ML18151A524

a Pilot Application of RISK-INFORMED Methods to Establish Inservice Inspection Priorities for Nuclear Components at Surry Unit 1 Nuclear Power Station

ML18151A524
Person / Time
Site:	Surry
Issue date:	02/28/1997
From:	Doctor S, Gore B, Hanh Phan, Simomen F, Vo T Battelle Memorial Institute, PACIFIC NORTHWEST NATION
To:	NRC OFFICE OF NUCLEAR REGULATORY RESEARCH (RES)
References
CON-FIN-B-2289 NUREG-CR-6181, NUREG-CR-6181-R01, NUREG-CR-6181-R1, PNNL-9020, NUDOCS 9703100220
Download: ML18151A524 (70)

Text

NUREG/CR-6181, Rev. 1 PNNL-9020, Rev. 1 A Pilot Application of Risk-Informed Methods to Establish Inservice Inspection Priorities for Nuclear Components at Surry Unit 1 Nuclear Power Station

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,Prepared by .

• r. V. Vo, H. K. Phan, B. F. Gore, F. A Simonen, S. R. Doctor Pacific Northwest National Laboratory Operated by Battelle Memorial Institute Prepared for U.S. Nuclear Regulatory Commission

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NUREG/CR-6181, Rev. 1 PNNL-9020, Rev. 1 A Pilot Application of Risk-Informed* Methods to Establish lnservice Inspection Priorities for Nuclear Components at Surry Unit 1 Nuclear Power Station Manuscript Completed: February 1997 i Date Published: February 1997 t Prepared by T. V. Vo, H. K Phan, B. F. Gore, F. A Simonen, S. R. Doctor Pacific Northwest National Laboratory Richland, WA 99352 J. Muscara, NRC Project Manager Prepared for Division of Engineering Technology Office of Nuclear Regulatory Research U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 NRC Job Code B2289

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Abstract As part of the Nondestructive Evaluation Reliability Program sponsored by the U.S. Nuclear Regulatory Commission, the Pacific Northwest National Laboratory has developed risk-informed approaches for inservice inspection plans of nuclear power plants. This method uses probabilistic risk assessment (PRA) results to identify and prioritize the most risk-important components for inspection. The Surry Nuclear Power Station Unit 1 was selected for pilot application of this methodology.

This report, which incorporates more recent plant-specific information and improved risk-informed methodology and tools, is Revision 1 of the earlier report (NUREG/CR-6181). The methodology discussed in the original report is no longer current and a preferred methodology is presented in this Revision. This report, NUREG/CR-6181, Rev. 1, therefore supersedes the earlier NUREG/CR-6181 published in August 1994. The specific systems addressed in this report are the auxiliary feedwater, the iow-pressure injection, and the reactor coolant systems. The results provide a risk-informed ranking of components within these systems.

iii NUREG/CR-6181, Rev. I

Contents Abstract . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . iii Executive Summary . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . ix Acknowledgments ................................................................... : . . . . . . . . . . xv Acrony~s . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xvii Previous Reports in Series . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xix 1.0 Introduction . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 1.1 2.0 Overall Methodology . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1 2: 1 Risk Prioritization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1 2.1.1 Failures Causing System Degradation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.1 2.1.2 Failures Causing an Initiating Event . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2 2.1.3 Faiiures Causing System Degradation and an Initiating Event . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2 2.1.4 Pipe Segment Contribution to Core Damage Frequency . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2 2.2 Estimates of Component Rupture Probabilities . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.2 2.3 Inspection Program Development . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.5 2.3.1 Sampling Strategy ........ : . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.8 2.3.2 Inspection Method . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.8 2.3.3 NDE Reliability and Performance Demonstration . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.9 2.3.4 Time of Inspection . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.9 3.0 Analyses ofSurry-1 Plant Systems . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1 3.1 Plant Familiarization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1 3.1.1 Plant Visits and Information Obtained . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.1 3 .1.2 Utility Interface . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 .2 3.2 Plant System Description . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 .2 3.2.1 Auxiliary Feedwater System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.2 3.2.2 Low-Pressure Injection System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.3 3.2.3 Reactor Coolant System . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.6 3.3 Analysis Assumptions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.7 3 .4 Component Prioritization . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3. 7 3.5 Results of Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.8 3.6 Sensitivity Analyses . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.13 3.6.1 Sources ofUncertainty . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.13 3.6.2 Results of Sensitivity Analyses ......................... : . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.13 V NUREG/CR-6181, Rev. 1

Contents 4.0 Discussion of the Results . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1 4.1 High-Risk Importance Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1 4.2 Low-Risk Importance Components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.1 5.0 Summary and Conclusions . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 5.1 6.0 References ...........................................*. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 6.1 Appendix A - Risk-Informed Calculation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . A. l Appendix B - Review of the Risk Importance Approaches Which have been Developed by Pacific Northwest National Laboratory ...................................................... ; . . B. l NUREG/CR-6181, Rev. I vi

Contents Figures S.l Risk contributions of Surry- I components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xi S.2 Cumulative risk contributions of Surry- I components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xii 2.1 Information provided to the participants in the expert judgment elicitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.3 2.2 Estimates of rupture probabilities for Surry- I auxiliary feedwater system components from expert judgment elicitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.6 2.3 Estimates of rupture probabilities for Surry-I low pressure injection system components from expert judgment elicitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2. 7 2.4 Estimates of rupture probabilities for Surry- I reactor coolant system components from expert judgment elicitation . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 2.8 3.1 Surry- I auxiliary feedwater system simplified schematic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 .4 3.2 Surry-I low-pressure injection/recirculation system simplified schematic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.5 3.3 Surry- I reactor coolant system simplified schematic . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 .6

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3.4 Risk contributions of Surry- I components ............................................. *. . . . . . . . . . 3 .10 3.5 Cumulative risk contributions for Surry- I components . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3 .11 Tables S .1 Risk importance for components of selected systems at Surry- I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . xiii 3J Component rankings based on core damage frequency for three selected systems at Surry- I . . . . . . . . . . . . . . . . 3 .9 3.2 Risk importance for components of selected systems at Surry-I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 3.12 4.1 Component importance ranking compared with ASME BPVC Section XI classifications and ISI requirements for selected systems at Surry- I . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . . 4.3 vii NUREG/CR-6181, Rev. 1

Executive Summary As part of the Evaluation and Improvement of Nondestructive Evaluation (NDE) Reliability for lnservice Inspection of Light Water Reactors Program sponsored by the U.S. Nuclear Regulatory Commission (NRC), the Pacific Northwest National Laboratory (PNNL) has developed and applied a method using risk-informed techniques for inservice inspection (ISi) plans of nuclear power plants. As described in this report, the method uses probabilities of component failures (estimated by using an expert judgment elicitation process) and plant-specific probabilistic risk assessment (PRA) results to identify ISi priorities for components. This report is a revision of the earlier report (NUREG/CR-6181), which incorporates recent plant-specific information and improved risk-informed calculational tools. Since this report, NUREG/CR-6181, Rev. 1, provides a preferred methodology, it supersedes the earlier NUREG/CR-6181 report published in August 1994.

The Surry Nuclear Power Station Unit 1 (Surry-1) was selected for demonstrating the risk-informed methodology. The specific systems addressed in this report are the auxiliary feedwater, low-pressure injection, and the reactor coolant systems.

Worksheets to guide the analyses were initially formulated using plant system drawings and other plant-specific information.

The Standard Review Plan information developed by the NRC was used in determining the effects of system and component failures. To ensure that the plant models were as realistic as possible, visits at the Surry-I plant were conducted for plant system walkdowns and discussions were held with plant operational and technical staff. Participation of Virginia Electric Power Company staff was an essential part of the pilot study.

Because of similarities in objectives, the PNNL program task related to risk-informed methodology for ISi was coordinated with the activity of the American Society of Mechanical Engineers (ASME) Research Task Force on Risk-Based Inspection Guidelines. This Task Force has made general recommendations on the application ofrisk-informed methods to inservice inspection and will make specific proposals to ASME for improved codes and standards. Results of PNNL studies have been made available to the ASME Research Task Force to demonstrate and validate the usefulness of the risk-based concepts.

The results of the risk-informed component prioritization (for the systems identified above) for Surry-I are summarized in Figure S.l. Table S.1 shows the risk importance for Surry-I components. Included in this table are the estimated rupture probabilities for the components of the systems analyzed. The estimated component rupture probabilities were based on expert judgment elicitation as described in Vo et al. (1993, 1991, 1990). These component rupture probabilities were based on a number of assumptions including the benefits of ISi activities and the periodic testing of components.

On the basis of core damage frequency, the calculated contributions of component failures to core damage frequency range from about 1.0E-12 to 6.0E-06 per plant year. The cumulative risk contribution for all of the components considered was estimated to be about l .SE-05 per plant year. Figure S.2 shows the results of cumulative risk contribution for Surry-I components within the systems analyzed. The total estimated risk is dominated by failures of the auxiliary feedwater system components (60% of the total estimated risk). This risk is followed by the low-pressure injection system components (39%),

and then other various components within the reactor coolant system (1%).

Sensitivity analyses were performed to address the changes in component rankings using the upper/lower estimates of component rupture probabilities. The results indicated no significant changes in component risk contribution rankings (as shown in Figure S.1). Sensitivity analyses were also performed to determine the core damage frequency contribution due to component failures by indirect effects (pipe whip,jet impingement effects, etc.). The results indicate that contributions from the indirect effects were negligible.

ix NUREG/CR-6181, Rev. 1

Executive Summary Included in the report is a comparison of the risk-informed inspection priorities from this study with the current Surry- I plant ISi practices. ASME classifications and ISi requirements are only in partial agreement with the risk-informed rankings based on core damage frequency. The components with the greatest contribution to the core damage frequency should have the more stringent ASME inspection requirements (i.e., volumetric or both volumetric and surface examinations), but this study found only six of the twelve components contributing the most to risk (99%) received the more stringent ASME inspection requirements, and for the other six components contributing the most to risk, only a visual examination is required.

The analysis for the Surry- I plant could be completed by determining the risk importances of components in the remaining systems (e.g., reactor pressure vessel, high-pressure injection, service water, and balance of plant). Similar plant-specific analyses by other organizations are being performed for other pressurized-water reactors and for boiling-water reactors.

Generic trends in component importances can then be established from these plant-specific evaluations. Once the components contributing the most to risk have been identified, recommended inspection programs (method, frequency, and extent) could be developed. Probabilistic structural mechanics can be applied to establish inspection strategies that will ensure that component failure probabilities are maintained at given levels. However, any complete inservice inspection program plan should also consider other additional objectives ofISI including defense-in-depth and the identification of unexpected degradation in operating plants.

The methodology and results of the present work represent a step in the development and refinement of an approach to risk-informed inservice inspection. It is therefore important to note that the present calculations were performed for demonstration purposes, and are considered to be approximate. The results should be interpreted cautiously and should not be used as a basis for actual changes to plant inservice inspection plans.

An independent and more complete Surry risk-informed ISi application is currently being performed by the NRC, ASME, and the Westinghouse Owners Group (WOG). This work utilizes detailed fracture mechanics calculations, the plant-specific IPE evaluation, and up to date plant information. When the results of this work become available, they could be used to validate this study as described in the present report.

NUREG/CR-6181, Rev. 1 X

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- AFW Isolation Valve to SG 15 RCS 3 AFW - Pipe Segment Between Containment Isolation 16 AFW - Main Steam to AFW Pump Turbine Drive 1.IXE-10 and SG Isolation Valves - 17 RCS - Pipe Segment Between RPV and Loop Stop 4 AFW - AFW MDP Discharge Line Valve (Hot Leg) 5 AFW - CST, Supply Line 18 RCS - Pressurizer Surge Line 6 LPI - LPI Sources (RWST, Sump), Supply Line 19 RCS - Pipe Segment Between SG and RCP 7 AFW - AFW MDP Suction Line 20 RCS - Pipe Segment Between Loop Stop Valve and 1.IXE-11 B AFW - Pipe Segment from Unit 2 AFW Pumps SG (Hot Leg) 9 LPI - Pipe Segment Between Containment Isolation 21 RCS - Pipe Segment Between Loop Stop Valve and Valve Qnside) and Hot Leg Injection RPV (Cold Leg) 10 AFW - AFW TDP Suction Line 22 RCS - Pipe Segment Between RCP and Loop Stop 11 AFW - AFW TDP Discharge Line Valve (Cold Leg) 1.IXE-12 12 LPI - LPI Pump Suction Line 23 LPI - Pipe Segment Between Containment Isolation 0 13 RCS - Pressurizer Spray Line Valves

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ID System Components LPI - Pipe Segment Between Containment Isolation Valve (inside) and Cold Leg Injection 1.IXE-05 2 AFW - AFW Isolation Valve to SG 15 RCS - Pressurizer Relief/Safety Line 3 AFW - Pipe Segment Between Containment Isolation 16 AFW - Main Steam to AFW Pump Turbine Drive and SG Isolation Valves 17 RCS - Pipe Segment Between RPV and Loop Stop

~: 4 AFW AFW MOP Discharge Line Valve (Hot Leg) 5 AFW - CST, Supply Line 18 RCS - Pressurizer Surge Line 6 LPI - LPI Sources (RWST, Sump), Supply Line 19 RCS - Pipe Segment Between SG and RCP 7 AFW - AFW MOP Suction Line 20 RCS - Pipe Segment Between Loop Stop Valve and B AFW - Pipe Segment from Unit 2 AFW Pumps SG (Hot Leg) 9 LPI - Pipe Segment Between Containment Isolation 21 RCS - Pipe Segment Between Loop Stop Valve and Valve (inside) and Hot Leg Injection RPV (Cold Leg) 10 AFW - AFWTDP Suction Line 22 RCS - Pipe Segment Between RCP and Loop Stop 11 AFW - AFW TOP Discharge Line Valve (Cold Leg) 12 LPI - LPI Pump Suction Line 23 LPI - Pipe Segment Between Containment Isolation Valves 13 RCS Pressurizer Spray Line 14 LPI - Pipe Segment Between Pump Discharge and 24 AFW - Pipe Segment from Emergency Makeup System Containment Isolation Valves and from Fire Main to AFW Pump Suction 0 5 10 15 25 ConTJOl1E!l'll lclentiflcatlon Figure S.2 Cumulative risk contributions for Surry-1 components

Executive Summary Table S.1 Risk importance for components of selected systems at Surry-1 1 Core Rupture damage System component' Rank frequency frequency LPI - Pipe Segment Between Containment Isolation Valve (Inside) and Cold Leg 2.65E-05 5.96E-06 Injection AFW - AFW Isolation Valve to SG 2 2.33E-04 3.31E-06 AFW - Pipe Segment Between Containment Isolation and SG Isolation Valves 3 5.27E-05 2.91E-.06 AFW - AFW MDP Discharge Line 4 4.33E-05 2.39E-06 AFW - CST, Supply Line 5 l.84E-05 l.OJE-06 LPI - LPI Sources (RWST, Sump), Supply Line 6 2.34E-05 6.85E-07 AFW - AFW MDP Suction Line 7 l.OIE-05 5.60E-07 AFW - Pipe Segment from Unit 2 AFW Pumps 8 3.00E-06 3.SOE-07

• LPI - Pipe Segment Between Containment Isolation Valve (inside) and Hot Leg 9 l.33E-05 2.84E-07 Injection AFW - AFW TDP Suction Line 10 5.03E-06 2.78E-07 AFW -AFW TDP Discharge Line 11 5.00E-06 2.76E-07 LP! - LPI Pump Suction Line 12 7.65E-06 2.02E-07 RCS - Pressurizer Spray Line 13 2.76E-05 5.ISE-08 LPI - Pipe Segment Between Pump Discharge and Containment Isolation Valves 14 l.29E-05 4.SIE-08 RCS - Pressurizer Relief/Safety Line 15 8.41E-06 2.86E-08 AFW - Main Steam to AFW Pump Turbine Drive 16 l.SIE-05 l.48E-08 RCS - Pipe Segment Between RPV and Loop Stop Valve (Hot Leg) 17 3.00E-06 l.19E-08 RCS - Pressurizer Surge Line 18 l.60E-06 6.38E-09 RCS - Pipe Segment Between SG and RCP 19 9.24E-07 2.84E-09 RCS - Pipe Segment Between Loop Stop Valve and SG (Hot Leg) 20 4.35E-07 l.89E-09 RCS - Pipe Segment Between Loop Stop Valve and RPV (Cold Leg) 21 3.06E-07 l.20E-09 RCS - Pipe Segment Between RCP and Loop Stop Valve (Cold Leg) 22 2.45E-07 9.31E-10 LPI - Pipe Segment Between Containment Isolation Valves 23 l.83E-06 9.00E-10 AFW - Pipe Segment from Emergency Makeup System and from Fire Main to AFW 24 8.06E-06 <l.OOE-12 Pump Suction 1

Based on estimated median values.

2AFW = Auxiliary Feedwater; LPI = Low Pressure Injection; RCS = Reactor Coolant System.

xiii NUREG/CR-6181, Rev. 1

Acknowledgments This work was.supported by the U.S. Nuclear Regulatory Commission (NRC) under a Related Service Agreement with the U.S. Department of Energy under contract DE-AC06-76RLO 1830. The authors wish to acknowledge the direction and support provided by Dr. Joe Muscara, NRC Program Manager. Dr. L. R. Abramson from the NRC staff provided guidance to the elicitation process. Acknowledgments are also addressed to the many Virginia Electric Power Company staff for their participation iri this work, particularly Ms. C. G. Lovett, Mr. R. K. MacManus, Mr. A. McNeill, Mr. D. Rogers, Mr. D. Sommers, and Mr. E. W. Throckmorton. The authors wish to thank Mr. Stephen Minister, PNNL summer student; Mr. Kenneth Balkey and Ms. Nancy Closky of Westinghouse Electric Corporation, and Mr. R~ymond Art of ASME, CRTD, for their assistance in performing calculations and technical discussions; and Dr. William Vesely of.SAIC, and Dr. Art Buslik ofNRC for their contributions and review of this work.

xv NUREG/CR-6181, Rev. 1

~-

Acronyms AFW Auxiliary Feedwater System ASME American Society of Mechanical Engineers ASTM American Society of Testing and Materials BPVC Boiler and Pressure Vessel Code BWR Boiling Water Reactor CDF Core Damage Frequency CST Condensate Storage Tank FMEA Failure Modes and Effects Analysis FSAR Final Safety Analysis Report IPE Individual Plant Evaluation IRRAS Integrated Reliability and Risk Analysis System ISi Inservice Inspection 1ST lnservice Testing LOCA Loss of Coolant Accident LPI Low-Pressure Injection System LPI/LPR Low-Pressure Injection/Recirculation System MDP Motor-Driven Pump MOY Motor-Operated Valves NDE Nondestructive Evaluation NRC U.S. Nuclear Regulatory Commission P&ID. Piping and Instrumentation Diagram PNNL Pacific Northwest National Laboratory POD Probability of Detection

.,,. xvii NUREG/CR-6181, Rev. 1

Acronyms PRA Probabilistic Risk Assessment PWR Pressurized Water Reactor RAW Risk Achievement Worth RCP Reactor Coolant Pump RCS Reactor Coolant System RHR Residual Heat Removal RPV Reactor Pressure Vessel RWST Reactor Water Storage Tank SAIC Science Applications International Corporation SG Steam Generator TDP Turbine-Driven Pump VEPCO Virginia Electric Power Company VIMS Video Information Management System WOG Westinghouse Owners Group NUREG/CR-6181, Rev. 1 xviii

Previous Reports in Series Heasler, P. G., S. R. Doctor. 1996. Piping Inspection Round Robin. NUREG/CR-5068, PNNL-10475. Pacific Northwest National Laboratory, Richland, Washington .

.Yo, T. V., B. W. Smith, F. A. Simonen, B. F. Gore. 1994. Feasibility ofDeveloping Risk-Based Rankings of Pressure Boundary Systems for lnservice Inspection. NUREG/CR-6151, PNNL-8912. Pacific Northwest Laboratory, Richland, Washington.

Vo, T. V., B. F. Gore, F. A. Simonen, S. R. Doctor. 1994. A Pilot Application ofRisk-Based Methods to Establish lnservice Inspection Priorities for Nuclear Components at Surry Unit I Nuclear Power Station. NUREG-CR-6181, PNNL-9020.

Pacific Northwest Laboratory, Richland, Washington.

Heasler, P. G., T. T. Taylor, S. R. Doctor. 1993. Statistically Based Reevaluation ofPISC-11 Round Robin Test Data.

NUREG/CR-5410, PNNL-8577. Pacific Northwest Laboratory, Richland, Washington.

Doctor, S. R., A. A. Diaz, J. R. Friley, M. S. Greenwood, P. G. Heasler, R. J. Kurtz, F. A. Simonen, J.C. Spanner, T. V. Vo.

1993. Nondestructive Examination (NDE) Reliability for lnservice Inspection ofLight Water Reactors. NUREG/CR-4469, PNNL-5711, Vol. 16. Pacific Northwest Laboratory, Richland, Washington.

Doctor, S. R., A. A. Diaz, J. R. Friley, M. S. Good, M. S. Greenwood, P. G. Heasler, R. L. Hockey, R. J. Kurtz, F. A. Simonen, J. C. Spanner, T. T .. Taylor, and T. V. Vo. 1993. Nondestructive Examination (NDE) Reliability for

- lnservice Inspection of Light Water Reactors. NUREG/CR-4469; PNNL-5711, Vol. 15. Pacific Northwest Laboratory, Richland, Washington.

~ Doctor, S. R., A. A. Diaz, J. R. Friley, M. S. Good, M. S. Greenwood, P. G. Heasler, R. L. Hockey, R. J. Kurtz, F. A. Simonen, J. C. Spanner, T. T. Taylor, and T. V. Vo. 1992. Nondestructive Examination (NDE) Reliability for lnservice Inspection of Light Water Reactors. NUREG/CR-4469, PNNL-5711, Vol. 14. Pacific Northwest Laboratory, Richland, Washington.

Green, E. R., S. R. Doctor, R. L. Hockey, and A. A. Diaz. 1992. Development of Equipment Parameter Tolerances/or the Ultrasonic Inspection of Steel Components: Application to Components up to 3 Inches Thick. NUREG/CR-5817, Vol 1. Pacific Northwest Laboratory, Richland, Washington.

