-2 as well as Figure 3-2 is 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 the critical weld location for pipe. Location 1 is also the critical location for the stainless steel and Alloy 182 welds.

Since the elbows are made of cast materials, the critical weld locations for the elbows are as follows. 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 13. It is thus concluded that the enveloping locations in H. B.

Robinson Unit 2 for which LBB methodology is to be applied are locations 1, 3, 6 and 13. The tensile properties and the allowable toughness for the critical locations are shown in Tables 4-3 and 4-5.

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 < Jlc then the crack will not initiate; (2)

If Japp > Jlc, but, if Tapp < Tat and Japp < Jmax, then the crack is stable.

Where:

Japp

=

Applied J Jic

=

J at Crack Initiation Ta,pp =

Applied Tearing Modulus T,,t =

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 Locations and Evaluation Criteria April 2003 o:438non.doc:1 b-040103 Revision 0

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, (LDH) is greater than 1a,c,e 6.3 CALCULATION METHOD The basic method used in the leak rate calculations is the method developed by [

]a.c.e The flow rate through a crack was calculated in the following manner. Figure 6-1 from Reference 6-1 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 [

]a.c,e was found from Figure 6-2 (taken from Reference 6-1). For all cases considered, since [

Ia.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 APf =a[ce (6-1) where the friction factor f is determined using the [

]a.c,e The crack relative roughness,, was obtained from fatigue crack data on stainless steel samples. The relative roughness value used in these calculations was Ia.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 Leak Rate Predictions April2003 o:\\4438non.doc:1 b-04/01103 Revision 0

6-2 Ia,c,e Absolute Pressure - 14.7 = [

(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 correct 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 goveming locations previously identified in Section 5.1. The normal operating loads of Table 3-1 was applied, in these calculations. The crack opening areas were estimated using the method of Reference 6-2 and the leak rates were calculated using the two-phase flow formulation described above. The average material properties of Section 4.0 (see Table 4-3) 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. The flaw sizes so determined are called leakage flaw sizes.

The H. B. Robinson Unit 2 RCS pressure boundary leak detection system meets the intent of Reg. Guide 1.45, which is 1 gpm in 1 hour1.157407e-5 days <br />2.777778e-4 hours <br />1.653439e-6 weeks <br />3.805e-7 months <br /> or less. 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 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 o:\\4438non.doc:1 b-04/01103 April 2003 Revision 0

6-3

] a.c.e Leak Rate Predictions o:4438non.doc:1b-0401103 April 2003 Revision 0 Table 6-1 Flaw Sizes Yielding a Leak Rate of 10 gpm at the Governing Locations Location Leakage Flaw Size (in) 1

• 3.64 3

6.06 6

7.42 13 5.94

64 a, c, e

-I Figure 6-1 Analytical Predictions of Critical Flow Rates of Steam-Water Mixtures Leak Rate Predictions o:\\4438non.doc:1 b-04101103 April 2003 Revision 0

LENGTH/DIAMETER RATIO (LID)

Figure 6-2 [

]a,ce Pressure Ratio as a Function of L/D Leak Rate Predictions o:4438non.doc1 b-04101/03 6-5 r-a,c,e a

0 0

wc us I-u April 2003 Revision 0

L Figure 6-3 Idealized Pressure Drop Profile Through a Postulated Crack Leak Rate Predictions o:\\4438non.doc:1 b-04/01/03 6-6 a,c,e April 2003 Revision 0

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 finally 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 J10 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 Jlc 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 a da f2 where:

Tapp

=

applied tearing modulus E

=

modulus of elasticity of

=

0.5 (ay + au) (flow stress) a

=

crack length ay, ayu

=

yield and ultimate strength of the material, respectively Stability is said to exist when ductile tearing occurs if Tapp is less than Tma,, the experimentally determined tearing modulus. Since a constant Tmat 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 is greater than or equal to the Tmat used.

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

(1)

If Japp < Jlc, then the crack will not initiate.

(2)

If Japp > Jlc, but, if Tapp < Tmat and Japp < Jmax, then the crack is stable.

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 Fracture Mechanics Evaluation April 2003 o:\\4438non.doc:1 b-040103 Revision 0

7-2 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:

,] a,c,e

[

where:

[

Ia,c.e af

=

0.5 (ay + au) (flow stress), psi Ia.c.e I

I I a,c,e The analytical model described above accurately accounts for the piping intemal 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).