Doctor, S. R., M. S. Good, P. G. Heasler, R. L. Hockey, F. A. Simonen, J.C. Spanner, T. T. Taylor, and T. V. Vo.

1992. Nondestructive Examination (NDE) Reliability for Inservice Inspection of Light Water Reactors. NUREG/CR-4469, PNNL-5711, Vol. 13. Pacific Northwest Laboratory, Richland, Washington.

Doctor, S. R., M. S. Good, P. G. Heasler, R. L. Hockey, F. A. Simonen, J.C. Spanner, T. T. Taylor, and T. V. Vo.

1992. Nondestructive Examination (NDE) Reliability for Inservice Inspection of Light Water Reactors. NUREG/CR-4469, PNNL-5711, Vol. 12. Pacific Northwest Laboratory, Richland, Washington.

Doctor, S. R., M. S. Good, E. R. Green, P. G. Heasler, F. A. Simonen, J.C. Spanner, T. T. Taylor, and T. V. Vo.

1991. Nondestructive Examination (NDE) Reliability for Inservice Inspection of Light Water Reactors. NUREG/CR-4469, PNNL-5711, Vol. 11. Pacific Northwest Laboratory, Richland, Washington.

xix NUREG/CR-6181, Rev. 1

Previous Reports Heasler, P. G., T. T. Taylor, J.C. Spanner, S. R. Doctor, and J. D. Deffenbaugh. 1990. Ultrasonic Inspection Reliability for Intergranular Stress Corrosion Cracks: A"Round Robin Study of the Effects of Personnel, Procedures, Equipment and Crack Characteristics. NUREG/CR-4908. Pacific Northwest Laboratory, Richland, Washington.

Spanner, J.C., S. R. Doctor, T. T. Taylor/PNNL and J. Muscara/NRC. 1990. Qualification Process for Ultrasonic Testing in Nuclear Inservice Inspection Applications. NUREG/CR-4882, PNNL-6179. Pacific Northwest Laboratory, Richland, Washington.

Doctor, S. R., J. D. Deffenbaugh, M. S. Good, E. R. Green, P. G. Heasler, F. A. Simonen, J. C. Spanner, T. T. Taylor, and T. V. Vo. 1990. Nondestructive Examination (NDE) Reliability for Inservice Inspection of Light Water Reactors. NUREG/CR-4469, PNNL-5711, Vol. 10. Pacific Northwest Laboratory, Richland, Washington.

Doctor, S. R., J. D. Deffenbaugh, M. S. Good, E. R. Green, P. G. Heasler, F. A. Simonen, J. C. Spanner, and T. T. Taylor. 1989. Nondestructive Examination (NDE) Reliability for Inservice Inspection of Light Water Reactors.

NUREG/CR-4469, PNNL-5711, Vol. 9. Pacific Northwest Laboratory, Richland, Washington.

Doctor, S. R., J. D. Deffenbaugh, M. S. Good, E. R. Green, P. G. Heasler, F. A. Simonen, J. C. Spanner, and T. T. Taylor. 1989. Nondestructive Examination (NDE) Reliability for Inservice Inspection of Light Water Reactors.

NUREG/CR-4469, PNNL-5711, Vol. 8. Pacific Northwest Laboratory, Richland, Washington.

Doctor, S. R., J. D. Deffenbaugh, M. S. Good, E. R. Green, P. G. Heasler, F. A. Simonen, J. C. Spanner, and T. T. Taylor. 1988. Nondestructive Examination (NDE) Reliability for Inservice Inspection of Light Water Reactors.

NUREG/CR-4469, PNNL-5711, Vol. 7. Pacific Northwest Laboratory, Richland, Washington.

Doctor, S. R., J. D. Deffenbaugh, M. S. Good, E. R. Green, P. G. Heasler, G. A. Mart, F. A. Simonen, J.C. Spanner, T. T. Taylor, and L. G. Van Fleet. 1987. Nondestructive Examination (NDE) Reliability for Inservice Inspection of Light Water Reactors. NUREG/CR-4469, PNNL-5711, Vol. 6. Pacific Northwest Laboratory, Richland, Washington.

Doctor, S. R., D. J. Bates, J. D. Deffenbaugh, M. S. Good, P. G. Heasler, G. A. Mart, F. A. Simonen, J.C. Spanner, T. T. Taylor, and L. G. Van Fleet. 1987. Nondestructive Examination (NDE) Reliability for Inservice Inspection of Light Water Reactors. NUREG/CR-4469, _PNNL-5711, Vol. 5. Pacific Northwest Laboratory, Richland, Washington.

Doctor, S. R., D. J. Bates, J. b. Deffenbaugh, M. S. Good, P. G. Heasler, G. A. Mart, F. A. Simonen, J.C. Spanner, A. S. Tabatabai, T. T. Taylor, and L. G. Van Fleet. 1987. Nondestructive Examination (NDE) Reliability for Inservice Inspection of Light Water Reactors. NUREG/CR-4469, PNNL-5711, Vol. 4. Pacific Northwest Laboratory, Richland, Washington.

Collins, H. D. and R. P. Gribble. 1986. Siamese Imaging Technique for Quasi-Vertical Type (QVT) Defects in Nuclear Reactor Piping. NUREG/CR-4472, PNNL-5717. Pacific Northwest Laboratory, Richland, Washington.

Doctor, S. R., D. J. Bates, R. L. Bickford, L. A. Charlot, J. D. Deffenbaugh, M. S. Good, P. G. Heasler, G. A. Mart, F. A. Simonen, J. C. Spanner, A. S. Tabatabai, T. T. Taylor, and L. G. Van Fleet. 1986. Nondestructive Examination (NDE) Reliability for Inservice Inspection of Light Water Reactors. NUREGiCR-4469, PNNL-5711, Vol. 3. Pacific Northwest Laboratory, Richland, Washington.

Doctor, S. R., D. J. Bates, L.A. Charlot, M. S. Good, H. R. Hartzog, P. G. Heasler, G. A. Mart, F. A. Simonen, J. C. Spanner, A. S. Tabatabai, and T. T. Taylor. 1986. Evaluation and Improvement of NDE Reliability for Inservice Inspection of Light Water Reactors. NUREG/CR-4469, PNNL-5711, Vol. 2. Pacific Northwest Laboratory, Richland, Washington.

NUREG/CR-6181, Rev. I xx

Previous Reports Doctor, S. R., D. J. Bates., L.A. Charlot, H. D.- Collins, M. S. Good, H. R. Hartzog, P. G. Heasler, G. A. Mart, F. A. Simonen, J. C. Spanner, and T. T. Taylor. 1986 .. Integration of Nondestructive Examination (NDE) Reliability and Fracture Mechanics, Semi-Annual Report, April 1984 - September 1984. NUREG/CR-4469, PNNL-5711, Vol. 1. Pacific Northwest Laboratory, Richland, Washington.

Good, M. S. and L. G. Van Fleet. 1986. Status of Activities for Inspecting Weld Overlaid Pipe Joints.

NUREG/CR-4484, PNNL-5729. Pacific Northwest Laboratory, Richland, Washington.

Heasler, P. G., D. J. Bates, T: T. Taylor, and S. R. Doctor. 1986. Performance Demonstration Tests for Detection of Intergranular Stress Corrosion Cracking. NUREG/CR-4464, PNNL-5705, Pacific Northwest Laboratory, Richland, Washington.

Simonen, F. A. 1984. The Impact of Nondestructive Examination Unreliability on Pressure Vessel Fracture Predictions.

NUREG/CR-3743, PNNL-5062. Pacific Northwest Laboratory, Richland, Washington.

• Simonen, F. A. and H. H. Woo. 1984. Analyses of the Impact of Inservice Inspection Using Piping Reliability Model.

NUREG/CR-3869, PNNL-5140. Pacific Northwest Laboratory, Richland, Washington.

Taylor, T. T. 1984. An Evaluation of Manual Ultrasonic Inspection of Cast Stainless Steel Piping. NUREG/CR-3753, PNNL-5070. Pacific Northwest Laboratory, Richland, Washington.

Bush, S. H. 1983. Reliability of Nondestructive Examination, Volumes I, II, and Ill. NUREG/CR-3110~1. -2, and -3; PNNL-4584. Pacific Northwest Laboratory, Richland, Washington.

Simonen, F. A. and C. W. Goodrich. 1983. Parametric Calculations of Fatigue Crack Growth in Piping.

NUREG/CR-3059, PNNL-4537. Pacific Northwest Laboratory, Richland, Washington.

Simonen, F. A., M. E. Mayfield, T. P. Forte, and D. Jones. 1983. Crack Growth Evaluation for Small Cracks in Reactor-Coolant Piping. NUREG/CR-3176, PNNL-4642. Pacific Northwest Laboratory, Richland, Washington.

Taylor, T. T., S. L. Crawford, S. R. Doctor, and G. J. Posakony. 1983. Detection of Small-Sized Near-Surface Under-Clad Cracks for Reactor Pressure Vessels. NUREG/CR-2878, PNNL-4373. Pacific Northwest Laboratory, Richland, Washington.

Busse, L. J., F. L. Becker, R. E. Bowey, S. R. Doctor, R. P. Gribble, and G. J. Posakony. 1982. Characterization Methods for Ultrasonic Test Systems. NUREG/CR-2264, PNNL-4215. Pacific Northwest Laboratory, Ri~hland, Washington.

Morris, C. J. and F. L. Becker. 1982. State-of-Practice Review of Ultrasonic In-service Inspection of Class I System Piping in Commercial Nuclear Power Plants. NUREG/CR-2468, PNNL-4026. Pacific Northwest Laboratory, Richland, Washington.

Becker, F. L., S. R. Doctor, P. G. Heasler, C. J. Morris, S. G. Pitman, G. P. Selby, and F. A. Simonen. 1981.

Integration of NDE Reliability and Fracture Mechanics, Phase I Report. NUREG/CR-1696-1, PNNL-3469. Pacific Northwest Laboratory, Richland, Washington.

Taylor, T. T. and G. P. Selby. 1981. Evaluation of ASME Section XI Reference Level Sensitivity for Initiation of Ultrasonic Inspection Examination. NUREG/CR-1957, PNNL-3692. Pacific Northwest Laboratory, Richland, Washington.*

.('

xxi NUREG/CR-6181, Rev. 1

l.O Introduction Pacific Northwest National Laboratory (PNNL) is con- consider other additional objectives of ISi inspection, ducting a multi-year program for the U.S. Nuclear Regu- including defense-in-depth and the identification of latory Commission (NRC) entitled "Evaluation and unexpected degradation in operating plants.

Improvement in Nondestructive Evaluation Reliability for Inservice Inspection (ISi) of Light Water Reactors." The* This report describes evaluations for the Surry Nuclear goals ofthis program are to determine the reliability of Power Station Unit 1 (Surry- I) which was selected for current ISI for reactor systems and components, and to demonstrating the risk-informed methodology. Participa-develop recommendations that can ensure high inspection tion of Virginia Electric Power Company (VEPCO) staff reliability. The long-term objective is to develop technical was an essential part of the pilot study. Plant-specific infor-bases for improvements to the inspection requirements of mation was obtained through system drawings, visits to the nuclear power plant components. One task of the PNNL plant site, and discussions with plant operational staff. The program was to develop and evaluate risk-informed specific systems selected for study were the auxiliary techniques for ISi plans of nuclear power plants. feedwater, reactor coolant, and the low-pressure injection systems. This report presents the results for the most risk-Because of similarities in objectives, the PNNL program important components within the three selected systems at task related to risk-informed methodology for ISi was Surry- I and compares the results for ISi priorities with the coordinated with the activity of the American Society of current ISi practices. Differences are being assessed to Mechanical Engineers (ASME) Research Task Force on determine the extent of potential improvements to ISi plans Risk-Based Inspection Guidelines. The initial Task Force provided by the new methodology.

document (ASME 1991) has made general recommen-dations on the application ofrisk-informed methods to ISi, This report is a revision of the earlier report (Vo et al.

and forms the basis of future proposals to ASME Codes and 1994) that incorporates recent plant-specific information Standards Comniittees for improved codes and standards. and improved risk-informed methodology. Sirice this Results of PNNL studies have been made available to the report, NUREG/CR-6181, Rev. 1, provides a preferred ASME Research Task Force to demonstrate and validate methodology, it supersedes the earlier NUREG/CR-6181 the usefulness of the risk-informed methodology. A subse- report published in August 1994. In the previous version, quent task force document (ASME 1992) specifically the approximate risk-informed methodology was developed addressed nuclear power plant components. Additional for assessing component risk contributions by combining documents addressing nuclear power plant components will system risk importance with the contributions of com-be issued by the ASME Task Force. ponents to system failures, to provide a quantitative measure of component risk importance. With lessons To provide technical bases for improved ISi plans, a learned from the application of the PNNL approximate method as described in this report uses results of methodology and from recent research efforts being probabilistic risk assessments (PRAs) to estimate the performed by the ASME Research Task Force on Risk-consequences of component failures. The probabilities of Based ISi, an improved risk-informed methodology has these component failures have been estimated by using an evolved. This improved methodology was used for expert judgment elicitation process (Vo et al. 1991). Using redetermining the risk importance of individual Surry- I these estimates of consequences and probabilities, risk components, and the results of these new calculations are calculations can be performed to identify ISi priorities for the subject of this report.

nuclear power plant components. Once high-priority components have been identified, recommended inspection This revised report includes information from the earlier programs (method, frequency, and extent) can be developed (NUREG/CR-6181) report that is still relevant and was by using probabilistic structural mechanics to identify used in this study to evaluate the evolved methodology.

inspection strategies that will ensure that component failure Section 2.0 of this report discusses the overall methodology rates are maintained at given levels. However, any for risk-informed ranking of components. Part of this dis-complete inservice inspection program plan should also cussion addresses the methods used to estimate component 1.1 NUREG/CR-6181, Rev. 1

Introduction rupture probabilities. Section 3.0 provides details of the summary and conclusions of the study are presented in Surry- I pilot study. Descriptions are provided for the three Section 5.0. Appendix A of this report provides details of systems addressed, and the assumptions made in the the risk-informed calculations for the components selected analyses are also included. Results of the component for this study. Appendix B describes a peer review and rankings as well as sensitivity analyses are presented. some insights of the risk-informed approach developed by Section 4.0 provides a detailed discussion and PNNL.

interpretation of the results of Section 3.0. Finally, a NUREG/CR-6181, Rev. 1 1.2

2.0 Overall Methodology This section describes the methodology which was used to

• Failures that cause any combination of the above.

perform the risk-ranking process. This is an improved methodology that was based on lessons learned from the Because the consequences can vary and the correct PRA application of the PNNL approximate methodology and and failure probability information is necessary for the CDF from recent research efforts of the ASME Research Task calculation, the process requires different manipulations for Force on Risk-Based ISI with PNNL input. The following each type of consequence. Different equations were discussion summarizes the overall methodology. developed to ensure the proper calculation for each type of consequence. The risk increase values are combined with the results of the component failure probability/rate to 2.1 Risk Prioritization obtain core damage frequency for each component.

Depending upon the type of consequence; one of the three For the systems selected in the study, a detailed component- equations (as shown below) was then used to compute the level prioritization was performed. Simplified Piping and component or pressure boundary core damage frequency.

Instrumentation Diagram (P&ID) drawings for each system of interest and worksheets were developed to support the 2.1.1 Failures Causing System Degradation analysis. The P&ID drawings were used to identify the pipe segment boundaries. The worksheets contained For component failures that cause only mitigating system information specific to a component, such as the failure degradation or loss, the core damage frequency for the com-probability and consequences of component rupture. The ponent is determined by the following equation:

consequence type is categorized as being a component failure that causes system degradation; an initiating event; CDFPB = FPbreak

• RAW (2.1) or a combination of system degradation and an initiating where CDFp8 = Core damage frequency from a event. To compute the contribution to core damage component failure per unit year frequency of a component, the plant PRA was used to find a RAW = Risk Achievement Worth basic event whose failure would have the same effect as a FPh,eak = Component failure probability given as component rupture. In this analysis, the risk increase for A* T/2 that basic event was used to measure the contribution to A = Component failure rate core damage frequency of a component rupture. The risk T = Inspection interval, assuming end-of-increases for the basic events were calculated by setting the life, 40 yrs failure probability for the events to one, and then computing the new core damage frequency. To obtain the contribution to CDF, a surrogate component that is already modeled in the plant PRA is identified in In order to use the plant PRA as input to the core damage which the consequence or impact on the CDF matches the frequency (CDF) calculation, the postulated consequences postulated consequences for the component failure. The of the failure were identified. Then based on the identified surrogate component is assumed to fail with a failure proba-consequences, the PRA model was manipulated to obtain bility of 1.0 to obtain a new total plant core damage the required information. The consequences considered frequency. In order to determine the contribution to core from both direct effects and indirect effects include: damage frequency for the component only, the base total plant PRA CDF is subtracted from the new total plant CDF

• Failures that cause an initiating event such as a LOCA as shown by:

or reactor trip RAW= CDFPB=l.O - CDFBASE (2.2)

• Failures that disable a single component, train or system where CDFPa=1.o = New total plant CDF with surrogate

• Failures that disable multiple components, trains or component = 1.0 systems, and CDFaAsE = Base total plant CDF 2.1 NUREG/CR-6181, Rev. 1

Overall Methodology 2.1.2 Failures Causing an Initiating Event where CDFp8 = Core Damage Frequency from a component failure For piping failures that cause an initiating event only, the CONTINS = Contribution to core damage probability portion of the PRA model that is impacted is the initiating for the initiator with mitigating system event and its frequency. For a piping segment, the core component assumed to fail damage frequency from the piping failure is calculated by: FRii,ea1c = Component failure rate CDFPB = FRPB

• CONTINT (2.3) The contribution to core damage probability for the initiator is determined by the following equation:

where CDFp8 = Core damage frequency from a component failure CONTINS = RI / IEVfreq (2.6)

CONTINT = Contribution to core damage probability for the initiator where RI = CDF from the initiating event with FRp8 = Component failure rate segment failed IEVfreq = Initiating event frequency The contribution to core damage probability is determined from existing base PRA results. The core damage fre- 2.1.4 Pipe Segment Contribution to Core quency contribution from the initiating event postulated for Damage Frequency the piping failure is identified along with the base PRA ini-tiating event frequency. Dividing the CDF by the initiating Each component within the scope of this study is evaluated event frequency yields the contribution to core damage to determine its contribution to core damage frequency due probability as shown by: to component failure: Once this is completed, the pipe segment contribution to core damage frequency is CONTINT= EVENTcom I IEVr,eq (2.4) calculated by summing across each individual component.

This summation was performed for the purpose of where EVENTcom = Base PRA core damage frequency demonstration only. The detailed calculations of from the initiating event component core damage frequency contributions can be IEV freq = Initiating event frequency from found in Appendix A of this report. As shown by the basePRA equations above, estimates of component failure probabilities are required in order to perform component 2.1.3 Failures Causing System Degradation prioritization. These estimates are summarized in the and an Initiating Event following subsection.

For component failures that cause an initiating event and system degradation, core damage sequences involving both 2.2 Estimates of Component Rupture events simultaneously must be evaluated. For component failures that cause an initiating event and system degrada-Probabilities tion, the following equation is applied:

For each system selected (e.g., auxiliary feedwater, low-pressure injection, and reactor coolant), the per-component CDFp8 = FRi,,eak

• CONTINS (2.5) failure probability was estimated. Because historical failure data on low-probability events (e.g., pipe rupture) are lacking, an expert judgment elicitation was used to estimate component failure probabilities. This section summarizes the procedures and the results of PNNL's expert judgment NUREG/CR-6181, Rev. 1 2.2 .

Overall Methodology elicitation. More detailed discussions are given in Vo et al. Prior to the expert judgment elicitation workshop, PNNL (1993, 1991, 1990). The expert judgment elicitation used a sent reference materials to the experts, including data sourc-systematic procedure, which closely followed the es, reports, probabilistic models, and recent PRA results.

approaches reported in the NRC Severe Accident Risks Panel members were asked to study thes.e materials and to Document (NRC 1989; Wheeler et al. 1989; Meyer et al. make initial estimates of failure probabilities.

1989). The specific objective of the PNNL elicitation was to develop numerical estimates for probabilities of catas- At the meeting, a formal presentation was provided for each trophic or disruptive failures in the selected components at system addressed. Presentations covered technical descrip-Surry- I. In this demonstration study, component rupture is tions, historical component failure mechanisms, elicitation defined as a break or leak that is greater than make-up capa- statements, suggested approaches, questionnaire forms, and bility and/or that can disable the systems intended function. any materials that supported the issue descriptions .. The In his study, small leaks that may cause system degradation presentations were followed by discussions. The experts were not included. Figure 2.1 shows information that was provided their knowledge regarding plant design and opera-used to obtain the desired estimates from the experts. tion, failure history, material degradation mechanisms, and methods for recomposition and aggregation of the data.

Data from PRA Results and Hist<;>rical Fracture Mechanics Other Relevant Information Failure Data Analyses (system, component prioritization, system descriptions, etc.)

~ ,

Expert Judgment Additional Information Elicitation and ..... (additional plant-specific Discussion -. information, etc.)

~,

Estimated Rupture Probabilities Figure 2.1 Information provided to the participants in the expert judgment elicitation 2.3 NUREG/CR-6181, Rev. 1

Overall Methodology Each expert then completed questionnaire forms that account for the relevant failures versus irrelevant failures.

addressed location-specific rupture probabilities for the The failure probabilities (per demand) for standby systems systems of interest. These responses included best esti- were probably overestimated by the experts, and the mates of probabilities arid uncertainties, and the rationale importances of piping segments in standby systems were for these estimates. Following the meeting, the informa- also likely overestimated.

tion provided by the expert panel was recomposed and aggregated. PNNL prepared a preliminary report of the The experts on the judgment elicitation panels were elicitation, which was then submitted to each panel mem- requested to estimate frequencies for pipe ruptures. It was ber for review. This report included the initial recompo- clear to the experts that occurrences of cracking and small sition, additional plant-specific data, and other relevant leaks were not of interest. Large leaks and small breaks information. The experts were requested to review the sufficiently severe to disable the function of a system were report containing the compilation of expert data and the of interest, even if these failures did not correspond to new data that had been assembled. The experts were fracture mechanics criteria for unstable fractures or requested to determine if this information would cause double-ended pipe breaks. It is notable that the numerical them to change their position. If it did, then they were values for pipe rupture probabilities provided by the requested to provide revised estimates of rupture experts were greater than the typical pipe break probabilities. The revised information was again recom- probabilities which are calculated by probabilistic fracture posed and aggregated to provide single composite mechanics codes, and correlate better with calculated judgments for each issue. values for large leak probabilities.

The appropriate failure probabilities for the risk ranking It has been noted that in some cases the pipe rupture calculations should assume that no inservice inspections frequencies estimated by the experts were approximately are performed. However, the expert judgment elicitation two orders of magnitude less than LOCA frequencies that process was based largely on plant operating experience, have been used in PRAs. In part, this may be due to which implicitly reflects any benefits derived from the consideration by the experts of only structural failures of ongoing inservice inspections. This issue was addressed piping excluding other events that can also cause LOCAs.

in discussions by the expert judgment elicitation panels. Another more likely explanation is that the estimates from The consensus was that routine inservice inspections using the experts were based on their detailed knowledge of representative industry practices have had only relatively materials science, fracture mechanics, and conditions small impacts on the piping failure rates. For most piping specific to the Surry-I piping. Such knowledge is not segments, these inspections have been performed reflected in the generic estimates of LOCA frequencies relatively infrequently (10 year intervals), on a small which have been used in the development of PRAs, which sample of welds (e.g., 7 percent), and with techniques may tend to be bounding values. Such bounding values often having marginal flaw detection capabilities. are often based on operating experience which is too Therefore, except for piping subject to augmented limited to provide data on actual pipe ruptures given the inspection programs (such as for stress corrosion cracking low expected values for these failure probabilities.

and wall thinning due to flow assisted corrosion), it was reasonable to neglect the benefits of inservice inspections. It should also be noted that the intention of the present calculations was to use failure probabilities from the Discussions during the expert judgment elicitation panel expert judgment elicitation panels fo the exclusion of meetings also addressed the role of current inservice generic data or estimates from other sources. However, testing (1ST) programs on piping reliability. In the Surry- I PRA was applied to quantify the*

calculations for ISi programs, it is believed to be consequences of the failure of each given pipe segment.

appropriate to hiclude the benefits of current 1ST In this regard, the PRA implicitly addresses the reliability programs in estimating baseline failure probabilities. On of other piping components, which may also be the other hand, the expert judgment elicitation panels did unavailable due to pipe ruptures already modeled in the recognize that failures which occur during standby periods PRA using failure rates inconsistent with the failure rates or during inservice testing should not be included as estimated by the expert judgment elicitation panels. In failures relevant to risk ranking calculations. Never- particular, when quantifying the Risk Achievement Worth theless, it is unlikely that the experts could adequately (RAW) of pipe failures causing only mitigating system NUREG/CR-6181, Rev. 1 2.4 .

Overall Methodology degradation or loss, the Surry- I PRA values for LOCA (1) the selection of the particular structural elements or frequencies are used. Because these values are two orders locations that will be inspected; this selection should of magnitude higher than those estimated by the expert be made to ensure that the selected component panels, for LOCAs caused by RCS piping failures, the locations include those with the higher contribution potential exists for overestimation of the ISI priorities for to risk.

pipe failures causing only mitigating system degradation or loss, for systems used primarily to mitigate the effects (2) the establishment of inspection strategies for the ofLOCAs. This effect is mitigated by the fact that the selected locations, such that the NDE methods and High Pressure Injection (HPI) system is also used to inspection frequencies provide the needed mitigate steam generator tube ruptures (SGTRs) and probability of detection and sizing accuracy of reactor coolant pump (RCP) seal LOCAs, and the degradation to maintain or reduce the failure frequencies of these events are not affected by the probabilities.

estimates of the expert panels. Moreover, the analysis supposes that failures of some piping in the LPI system (3) steps one and two _lead to a partial ISI plan/program also fail the HPI system; given this supposition, the that needs to be supplemented with additional ISI to dominant contribution to the RAW, for such LPI piping, accommodate defense-in-depth and the additional comes from SGTR sequences and RCP seal _LOCA objective of ISI to identify degradation mechanisms sequences. Future refinements of the risk ranking in various components not expected or anticipated methodology should address these potential in the original design.

inconsistencies. The methodology should be revised as

_needed to address cases for which the results of the The risk-ranking study described in this report focuses on calculations are impacted by accident scenarios involving the first step. However, this work was performed by more than one pipe failure event. PNNL for NRC as part of a larger research project with broader objectives (as described in Section 1.0) that also Figures 2.2, 2.3, and 2.4 show the estimated failure proba- addresses the second and third step of the process. This bilities of the AFW, LPI, and RCS components obtained work involves probabilistic fracture mechanics calcu-from the expert judgment elicitation approach. For lations which are being perform.ed to estimate component readability, the probabilities are presented with a log 10 failure probabilities and to quantify the benefits of scale, with the probabilities expressed as failures per alternative inspection strategies. Parametric calculations component per year. with the pc-PRAISE code have addressed crack growth by fatigue (Khaleel and Simonen 1994a, 1994b) and The ranges of best estimates from the experts were sum- intergranular stress corrosion cracking of stainless steel marized in a series of plots (boxes and whiskers) as shown piping (Khaleel et al. 1995).

in these figures. An individual plot displays five features of the distribution of estimated probabilities. The "whis- The PNNL work is evaluating various inspection kers" display the extreme upper and lower bound values strategies to identify combinations of inspection methods of the distribution, while the box itself locates the 25% (POD, sizing accuracy) and frequencies at selected and 75% quartiles of the distribution. Finally, the circle locations that can be effective in maintaining or reducing within the box is the median of the distribution. the failure probabilities of passive reactor components.

To accomplish this goal the inspection strategies must address the failure mechanisms of concern, and have 2.3 Inspection Program Development sufficiently high probabilities of detection and sizing accuracy so that the expected damage can be detected The methods as described in this report can support the (given various frequencies of inspection) and the development of improved inservice inspection plans (what components repaired before structural integrity is to inspect, where to inspect, when to inspect and by what impacted. Considerations include acceptable approaches method) using risk-informed approaches. In this regard, for determining the number of locations to be inspected the development of a risk-informed inspection plan can be (size of inspection sample) and the desired reliability and viewed as a three step process: frequency of the inspections to be performed at these 2.5 NUREG/CR-6181, Rev. 1

Overall Methodology

-9 -8 -7 -6 -5 -4 -3 SG to first isolation valve (main feedwater portion) i--e:=:::il-t SG to AFW first isolation valve o:J First to second isolation valve I + I Containment penetration to second isolation valve --c:::n-From Unit 2 AFW pumps t---{IJ---t Pipe segment between containment isolation valves +I AFW pump discharge headers * *

~

From Unit 2 AFW system Motor-driven pump (MDP)

+ I discharge -o:::J---i Turbine discharge pump (TDP) discharge ~ +

SG to turbine drive for TDP I ! b---t AFW pumps CST return lines -DJ-----

AFW TDP suction ~

TDP to CST1 t+ I AFW MDP suction ~

MDP to CST1 ,+ I CST1 ~

CST) to CST2. I + I CST2 ~

Emergency makeup to AFW MDPs ~

Emergency makeup to AFW TDPs - ~

-9 -8 -7 -6 -5 -4 -3 log(10) (failure/yr)

Figure 2.2 Estimates of rupture probabilities for Surry-I auxiliary feedwater system components from expert judgment elicitation NUREG/CR-6181, Rev. 1 2.6 .

Overall Methodology

-9 -8 -7 -6 -5 3 LPI cold-leg injection line (including first isolation valve) to RCS loop ~

Pipe segment between LPI isolation valves ~

Pipe segment from .

high-pressure injection (HPI) ---[]1-----1 to LPI cold-leg injection LPI isolation valve to common discharge header

---~t---1 Common discharge header to pump discharge ~

LPI hot-leg injection line to RCS loop ~

Pipe segment between LPI hot-leg isolation valves t-0]-t Hot-leg isolation valve to pump discharge header --[l]..---.

Pipe segment from HPI to LPI hot-leg injection --[]~---i LPI pump discharge lines t----11 + J------t LPI pump discharge to charging system ~

LPI pump discharge to relief/test lines t---C))t-----t Pump suction line Containment sump to

~ +I--

pump suction line *~

Refueling water storage tank (RWST) to pump suction RWST

+

-9 -8 -7 -6 -5 3 log(10) (failure/yr)

Figure 2.3 Estimates of rupture probabilities for Surry-1 low pressure injection system components from expert judgment elicitation 2.7 NUREG/CR-6181, Rev. 1

' -1 Overall Methodology

-9 -8 -7 -6 -5 -4 -3 RCS loop stop valve (hot leg) to vessel nozzle ~

Loop stop valve to SG

~

SG to RC pump t-0:J--t RC pump to loop stop

• valve (cold leg) ~

Loop stop valve (cold leg) to vessel inlet nozzle ~

Pressurizer inlet line (from RCS loops) t-[D------c Pressurizer spray line +J-t Auxiliary spray line t--CJ::}-i

~

Pressurizer spray common header Pressurizer surge line ..-[I}-t Pressurizer relief line ~

Pressurizer safety line ~

Pressurizer drain line ~ . ._ . .+,.__.--

-9 -8 -7 -6 -5 -4 -3 log(10) (failure/yr)

Figure 2.4 Estimates of rupture probabilities for Surry-I reactor coolant system components from expert judgment elicitation locations. Since several potential inspection strategies and should include additional elements to address may provide the desired maintenance or reductions in defense-in-depth for lower risk components, and to failure probabilities, the final selection can be based on address unanticipated generic failure mechanisms that other important considerations including man-rem have not been detected or that have not yet occurred. The exposures to inspection personnel and cost effectiveness. strategy should include immediate expansion of the sample when flaws are detected during an ISi through An inservice inspection strategy is defined by the sequential sampling based on feedback from ISi findings following elements: and operating experience.

2.3.1 Sampling Strategy 2.3.2 Inspection Method The sampling strategy is defined by the selection of Inspection methods are selected to address the degrada-structural elements that are proposed for inclusion in the tion mechanisms, pipe sizes and materials of concern.

inspection program. The selection of structural elements The inspection method includes the basic technique itself should be guided by the calculations ofrisk importances (e.g., ultrasonics) along with the particular equipment and NUREG/CR-6181, Rev. I 2.8 .

Overall Methodology the procedures to be applied for detecting and sizing program. Inspection systems with known reliability are flaws. Candidate inspection techniques for piping include needed to achieve the desired levels in failure ultrasonic testing, surface examinations with dye probabilities consistent with the goals of the risk-informed penetrants (or magnetic particles), visual examinations, inspection process. A risk-informed inspection program and radiography. In a larger context, monitoring methods should justify the inspection reliability using data from such as leak detection, thermal transient monitoring, and performance demonstration programs.

acoustic emission monitoring can be used to supplement or replace nondestructive testing methods. Detailed 2.3.4 Time of Inspection aspects of equipment, procedures, and personnel quali-fications are significant factors that govern the reliability The inservice inspection strategy must define when the of the inspections. The risk-informed inspection concept inspections are to be performed. In most cases inspec-requires that the reliability of the inspection method be tions are performed periodically at regular intervals such established in order to justify the selection of a particular as with the 10 year interval of ASME Section XL A risk-inspection strategy. Based on materials, environments, informed inspection program will identify the appropriate loads, and degradation mechanisms, probabilistic fracture inspection intervals, such that the inspection program mechanics calculations can establish the probability of provides the desired maintenance or reductions in detection, the sizing accuracy, and the frequency of component failure probabilities. Inspection intervals must inspection needed to meet target goals for passive reactor be sufficiently short so that degradation too small to be component failure probabilities. detected during one inspection does not grow to an unacceptable size before the next inspection is performed.

2.3.3 NDE Reliability and Performance Demonstration Qualification of the NDE system (personnel, procedure and equipment) is an important element of an inspection 2.9 NUREG/CR-6181, Rev. 1

3.0 Analyses of Surry-1 Plant Systems This section presents the analyses of the three selected performed the system walkdowns and obtained relevant Surry- I systems using the improved methodology detailed plant information. The visiting PNNL team included plant in Section 2. The information in Sections 3.1 through 3.3 is system specialists and PRA specialists. Because the plant being repeated from the earlier NUREG/CR-6181 report was in operation during the initial visit, system walkdowns since this information is needed as background and for use for some locations were not possible (e.g., inside the in the planned analyses. Following a brief discussion of containment building and other high-radiation areas).

plant familiarization, system descriptions, and analysis Therefore, the Video Information Management System assumptions, the components of the three selected Surry-I (VIMS) developed by VEPCO was also used. VIMS is a systems are prioritized and the results of the analysis are computerized system, that displays photographs of plant discussed. The section concludes with sensitivity analyses. systems and components that have been stored in digital form on a laser disc. Following simple instructions, the plant photographs could be retrieved and viewed at any 3.1 Plant Familiarization location within the plant.

Participation ofVEPCO was an essential part of the study. For each of the systems selected for the study, a system Before initiating the study, a visit to VEPCO headquarters walkdown was conducted where possible. The information was conducted. The purpose of this first visit was to get obtained from the walkdowns was later used to assess the acquainted with VEPCO personnel and to request needed indirect effects on the systems. The walkdowns for each data. system included the plant engineer and one or two project team analysts. For each component (e.g., pipe segment), all Prior to the initial plant visit, the PNNL project team ana- the necessary information related to that component was lysts reviewed the fault trees reported in the Surry- I PRA, obtained. This information was entered into the work-the system descriptions, and the sections of the final safety sheets. For example, for a given pipe segment within a analysis report (FSAR) applicable to the systems of interest. selected system, the component identification, including the Worksheets were prepared and preliminary success criteria pipe size, was identified. Numbers of welds; elbows, and dependency matrices were developed to identify supports, connections, penetrations, etc., within the pipe specific areas where information was needed to develop an segment in question were identified and recorded. Given a accurate model. Based on these initial activities, a letter of component failure, the potential targets that might be request was prepared and sent to plant personnel to identify impacted by the failed components (e.g., vital electrical the plant-specific information that was required. The buses, system components nearby, etc.) were also recorded.

following subsections provide a description of the plant Additionally, a video camera was used to record the visits and the information obtained during the visits. conversations with the responsible engineer and views of significant locations of concern to system design and operation.

3.1.1 Plant Visits and Information Obtained In addition to the plant system walkdowns, discussions with A number of plant visits were required during this study. plant operational and technical staff were also conducted.

The first several plant visits were required because the very The areas of discussion included plant and system modeling first visit occurred while the plant was in operation and questions, collections of system design and operational thus, prevented access to all areas of the plant. Further information, discussions of transient sequence progressions, PNNL staff required additional information following the and the operators' responses to these events. During the review of information from the earlier visits, and further it first plant visit the team had discussions with the Surry- I was simply not possible to have everyone (both PNNL staff supervisor of system safety, the operator training coor-and plant staff) together for enough time during one visit. dinator, and the supervisor of the ISL Project analysts talked with reactor operators, the shift technical advisor, The first week-long plant visit was arranged to meet with and members of the maintenance and engineering staff.

plant personnel. During this visit, project team analysts 3.1 NUREG/CR-6181, Rev. 1

Surry- I Systems Analyses Discussions centered on gaining a clear understanding of 3.1.2 Utility Interface the following items:

An ongoing interface was maintained with the utility

• the normal and emergency configurations and opera- throughout the duration of the study. The project team tions of the various systems of interest leader was in frequent contact with Surry- I plant personnel to ask questions and verify information. Surry- I personnel

• system dependencies also reviewed the results of the study when they became available.

• operational problem areas identified by plant personnel that may impact the analysis

• automatic and manual actions taken in response to 3.2 Plant System Description various emergency conditions Surry-I is part of a two-unit plant located on the James River near Williamsburg, Virginia. Surry- I is a

• availability of plant specific operational data. Westinghouse-designed, three-loop, pressurized-water reactor (PWR) rated a_t 788 MWe capacity with a sub-The emergency procedures which addressed actions iden- I atmospheric containment. The balance of the plant and

• I tified by the project analysts as important actions were containment building were designed and constructed by explained to operations personnel.

Stone and Webster Engineering Corporation. Surry-I is operated by VEPCO. Commercial operation started in During the course of the study, additional plant visits were 1972.

needed. One of these visits was to obtain additional plant-specific failure mechanisms for components within the The Surry- I systems selected for this re-analysis study to system analyzed. This information was provided to the evaluate the new methodology were the primary pressure expert judgment elicitation workshop participants for boundary system, the front-line safety systems, and certain estimating component rupture probabilities. Another plant important support systems. These were the auxiliary feed-visit was conducted during the plant shutdown for refueling.

water (AFW), low-pressure injection (LPI), and the reactor This visit was to obtain additional information and to verify coolant (RCS) systems. The following paragraphs the information that was obtained from earlier visits (e'.g.,

summarize the descriptions for these systems. Detailed areas inside the containment building).

descriptions can be found in the Surry- I FSAR.

A complete set of the current Surry P&ID, isometric drawings, composite drawings, and stress analysis reports 3.2.1 Auxiliary Feedwater System were provided by the Surry- I staff. Also, the Surry- I staff provided copies of the Surry Emergency Procedures, The AFW system provides feedwater to the steam genera-Abnormal Procedures, Emergency Contingency Action tors for heat removal from the primary system after a reac-Procedures, Functional Restoration Procedures, and several tor trip. The AFW system may also be used following a sections from the current revisions of the Surry- I FSAR. reactor shutdown, in conjunction with the condenser dump The plant information was incorporated into PNNL's valves or atmospheric relief valves, to cool the RCS to worksheets. For instance, the isometric and composite about 300°F and 300 psig, at which time the residual heat drawings were used to obtain additional information removal system is brought into operation. The AFW regarding component orientation and number of subcom- system also provides emergency water following a ponents. The Emergency Procedures were used to assess secondary-side line rupture. Removal of heat in this the recovery actions by the operators given a component manner prevents the reactor coolant pressure from increas-rupture. ing and causing release of reactor coolant through the pressurizer relief and/or safety valves.

NUREG/CR-6181, Rev. 1 3.2

Surry- I Systems Analyses The AFW system is diagramed in Figure 3.1. The AFW is RCS is depressurized, the LPR discharge provides the suc-a multiple-train system; it consists of electric motor-driven tion source for the high-pressure recirculation system pumps and steam turbine-driven pumps. Each pump draws following drainage of the refueling water storage tank suction through an independent line from the condensate (RWST).

storage tank. Each AFW pump discharges to parallel headers; each of these headers can provide AFW flow to The LPI/LPR at Surry-I is diagramed in Figure 3.2. The any or all of the steam generators. Flow from each header system consists of two 100% capacity pump trains. In the to any one steam generator is through a normally open injection mode, the pump trains share a common suction MOV and locked-open valve in series, paralleled with a header from the RWST. Each pump draws suction from the line from the other header. These lines feed one line header through normally open motor-operated valves containing a check valve that joins the main feedwater line (MOVs), check valves, and locked-open manual valves.

to a steam generator. Each pump discharges through a check valve and normally open MOV in series to a common injection header. The The motor-driven pumps automatically start on receipt of a injection header contains a locked-open MOV and branches safety actuation system signal, loss of main feed water, low to separate lines, one to each cold leg. Each of the .lines to steam generator level in any steam generator, or loss of off- the cold legs contains two check valves in series to provide site power. The turbine-driven pumps automatically start isolation from the high-pressure RCS.

on indication of a low steam generator level in any steam generator or undervoltage of any of the main RCS pumps. In the recirculation mode, the pump trains draw suction from the containment sump through a parallel arrangement Most of the AFW equipment is located in the auxiliary of suction lines to a common header. Flow from the suction building. This building is designed to withstand the effects header is drawn through a normally closed MOV and check of earthquakes, tornadoes, floods, and other natural phe- valve in series. Discharge of the pump is directed to either nomena. Provisions are incorporated in the AFW design to the cold legs through the same lines used for injection or to allow periodic operation to demonstrate performance and a parallel set of headers that feed the charging pumps, structural leak-tight integrity. Leak detection is provided by depending on the RCS pressure.

visual examination and sensors in the floor drain system.

The capability to isolate components or piping is provided, In the hot-leg injection mode, system operation is identical if required, so that the AFW system's safety function will to normal recirculation with the exception that the normally not be compromised. Provisions are made to allow for ISI open cold-leg injection valves must be manually closed of components at the appropriate times specified in the remotely, and one or more normally closed hot-leg recircu-ASME,Section XI. lation valves must be manually opened.

3.2.2 Low-Pressure Injection System The associated components, piping, structures, and power supplies of the LPI system are designed to conform with The LPI consists of several independent subsystems char- Class 1 seismic criteria. All motors, instruments, trans-acterized by equipment and flow path redundancy inside the mitters, and their associated cables located inside the con-missile protection boundaries. The two phases of low- tainment are designed to function during and under the pressure system operation including active low-pressure postulated temperature, pressure, and humidity conditions.

injection and recirculation mode and the passive accumu-lator injection. The passive accumulator system is not All LPI piping in contact with borated water is austenitic included in this evaluation. stainless steel. The piping is designed to meet the minimum requirements set forth in B 31.1 Code for Pressure The Surry- I low-pressure injection/recirculation system Piping, B36.10 and B16.19, ASTM Standards, Supple-(LPI/LPR) provides emergency coolant injection and mentary Standards, and Additional Quality Control Meas-recirculation following a loss-of-coolant accident (LOCA) ures. The piping is supported to accommodate expansion when the RCS depressurizes below the low-pressure due to temperature changes and hydraulic forces during an setpoint (about 300 psig). In addition to the direct recircu- accident. All components of the LPI/LPR are tested lation of coolant during the recirculation phase once the periodically to demonstrate system readiness. All 3.3 NUREG/CR-6181, Rev. 1

Cl.l

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o Main Steam 3

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in

~

0 Ll)

~

~

~

"'G XV120 LO PS95 PS96 ToUnl12 AFWSystem PS94

.-- - MOVFW260A

._.._...,._. MOVFW260B ADVMS102A XV'Z70 Turbine Drive for PSB4 CV133 CV131 PumpTDPFW2 PSB3 CV13B MOVFW160B 1.-+--+1-..,...-+--1+...,._,.....,...... From Fire Main CV309

_1o-----1-t-tl- From Emergency Makeup System

, . - .....~~-

From Unit 2 AFW Pumps MOVFW160A CV273 R9312053.2 Figure 3.1 Surry-1 auxiliary feedwater system simplified schematic

To Charging Pump Inlet Header From HPI NO/FAI NC-FAI 18858 6'-51-50-1502 To -=~,-NO/FAI Hot Leg Loop 3 HPI Power Removed

~Ki PS 47 6'-51-48-1502 Hot Leg Loop 2 18908 CV228 From HPI Cold Leg Loop 1 Power Removed CV241 CV79 NOFAI PS44 6' -Sl-152-1502 Cold Leg Loop 2 PS36 CV242 1890C CV82 PS45 Cold Leg Loop 3 CV243 CV85 6'-Sl-49-1502 Hot Leg Loop 1 CV46A XV57 (1-S1-P-1A) 1863A PS32 PS39 MDPSIIA Froni HPI Sump To Charging Pumps AL - Out of Position Alarm in Control Room R9312053,3 Figure 3.2 Surry-I low-pressure injection/recirculation system simplified schematic CZl lC/l

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Surry- I Systems Analyses pressure piping butt welds containing radioactive fluid, at The pipes through which the heated water flows from the greater than 600°F and 600 psig, were radiographed. The RPV to the steam generator are called the "hotlegs" and remaining piping butt welds were randomly radiographed. the pipes through which the cooled water flows from the Pressure-containing components are inspected for leaks steam generator and back into the RPV are called the from pump seals, valve packing, flanged joints, and safety "cold legs." The working fluid is boiled on the secondary valves during system testing. Frequency of testing and sides of the steam generator and transported through a maintenance of the system components are specified in the conventional turbine-condenser system.