Fracture Mechanics Evaluation o:\\4438non.doc: 1 b-040103 April 2003 Revision 0

7-3 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.

7.3 RESULTS OF CRACK STABILITY EVALUATION J-integral Method:

Stability analyses were performed at the critical locations established in Section 5.1. The elastic-plastic fracture mechanics (EPFM) J-integral analyses for the through-wall circumferential cracks in a cylinder were performed using the procedure in the EPRI fracture mechanics handbook (Reference 7-2). Table 7-1 shows the J-integral analysis results. As shown in this table Jpp values are less than Jc for the critical flaw size(s) of two times the 1 Ogpm leakage flaw size(s) and therefore, stability criteria was satisfied and also margin on flaw size of 2.0 was satisfied.

Limit Load Method:

A stability analysis based on limit load was performed for all the critical locations (locations 1, 3, 6 and 13) as described in Section 7.2. The field weld at location 1 is made of GTAW and SMAW combination weld. The shop welds are assumed to be made of GTAW, SMAW or SAW combination weld. Field weld is at critical location 1. Shop welds are at critical locations 3, 6 and 13. The Z" factor correction for GTAW is 1.0. The Zf factor correction for SMAW was applied (Reference 7-3) at the field weld critical location (location 1) and the Z" factor correction for SAW was applied (Reference 7-3) at the shop weld locations (locations 3, 6 and

13) and the equations are 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 location 1, 1.69 for location 3, 1.72 for location 6 and 1.667 for location 13. 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.

For the Alloy 182 weld critical flaw size by LIMIT load method is also shown in Table 7-2. 'Z' factor correction for the Alloy 182 weld is 1.0. As shown in Table 7-2 the margin between the critical flaw size(s) and the leakage flaw size(s) is more than 2.0 and therefore, flaw size margin criteria of 2.0 was satisfied.

Fracture Mechanics Evaluation April 2003 o:4438non.doc:1 b-040103 Revision 0

7-4

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 Kumar, V., German, M. D. and Shih, C. P.," An Engineering Approach for Elastic-Plastic Fracture Analysis," EPRI Report NP-1931, Project 1237-1, Electric Power Research Institute, July 1981.

7-3 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.

Fracture Mechanics Evaluation o04438non.doc:1 b-0401 03 April 2003 Revision 0

7-5 a,c,e

• Not calculated since not required for the analysis results.

Note: Tpp is not applicable since Japp < Jic

]a.c.e Fracture Mechanics Evaluation o:\\4438non.doc:1 b-040103 April 2003 Revision 0 Table 7-2 Stability Results for H. B. Robinson Unit 2 Based on Limit Load Location Critical Flaw Size (in)

Leakage Flaw Size (in) 1*

19.70 3.64 3

38.04 6.06 6

42.07 7.42 13 36.28 5.94

Figure 7-1 [

7-6 af Iac.e Stress Distribution Fracture Mechanics Evaluation oM4438non.doc:lb-040103 April 2003 Revision 0

7-7 a,c,e OD = 34.00 in.

t=2.40 in.

ay = 20.65 ksi a = 52.50 ksi F = 1639 kips M = 22824 in-kips A376 - TP316 with SMAW weld Figure 7-2 Critical Flaw Size Prediction - Hot Leg at Location I Fracture Mechanics Evaluation o:\\4438non.doc:1 b-0401 03 April 2003 Revision 0

7-8 a,c,e OD = 34.00 in.

t = 2.40 in.

ay = 27.16 ksi au = 81.84 ksi F = 1638 kips M = 9714 in-kips A351 - CF8M with SAW weld Figure 7-3 Critical Flaw Size Prediction - Hot Leg at Location 3 Fracture Mechanics Evaluation o:\\4438non.doc:1 b-040103 April 2003 Revision 0

7-9 ac,e OD = 36.32 in.

t = 2.56 in.

ay = 27.99 ksi au = 81.84 ksi F = 1840 kips M = 9572 in-kips A351 - CF8M with SAW weld Figure 7-4 Critical Flaw Size Prediction - Cross-Over Leg at Location 6 Fracture Mechanics Evaluation o:\\4438non.doc:1 b-0401 03 April 2003 Revision