ASME,Section XI.

The RCS also includes a pressurizer that maintains the 3.2.3 Reactor Coolant System reactor coolant at a constant pressure. The pressurizer system consists of power-operated relief valves with asso-The function of the RCS is to remove heat and transfer it ciated block valves, ASME code safety valves, pressurizer to the secondary system. It also provides a barrier against sprays, and electrical heaters. There is continuous control the release of reactor coolant or radioactive materials to of the water and steam inventory with~ the pressurizer the containment environment. The RCS for Surry- I is vessel. The pressurizer is connected to a coolant loop and diagramed in Figure 3 .3. It consists of three identical heat is maintained at the saturation temperature that corres-transfer loops (connecting parallel to the RPV), each of ponds to the system pressure.

which includes a steam generator; reactor coolant pump, connecting piping and instrumentation for flow and tem-perature measurements.

Figure 3.3 Surry-I reactor coolant system simplified schematic NUREG/CR-618I, Rev. I 3.6

Surry-1 Systems Analyses To regulate the reactor coolant chemistry within design

• In these analyses, failures in piping of less than 1-in.

limits and control the pressure level, a constant letdown diameter generally are not considered, primarily flow from one loop upstream of the reactor coolant pump is because of the enormous amount of instrumentation maintained. This flow is, in turn, controlled by the pres- piping of this size. Active functions of components surizer level. Constant coolant makeup is added by charg- such as pumps and valves, which make up part of the ing pumps in the chemical and volume control systems. system pressure boundary, are not considered. Steam The inservice integrity of the RCS is addressed through generator tube failures have been considered in other periodic inspections performed in accordance with the studies and are not included in this study.

requirements of ASME,Section XI.

• Only breaks/ruptures that are greater than make-up capability and/or needed to disable the intended system 3.3 Analysis Assumptions function were considered.

General assumptions used for the analyses are the

• The Standard Review Plan 3.6.2, developed by the NRC following: (1981), was used in determining the indirect effects (e.g., pipe whip, jet forces, etc.) of component failures,

• Core damage frequency was used as the bottom-line risk when such failures effected other components in the measure to prioritize plant system components. zone of interest (e.g., vital electrical buses). Addi-tionally, when a larger diameter pipe impacts a smaller

• For the three selected systems, the discrete components diameter pipe of the same pipe schedule, a smaller (piping segments, welds, fittings, etc.) are identified for diameter pipe is assumed to fail.

purposes of the risk-informed evaluation. For the systems analyzed, the components of interest were pipe

• Potential flooding due to pipe ruptures that could dam-segments. Each pipe segment included the straight age safety-related systems and equipment are not lengths of pipe, pipe elbows, couplings, fittings, flanged included in these analyses. Flooding should be joints, and welds. Additionally, tanks and heat addressed at a later date.

• exchangers, including the pressurizer, are also included as components in the analyses. The reactor pressure vessel and the accumulator systems are not included in 3.4 Component Prioritization this report.

The following sources of information were used to

• Generally, the risk achievement worth (RAW) results prioritize components for inspection: 1) the component reported in NUREG/CR-4550 were used to provide the failure probabilities estimated from expert judgment contributions to probabilities of core damage given the elicitation (Vo et al. 1990, 1991, 1993), and 2) Surry-1 component failures. PRA (NUREG/CR-4550 Bertucio and Julius 1990).

Commercially available PRA and spreadsheet programs

• Identical components in identical trains within the same were used for the calculations.

system were assumed to have the same failure consequences. Worksheets were initially formulated using plant system drawings and other relevant plant-specific information. As

• The pipe segments are grouped on the basis of similar stated in the assumptions, Standard Review Plan guidance consequence. The grouping process was based on developed by the NRC was used in determining the available information reported in NUREG/CR-4550. potential effects of system component failures on other components in the zone of interest. To ensure that plant

• Operator actions regarding pipe rupture recovery are not models were as realistic as possible and reflected plant considered.

3.7 NUREG/CR-6181, Rev. 1

Surry- I Systems Analyses operational practices, visits to the Surry- I plant were con- pipe runs was estimated as l .OE-06. This value describes ducted for plant system walkdowns, and discussions were the expected risk-informed implication of the segment held with plant operational and technical staff. For loca- under consideration.

tions where the walkdowns were not possible, (e.g., high-radiation areas) the VIMS developed by VEPCO was used to identify the potentially impacted systems and equipment 3.5 Results of Analyses (given a failure of a component in the zone of interest).

The worksheets were devised so that the necessary Within the three systems analyzed, there are approximately information could be systematically tabulated. In the 200 individual pipe segments. By assuming that identical following paragraphs, the example of the AFW system is components in identical trains within the same system have discussed. The detailed calculations are provided in the same failure probabilities and consequences, this total is Appendix A of this report. reduced to approximately 100. For ranking purpose, components within the same train can be further grouped, The first step of the analysis was to identify the component based on major discontinuities (e.g., between pumps and locations and/or the number of subcomponents within a major valves). This resulted in 24 major groups within the specified pipe segment. For example, the AFW pipe seg- systems analyzed.

ment between the check valve XV183 (pump suction) and the condensate storage tank (CST) consists of 13 welds, Table 3.1 shows the results of the risk-informed ranking of 6 elbows, 5 hangers, and 1 wall penetration. The pipe seg- major components within three selected systems at Surry-I, ment rupture probability was estimated as l .9E-06 per year based on the contributions of component failures to core as shown in Appendix A. damage frequency. Using input and data described earlier and under a PNNL contract and guidance, the ASME Information from the plant PRA, system walkdowns, Research Task Force conducted the calculations using the discussions with VEPCO staff, and the standard review plan revised methodology described in Section 2.1 of this report.

were used to determine the failure effects. For the pipe Included in Table 3 .1 are the estimated upper- and lower-segment above, the primary effect of a pipe segment failure bound values which indicate the effects of uncertainties in was conservatively assumed to be the loss of CST which the estimates of component rupture probabilities. (Note supplies all AFW pumps. The Surry- I PRA (NUREG/CR- that the pipe rupture probabilities used for the table are the 4550) was then used to estimate the contribution to CDF. sum of the rupture probabilities of all individual pipe For instance, page E-13 in the NUREG/CR-4550 contains segments making up the major component groupings of the RAW value for basic event AFW-1NK-VF-CST interest.) The rankings (as shown in the table) are based on (2.SE-03). the median values estimated from the Surry- I PRA and PNNL evaluations of other factors such as rupture Depending upon type of consequence; one of three equa- probabilities, as discussed in the preceding section.

tions provided in Section 2 was then used to compute the Figure 3 .4 presents this information graphically for the pipe segment core damage frequency. In this case, three systems. As shown in Table 3.1, the contributions of Equation 2.1 was applied and the pipe segment CDF was different components to core damage frequency (based on estimated as l.5E-06/yr * (T/2)

• 2.8E-03 = 1.lE-07, where the median values) range widely from about l.OE-12 to T = 40 year inspection interval. 6.0E-06 per plant year. The cumulative risk contribution from all components as shown in Figure 3 .5 is about Once this was completed, a total contribution to core l .8E-05 per plant year. It is interesting to note that the risk damage frequency was calculated by summing across each contribution is dominated by approximately the first individual pipe segment CDF. Note, grouping of the 12 highest-ranked components. The system level rankings smaller pipe segments with the same consequences is for obtained by summing contributions are the following:

the purpose of prioritization and demonstration. For exam- 1) AFW, 2) LPI, and 3) RCS.

ple, in the AFW system, the total CDF for pipe segment AFW-1 named "CST, Supply Line" which includes the Table 3 .2 shows the risk importance parameters for the piping between XV183 to CST and six other individual 24 major components identified in Table 3.1, which are ranked based on core damage frequency.

NUREG/CR-6181, Rev. 1 3.8

Surry-1 Systems Analyses Table 3.1 Component rankings based on core damage frequency for three selected systems at Surry-1 1 Estimated core damage frequency System - components 1 Upper Median Lower Rank' LPI - Pipe Segment Between Containment Isolation Valve (inside) and Cold Leg Injection l.IBE-05 5.96E-06 2.37E-06 AFW - AFW Isolation Valve to SG l.17E-05 3.31E-06 7.97E-07 2 AFW - Pipe Segment Between Containment Isolation and SG Isolation Valves 8.86E-06 2.9JE-06 6.lBE-07 3 AFW - AFW MDP Discharge Line 1.04E-05 2.39E-06 5.lSE-07 4 AFW - CST, Supply Line 6.35E-06 l.OIE-06 3.53E-07 5 LPI - LPI Sources (RWST, Sump), Supply Line 6.25E-06 6.BSE-07 l.95E-08 6 AFW - AFW MDP Suction Line 1.99E-06 5.60E-07 2.45E-07 7 AFW - Pipe Segment from Unit 2 AFW Pumps J.6IE-06 3.SOE-07 l.04E-07 8 LPI - Pipe Segment Between Containment Isolation Valve (inside) and Hot Leg Injection 6.26E-07 2.84E-07 l.44E-07 9 AFW - AFW TDP Suction Line 2.13E-06 2.78E-07 9.SlE-08 10 AFW - AFW TD Pump Discharge Line 2.34E-06 2.76E-07 4.97E-08 11 LPI - LPI Pump Suction Line 1.02E-06 2.02E-07 l.70E-08 12 RCS - Pressurizer Spray Line 1.IBE-07 5.ISE-08 1.0BE-08 13 LPI - Pipe Segment Between Pump Discharge and Containment Isolation Valve 2.06E-07 4.SIE-08 1.SOE-08 14 RCS - Pressurizer Relief/Safety Line 1.38E-07 2.86E-08 l.54E-08 15 AFW - Main Steam to AFW Pump Turbine Drive 6.94E-08 l.48E-08 2.33E-09 16 RCS - Pipe Segment Between RPV and Loop Stop Valve (Hot Leg) 1.19E-08 l.19E-08 7.16E-10 17 RCS - Pressurizer Surge Line J.91E-08 6.38E-09 2.83E-09 18 RCS - Pipe Segment Between SG and RCP 1.19E-08 2.84E-09 7.16E-10 19 RCS - Pipe Segment Between Loop Stop Valve and SG (Hot Leg) 9.SSE-09 l.89E-09 7.16E-10 20 RCS - Pipe Segment Between Loop Stop Valve and RPV (Cold Leg) l.31E-08 l.20E-09 5.97E-10 21 RCS - Pipe Segment Between RCP and Loop Stop Valve (Cold Leg) 5.97E-09 9.3JE-I0 2.39E-10 22 LPI - Pipe Segment Between Containment Isolation Valves 3.35E-09 9.00E-10 4.92E-I0 23 AFW - Pipe Segment from Emergency Makeup System and from Fire Main to AFW Pump <l.OOE-12 <l.OOE-12 <l.OOE-12 24 Suction

'Based on estimated median values of component rupture probabilities.

2 AFW = Auxiliary Feedwater; LPI = Low Pressure Injection; RCS = Reactor Coolant System.

'Rankings were based on median values.

3.9 NUREG/CR-6181, Rev. 1

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9 g, be C Ill ID System Components ca u I!! 1.CJIE-09 LPI - Pipe Segment Between Containment Isolation 0 Valve (inside) and Cold Leg Injection u 2 AFW - AFW Isolation Valve to SG 15 RCS 3 AFW - Pipe Segment Between Containment Isolation 16 AFW* - Main Steam to AFW Pump Turbine Drive and SG Isolation Valves 17 RCS - Pipe Segment Between RPV and Loop Stop 1.0IE-10 Valve (Hot Leg) 4 AFW - AFWMDP Discharge Line 5 AFW - CST, Supply Line 18 RCS - Pressurizer Surge Line 6 LPI - LPI Sources (RWST, Sump); Supply Line 19 RCS - Pipe Segment Between SG and RCP 7 AFW - AFW MDP Suction Line 20 RCS - Pipe Segment Between Loop Stop Valve and 1.0IE-11 e AFW - Pipe Segment from Unit 2 AFW Pumps SG (Hot Leg) g LPI - Pipe Segment Between Containment Isolation 21 RCS - Pipe Segment Between Loop Stop Valve and Valve Onside) and Hot Leg Injection RPV (Cold Leg) .

1O AFW - AFW TDP Suction Line 22 RCS - Pipe Segment Between RCP and Loop Stop 11 AFW - AFW TDP Discharge Line Valve (Cold Leg) 1.0IE-12 12 LPI - LPI Pump Suction Line 23 LPI - Pipe Segment Between Containment Isolation 0 13 RCS - Pressurizer Spray Line Valves 14 LPI - Pipe Segment Between Pump Discharge and 24 AFW - Pipe Segment from Emergency Makeup System Containment Isolation Valves and from Fire Main to AFW Pump Suction 1.0IE-13 1-......L.-L-...L.---li-.......L----1-.....L---1-.....L----'--'--.&.-....i..........&.-....i..........i._........._..._...1..-......1._...1..-......1._..____.__.L...-..J 0 5 15 20 ca,ipooentldentlfication Figure 3.4 Risk contributions of Surry-1 components

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ID System Components LPI - Pipe Segment Between Containment Isolation Valve (inside) and Cold Leg Injection 1.IXE-05 2 AFW - AFW Isolation Valve to SG 15 RCS - Pressurizer Relief/Safety Line 3 AFW - Pipe Segment Between Containment Isolation 16 AFW - Main Steam to AFW Pump Turbine Drive and SG Isolation Valves 17 RCS - Pipe Segment Between RPV and Loop Stop

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Surry-1 Systems Analyses Table 3.2 Risk importance for components of selected systems at Surry-1 1 Core Rupture damage System component' Rank frequency frequency LPI - Pipe Segment Between Containment Isolation Valve (Inside) and Cold Leg 1 2.65E-05 5.96E-06 Injection AFW - AFW Isolation Valve to SG 2 2.33E-04 3.31E-06 AFW - Pipe Segment Between Containment Isolation and SG Isolation Valves 3 5.27E-05 2.91E-06 AFW -AFW MDP Discharge Line 4 4.33E-05 2.39E-06 AFW - CST, Supply Line 5 l.84E-05 l.OlE-06 LPI - LPI Sources (RWST, Sump), Supply Line 6 2.34E-05 6.85E-07 AFW - AFW MDP Suction Line 7 l.OlE-05 5.60E-07 AFW - Pipe Segment from Unit 2 AFW Pumps 8 3.00E-06 3.SOE-07 LPI - Pipe Segment Between Containment Isolation Valve (inside) and Hot Leg 9 l.33E-05 2.84E-07 Injection

• AFW - AFW TDP Suction Line 10 5.03E-06 2.78E-07 AFW - AFW TDP Discharge Line 11 5.00E-06 2.76E-07 LPI - LPI Pump Suction Line 12 7.65E-06 2.02E-07 RCS - Pressurizer Spray Line 13 2.76E-05 5.15E-08 LPI - Pipe Segment Between Pump Discharge and Containment Isolation Valves 14 l.29E-05 4.51E-08 RCS - Pressurizer Relief/Safety Line 15 8.41E-06 2.86E-08 AFW - Main Stearn to AFW Pump Turbine Drive 16 l.51E-05 l.48E-08 RCS - Pipe Segment Between RPV and Loop Stop Valve (Hot Leg) 17 3.00E-06 l.19E-08 RCS - Pressurizer Surge Line 18 l.60E-06 6.38E-09 RCS - Pipe Segment Between SG and RCP 19 9.24E-07 2.84E-09 RCS - Pipe Segment Between Loop Stop Valve and SG (Hot Leg) 20 4.35E-07 l.89E-09 RCS - Pipe Segment Between Loop Stop Valve and RPV (Cold Leg) 21 3.06E-07 l.20E-09 RCS - Pipe Segment Between RCP and Loop Stop Valve (Cold Leg) 22 2.45E-07 9.31E-10 LPI - Pipe Segment Between Containment Isolation Valves 23 1.83E-06 9.00E-10 AFW - Pipe Segment from Emergency Makeup System and from Fire Main to AFW 24 8.06E-06 <l.OOE-12 Pump Suction

'Based on estimated median values.

2 AFW = Auxiliary Feedwater; LPI = Low Pressure Injection; RCS = Reactor Coolant System.

NUREG/CR-6181, Rev. 1 3.12

Surry- I Systems Analyses 3.6 Sensitivity Analyses 3.6.2 Results of Sensitivity Analyses There are various sources of uncertainty in the numerical Sensitivity analyses were performed on issues that could results of this study. This section describes specific potentially have significant impacts on component rank-sources of uncertainty and provides the results of ings. The sensitivity analyses addressed the changes in sensitivity analyses. component rankings by using upper- and lower-estimated

• values of component rupture probabilities as reported in 3.6.1 Sources of Uncertainty Vo et al. (1990). As shown previously in Table 3.1, although variation exists in the numerical results, most Two basic types of uncertainties addressed in this study components have relatively the same ranking, as were parameter value uncertainty and modeling uncer- compared to the ranking based on the median values. The tainty. Parameter value uncertainties were evaluated for largest variations in component ranking were the LPI component rupture probabilities. Modeling uncertainty supply lines and sources, .pipe segments extending from was evaluated for the treatment of the indirect effects of isolation valves to the steam generator, LPI pump suction the component failures. line, and pump suction and discharge lines of the AFW system. Pipe segments between the RCS loop stop valves The uncertainties in the component rupture probabilities and the RPV have moderate variations in ranking.

have been addressed in Vo et al. 1990. For example, the population quartile was chosen to describe uncertainty in Sensitivity analyses were performed to address contribu-the estimates of component rupture probabilities (see tions to core damage from indirect effects of component Figure 2.2). The uncertainties in CDF estimation, compo- failures. The preliminary results show that contributions nent unavailabilities, initiating event frequencies, and of the indirect effects to the overall core damage frequen-cutset element unavailabilities and their associated cy are negligible (less than 2%). The pipe segment modeling were not addressed in this study. Consideration identified to have greatest potential failure effects on the of functional dependencies and common-cause effects on other systems nearby was the pipe segment between LPI systems were based on the results evaluated by the pump discharge line and the containment isolation valve.

selected PRAs. Rupture of this line could disable the charging pump inlet header.

There are many variables involved in calculating the indirect effects given a pipe breal<: (e.g., location of pipe Although analyses regarding potential flooding within the break, orientation ofthe_equipment, direction of whipping plant due to pipe ruptures were not part of this study, a pipe, number of hangers and/or supports, impact location, complete study should include flooding. This is an impor-tant issue and should be addressed. Component risk angle of impacts, etc.). Guidance provided in the Standard Review Plan 3.6.2 and information obtained prioritization for the entire reactor system should be through discussions with VEPCO staff during system completed and the main steam and main feedwater lines walkdowns were used to assess the indirect effects. The should be included in the evaluation.

assessments of the indirect effects using Standard Review Plan 3.6.2 are likely to be conservative. A sensitivity evaluation was.performed by excluding the potential indirect effects of component failures from the model (e.g., pipe whip or jet impingement effects) and recalculating the overall core damage frequency.

3.13 NUREG/CR-6181, Rev. 1

4.0 Discussion of the Results This section discusses the results presented in Section 3.0. also important but had somewhat lower rankings due to The discussions are based on the estimated median parame- relatively lower estimated rupture frequencies and/or RAW ter values. As noted in Section 3.0, risk-importances for the values of these components.

LPI-accumulator system are not included in the discussion.

The high-risk importance was also identified for compo-The rankings of Table 3.1 were developed on the basis of . nents located within the AFW system. A high-risk impor-core damage frequency. In this discussion we will identify tance is associated with the pipe segments between contain-the factors that govern these rankings, beginning with the menf isolation valves and steam generators, and motor- and highest ranked segment and ending with the lowest ranked turbine-driven pump discharge lines of the AFW system.

segment. The importance of these lines is due to a combination of high stress and high conditional core damage resulting from The pipe segments in the current study were defined for a line rupture. Failures of the pipe segment extending from convenience such as group runs of pipe with similar the AFW isolation valves to the steam generators would consequences of failure. The definitions were also based in result in steam generator blowdown through the break part to correspond with information as reported in (similar to a main steam line break) and a loss of secondary NUREG/CR-4550. As a result, there were some large cooling. Relatively high rankings were calculated for the differences between the segments in terms of the total pipe segments of the AFW system supply lines and sources length of pipe and the numbers of welds and fittings within ( e.g., condensate storage tank), the motor-driven and each segment. This has the potential to distort the rankings, turbine-driven pump suction lines, and pipe segment from because a segment can have a high failure probability by Unit 2 AFW pumps. Although these pipe segments have virtue of the large number of welds and fittings within the relatively low pressure, failure of these pipe segments could segment. Future refinements of the ranking process should disable the entire AFW system, and thus contribute signifi-work to minimize distortions of the ranking process by cantly to core damage. The importance of the Unit 2 pump seeking an appropriate balance between the accuracy of the cross-connected line is due to its key function in providing ranking calculations and the computational effort needed to cooling to the steam generators in the case that Unit I AFW perform calculations. is lost. This cross-connected line is also used for mitigating other initiating events (e.g., station blackout).