7-10 a,c,e OD = 32.26 in.

t = 2.28 in.

cy = 27.99 ksi au = 81.84 ksi F = 1406 kips M = 9465 in-kips A351 - CF8M with SAW weld Figure 7-5 Critical Flaw Size Prediction - Cold Leg at Location 13 Fracture Mechanics Evaluation o:\\4438non.doc:1 b-0401 03 April 2003 Revision 0

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 Reactor vessel inlet nozzle safe-end and the outlet nozzle safe-end regions (see Locations 1 and 14 of Figure 3-2). These regions were selected because crack growth calculated in these regions would be typical of that in the entire primary loop. Crack growths calculated at other locations could be expected to show less than 1 0% variation.

The methods used in the fatigue crack growth analysis reported here are the same as those suggested by Section Xl of the ASME Code. The analysis procedure involves postulating an initial flaw at specific regions and predicting the growth of that flaw due to an imposed series of loading transients. The input required for a fatigue crack growth analysis is basically the information necessary to calculate the parameter AK, which depends on crack and structure geometry and the range of applied stresses in the area where the crack exists. Once AK is calculated, the growth due to that particular stress cycle can be calculated. This increment of growth is then added to the original crack size, and the analysis proceeds to the next transient.

The procedure is continued in this manner until all the transients predicted to occur in the period of evaluation have been analyzed.

The transients used for the fatigue crack growth of the H. B. Robinson Unit 2 plant are listed in Table 8-1. The transients used in this evaluation are not those contained in the original equipment specification (Reference 8-1); instead, the latest transient specification available has been used.

All normal, upset and test conditions were considered. A summary of applied transients is provided in Table 8-1. Circumferentially oriented surface flaws were postulated in these regions, assuming the flaw was located in three different locations, as shown in Figure 8-1.

Specifically, these were:

Cross Section A: Inconel Cross Section B: SA 508 Class 2 or 3 Low Alloy Steel Cross Section C: Stainless Steel CRACK GROWTH RATE REFERENCE CURVES - FERRITIC STEEL The crack growth rate curves used in the analyses were taken directly from Appendix A of Section Xl of the ASME Code. Water environment curves were used for all inside surface flaws, and the air environment curve was used for embedded flaws and outside surface flaws.

For water environments the reference crack growth curves are shown in Figure 8-2, and growth rate is a function of both the applied stress intensity factor range, and the R ratio (Kmin/Kmax) for the transient.

Fatigue Crack Growth Analysis April 2003 o:\\4438non.doc:1 b-040103 Revision 0

8-2 For R*0.25 (8-1)

(AK1Ž 19 ksi1in), (da/dN)=(1.01x10') AK, 1 95 where, da = Crack Growth rate, micro-inches/cycle.

dN For R 20.65 x<

1 )

da (1

x

.105),95 (8-2)

(AK,> 12 ksi 1in), (da/dN)=(2.52x1 0') AK, 1.95 For R ratio between these two extremes, interpolation is recommended.

The crack growth rate reference curve for air environments is a single curve, with growth rate being only a function of applied AK. This reference curve is also shown in Figure 8-2.

d

= (0.0267 x 10-3 )

I3.726 (8-3) where, da

=

dN Crack growth rate, micro-inches/cycle AKI

=

stress intensity factor range, ksi -4in

=

(iKmax

- Kimin)

FATIGUE CRACK GROWTH RATE REFERENCE CURVES - STAINLESS STEEL The reference crack growth law used for the stainless steel portions of the system was taken from that developed by the Metal Properties Council - Pressure Vessel Research Committee Task Force In Crack Propagation Technology. The reference curve has the equation:

[

Fatigue Crack Growth Analysis o:\\4438non.doc:1 b-0401 03 April 2003 Revision 0 (AKX I<19 ksi i-), dN (1.02 x O6)

I5

8-3 Ia,c,e This equation appears in Section Xl, Appendix C (1989 Addendum) for air environments and its basis is provided in Reference 8-2, and shown in Figure 8-3. For water environments, an environmental factor of 2 was used, based on the crack growth tests in PWR environments reported in Reference 8-3.

FATIGUE CRACK GROWTH RATE REFERENCE CURVES - ALLOY 600, 182, AND 82 MATERIALS The crack growth rate reference curves for these nickel base alloys have not been developed for the ASME Code, so information was obtained from the literature. The crack growth rate is a function of both R Ratio (Kmi/Kmax) and the range of applied stress intensity factor. Using the results reported in references 8-4 and 8-5 a curve was developed for application to a water environment, as shown below.

da 2.23 x IO-13 [AK/ (1.0 -

.5R)] 566 (8-5)

The crack growth rate law is slightly steeper than that for stainless steel.

RESULTS AND CONCLUSIONS The transients and cycles for the H. B. Robinson Unit 2 plant for 60 years are the same as those of 40 years. It is therefore concluded that the fatigue crack growth analysis shown in Table 8-2 and Table 8-3 is applicable for 60 years. The results show that fatigue crack growth is not a concern for the H. B. Robinson Unit 2 primary loop piping.

As shown in Tables 8-2 and 8-3 fatigue crack growth is not significant and it is therefore expected that with a reasonable increase in transient cycles these should also be of no concern for the fatigue crack growth.

Fatigue Crack Growth Analysis April 2003 o:\\4438non.doc:1 b-0401 03 Revision 0

8-4 8.1

References:

8-1 Westinghouse Equipment Specification Number 676413 - Rev. 4, and Addendum 952542,1973.

8-2 James, L. A., and Jones, D. P., "Fatigue Crack Growth Correlations for Austenitic Stainless Steel in Air," in Predictive Capabilities in Environmentally Assisted Cracking."

ASME publication PVP-99, Dec. 1985..

8-3 Bamford, W. H., "Fatigue Crack Growth of Stainless Steel Piping in a Pressurized Water Reactor Environment," Trans ASME, Journal of Pressure Vessel Technology, Feb.

1979.Engineering Development Labs Report HEDL-TME-76-43, May 1976.

8-4 James, L. A., "Fatigue Crack Propagation Behavior of Inconel 600," in Hanford Engineering Labs Report HEDL-TME-76-43, May 1976.

8-5 Hale, D. A. et al., "Fatigue Crack Growth in Piping and RPV Steels in Simulated BWR Water Environment.

Fatigue Crack Growth Analysis o:\\4438non.doc:1 b-0401 03 April 2003 Revision 0

8-5 Table 8-1 Summary of Reactor Vessel Transients Number Transient Identification Number of Occurrences Normal Conditions 1

Heatup and Cooldown 200 2

Unit Loading and Unloading between 15% and 100%

18300

@5% of Full Power 3

Unit Loading and Unloading between 0% and 15% of 500 Full Power 4

Step Load increase and decrease 2000 5

Large Step load decrease, with steam dump 200 6

Steady State Fluctuations 150000 7

Random Fluctuations 3000000 8

Feedwater Cycling 2000 9

Refueling 80 10 Loss of Load 80 11 Loss of Power 40 12 Loss of Flow 80 13 Reactor Trip with no Cooldown 230 14 Reactor Trip with Cooldown, no SI 160 15 Reactor Trip with Cooldown, and SI 10 16 Inadvertent RCS Depressurization 60 17 Inadvertent Startup of an Inactive Loop 20 18 Inadvertent SI Actuation 60 19 Control Rod Drop 80 Fatigue Crack Growth Analysis o:4438non.doc:1 b-0401 03 April 2003 Revision 0

Fatigue Crack Growth Analysis o:4438non.doc:1b-040103 8-6 Table 8-1 Summary of Reactor Vessel Transients (cont.)

Number Transient Identification Number of Occurrences Test Conditions 20 Excessive Feedwater Flow 30 21 Boron Concentration 26400 22 Loop Out-of-Service, Normal Loop Startup 70 23 Loop Out-of-Service, Normal Loop Shutdown 80 24 Primary Side Leak Test 200 25 OBE 200 April 2003 Revision 0

8-7 Table 8-2 Fatigue Crack Growth at RPV Inlet Nozzle Safe-End Region (40 and 60 years)

FINAL FLAW (in.)

Initial Flaw (in.)