For discussion purposes in this section, we refer to "high-risk importance components" as those having a core damage frequency greater than l .OOE-07 and we refer to 4.2 Low-Risk Importance Components "low-risk importance components" as those having core damage frequencies less than l .OOE-08. As shown in Table 3.1, the next risk-important pipe seg-ments are the RCS pressurizer spray line, pressurizer relief/

safety line, and the main RCS piping from the hot-leg stop 4.1 High-Risk Importance Components valves to the pressure vessel. Failure of any of these lines results in a large LOCA. The importance of the pressurizer Pipe segments of the LPI system extending from the inside spray line results from a relatively high-estimated failure containment isolation valves to the RCS cold- and hot-leg probability due to thermal stress and the key function of this injection headers were identified to be high risk-important line in controlling the desired primary system pressure.

components. The high rankings are due to the relatively Failure of the spray line could result in LOCAs in Loops A high stresses, potential for overpressurization of these lines, and C, in addition to the loss of the pressurizer function.

and the important functions of these lines in providing cool-ant to he RCS following a large LOCA. The LPI supply Low rankings were estimated for the pipe segments of the lines and water sources (e.g., refueling water storage tank LPI system for the LPI system extending from the pump and containment sump) and the pump suction lines were discharge lines to the containment isolation valves (pipe 4.1 NUREG/CR-6181, Rev. I

Discussions of Results segment between pump discharge and containment isolation dominates the risk, accounting for almost 32% of the core valves and pipe segment between containment isolation damage frequency due to component ruptures. The AFW valves). The importance of these lines is due to their pipe segments extending from the AFW supply lines and important safety functions in providing coolant to the RCS sources, motor-driven pump discharge lines to the contain-following an accident. Equal importance was calculated for ment isolation valves, containment isolation valves to steam the pipe segment of the Af:W system extending from steam *generator isolation valves, and isolation valve to steam supply lines to the AFW pump turbine drive. The impor- generator account for another 52%c The various welds in tance of this line is due to a combination of high stress and the AFW and LPI systems contribute another 15%. This high system unavailability resulting from a line rupture. adds up to 99% of the total core damage frequency risk associated with component ruptures for the three systems Lower importances are noted for the RCS pressurizer surge analyzed. The system level rankings derived from the line and the main RCS piping from the steam generators to component contributions to core damage are the following:

the reactor coolant pumps (RCPs), and the pipe segments 1) AFW, 2) LPI, and 3) RCS.

from cold- and hot-leg stop valves, and the pipe segments from the RCPs to the loop stop valves. Failures of any of Table 4.1 presents the Surry-1 plant-specific ASME classi-these lines results in a large LOCA which cannot be iso- fications and required ISi examinations for each piping seg-lated by the loop stop valves, as is the cases with other ments or components of Table 3 .1. Table 4.1 shows that segments of the main RCS main piping. High estimated ASME classifications and ISi requirements are in partial consequences resulting from lines being connected to the agreement with the importance rankings based on core RCS loop (e.g., safety injection, RHR lines, etc.) increase damage frequency. The first twelve components contribute the importance of these particular pipe segments within the the most risk (99%) for the three systems studied.

reactor coolant loop. However, the inspection requirements from Table 4.1 for six of these twelve components require only a visual The cumulative risk contribution for all components (as inspection. The other six require a more stringent inspec-shown in Table 3.1) for the three system is about l.SE-05 tion of a volumetric or a combination of a volumetric and per plant year. Significant contributions to risk come only surface examination. Furthermore, recommendations for from failures of approximately the first 12 components setting inspection requirements based solely on Table 4.1 (99%). The single LPI line extending from the inside con- should be made cautiously because all plant systems and tainment isolation valves to the RCS cold leg injection components must be considered.

NUREG/CR-6181, Rev. 1 4.2

Discussions of Results Table 4.1 Component importance ranking 1 compared with ASME BPVC Section XI classifications and ISi r~quirements for selected systems at Surry-1 2 ASME BPVC system System-component Rank Category Examination LPI Pipe Segment Between Containment Isolation Valve B-J, C-F-1 Volumetric and Surface (inside) and Cold-Leg Injection AFW AFW Isolation Valve to SG 2 C-F-1 Volumetric and Surface AFW Pipe Segment Between Containment Isolation and SG 3 C-F-1 Volumetric and Surface Isolation Valves AFW AFW MDP Discharge Line 4 D-B Visual AFW CST, Supply Line 5 D-B Visual LPI LPI Sources (RWST, Sump), Supply Line 6 D-C Visual AFW AFW MDP Suction Line 7 D-B Visual AFW Pipe Segment from Unit 2 AFW Pumps 8 C-F-1 Volumetric LPI Pipe Segment Between Containment Isolation Valve 9 B-J, C-F-1 Volumetric and Surface (inside) and Hot-Leg Injection AFW AFW TDP Suction Line 10 D-B Visual AFW AFW TD Pump Discharge Line 11 D-B Visual LPI LPI Pump Suction Line 12 C-F-1 Volumetric and Surface RCS Pressurizer Spray Line . 13 B-J Volumetric LPI Pipe Segment Between Pump Discharge and Containment 14 C-F-1 Volumetric and Visual Isolation Valve RCS Pressurizer Relief/Safety Line 15 B-J Volumetric AFW Main Steam to AFW Pump Turbine Drive 16 C-F-1 Volumetric RCS Pipe Segment Between RPV and Loop Stop Valve (Hot 17 B-J Volumetric Leg)

RCS Pressurizer Surge Line 18 B-J Volumetric RCS Pipe Segment Between SG and RCP 19 B-J Volumetric RCS Pipe Segment Between Loop Stop Valve and SG (Hot 20 B-J Volumetric Leg)

RCS Pipe Segment Between Loop Stop Valve and RPV (Cold 21 B-J Volumetric Leg)

RCS Pipe Segment Between RCP and Loop Stop Valve (Cold 22 B-J Volumetric Leg)

LPI Pipe Segment Between Containment Isolation Valves 23 C-F-1 Volumetric and Visual AFW Pipe Segment from Emergency Makeup System and from 24 D-B Visual Fire Main to AFW Pump Suction 1

Ranking based on Table 3.2.

2 Based on Surry- I plant-specific system classifications.

4.3 NUREG/CR-6181, Rev. 1

5.0 Summary and Conclusions As part of the work sponsored by the NRC, PNNL has been contribution to core damage frequency for a pipe segment pioneering the application of risk-informed techniques that (or component), and a consequence type were assigned for can be used for improving ISi plans for nuclear power each pipe segment. To compute the contribution to CDF plants. The goal of this work was to develop methodol- for a pipe segment, the plant PRA was reviewed to find a ogies to improve ISi plans (what and where to inspect, and basic event whose failure would have the same effect as a how reliably and how often to inspect) to ensure that pipe break. Likewise, from the PRA analysis, the RAW degradation in components important to safety could be value for that basic event measures the contribution to core reliably detected b,efore structural integrity would be damage frequency given a pipe break.

compromised. To 1accomplish the first step in this activity-that is, to,rank the components' importance to It is important to note that this modification of the PNNL safety and assign commensurate probability of failure goals, approximate risk-informed methodology improves the to be maintained with the aid of inspection, for the various accuracy of the detailed risk rankings of individual components-the use of PRAs was explored. components.

\

PNNL's work involved'two risk-informed methodologies. Both the "approximate" and the "revised" risk-informed The "approximate risk-informed methodology" was methodologies have undergone a peer review by developed in the mid 1980s and applied to the Surry- I Dr. Bill Vesely of SAIC, an expert knowledgeable in risk-nuclear power plant. This approximate methodology was based applications. Dr. Vesely concluded that the appropriate for use with early PRAs that reported system approximate methodology was valid but it was difficult to importances and commonly reported only abbreviated lists apply and requires the PRA satisfy certain constraints. The of dominant cutsets, which typically did not include the revised methodology overcomes the constraints of the necessary information for all components (or pipe seg- approximate approach. Further details of Dr. Vesely' s ments) of interest. It assessed component risk contributions review of the methodologies are provided in Appendix B.

by combining system risk importance with the conditional probabilities of system failure, to provide an approximate This revised methodology has been applied in a pilot study quantitative measure of component risk importance to identify and prioritize the most risk-important com-(NUREG/CR-6181, 1994). This methodology utilized the ponents in three systems at the Surry- I nuclear power plant.

reanalysis of system fault trees by simulating the failures of It should be noted that this analysis was performed for pressure boundary components by substituting the failure of demonstration purposes. In the pilot application, the surrogate active components modeled in the fault trees. method used component failure probabilities estimated Results from the system level and component level were from expert judgment elicitation, relevant plant infor-

• combined, along with estimated values of component mation, and the Surry- I PRA to prioritize components.

rupture probabilities, into an approximate methodology for determining the risk importance of individual components. The component rupture probabilities estimated by the At that time, requantification of the PRA was impractical expert judgment elicitation panels implicitly credited ISi because of limitations on software and data storage and activities and periodic testing of components. These handling capabilities, so that an approximate methodology component rupture probabilities may be underestimated due was needed. to inclusion of these activities, and it is recommended that fracture mechanics calculations be performed in the future The revised risk-informed methodology eliminates the . to refine the estimates.

determination of system risk importances, and proceeds to directly analyze component risk importances from the For the RCS piping, the estimations were based on plant-cutset output of the PRA. The revised methodology utilizes specific system operating conditions, stresses, consideration lessons learned from the approximate methodology and of aging, and the extensive base of fracture mechanics from recent research efforts being performed by the ASME calculations for this system. The estimated values were Research Task Force on Risk-Based ISL In summary, the approximately two orders of magnitude lower, as compared 5.1 NUREG/CR-6181, Rev. 1

Summary and Conclusions to the generic LOCA frequencies (all pipe sizes) reported in frequency due to indirect effects of component failures.

the NUREG/CR-4550. The lower probabilities are due to a The results indicate that the overall contribution to core combination of available plant-specific information, and the damage frequency from the indirect effects was negligible.

favorable operating history of PWR plants in the U.S. Sensitivity and uncertainty analyses regarding potential Because this study is based on the limited data and models, flooding within the plant due to pipe ruptures were not the results are approximate and subject to future refinement. performed. A complete study should include flooding.

As shown in Table 3 .1, contributions of component failures Risk importances of components were qualitatively to core damage frequency range widely for different compared with the current Surry- I plant-specific ASME components from about 6.0E-06 to <l.OE-12 per plant year. classifications and required ISi examinations. The ASME The cumulative risk contribution (as shown in Figure 3.5) is classifications and ISi requirements are in partial qualitative l.SE-05 per plant year. This estimated value is about 45% agreement with risk-rankings based on core damage of the total Surry- I PRA risk. The total estimated risk is frequency. Only one-half of the components with the dominated by failures of the auxiliary feedwater system greatest contributions to the core damage frequency components (60%). This risk is followed by the low- currently have the more stringent inspection requirements, pressure injection system components (39%), and then while the other half only receives a visual inspection.

other components within the reactor cooling system (1 %). However, final conclusions for setting inspection requirements should await further pilot studies.

These results must be viewed in the light of the discussion in Section 2.2, which indicates the potential for over- In a study aimed at developing improved ISi plans, a estimation of the importance of piping failures in standby complete analysis of the entire plant (all systems and systems. One reason for the overestimation is that 1ST can components) is needed. The work reported here detect piping failures in standby systems; this can reduce demonstrates a methodology that can be used for a the importance oflSI for standby systems. Another reason complete analysis of an entire plant. This will provide a is that the LOCA frequencies from the Surry- I PRA were ranking of all components and their contribution to risk.

used in estimating the Risk Achievement Worth of piping The contributions to risk can be used to set probability of failures that cause only mitigating system degradation or failure goals for the various components to be maintained loss, and these LOCA frequencies were two orders of with the aid of ISL Probabilistic fracture/structural magnitudes higher than those estimated by the expert mechanics can then be used to assess various inspection panels. This introduces an overestimation of ISi priorities strategies, that is combinations of probability of flaw for standby systems used primarily to mitigate the effects of detection and flaw sizing accuracy as a function of flaw LOCAs; the overestimation is reduced in importance by the size, and inspection frequencies needed to achieve the fact that injection systems are used to mitigate not only probability of failure goals. Improved ISi plans include the LOCAs from RCS piping failures, but also steam generator component sampling strategy, the inspection method, the tube ruptures and reactor coolant pump seal LOCAs, and inspection reliability, and the frequency of inspection.

the frequencies of these events were not changed by the expert panels. The final ISi sampling plan should include components or elements from the risk studies (that includes all high-risk The sensitivity of component rankings to upper- and lower- components), be supplemented with additional ISi to bounding values of estimated rupture probabilities was accommodate defense-in-depth, and address the additional established. As shown in Table 3 .1, the results indicated no objective of ISi to identify unanticipated degradation significant changes in component rankings. Additional mechanisms that have not been detected or that have not yet sensitivity analyses addressed contributions to core damage occurred.

NUREG/CR-6181, Rev. I 5.2

1 6.0 References ASME Research Task Force on Risk-Based Inspection Meyer, M. A, and J.M. Booker. 1989. Eliciting and Guidelines. 1991. Risk-Based Inspection - Development of Analyzing Expert Judgment. NUREG/CR-5424, Guidelines, Volume 1 Genera/Document. CRTD-Vol. Los Alamos National Laboratory, Los Alamos, 20-1, American Society of Mechanical Engineers Center New Mexico.

for Research and Technology Development.

U.S. Nuclear Regulatory Commission (NRC). 1981.

ASME Research Task Force on Risk-Based Inspection Standard Review Plan 3.6.2 Determination ofRupture Guidelines. 1992. Risk-Based Inspection, Volume 2 - Locations and Dynamic Effects Associated with the Part 1: Light Water Reactor (LWR) Nuclear Power Plant Postulated Rupture ofPiping. NUREG-0800, Rev. 1, Components. CRTD - Vol, 20-2, American Society of U.S. Nuclear Regulatory Commission, Washington, D.C.

Mechanical Engineers Center for Research and Technology Development. (Also published by the U.S. Nuclear U.S. Nuclear Regulatory Commission (NRC). 1989.

Regulatory Commission as NUREG/GR-0005, Vol. 2, Severe Accident Risks: An Assessment for Five Part 1, July 1993). U.S. Nuclear Power Plants. NUREG-1150, Summary Report, Second Draft For Peer Review, U.S. Nuclear Bertucio, R. C., and J. A Julius. 1990. Analysis of Core Regulatory Commission, Washington, D.C.

Damage Frequency: Suny, Unit 1 Internal Events.

NUREG/CR-4550, Sandia National Laboratories, U.S. Nuclear Regulatory Commission (NRC). 1990.

Albuquerque, New Mexico. Analysis of Core Damage Frequency: Surry, Unit 1 Internal Events. NUREG/CR-4550, SAND 86-2084, Khaleel,M. A;., andF. A Simonen. 1994a. "AParametric Vol. 3,Rev. l,Part 1 andPart2, Sandia National Approach to Predicting the Effects of Fatigue on Piping Laboratories.

Reliability," Service Experience and Reliability Improvement: Nuclear, Fossil and Petrochemical Plants, Vo, T. V., B. W. Smith, F. A Simonen, and S. R. Doctor.

Vol. 1, ASMEPVP Vol. 288, pp. 117-125, American 1990. "Development of Generic Inservice Inspection Society of Mechanical Engineers. Guidance for Pressure Boundary Systems." Nuclear Technology, Volume 92 (3), American Nuclear Society, Khaleel,M. A, andF. A Simonen. 1994b. "The Effects La Grange Park, Illinois.

of Initial Flaw Sizes and Inservice Inspection on Piping Reliability," Service Experience and Reliability Vo, T. V., P. G. Heasler, S. R. Doctor, F. A Simonen, and Improvement: Nuclear, Fossil and Petrochemical Plants, B. F. Gore. 1991. "Estimate of Component Rupture Vol. 1, ASME PVP Vol. 288, pp.95-107, American Society Probabilities. Expert Judgment Elicitation." Nuclear of Mechanical Engineers. Technology, Volume 94 (1), American Nuclear Society, La Grange Park, Illinois.

Khaleel, M. A, F. A Simonen, D. 0. Harris, and D. Dedhia. 1995. "The Impact of Inspection on Vo, T. V., F. A Simonen, B. F. Gore, and J. V. Livingston.

Intergranular Stress Corrosion Cracking for Stainless Steel 1993. "Expert Judgment Elicitation on Component Rupture Piping," Risk and Safety Assessment: Where is the Probabilities for Five PWR Systems". PVP-Vol. 251.

Balance, ASMEPVP Vol. 266/SERA-Vol. 3, pp. 411-422, Reliability and Risk in Pressure Vessels and Piping.

American Society of Mechanical Engineers. pp. 115-140, American Society of Mechanical Engineers.

6.1 NUREG/CR-6181, Rev. 1

References Vo. T. V., B. F. Gore, F. A Simonen, S. R. Doctor. 1994. Wheeler, T. A, S. C. Hora, W.R. Cramond, and A Pilot Application ofRisk-Based Methods to Establish S. D. Unwin. 1989. Analysis of Core Damage Frequency Inservice Inspection Priorities for Nuclear Components at from Internal Events: Expert Judgment Elicitation.

Suny Unit 1 Nuclear Power Station. NUREG/CR-6181, NUREG/CR-4550, Volume 2, Sandia National PNNL-9020. Pacific Northwest Laboratory, Richland, Laboratories, Albuquerque, New Mexico.

Washington.

NUREG/CR-6181, Rev. 1 6.2

Appendix A Risk-Informed Calculation

_,i

Appendix A Risk-Informed Calculation This appendix describes the component risk importance calculations for the auxiliary feedwater, low-pressure injection, and reactor coolant systems. The calculations use the revised methodology based on lessons learned from the PNNL approximate methodology and from recent research efforts performed by the ASME Research Task Force on Risk-Based ISi. The revised methodology is described in Section 2 of the main report and also in an ASME report. 1 The following information was used for the component CDF analysis:

• The analysis uses pipe failure rates from Section 2 of this report.

• CDF was calculated using data and modeling from the Surry PRA (NUREG/CR-4550 1990).

This analysis was performed for components of the auxiliary feedwater, low pressure injection, and reactor coolant system.

The worksheets and simplified P&ID drawings were used for each system of interest. The P&ID drawings were used to identify the pipe segment boundaries corresponding to those listed in Table 3 .1 of the main report. Each pipe segment is composed of a set of individual components. The worksheets contain information specific to a pipe segment, such as the mean rupture probability and consequences of a pipe break in that segment. Using the methodology as described in Section 2 of the main report, core damage frequency calculations were performed for each pipe segment. Pipe segment core damage frequencies were calculated by summing the CDF for the components within the pipe segment.

To compute the contribution to CDF for a pipe segment, a consequence type was assigned to each pipe segment. The consequence type is categorized as being a component failure that causes system degradation, an initiating event, or a combination of system degradation and an initiating event. To compute the core damage frequency of a component, the Surry PRA was reviewed to find a basic event whose failure would have the same effect as a component failure. Likewise, from the PRA analysis, the RAW for that basic event measures the contribution to core damage frequency of a component failure. The Surry PRA (NUREG/CR-4550) contains RAW values for all the basic events modeled in the PRA. For example: Page E-13 contains the RAW value for basic event AFW-TNK-VF-CST (2.76E-03). The RAW for this basic event corresponds to the contribution to CDF for a pipe break that would cause the loss of all AFW. Depending upon the type of consequence; one of the three equations provided in Section 2 of the main report was then used to compute the component or pressure boundary core damage frequency.

Spreadsheets were developed to automate the core damage frequency calculations. Each row in the spreadsheet corresponds to a pipe segment. The key elements (column headings) of the spreadsheets are described as follows.

1 ASME Research Task Force on Risk-Based Inspection Guidelines. Risk-Based Inspection, Volume 2 - Part 2: Light Water Reactor (L WR) Nuclear Power Plant Components. CRTD-Vol. 20-4, American Society of Mechanical Engineers Center for Research and Technology Department. To be published.

A.I NUREG/CR-6181, Rev. 1

.,\

Appendix A

• Column A identifies the pipe segment of interest.

• Columns E and F identify the pipe segment failure rate and failure consequence, respectively. This information was obtained from the FMEA worksheets.

• Column I contains the basic event in the Surry PRA whose failure would have the same consequence as a pipe break in the segment of interest.

• Column J contains the contribution to core damage frequency given a break in the pipe segment. This information was obtained from the PRA and was calculated in one of three ways (see the equations for CONDcoF in the pipe segment CDF equations described in Section 2 of the main report).

• Column M contains the pipe segment CDF equation.

• Column N contains the core damage frequency given a pipe break for the segment of interest.

Table A.1 describes the contents of the spreadsheets in more detail, and Table A.2 summarizes the CDF results for Surry- I AFW, LPI, and RCS pipe segments.

References

1. NUREG/CR-6181, A Pilot Application of Risk-Based Methods to Establish Inservice Inspection Priorities for Nuclear Components at Surry Unit 1 Nuclear Power Station, T. Vo, et. al, January 1994.

2. NUREG/CR-4550, Analysis of Core Damage Frequency: Surry, Unit 1 Internal Events, February 1990.

NUREG/CR-6181, Rev. 1 A.2

I -

. Appendix A Table A.I Surry evaluation of pipe break core damage frequency ID Column Description A Segment ID Corresponds to the system and component segment identification used in NUREG/CR-6181. Listed underneath the segment ID is the CDF contribution for the pipe segment.

B Description Corresponds to the system and component segment description in NUREG/CR-6181.

C Element ID Corresponds to the piping segments used for the failure modes and effects analysis.

D Element Description Corresponds to the piping segment description.

E,F,G Rupture Probabilities Corresponds to the rupture probabilities assigned by the expert panel during the failure modes and effects analysis. (25%, median, 75%)

H Units Mean failure probability units; either probability or frequency.

I Consequence Corresponds to the consequence of a pipe break in a given segment. This information corresponds to the failure effects from the FMEA.

J Type Corresponds to the type of failure consequence; The failure can cause either system degradation, system degradation and an initiating event, or an initiating event.

K Linked Basic Event Corresponds to the basic event in the IPE analysis used to measure the risk increase in a pipe segment that would have the same failure effect as the basic event.

L Contribution to CDF Corresponds to the contribution to core damage frequency value given a pipe break.

M Units Contribution to core damage freque1:1cy units; either probability or frequency (per year).

N Inspection Interval Interval of pipe inspection or testing (in years) used for mean time between failure calculation.

0 CDF Equation Equation used to.compute the pressure boundary core damage frequency value.

P,Q,R CDF Core damage frequency contribution.for the pipe segment. (25%, median, 75%)

s Comments General comments related to the pipe segment.

A.3 NUREG/CR-6181, Rev. I

Appendix A

• Table A.2 Surry evaluation of pipe break core damage frequency System/ CDF segment Segment ID (median)

LPI- 1 Pipe segment between containment isolation valve and cold leg injection 5.96E-06 LPI-2 Pipe segment between containment valve and hot leg injection 2.84E-07 LPI- 3 LPI sources (RWST, sump), supply line 6.85E-07 LPI-4 Pipe segment between pump discharge and containment isolation valve 4.51E-08 LPI-5 Pipe segment between containment isolation valves 9.00E-10 LPI- 6 LPI pump suction line 2.02E-07 AFW-1 CST, supply line l.OlE-06 AFW-2 Pipe segment between containment isolation and SG isolation valves 2.91E-06 AFW-3 Main steam to AFW pump turbine drive l.48E-08 AFW-5 AFW TD pump discharge line 2.76E-07 AFW-6 Pipe segment from Unit 2 AFW pumps 3.50E-07 AFW-7 AFW isolation valve to SG 3.31E-06 AFW-8 AFW MDP suction line 5.60E-07 AFW-9 AFW MDP discharge line 2.39E-06 AFW-10 AFW TDP suction line 2.78E-07 AFW-11 Pipe segment from emergency make-up system and from fire main to <l.OOE-12 AFW pump suction RCS-1 Pipe segment between loop stop valve and RPV (cold leg) l.20E-09 RCS-2 Pressurizes spray line 5.15E-08 RCS-3 Pipe segment between RPV and loop stop valve (hot leg) l.19E-08 RCS-4 Pressurizer relief/safety line 2.86E-08 RCS-5 Pressurizer surge line 6.38E-09 RCS-6 Pipe segment between SG and RCP 2.84E-09 RCS-7 Pipe segment between loop stop valve and SG (hot leg) l.89E-09 RCS-8 Pipe segment between RCP and loop stop valve (cold leg) 9.31E-10 NUREG/CR-6181, Rev. 1 A.4

• A 8 C D E I F I 0 H I J K L M N 0 p Q I R s SURRY AFW SYSTEM I *---*-*----- --- -

ELEMENTS ELEMENTS MEAN FAILURE CONSEQUENCE TYPE LINKED COND COF TEST CDF PRESS BOUND Lower COMMENTS

---

* -- Appendix A SEGMENT ID DESCRIPTION ID DESCRIPTION Uppar VALUE Lower UNITS BASIC EVENT VALUE UNITS INTER EQUATION Upper CDF X T CST, SUPPLY LINE 1A 2.75E-05 1.95E-06 1.00E.()6 PER YEAR LOSS OF CST TO AFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 1.52E-06 1.oae-01 S.52E-08 AFW-1 XV153 TO CST1 1.00E.()6 PER YEAR LOSS OF CST TO AFW SYS AFW-TNK-VF-CST 2.76E.03 FREQ 40 (l"(T/2))"C 1.52E-06 1.0SE-07 5.52E-08 18 XV168 TO CST1 2.75E-05 1.IISE-06 1C XV153 TO CST1 2.00E.05 1.BSE-06 1.00E-06 PER YEAR LOSS OF CST TO AFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (l"(T/2))"C 1.1bE-06 1.0SE-07 5.52E-08 10 CST1 TO CV151 1.00E-05 2.39E-06 8.9'E-07 PER YEAR LOSS OF CST TO AFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (l"(T/2))"C 5.52E-07 1.32E-07 4.93E-08 5.00E-07 PER YEAR LOSS OF CST TO AFW SYS 2.76E-03 FREQ 40 (l"(T/2))"C 5.52E-07 1.32E-07 2.76E-OB 1E 1F CV151 TO CST2 CST1 1.00E-05 1.00E-05 2.39E-06 3.87E-06 1.00E-06 PER YEAR LOSS OF CST TO AFW SYS AFW-TNK-VF-CST AFW-TNK-VF-CST 2.78E-03 FREQ 40 (l"(T/2))"C 5.52E-07 2.14E-07 5.52E-08 10 CST2 1.00E-05 3.87E-06 1.00E-00 PER YEAR LOSS OF CST TO AFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (l"(T/2))"C 5.52E-07 2.1 .. E-07 S.52E-OB SUM 1.15E-04 1.ME-05 8.39E-06 SUM 1.93E-02 SUM 6.35E-06 1.01E.OS 3.53E-07 AVERAGE 1.UE-05 2.62E.OS 9.13E-07 AVERAGE 2.76E--03 AVERAGE 9.07E-07 1.'5E-07 5.0.. E-08 AFW-2 PIPE SEGMENT BETWEEN CONTAINMENT ISOLATION 2A 151ETOA4 1 *.0E-05 3.00E-08 1.00E-08 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (l"(T/2))"C 7.73E-07 1.66E-07 5.52E-08 AND SO ISOLATION VALVES 28 151F TO CV131 2.20E-05 2.19E-06 2.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.78E-03 FREQ 40 (l"(T/2))"C 1.21E-06 1.21E-07 1.10E-07 2C NODE 7 TO CV310 1.00E-05 3.00E-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF.CST 2.78E-03 FREQ 40 (l"(T/2))"C 5.52E-07 1.68E-07 5.52E-08 20 151CTO 151A 1 *.0E-05 3.00E-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E--03 FREQ 40 (l"(T/2))"C 7.73E-07 1.66E-07 5,52E-OB 2E BC4TO CV138 2.20E--05 1.00E-05 2.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF.CST 2.76E-03 FREQ 40 (l"(T/2))"C 1.21E-06 S.52E-07 1.10E-07 2F NODE 9 TO CV309 1.00E-05 3.00E-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (l"(T/2))"C 5.52E-07 1.66E-07 5.52E-08 20 1510TOA5 1.40E-05 3.00E-06 1.00E-08 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (l"(T/2))"C 7.73E-07 1.66E-07 5.52E-08 2H 1519 TO CS 2.20E-05 1.00E..05 2.00E-08 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 1.21E-06 5.52E-07 1.10E-07 21 CV136 TO CV138 1.65E-05 7.75E-06 1.00E-07 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (l"(T/2))"C 9.11E-07 4.28E-07 S.52E-09 2J CV131 TO CV133 1.60E-05 7.75E-06 1.00E-07 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (l"(T/2))"C 8.63E-07 4.28E-07 S.52E-09 SUM 1.61E--04 S.27E--OS 1,12E-05 SUM 2.76E-02 SUM 8.86E-06 2.91E-06 8.1BE-07 AVERAGE 1.e1E-0s 5.27E-06 1.12E.Q6 AVERAOE 2.76E-03 AVERAGE 8.BBE-07 2.91E-07 6.18E-08 AFW-3 MAIN STEAM TO AFW PUMP TURBINE DRIVE 3C MS LINE TO CV182 1.00E-05 2.29E-06 1.00E-06 PER YEAR MSLB & LOSS OF TOP SYS+INIT AFW-TDP..f~2 5.S7E-06 PROB re 1.76E-10 3.98E-11

• 1.76E-11 <-COND CDF

• SUM(TDP seq)/ T2 freq

-~

30 CV182TOTDP 6.00E-05 1.28E--OS 2.00E-06 PER YEAR LOSS OF TOP SYS AFW-TDP-FS.fW2 5.77E-05 FREQ 40 (r(T/2))"C 6.B2E-08 1.48E..08 2.31E-09 COND CDF * (3.31E-6+2.S6E-6Y.94

• 5.87E--06 SUM 7.00E-OS 1.51E-05 3.00E-06 SUM 6.36E-05 SUM 6.B4E-08 1.'8E-08 2.33E--09 AVERAOE 3.SOE-05 7.S3E-06 1.SOE-08 AVERAGE 3.18E-05 AVERAGE 3.47E-08 7.'1E--09 1.16E--09 FINAL COF VALUE IS MULTIPLIED BY 3 (3 LOOPS)

AFW.S AFW TD PUMP DISCHAROE LINE SA XV140 TQ CV142 1.00E--OS u,E-06 2.00E--07 PER YEAR LOSSOFAFW SYS AFW-TNK-VF.CST 2.76E-03 FREQ 40 (r(T/2))"C 5.52E-07 7 *.WE-08 1.10E-08 Risk Increase results are In NUREGICR--4550 58 XV141 T034 1.00E-05 1~E-06 2.00E-07 PER YEAR LOSSOFAFW SYS AFW-TNK-VF.CST 2.76E-03 FREQ 40 (r(T/2))"C 5.52E-07 7 ..toE-08 1.10E-08 Appendix E pages 133 and 153 SC cv1*2TOTOP 2.24E-05 2.32E-Oe 5.00E-07 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 1.2.CE-06 1.28E-07 2.76E-OB for the above calc BE AFW-TDP.fS-FW2 was used SUM *.2*e~ 5.00E-06 9.00E-07 SUM 8.28E-03 SUM 2.loCE--06 2.76E-07 4.97E-08 for the below calc BE Is listed In equation AVERAGE 1 ...1E-05 1.67E-06 3.00E-07 AVERAOE 2.76E-03 AVERAGE 7.SOE-07 9.20E-08 1.66E-08 AFW-8 PIPE SEGMENT FROM UNIT 2 AFW PUMPS 9A CV310 TO CV273 1.lBE-05 3.00E-06 8.ME-07 PER YEAR LOSS OF UNIT2 AFW SUPPLY SYS AFW..PSF-FC-XCONN 5.83E-03 FREQ 40 (r(T/2))"C 1.81E-06 3.SOE-07 1.04E-07 SUM 1.38E-05 3.00E-08 8.IWE-07 SUM 5.83E-03 SUM 1.61E-06 3.SOE-07 1.o,E--01 AVERAOE 1.38E-05 3.00E-06 IS.ME-07 AVERAOE 5.83E-03 AVERAGE 1.61E-06 3.SOE-07 1.04E-07 AfW.7 AFW ISOLATION VALVE TO SO 7A SGATOCV10 1.00E..o.t 8.07E-05 1.90E-08 PER YEAR LOSS OF MFW & AFW SYS+INIT AFW*TNK-VF-CST 5.15E-03 PROB re 5.15E-07 J.13E-07 9.79E-09 <-COND COF*

78 A2 TOCV27 1.40E-05 U7E-06 1.60E--OII PER YEAR LOSS OF MFW & AFW SYS+INIT AFW-TNK-VF-CST 5.15E-03 PROB 1*c 7.21E-08 2.JOE-08 B.24E-09 SUM[(AFW-TNK-VF-CST for T2LD2 seq)+

7C CV27TO XVJO 1,40E-05 2.26E-08 1.00E-08 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 7.73E-07 1.25E-07 5.52E-0S (AFW-PSF.fC-XCONN FOR T2LP seq)]/ T2 freq 70 A3TOXV31 1.40E-05 4.2.E-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 7.73E-07 2.34E-07 5.52E-08 * (2 *.0E-3+2.44E-3Y,IM 7E XV30TO 1S1E 1.40E-05 3.87E-06 1.00E-08 PER YEAR LOSSOFAFW SYS AFW*TNK.Vf-CST 2.7BE-03 FREQ 40 (r(T/2))"C 7.73E-07 2.14E-07 5.52E-08

• 5.15E-3 (typical calc for aeqmentJ 7F 131 TO 151F 1.40E-05 2.19E-06 1.00E-08 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.7BE-03 FREQ 40 (r(T/2))"C 7.73E-07 1.21E-07 5.52E-08 70 S0BTOCV41 1.00E-<M 8.D7E-05 1.90E-06 PER YEAR LOSS OF MFW & AFW SYS+INIT AFW-TNK-VF-CST 5.15E-03 PROB re 5.15E-07 3.13E-07 9,79E-09 7H B2TO cvse 1 *.0E-05 4.47E-06 1.60E-08 PER YEAR LOSS OF MFW & AFW SYS+INIT AFW-TNK-VF-CST 5.15E-03 PROB re 7.21E-08 2.JOE-08 8.24E-09 71 CVS8TOXV61 1 ..0E-05 2.26E-06 1.00E-08 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 7.73E-07 1.25E-07 5,52E-OB 7J B3TOXVB2 1.40E-05 ...20E-06 1.00E-08 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E.03 FREQ 40 (r(T/2))"C 7.73E-07 2.32E-07 5.52E-OB 7K XV61 TO 151C 1.40E--OS 3.IS7E-06 1.00E--OII PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 7.73E-07 2.14E-07 5.52E-08 7L XV62TO 1510 1.40E-05 2.19E-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.78E-03 FREQ 40 (r(T/2))"C 7.73E-07 1.21E-07 5.52E-08 7M SGCTOCV72 1.00E-<M 6.07E-05 1.90E-08 PER YEAR LOSS OF MFW & AFW SYS+INIT AFW-TNK-VF-CST 5.15E-03 PROB re 5.15E-07 3.13E-07 9.79E-09 7N C2TO CV89 1.40E-05 4.47E-06 1.60E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 7.73E-07 2.47E-07 8.83E-08 70 CV89 TOXV92 1.40E-05 2.26E-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 7.73E-07 1.25E-07 5.52E-08 7P C3TOXV93 1.40E-05 4.24E-06 1,00E-08 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.7BE-03 FREQ 40 (r(T/2))"C 7.73E-07 2.34E-07 5.52E-OB 7Q XV92 TO 151A 1.40E-05 3.87E-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 7.73E-07 2.14E-07 5.52E-OB 7R XV93TO 1519 1.40E-05 2.19E-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW*TNK-VF-CST 2.78E-03 FREQ 40 (r(T/2))"C 7.73E-07 1.21E-07 5,52E-08 SUM 5.10E--04 2.JJE~ 2.2SE--OS SUM 8.16E-02 SUM 1.17E-05 3.31E-06 7.97E-07 AVERAGE 2.83E-05 1.JOE-05 1.25E-08 AVERAGE 3.42E-03 AVERAGE 6.52E-07 1.84E-07 4.43E-08 AFW_,, AFW MOP SUCTION LINE BA MOP3A TO XV188 1.00E-05 2.39E-06 1.00E-06 PER YEAR LOSS OF CST & MDP3A SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (l"(T/2))"C 5.52E-07 1.32E-07 5.52E-08 88 MDP3B TO XV183 1.00E-05 2.39E-06 1.ooE..oe PER YEAR LOSS OF CST & MDP3B SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (l"(T/2))"C 5.52E-07 1.32E-07 5.52E-08 ec ..9TOXV169 3.00E-06 1.34E-06 7.75E-07 PER YEAR LOSS OF CST & MDP3A SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 1.86E-07 7 *.toE-08 ** 28E-08 eo S8TOXV2H 5.00E-06 1.34E-06 *.47E-07 PER YEAR LOSS OF CST & MDP3A SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (l"(T/2))"C 2.76E--07 7.~E-08 2.47E-08 BE 52TOXV1U 3.00E-06 1.:wE-08 7.75E-07 PER YEAR LOSS OF CST & MDP3B SYS AFW-TNK-VF-CST 2.7BE-03 FREQ 40 (r(T/2))"C 1.6SE-07 7 *.toE-08 4.28E--08 BF 58TO XV285 5.00E-06 1.34E-06 4.47E-07 PER YEAR LOSS OF CST & MDPJA SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 2.78E-07 7 *.0E-08 2 **7E-08 SUM 3.BOE-05 1.01E-05 4.44E-06 SUM 1.66E-02 SUM 1.99E-06 5.SOE-07 2.45E-07 AVERAGE 6.00E-06 1.69E-06 7.41E-07 AVERAGE 2.76E--03 AVERAGE 3.31E-07 9.33E-08 *.o9E-08 AFW-8 AFW MOP DISCHARGE LINE SA CV138 TO XV141 ,.12E--OS 8.UE-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 2.27E-06 4.B3E-07 5.52E-08 98 13 TO XV270 1.04E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (1°(T/2))"C 5.7.E-08

• c 15TOXV171 1.00E--OS 2.32E-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E--03 FREQ 40 (l"(T/2))"C 5.S2E-07 1.28E-07 S.52E-08 90 16TQXV156 1.00E~S 2.32E-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 5.52E-07 1.28E-07 5.52E-OB 6E CV133 TO XV140 *.12E-05 8.NE-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-Vf-CST 2.76E.03 FREQ 40 (l"(T/2))"C 2.27E-06 ... 93E-07 5,52E-08 9F 2S TO XV271 6.00E-06 1.o.aE-00 1.00E--07 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.7SE-03 FREQ 40 (l"(T/2))"C 3.31E-07 5.74E..08 5.52E-09 90 28 TO XV170 1.00E--OS 2.32E-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (l'(T/2))"C 5.52E-07 1.28E-07 5.52E-08 SH 27TO XV155 1.00E-05 2.32E-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 5.52E-07 1.28E-07 5.52E-08 81 XV1S6 T038 1.00E-05 1.34E-06 2.00E-07 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 5.52E-07 7.40E-08 1.10E-08 9J XV155 TO CV157 1.00E-05 2.32E-06 e.32E-07 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 5.52E-07 1.28E-07 3 ...9E-08 8K CV157 TO MDPJA 1.00E-05 3.87E-06 1.00E-08 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 5.52E-07 2.14E-07 5.52E-0S 9L XV170 TO CV172 1.00E-05 1.:wE-06 2.00E-07 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (l"(T/2))"C 5.52E-07 7 *.0E-08 1.10E-0e SM XV171 T0'1 1.00E--OS 1.3.E-06 2.00E-07 PER YEAR LOSSOFAFW SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 5.52E-07 7.40E-08 1.10E-OB 9N CV172 TO MDP 38 1.00E-05 3.87E-06 1.00E-06 PER YEAR LOSSOFAFW SYS AFW*TNK-VF-CST 2.76E-OJ FREQ 40 (l"(T/2))"C 5.52E-07 2.14E-07 S.52E-08 SUM 1.BBE...O.C **33E-05 9.33E-06 SUM 3.86E-02 SUM 1.04E-05 2.39E-06 5.15E-07 AVERAGE 1.45E-05 3.09E-06 7.18E-07 AVERAGE 2.76E-03 AVERAGE 8.00E-07 1.71E-07 3.9BE-08 AFW-10 AFW TOP SUCTION LINE 10A TOP TO XV153 2.75E~5 2.39E-06 5.00E-07 PER YEAR LOSS OF CST & TOP SYS AFW-TNK-VF-CST 2.76E-OJ FREQ 40 (r(T/2))"C 1.52E-06 1.32E-07 2.76E-0S 108 46 TO XV1S4 B.OOE-06 1.34E-06 7.75E-07 PER YEAR LOSS OF CST & TOP SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 3.31E-07 7.40E-08 4.2BE-08 10C 54 TO XV283 5.00E-06 1.JOE-06 4.47E-07 PER YEAR LOSS OF CST & TOP SYS AFW-TNK-VF-CST 2.76E-03 FREQ 40 (r(T/2))"C 2.76E-07 7.18E-OS 2.47E-0S SUM 3.SSE-05 5.0JE-06 1.72E-06 SUPJ! 8.2SE-03 SUM 2.13E-06 2.7SE-07 9.51E..OS AVERAGE 1.28E-05 1.BSE-06 5,74E-07 AVERAGE 2.78E-03 AVERAGE 7.0BE-07 9.26E-08 3.17E-08 AFW-11 PIPE SEGMENT BETWEEN RCP AD LOOP STOP 11A XV1S4 TO XV185 3.16E-06 1.JOE-06 1.00E-06 PER YEAR LOSS OF FIRE MAIN NONE NONE <1.00E-12 <1.00E-12 <1.00E-12 <1.00E-12 VALVE (COLO LEG) 118 XV283 TO XV285 6.00E-06 1.3.aE-06 7.75E-07 PER YEAR LOSS OF EMER MAKEUP NONE NONE <1.00E-12 <1.00E-12 <1.00E-12 <1.00E-12 11C XV169 TO 63 6.00E-06 1.J.aE--06 8.32E-07 PER YEAR LOSS OF FIRE MAIN NONE NONE <1.00E-12 <1.00E-12 <1.00E-12 <1.00E-12 110 XV2U TO 100 6.00E-06 1.34E-06 7.75E-07 PER YEAR LOSS OF EMER MAKEUP NONE NONE <1.00E-12 <1.00E-12 <1.00E-12 <1.00E-12 11E XV1B4TOU 8.00E-06 1.34E-06 8.23E-07 PER YEAR LOSS OF FIRE MAIN NONE NQNE <1.00E-12 <1.00E-12 <1.00E-12 <1.00E-12 11F 100 TO MAKEUP 5.48E-06 1.J.CE-06 1.00E-06 PER YEAR LOSS OF EMER MAKEUP NONE NONE <1.00E-12 <1.00E-12 <1.00E-12 <1.00E-12 SUM 3.26E~5 8.06E-06 4.81E-06 SUM <1.00E-12 SUM <1.00E-12 <1.00E-12 <1.00E-12 AVERAGE 5.44E-06 1.J.CE-06 a.01E-07 AVERAGE <1.00E-12 AVERAGE <1.00E-12 <1.00E-12 <1.00E-12 NUREG/CR-6181, Rev;.}

-01

"- f .