Ferritic Steel Stainless Inconel 0.305 0.3069 0.3066 0.3053 0.458 0.4644 0.4609 0.4590 0.610 0.6194 0.6141 0.6123 Table 8-3 Fatigue Crack Growth at RPV Outlet Nozzle Safe-End Region (40 and 60 years)

FINAL FLAW (in.)

Initial Flaw (in.)

Ferritic Steel Stainless Inconel 0.250 0.2761 0.2677 0.2525 0.375 0.4664 0.4119 0.3840 0.500 0.6128 0.5505 0.5160 Fatigue Crack Growth Analysis o:\\4438non.doc:1 b-040103 April 2003 Revision 0

8-8 a,c,e T = Thickness R = Inside Radius Figure 8-1 Typical Cross-Section of RPV Inlet and Outlet Nozzle Safe-End Fatigue Crack Growth Analysis o:\\4438non.doc:1 b-040103 April 2003 Revision 0

'Linar interpolation is rcornmended to account for R ratio dependence of vwatr environmwnt curw, for 0.25 <R <0.65 for stp slope:

2 5

7 10 20 Strom IntnsitV Factor Range (AK1 kui 4P;.)

SO 70 100 Figure 8-2 Reference Fatigue Crack Growth Curves for Carbon and Low Alloy Ferritic Steels Fatigue Crack Growth Analysis o:\\4438non.doc1 b-0401 03 8-9 1000 700 500 200 100 70 50 20 0

0 b

0 U

0 10 7

5 1

April 2003 Revision 0

8-10 3.xlp-4 10-4 u

I-In

• 10 2.OxlO' AK(ks ii)

Figure 8-3 Reference Crack Growth Curves for Stainless Steel in Air Environments Fatigue Crack Growth Analysis o04438non.doc:1 b-0401 03 10'2 April 2003 Revision 0

8-11 crack 67.drw 40 60 K - MPa SQRT(m) 80 3250C,Alloy 182 3300C Alloy 600 100

SUMMARY

OF WESTINGHOUSE AND STUDSVIK DATA TYPE 182 WELDS AT 325 C Figure 8-4 Crack Growth Model for Alloy in PWR Environments with Available Data Fatigue Crack Growth Analysis o:'4438non.doc:l b-0401 03 April 2003 Revision 0 I E-08 U,

E w

0 cc:

i:

u 1 E-09 I E-1 0 S "U~~~~~~~......

I~~~~~~~~~~.....

All Or.entat.ons West.....T...st...

Ed w el Wwe.

E3Swedash weld e

...........d...k....

.ld 3 25....

C......

1E-1 1 0

20

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.

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 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 as per SRP 3.6.3.

Assessment of Margins o:\\4438non.doc:1b/040103 April 2003 Revision 0

9-2 II Ia,c,e abased on limit load bbased on J-integral evaluation ( Note: critical flaw size postulated for the J-integral calculation is two times the leakage flaw size)

Assessment of Margins o:\\4438non.doclb/040103 April 2003 Revision 0 Table 9-1 Leakage Flaw Sizes, Critical Flaw Sizes and Margins for H. B. Robinson Unit 2 Location Leakage Flaw Size Critical Flaw Size Margin 1

3.64 in.

19.70a in.

5.4a 3

6.06 in.

38.04a in.

6.3a 3

6.06 in.

12.12 in.

>2.0b 6

7.42 in.

42.07a in.

5.7a 6

7.42 in.

14.84 bin.

>2.0 13 5.94 in.

36.28a in.

6.1a 13 5.94 in.

11.88 in.

>2.0

10-1

10.0 CONCLUSION

S This report justifies the elimination of RCS primary loop pipe breaks from the structural design basis for the H. B. Robinson Unit 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.

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 H. B. Robinson Unit 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 (relative to aging) 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 are satisfied for the H. B. Robinson Unit 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 of the H. B. Robinson Unit 2 Nuclear Power Plant for the License Renewal Program.

Conclusions o:4438non.doc:1b-040103 April 2003 Revision 0 I.

A-1 APPENDIX A LIMIT MOMENT I

Ia.c.e Appendix A - Limit Moment o:4438non.doc:lb-0401 03 April 2003 Revision 0

A-2 Figure A-1 Pipe with a Through-Wall Crack in Bending Appendix A - Limit Moment o:4438non.doc:1 b-040103 April 2003 Revision 0 0l I

I