B K 0 p I R s A e D E I F I G H I J L M N I Q f, '.t SEGMENT ID DESCRIPTION ELEMENTS ID ELEMENTS DESCRIPTION UPPER FAILURE VALUE MEDIAN LOWER UNITS CONSEQUENCE TYPE LINKED BASIC EVENT COND CDF VALUE UNITS TEST INTER eDF EQUATION UPPER PRESS BOUND eDF LOWER

- COMMENTS Appendix A 1.00E+OO X T LPl-1 BETWEEN CIV & CLEO INJ LPl-1A RCS CL 1 TO CV79 5.00E-06 2.45E-06 1.00E-06 PER YEAR LOCA & HPI/LPI 1 CLEO SYS+INIT 3.98E-OJ PROB re 1.99E-08 9.75E-09 3.BBE-09 <- COND CDF

• LLOCA CDF CONT I A freq 5.98E-06 LPl-1B CV79 TO NOOE A 5.00E-06 2.45E-06 1.00E-06 PER YEAR LOSS HPULPI INJ SYS RWT-TNK-LF-RWST 1.95E-02 FREQ 40 (r(T/2)"e) 1.95E-06 9.56E-07 3.90E-07 COND COF* 1.99E-t!/5.0E-4

• 3.98E-J LPl-1C V2J5 TO CV241 S.OOE-06 2.45E--06 1.00E-06 PER YEAR LOSS HPULPI INJ SYS RWT-TNK-LF-RWST 1.95E-02 FREQ 40 (r(T/2)"e) 1.95E-06 9.56E-07 J.90E-07 LPl-10 V241 TO NODE D 3.20E-06 1.35E-06 1.00E-06 PER YEAR LOSS LPI INJ SYS LPI-MDP-fS 2.24E..o.& FREQ 40 (r(T/2)"e) 1.43E-OB 6.0SE-09 4.48E-09 LLOCA CDF Contribution 11 from LPl-1E NOOE 1A TO VLV 246 PER YEAR NONE(<1") 0.00E+oo FREQ 40 (l"(T/2)"e) O.OOE+OO 0.00E+OO O.OOE+OO NUREG/CR-4550 page4.11-4 LPl-1F RCS CL 2 TO CV82 5.00E-06 2.45E-06 1.00E-06 PER YEAR LOCA & HPULPI 1 CLEG SYS+INIT J.9BE-03 PROB re 1.99E-08 9.75E-09 J.98E-09 1.99E-06*SUM OF A SEQUENCES LPl-1G VB2TO CV236 5.00E-06 2.45E-06 1.00E-06 PER YEAR LOSS HPIILPI INJ SYS RWT-TNK-l.F~ST 1.95E-02 FREQ 40 (l"(T/2) e) 0 1.95E..Q6 9.56E-07 J.i<>E-07 SE...,4

• large LOCA IE Freq.

LPl-1H NOOE B TO CV242 5.00E-06 2.GBE-06 1.00E-06 PER YEAR LOSS HPULPI INJ SYS RWT-TNK-l.F-RWST 1.95E-02 FREQ 40 (r(T/2)"e) 1.95E-06 1.0SE-06 J.90E-07

-- LPl-11 V242 TO NODE E J.20E-06 1.JSE-06 1.DOE-06 PER YEAR LOSS LPI INJ SYS LPI-MDP-FS 2.24E-04 FREQ 40 (l"(T/2)"e) 1.43E-OB 6.0SE-09 4.4SE-09 LPl-1J NODE 1B TO VLV 251 PER YEAR NONE(<1") O.OOE+OO FREQ 40 (r(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO LPl-1K RCS CLJ TO CV 85 5.00E-06 2.45E-06 1.00E-06 PER YEAR LOCA & HPI/LPI 1 CLEO SYS+INIT 3.98E-OJ PROB re 1.99E-08 9.75E-09 J,98E-09 LPl-1L W5TO CV237 5.00E-06 2.4SE-06 1.00E-06 PER YEAR LOSS HPULPI INJ SYS RWT-TNK-LF-RWST 1.95E-02 FREQ 40 (r(T/2)"e) 1.95E-06 9.56E-07 J.90E-07 LPl-1M NODE C TO CV243 5.00E-06 2.BSE-06 1.00E-06 PER YEAR LOSS HPULPI INJ SYS RWT-TNK-l.F-RW'ST 1.95E-02 FREQ 40 (l"(T/2)"e) 1.95E-06 1.0SE-06 J.90E-07 LPl-1N V243 TO MOV1S90C J.40E-06 1.25E-06 1.00E-06 PER YEAR LOSS LPI INJ SYS LPI-MDP.fS 2.24E-04 FREQ 40 (l"(T/2)"e) 1.52E-08 5.&0E-09 4.48E..Q9 LPl-10 NODE 1C TO VLV 258 PER YEAR NONE (<1") O.OOE+OO FREQ 40 (r(T/2)"e) O.OOE+OO 0.00E+oo O.OOE+OO LPl-1P NODE 1 D TO VENT PER YEAR NONE(<1'1 O.OOE+OO FREQ 40 (r(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO LPl-1Q NODE 10 TO VLV 189 PER YEAR NONE (<1") 0.00E+OO FREQ 40 (r(T/2)"e) 0.00E+OO O.OOE+OO O.OOE+OO

• SUM 5.48E-05 2.65E-05 1.20E-05 SUM 1.30E-01 SUM 1.1BE-OS 5.96E-06 2.37E-06 AVERAGE 4.57E-06 2.21E-06 1.00E-06 AVERAGE 1.SJE-03 AVERAGE 9.84E-07 4.97E-07 1.97E-07 LPl-2 BETWEEN CIV & HOT LEG INJ LPl-2A RCS HLEG 1 TO CV91 2.00E-06 1.10E-06 J.SOE-07 PER YEAR LOCA & HLEG INJ SYS+INIT LPR-CCF-PG-SUMP 3.SBE-03 PROB re 7.96E..Q9 4.38E-09 1.39E-09 2.84E-07 LPl-2B V91 TO CV239 1.21E-06 5.62E-07 1.00E-07 PER YEAR LOSS HPULPI HLEG INJ SYS LPR-CCF-PG-SUMP 1.SSE-03 FREQ 40 (l"(T/2)"e) 3.75E-08 1.74E-08 J.1DE-09 LPl-2C V239 TO CV229 3.10E-06 1.14E-06 8.00E-07 PER YEAR LOSS HLEG INJ SYS LPR-CCF-PG-SUMP 1.55E-OJ FREQ 40 (l"(T/2) 0 e) 9.61E-0S J.SJE-08 2.48E-08 LPl-2D NODE 11 TO XV341 1.7DE-06 1.24E-06 5.00E-07 PER YEAR LOSS HLEG INJ SYS LPR-CCF-PG-SUMP 1.SSE-03 FREQ 40 (r(T/2)"e) 5.27E-08 3.84E-08 1.SSE-08 O.OOE+OO FREQ 40 (l"(T/2) e) 0 LPl-2E NODE 1H TO VLV 254 PER YEAR NONE(<1") O.OOE+OO O.OOE+OO O.OOE+OO LPl-2F RCS HLEG 2 TO cvaa 2.00E-06 1.10E-06 J.SOE-07 PER YEAR LOCA & HLEG INJ SYS+INIT LPR-CCF-PG-SUMP J.98E-03 PROB re 7.96E-09 4.JBE-09 1.39E-09 LPl-2.G vse TO CV238 1.21E-06 5.S2E-07 1.00E-07 PER YEAR LOSS HLEG INJ SYS LPR-CCF-PG-SUMP 1.55E-03 FREQ 40 (l"(T/2)"e) J.75E-08 1.74E-08 3.1DE-OS LPl-2H V238 TO CV228 J.10E-06 1.14E-06 8.00E-07 PER YEAR LOSS HLEG INJ SYS LPR-CCF-PG-SUMP 1.5SE-OJ FREQ 40 (r(T/2)"e) 9.61E-08 3.SJE-08 2.48E-08 LPl-21 NODE 1 K TO XVJJ9 1.70E-06 1.24E-06 5.00E-07 PER YEAR LOSS HLEG INJ SYS LPR-CCF-PG-SUMP 1.SSE-03 FREQ 40 (l"(T/2)"e) 5.27E-08 J.&tE-08 1.55E-08 LPl-2J NODE 1J TO VLV 252 PER YEAR NONE(<1'1 O.OOE+OO FREQ 40 (l"(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO LPl-2K NODE 1L TO VXVXXX PER YEAR NONE(<1") O.OOE+oo FREQ 40 (l"(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO LPl-2L RCS HLEG J TO CV94 2.00E-06 1.10E-06 J.SOE-07 PER YEAR LOCA & HLEG !NJ SYS+INIT LPR-CCF..PG-SUMP 3.98E-03 PROB re 7.96E-09 4.38E-09 1.39E-09 LPl-2.M V94 TO CV240 1.21E-06 5.62E.07 1.00E-07 PER YEAR LOSS HLEG INJ SYS LPR-CCF-PG-SUMP 1.55E-OJ FREQ 40 (r(T/2)"e) J.75E.0S 1.74E-08 3.10E-09 LPl-2N CV240 TO NODE G J.10E-06 1.14E-06 8.00E-07 PER YEAR LOSS HLEG INJ SYS LPR-CCF-PG-SUMP 1.SSE-03 FREQ 40 (r(T/2)"e) 9.61E.0S J.SJE-08 2.48E-08 LPl-20 NODE 1N TO VJ37 1.70E-06 1.24E-06 5.00E-07 PER YEAR NONE(<1") O.OOE+OO FREQ 40 (l"(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+oo LPl-2P NODE 1 M TO HCV11850E PER YEAR NONE(<1") O.OOE+oo FREQ 40 (l"(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO LPl-2.Q NODE I TO NODE H J.10E-06 1.14E-06 B.OOE-07 PER YEAR LOSS HLEG INJ SYS LPR-CCF-PG-SUMP 1.SSE-03 FREQ 40 (r(T/2)"e) 9.81E-08 J.SJE-08 2.48E-08 SUM 2.71E.05 1.JJE-05 8,0SE-06 SUM 2.59E-02 SUM 6.26E-07 2.154E-07 1.44E-07 AVERAGE 2.09E-06 1.02E-06 4.65E-07 AVERAGE 1.99E-OJ AVERAGE 4.82E-OB 2.18E.08 1.11E-08 LPl-3 LPI SOURCES SUPPLY LPI.JA MOV1860A TO SUMP 3.16E-07 PER YEAR LOSS SUMP RECIRC SYS LPR-CCF-PG-SUMP 1.SSE-03 FREQ 40 (l"(T/2)"e) 9.80E-09 6.BSE-07 LPl-3B MOV1860B TO SUMP J.16E-07 PER YEAR LOSS SUMP RECIRC SYS LPR-CCF-PG-SUMP 1.SSE-03 FREQ 40 (l"(T/2)"e) 9.80£-09 LPl-3C MOV1et12A TO XV15X 1.21E-06 2.11E.07 1.00E-08 PER YEAR LOSSRWST SYS RWT-TNK-LF-RWST 1.95E-02 FREQ 40 (l"(T/2)"e) 4.72E-07 B.2JE.0S J.90E-09 LPl-30 MOV1862B TO NODE U 1.21E-06 2.11E.07 1.00E-08 PER YEAR LOSSRWST SYS RWT-TNK-LF-RWST 1.95E-02 FREQ 40 (l"(T/2)"e) 4.72E.07 8.2JE-08 3.SOE-09 LPl-3E NODE V TO HPI ISO VLV 1.BOE-06 2.24E-07 1.00E-08 PER YEAR LOSSRWST SYS RWT-TNK-LF-RWST 1.95E-02 FREQ 40 (l"(T/2)"e) 7.02E-07 8.7.CE-08 J.90E-o9 LPl-3F XV15X TO RWST 1.BOE-06 2.24E-07 1.00E-08 PER YEAR LOSSRWST SYS RWT-TNK-LF-RWST 1.95E-02 FREQ 40 (r(T/2)"e) 7.02E-07 8.74E-08 J.9DE-09 LPI..JG RWST 1.00E-05 8.37E-07 1.00E-08 PER YEAR LOSSRWST SYS RWT-TNK-LF-RWST 1.95E-02 FREQ 40 (r(T/2)"e) J.90E-06 J.26E-07 3.90E-09 SUM 1.&0E-05 2.3.tE-09 5.00E-08 SUM 1.01E-01 SUM 8.25E-06 6,BSE-07 1.9SE-08 AVERAGE J.20E-06 3.34E-07 1.00E-08 AVERAGE 1.44E-02 AVERAGE 1.25E-06 9.79E-08 J.90E-09 LPl-4 PMP DISCH & CIV LPl-4A MOV1890C TO NODE F 2.00E-06 8.'59E-07 5.00E-08 PER YEAR LOSS LPI INJ SYS LPI-MDP-FS 2.24E-04 FREQ 40 (l"(T/2)"e) B.96E-09 J.OOE-09 2.24E-10

• .51E-08 LPl...,48 MOV18S4B TO 1884A 2.31E-06 1.00E-09 B.OOE-08 PER YEAR LOSS LPI INJ SYS LPI-MDP-FS 2.24E-04 FREQ 40 (r(T/2)"e) 1.0JE-08 4.48E-ct9 3.S8E-10 LPl...,CC NODE 1F TO RV1&15B PER YEAR NONE(<1") O.OOE+OO FREQ 40 (r(T/2)"e) O.OOE+OO O.OOE+oo O.OOE+OO LPl...,40 NODE 10 TO VLV 193 PER YEAR NONE(<1") O.OOE+OO FREQ 40 (r(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO LPl-4E MOV1890A TO NODE J 1.00E-05 1.52E-06 5.00E-07 PER YEAR LOSS LPI INJ SYS LPI-MDP-FS 2.24E..o.& FREQ 40 (l"(T/2)"e) 4.48E-08 6.S1E-09 2.24E-09 LPl...,4F MOV18MA TO cvsa J.40E-06 5.57E-07 1.00E-07 PER YEAR LOSS LPI INJ SYS LPI-MDP-fS 2.24E-04 FREQ 40 (r(T/2)"e) 1.52E-08 2.SOE-09 4.48E-10 LPl...,40 NODE K TO MOV1B63A 6.9JE-06 2.00E-06 1.00E-06 PER YEAR LOSS LPI INJ SYS LPI-MDP-FS 2.24E-04 FREQ 40 (l"(T/2)"e) 3.10E-08 8.96E-09 4.4SE-09 LPl-4H NODE 1U TO RV184SA PER YEAR NONE(<1") O.OOE+OO FREQ 40 (r(T12) 0 e) O.OOE+OO O.OOE+OO O.OOE+OO LPl...,41 NODE 1V TO VLV 191 PER YEAR NONE(<1'1 O.OOE+oo FREQ 40 (r(T/2)"e) O.OOE+OO O.OOE+OO 0.00E+OO LPl-4.J NODE L TOVLV19" PER YEAR NONE(<1") O.OOE+OO FREQ 40 (l"(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO LPl-4K NODE M TO VLV 195 PER YEAR NONE(<1'") O.OOE+OO FREQ 40 (r(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO LPl-4L NODE 1WTOVLV192 PER YEAR NONE (<1") O.OOE+OO FREQ 40 (l"(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO LPl-4M MOV1890B TO NODE N 1.00E-05 1.52E-06 5,00E-07 PER YEAR LOSS LPI INJ SYS LPI-MDP-fS 2.24E..Q.1 FREQ 40 (l"(T/2)"e) 4.48E-0S 8.81E-09 2.24E-09 LPl-4N MOV1864B TO CVSO 3.40E-06 5.57E-07 1.00E-07 PER YEAR LOSS LPI INJ SYS LPI-MDP..fS 2.24E-04 FREQ 40 (r(T/2)"e) 1.52E-08 2.50E-09 4.4SE-10 LPl-40 NODE OTO MOV1863B 6.9JE-06 2.00E-06 1.00E-06 PER YEAR LOSS LPI INJ SYS LPI-MDP-FS 2.24E..Q.1 FREQ 40 (r(T/2)"e) J.10E-08 8.98E-09 4.4SE-09 LPl...,4P NODE 1X TO CVSJ 1.10E-06 B.37E-07 2.00E-07 PER YEAR NONE2"' O.OOE+OO FREQ 40 (l"(T/2)"e) O.OOE+OO O.OOE+OO 0.00E+OO LPl...,4Q NODE 188 TO RV184SC PER YEAR NONE(<1'1 O.OOE+OO FREQ 40 (l"(T/2)"e) O.OOE+OO O.OOE+oo 0.00E+OO LPl-4R NODE 1Y TO VLV 187 PER YEAR NONE(<1") O.OOE+OO FREQ 40 (l"(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO LPI~ NODE 1Z TO VLV 197 PER YEAR NONE(<1'") O.OOE+OO FREQ 40 (l"(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO LPl...,4T NODE 1AA TO VLV 9']'. PER YEAR NONE(<1'1 O.OOE+OO FREQ 40 (l"(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO LPl-4U cvsa TO PUMP A 5.00E-06 1.10E-06 5.00E-08 PER YEAR LOSS LPI TRAIN A SYS LPI-MDP-FS-SIA 2.46E-05 FREQ 40 (r(T/2)"e) 2.46E-09 s.,1E-10 2.46E-11 LPl-4V CVSO TO PUMP B 5.00E-06 1.10E-06 5.00E-08 PER YEAR LOSS LPI TRAIN B SYS LPI-MOP-FS-SIA 2.olSE-05 FREQ 40 (r(T/2)"e) 2.46E-09 5.41E-10 2.46E-11 SUM 5.61E.05 1.29E-05 J.6JE-06 SUM 1.&1E~3 SUM 2.D6E-07 4.51E-09 1.SOE-08 AVERAGE 5.10E-06 1.17E-06 J.30E.07 AVERAGE 1.67E-04 AVERAGE 1.BeE-08 4.10E-09 1.J6E-09 LPI~ BETWEEN CNS LPl~A CV229 TO MOV1890A J.40E-06 9.15E-07 5.00E-07 PER YEAR LOSS LPI TRAIN A SYS LPI-MDP-fS-SIA 2.46E-05 FREQ 40 (l"(T/2)"e) 1.87E-09 4.SOE-10 2.46E-10 9.00E-10 LPl~B CV228 TO MOV1890B 3.40E-06 9.15E-07 5.00E-07 PER YEAR LOSS LPI TRAIN B SYS LPI-MDP-FS-SIA 2.46E-05 FREQ 40 (r(T/2)"e) 1.67E-09 4.SOE-10 2.46E-10 LPl~C NODE 1Q TO VLV 178 PER YEAR NONE(<1") O.OOE+OO FREQ 40 (l"(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO LPl~D NODE 1R TO VLV 190 PER YEAR NONE(<1") O.OOE+OO FREQ 40 (l"(T/2)"e) o.ooe+oo O.OOE+OO O.OOE+OO LPI-SE NODE 1S TO VLV 1n PER YEAR NONE(<1") O.OOE+OO FREQ 40 (r(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO LPl~F NODE 1T TO VLV 186 PER YEAR NONE(<1") O.OOE+OO FREQ 40 (l"(T/2)"e) O.OOE+OO O.OOE+OO O.OOE+OO SUM 6.BOE-06 1.D3E.o6 1.00E-06 SUM 4.92E-05 SUM J.35E-o9 9.00E-10 4.92E-10 AVERAGE 3.40E-06 9,15E-07 5.00E-07 AVERAGE 2.46E-05 AVERAGE 1.67E-09 4.soe.10 2.46E-10 LPl-6 LPI PUMP SUCTION LINE LPl-6A PUMP A TO XVS7 1.21E-06 1.00E-06 5.00E-08 PER YEAR LOSS LPI TRAIN A SYS LPI-MDP-FS-SIA 2.46E-05 FREQ 40 (l"(T/2)"e) 5.95E-10 4.92E-10 2.4&E-11 2.02E-07 LPl~B XV57 TO CV46A 2.00E-06 1.00E-06 5.00E-08 PER YEAR LOSS LPI TRAIN A SYS LPI-MDP-FS-SIA 2.46E-05 FREQ 40 (l"(T/2)"e) 9.ME-10 4.92E-10 2.46E-11 LPl~C NODE S TO CVS8 1.21E-06 8,69E-07 5.00E-08 PER YEAR LOSS LPI TRAIN A SYS LPI-MDP-FS-SIA 2.46E-05 FREQ 40 (r(T/2)"e) 5.95E-10 J.29E-10 2.46E-11 LPl-6D PUMP B TO XV48 1.21E-06 1.00E-06 5.00E-08 PER YEAR LOSS LPI TRAIN B SYS LPI-MDP-FS-SIA 2.46E-05 FREQ 40 (r(T/2)"e) 5.95E-10 4.92E-10 2.46E*11 LPl-6E XV48 TO CV46B 2.00E-06 1.00E-06 5.00E-08 PER YEAR LOSS LPI TRAIN B SYS LPI-MDP-FS-SIA 2.48E-05 FREQ 40 (r(T/2)"e) 9.UE-10 4.92E-10 2.46E-11 LPl-6F NODE T TO CV47 1.21E-OS 9.69E-07 5.00E-08 PER YEAR LOSS LPI TRAIN B SYS LPI-MDP-FS-SIA 2.46E-05 FREQ 40 (l"(T/2)"e) 5.95E-10 J.29E-10 2.46E-11 LPl-60 CV48A TO MOV1862A 1.21E-08 1.78E-07 2.00E-09 PER YEAR LOSS RWST SYS RWT-TNK-l.F-RWST 1.9SE-02 FREQ 40 (r(T/2)"e) 4.72E-07 6.94E-Oa 7.flOE-09 LPl-6H V56 TO MOV1860A 1.21E-06 1.78E-06 2.00E-09 PER YEAR LOSS SUMP RECIRC SYS LPR-CCF-PG-SUMP 1.SSE-03 FREQ 40 (r(T/2)"e) J.75E-09 5.52E-08 6.20E-10 LPl~I CV46B TO MOV1862B 1.21E-06 1.78E-07 2.00E-08 PER YEAR LOSSRWST SYS RWT-TNK-l.F-RWST 1.95E-02 FREQ 40 (r(T/2)"e) 4.72E-07 6.WE-08 7.SOE-09 LPl-6J V47 TO MOV1860B 1.21E-06 1.78E-07 2.00E-09 PER YEAR LOSS SUMP RECIRC SYS LPR.CCF-PG-SUMP 1.55E-OJ FREQ 40 (l"(T/2)"e) 3.75E-08 S.52E-ct9 I 6.20E-10 SUM 1.37E-05 7.65E-06 J,BOE-07 SUM 4.22E-02 SUM 1.02E-08 2.02E-07 1.70E-Ofl

AVERAGE 1.37E-06 7.65E-07 J.&OE-08 AVERAGE 4.22E-OJ AVERAGE 1.02E-07 2.02E-08 1.70E-09 I A.7 NUREG/CR-6181, Rev. 1 G/70310022(?) -

Appendix A .J!-

p A B C D E I F G H I J K L M N 0 Q R SURRY RCS I

ELEMENT ELEMENTS FAILURE PROBABILITY LINKED CDF PRESS BOUND SEGMENT ID DESCRIPTION ID DESCRIPTION Upper Median Lower UNITS CONSEQUENCE TYPE INITEVENT RAW UNITS EQUATION Upper CDF Lower COMMENTS RCS-1 LOOP STOP VLV TO RPV (CL) RCS1-A1 VLV 1591 TO PIPE WELD 27" 1.10E.Q6 1.00E.07 5.DOE.08 PER YR COLD LEG LRG LOCA (A) INIT A 3.9BE.03 PROB l"C 4.38E.09 3.9BE-10 1.99E-10 <- The RAW values were estimated as:

1.20E.09 RCS1-A2 27"" PIPE TO PIPE WELD "' INCLIN 1-A1 INCLIN 1-A1 INCL IN 1-A1 PER YR COLD LEG LRG LOCA (A) . LOCA CDF CONT / A RCS1-A3 27" PIPE TO ELBOW WELD"' INCLIN 1-A1 INCLIN 1-A1 INCLIN 1-A1 PER YR COLD LEG LRG LOCA (A) . . =1.99E.06/5E.04 =3.9BE.03 RCS1-A6 27" PIPE TO SAFE-1:ND WELD INCLIN 1-A1 INCLIN 1-A1 INCLIN 1-A1 PER YR COLD LEG LRG LOCA (A) -

RCS1-A7 6" SIS HIGH HEAD RC-17 INCLIN 1-A1 INCL IN 1-A1 INCLIN 1-A1 PER YR COLD LEG LRG LOCA (A) . .

RCS1-AB 2" LETDOWN CH-5 3.60E.09 PER YR COLD LEG SML LOCA (A) INIT S2 4.23E.04 PROB l"C 1.52E-12 SLOCA CDF CONT/ S2 RCS1-A9 12" ACCUM RC-22,Sl-45 INCLIN 1-A1 INCLIN 1-A1 INCLIN 1-A1 PER YR COLD LEG LRG LOCA (A) . =4.23E.07/1E.03 =4.23E.04 RCS1-81 VLV 1593 TO PIPE WELD 27"' 1.1DE.06 1.00E.07 5.00E.08 PER YR COLD LEG LRG LOCA (B) INIT A 3.98E.Q3 PROB re 4.38E.09 3.9BE-10 1.99E-10 RCS1-82 27"' PIPE TO PIPE WELD " INCLIN 1-81 INCLIN 1-81 INCLIN 1-81 PER YR COLD LEG LRG LOCA (B) . .

RCS1-83 27"' PIPE TO ELBOW WELD" INCLIN 1-81 INCLIN 1-81 INCLIN 1-81 PER YR COLD LEG LRG LOCA (BJ .

RCS1-86 27" PIPE TO SAFE-1:ND WELD INCLIN1-81 INCLIN 1-81 INCLIN 1-81 PER YR COLD LEG LRG LOCA (B) .

RCS1-87 6" SIS HIGH HEAD RC-19 INCLIN1-81 INCLIN 1-81 INCLIN 1-81 PER YR COLD LEG LRG LOCA (B) .

RCS1.SB 3" CHARGING LINE CH-1 2.5DE.09 PER YR COLD LEG MED LOCA (B) INIT S1 3.0BE.03 PROB re 7.7DE-12 MLOCA CDF CONT/ S1 RCS1-89 12"' ACCUM RC-23 INCLIN1-81 INCLIN 1-81 INCLIN 1-81 PER YR COLD LEG LRG LOCA (B) . . =3.0BE.Q6/1E.03 = 3.0BE.03 RCS1.C1 VLV 1595 TO PIPE WELD 2T' 1.10E.06 1.00E.07 5.00E.08 PER YR COLD LEG LRG LOCA (C) INIT A 3.98E.03 PROB l"C 4.38E.09 3.98E-10 1.99E-10 RCS1.C2 27"' PIPE TO PIPE WELD" INCLIN1.C1 INCLIN1.C1 INCLIN 1.C1 PER YR COLD LEG LRG LOCA (C) .

RCS1.C3 27" PIPE TO ELBOW WELD" INCLIN1.C1 INCLIN1.C1 INCLIN 1.C1 PER YR COLD LEG LRG LOCA (C) large, small, and medium LOCA RCS1.C6 27" PIPE TO SAFE-1:ND WELD INCLIN1.C1 INCLIN1.C1 INCLIN 1.C1 PER YR COLD LEG LRG LOCA (C) contributions were computed from RCS1.C7 6" SIS HIGH HEAD RC-20 INCLIN1.C1 INCLIN1.C1 INCLIN1.C1 PER YR COLD LEG LRG LOCA (C) - NUREG/CR-4550 page 4.11-4 RCS1.C9 12" ACCUM RC-24 INCLIN1.C1 INCLIN1.C1 INCLIN 1.C1 PER YR COLD LEG LRG LOCA* (C) . 5E-4 is A IE freq SUM 1.31E.OB 1.2DE.09 5.97E-10 1E-3 is the small and medium LOCA IE freq.

RCS-2 5.15E.OB PZR SPRAY LINE RCS2-A1 4" PZR SPRAY RC-14 4" PZR SPRAY RC-14 B.OOE.07 PER YR COLD U:G MED LOCA (A) INIT S1 3.0BE.03 PROB re re 2.46E.09 ~

~ --

&\.. ti"~-!!}-,~ ~ l'~

RCS2-A2 1.00E.05 5.93E.Q6 1.00E.06 PER YR COLD LEG MED LOCA (A) INIT S1 3.0BE.03 PROB 3.0BE.08 1.B3E.QB 3.0BE.09 RCS2-A3 4" PZR SPRAY RC-14 5.00E.06 B.22E.07 5.DOE.07 PER YR COLD LEG MED LOCA (A) INIT S1 3.DBE.03 PROB l"C 1.54E.08 2.53E.09 1.54E.09 RCS2.C1 4" PZR SPRAY RC-15 B.OOE.07 PER YR COLD LEG MED LOCA (C) INIT S1 3.0BE.03 PROB 1*c re 2.46E.09 1.0,\!P~[~ u t y RCS2.C2 4" PZR SPRAY RC-15 1.00E.05 5.0DE-06 1.00E.06 PER YR COLD LEG MED LOCA (C) INIT 51 3.DBE.03 PROB 3.0dE.08 1.54E.OB 3.0BE.09

~'"' ~-]

RCS2.C3 4" PZR SPRAY RC-15 1.00E.05 1.64E.Q6 7.70E.07 PER YR COLD LEG MED LOCA (C) INIT 51 3.0BE.03 PROB re 3.0BE.08 5.05E.09 2.37E.09 ~//:,.\ ft'il ii)

RCS2-C4 2" PZR AUX SPRAY 1.00E.05 1.00E.05 B.22E.07 PER YR COLD LEG SML LOCA INIT S2 4.23E.04 PROB re 4.23E.09 4.23E.09 3.48E-10 RCS2.CS 2" PZR AUX SPRAY 1.00E.05 1.64E.06 8.S7E.07 PER YR COLD LEG SML LOCA INIT S2 4.23E.Q4 PROB 1*c 4.23E.09 6.94E-10 3.75E-10

~ - .

RCS2.C6 1.5" SPRAY DRAIN RC-105 3.10E.06 1.00E-06 1.0DE.07 PER YR COLD LEG SML LOCA INIT 52 4.23E.04 PROB re 1.31E.09 4.23E-10 4.23E-11 ~U:.&(QI ffeWl:1m&JKi I,-

RCS2.C7 1.5"' RC-105 VLV 105 TO 157 NONE* UORM CLOSED VALVES O.OOE+OO f!,\_PJf~L71i' IC~

RCS2.CB 1.5"' RC-105 VLV 157 TO FLANGE NONE* NORM CLOSED VALVES . O.OOE+OO SUM 1.1BE.07 5.15E.QB 1.0BE.08 RCS-3 RPV TO LOOP STOP VLV (HL) RCS3-A1 RPV TO PIPE WELD 29" 1.00E.06 1.00E.06 6.00E.08 PER YR HOT L.E.G LRG LOCA (A) INIT A 3.9SE.03 PROB re 3.9BE.09 3.9SE.09 2.39E-10 7.16E-10 RCS3-A2 29" PIPE TO PIPE WELD INCLIN 3-A1 INCLIN 3-A1 INCLIN3-A1 PER YR HOT LEG LRG LOCA (A) .

RCS3-A3 29" PIPE TO VLV 1590 WELD INCLIN 3-A1 INCLIN 3-A1 INCLIN3-A1 PER YR HOT LEG LRG LOCA (A) - .

RCS3-A4 14"' RHR TAKEOFF RH-1 INCLIN3-A1 INCLIN 3-A1 INCLIN 3-A1 PER YR HOT LEG LRG LOCA (A) .

RCS3-A5 6" SIS LOW HEAD RC-16 INCLIN3-A1 INCLIN 3-A1 INCLIN 3-A1 PER YR HOT LlG LRG LOCA (A) . -

RCS3-A6 314" RC-47, RC.03 1.69E-10 PER YR HOT LEG SML LOCA (A) INIT S2 4.23E-04 PROB l"C 7.15E-14 RCS3-81 RPV TO PIPE WELD 29" 1.00E.06 1.00E.06 6.DOE.08 PER YR HOT LEG LRG LOCA (B) INIT A 3.9BE.03 PROB l"C 3.98E.09 3.9BE.09 2.39E-10 RCS3-82 29" PIPE TO PIPE WELD INCLIN 3-81 INCLIN 3-81 INCLIN 3-81 PER YR HOT LEG LRG LOCA (8) -

RCS3-83 29" PIPE TO VLV 1592 WELD INCLIN 3-81 INCLIN 3-81 INCLIN 3-81 PER YR HOT LEG LRG LOCA (B) -

RCS3-85 6" SIS LOW HEAD RC-18 INCL IN 3-81 INCLIN 3-81 INCLIN 3-81 PER YR HOT LEG LRG LOCA (B)

RCS3-86 3/4" RC-166, RC-48, RC-o4 1.69E-10 PER YR HOT LEG SML LOCA (8) INIT S2 4.23E.04 PROB l"C 7.15E-14 RCS3.C1 RPV TO PIPE WELD 29" 1.00E.06 1.00E-06 6.00E.08 PER YR HOT LEG LRG LOCA (C) INIT A 3.98E.03 PROB l"C 3.9SE.09 3.98E.09 2.39E-10 RCS3.C2 29" PIPE TO PIPE WELD INCLIN3.C1 INCLIN 3.C1 INCLIN 3.C1 PER YR HOT LEG LRG LOCA (C) . .

RCS3.C4 29" PIPE TO VLV 1594 WELD INCLIN3.C1 INCLIN 3.C1 INCLIN 3.C1 PER YR HOT LEG LRG LOCA (C) . .

RCS3.C5 6" SIS LOW HEAD RC-21 INCLIN 3.C1 INCLIN 3.C1 INCLIN 3.C1 PER YR HOT LEG LRG LOCA (C) .

RCS3.C6 3/4" RC-49, RC-65 1.69E-10 PER YR HOT LEG SML LOCA (C) INIT 52 4.23E.04 PROB re 7.15E-14 SUM 1.19E.OB 1.19E.QB 7.16E-10 RCS-4 PZR RELIF/SAFETY LINE RCS4-1 PZR TO SV 1551C 6" RC-37 3.81E.06 1.DOE.06 9.50E.07 PER YR PZRLRG LOCA INIT A 3.9BE.03 PROB l"C 1.52E.QB 3.98E.Q9 3.7SE.09 2.86E.0S RCS4-2 PZR TO SV 1551 B 6" RC.JS 1.00E.06 PER YR PZRLRG LOCA INIT A 3.9BE.03 PROB re 3.9SE.09 RCS4-3 PZR TO SV 1551A 6" RC-39 8.00E-06 1.00E.06 9.50E.07 PER YR PZRLRG LOCA INIT A 3.9BE.03 PROB re 3.1SE.08 3.9BE.09 3.78E.09 RCS4-4 PZR TO VLV 1535 4" RC-34 5.DOE.06 1.64E.Q6 7.7DE.07 PER YR PZR MEDLOCA INIT S1 3.0BE.03 PROB re 1.54E.0S 5,05E.Q9 2.37E.09 RCS4-5 VLV 1535 TO PORV 4"' RC-35 1.00E.05 1.00E-06 7.70E.07 PER YR PZR MED LOCA INIT 51 3.0BE.03 PROB l"C 3.0BE.08 3.0BE.09 2.37E.09 RCS4-6 PZR TO PORV 4"' RC-34 1.64E.06 1.DOE.06 1.00E.07 PER YR PZRMED LOCA INIT S1 3.0BE.03 PROB re 5.05E.Q9 3.0BE.09 3.0BE-10 RCS4-7 PZR TO VLV 1536 3" RC-61 5.00E.06 1.DOE-06 7.7DE.07 PER YR PZRMEDLOCA INIT S1 3.0BE.03 PROB 1*c 1.54E.08 3.0BE.09 2.37E.09 RCS4-B VLV 1536 TO PORV 3"' RC-61 B.OOE.06 7.7DE.07 1.SOE.07 PER YR PZRMEDLOCA INIT S1 3.0BE.03 PROB l"C 2.46E.QB 2.37E.09 4.62E-10 SUM 1.JBE.07 2.86E.08 1.54E.QB RCS-5 PZR SURGE LINE RCS5.C1 12"' PZRSURGE LINE RC-10 1.03E.07 PER YR HOT LEG LRG LOCA (C) INIT A 3.9SE.03 PROB l"C 4.1DE-10 6.38E.Q9 RCS5.C2 RC-10 (14"' PZR NOZZLE) 1.00E.06 5.00E.07 2.10E.07 PER YR HOT LEG LRG LOCA (C) INIT A 3.9BE.03 PROB l"C 3.98E.09 1.99E.09 B.36E-10 RCS5.C3 12"' PZR SURGE LINE RC-10 3.81E.06 1.DDE.06 5.00E.07 PER YR HOT LE<l LRG LOCA (CJ INIT A 3.9BE.03 PROB l"C 1.52E.08 3.9BE.09 1.99E.09 SUM 1.91E.0S 6.3BE.09 2.83E.09 A.9 NUREG/CR-6181, Rev. 1 C,103/ 0()22(!) -03 - . . ~

. A B C D E F G H I J K L M N o p Q R Appendix A SURRY RCS ELEMENT ELEMENTS FAILURE PROBABILITY LINKED CDF PRESS BOUND SEGMENT ID DESCRIPTION ID DESCRIPTION Upper Median LoYt"Br UNITS CONSEQUENCE TYPE INITEVENT RAW UNITS EQUATION Upper CDF Lower COMMENTS RCS-o SGTORCP RCS6-A1 SG A TO ELBOW WELD 31" 1.00E-06 2.00E-07 6.00E-08 PER YR COLD LEG LRG LOCA (A) INIT A 3.98E-03 PROB re 3.98E-09 7.96E-10 2.39E-10 2.84E-09 RCS6-A2 31" ELBOW TO PIPE WELD INCLIN6-A1 INCLIN 6-A1 INCLIN 6-A1 PER YR COLD LEG LRG LOCA (A) - -

RCS6-A3 31" PIPE TO ELBOW WELD INCLIN6-A1 INCLIN6-A1 INCLIN 6-A1 PER YR COLD LEG LRG LOCA (A) -

RCS6-A4 31" ELBOW TO PIPE WELD INCLIN 6-A1 INCLIN 6-A1 INCLIN 6-A1 PER YR COLD LEG LRG LOCA (A) - -

RCS6-A5 31" PIPE TO ELBOW INCLIN 6-A1 INCLIN 6-A1 INCLIN6-A1 PER YR COLD LEG LRG LOCA (A) - -

RCS6-A6 31" ELBOW TO RCP A WELD INCLIN 6-A1 INCLIN 6-A1 INCLIN6-A1 PER YR COLD LEG LRG LOCA (A) - -

RCS6-A7 WELD 18 LONGITUDINAL INCLIN6-A1 INCLIN6-A1 INCLIN 6-A1 PER YR COLD LEG LRG LOCA (A) - -

RCS6-A8 WELD 19 LONGITUDINAL INCLIN6-A1 INCLIN6-A1 INCLIN 6-A1 PER YR COLD LEG LRG LOCA (A) -

RCS6-A9 WELD 20 LONGITUDINAL INCLIN 6-A1 INCLIN 6-A1 INCLIN 6-A1 PER YR COLD lEG LRG LOCA (A) - -

RCS6-A10 WELD 21 LONGITUDINAL INCL IN6-A1 INCLIN6-A1 INCLIN 6-A1 PER YR COLD LEG LRG LOCA (A) -

RCS6-A11 3" RTD RETURN RC-131 4.00E-08 PER YR COLD 1!.EG MED LOCA (A) INIT 51 3.08E-03 PROB re 1.23E-10 RCS6-A12 2" FILL HEADER RC-198 6.80E-08 PER YR COLD LEG SML LOCA (A) INIT 52 4.23E-04 PROB re 2.88E-11 RCS6-81 SG B TO ELBOW WELD 31" 1.00E-06 2.00E-07 6.00E-08 PER YR COLD LEG LRG LOCA (B) INIT A 3.98E-03 PROB re 3.98E-09 7.96E-10 2.39E-10 RCS6-82 31" ELBOW TO PIPE WELD INCLIN 6-81 INCLIN 6-81 INCLIN 6-81 PER YR COLD LEG LRG LOCA (B) - -

RCS6-83 31" PIPE TO ELBOW WELD INCLIN 6-81 INCLIN 6-81 INCLIN 6-81 PER YR COLD LEG LRG LOCA (B) - -

RCS6-84 31" ELBOW TO PIPE WELD INCLIN 6-81 INCLIN 6-81 INCLIN 6-81 PER YR COLD LEG LR_G LOCA (B) - -

RCS6-85 31" PIPE TO ELBOW INCLIN 6-81 INCLIN 6-81 INCLIN 6-81 PER YR COLD LEG LRG LOCA (B) - -

RCS6-86 31" ELBOW TO RCP A WELD INCLIN 6-81 INCLIN 6-81 INCLIN 6-81 PER YR COLD LEG LRG LOCA (B) - -

RCS6-87 WELD 18 LONGITUDINAL INCLIN 6-81 INCL IN6-81 INCLIN6-81 PER YR COLD LEG LRG LOCA (B) -

RCS6-88 WELD 19 LONGITUDINAL INCLIN 6-81 INCL IN6-81 INCLINS-81 PER YR COLD LEG LRG LOCA (B) - -

RCS6-89 WELD 20 LONGITUDINAL INCLIN 6-81 INCL IN6-81 INCLIN6-81 PER YR COLD LEG LRG LOCA (B) - -

RCS6-810 WELD 21 LONGITUDINAL INCLIN 6-81 INCL INS-81 INCLINS-81 PER YR COLD LEG LRG LOCA (B) -

RCS6.S11 3" RTD RETURN RC-116 4.00E-08 PER YR COLD LEG MED LOCA (B) INIT 51 3.08E-03 PROB re 1.23E-10 RCS6-812 2" FILL HEADER RC-199 6.80E-08 PER YR COLD LEG SML LOCA (B) INIT 52 4.23E-04 PROB re 2.88E-11 RCS6-C1 SG C TO ELBOW WELD 31" 1.00E-06 2.00E-07 6.00E-08 PER YR COLD LEG LRG LOCA (C) INIT A 3.98E-03 PROB re 3.98E-09 7.96E-10 2.39E-10 RCS6-C2 31" ELBOW TO PIPE WELD INCL IN 6-C1 INCLIN6-C1 INCLIN6-C1 PER YR COLD LEG LRG LOCA (C) -

RCS6-C3 31" PIPE TO ELBOW WELD INCLIN 6-C1 INCL IN6-C1 INCLIN 6-C1 PER YR COLD LEG LRG LOCA (C) -

RCS6-C4 31" ELBOW TO PIPE WELD INCLIN 6-C1 INCLIN6-C1 INCLIN 6-C1 PER YR COLD LEG LRG LOCA (C) -

RCS6-C5 31" PIPE TO ELBOW INCLIN6-C1 INCLIN 6-C1 INCLIN 6-C1 PER YR COLD LEG LRG LOCA (C) -

RCS6-C6 31" ELBOW TO RCP C WELD INCLIN 6-C1 INCLIN6-C1 INCLIN 6-C1 PER YR COLD LEG LRG LOCA (C) - -

RCS6-C7 WELD 18 LONGITUDINAL INCLIN6-C1 INCLIN 6-C1 INCLIN 6-C1 PER YR COLD LEG LRG LOCA (C) - -

RCS6-C8 WELD 19 LONGITUDINAL INCL IN6-C1 INCLIN 6-C1 INCLIN 6-C1 PER YR COLD LEG LRG LOCA (C) - 8 P,,,1'1.

RCS6-C9 WELD 20 LONGITUDINAL INCL IN6-C1 INCLIN 6-C1 INCLIN 6-C1 PER YR COLD LEG LRG LOCA (C) - - I.~\ tf\\ij ~~ f,j ti "'~  ;]

r~

RCS6-C10 WELD 21 LONGITUDINAL INCL IN 6-C1 INCLIN 6-C1 INCLIN 6-C1 PER YR COLD LEG LRG LOCA (C) - - A ~°>:;'.I"""'"""*.. ~~""'

RCS6-C11 RCS6-C12 3" RTD RETURN RC-147 2" FILL HEADER RC-200 4.00E-08 6.80E-08 PER YR PER YR COLD LEG MED LOCA (C)

COLD LEG SML LOCA (C)

INIT INIT 51 52 3.08E-03 4.23E-04 PROB PROB re re 1.23E-10 2.88E-11 N'i1!,F ~~i,\ ~ u

~-~~.~

R~

SUM 1.19E-08 2.S4E-09 7.16E-10 VtP\a ~4J fl -:i RCS-7 1.69E-09 LOOP STOP VLV TO SG (HL) RCS7-A1 RCS7-A2 VLV 1590 TO PIPE WELD 29" 29" ELBOW TO SG A WELD B.OOE-07 INCLIN7-A1 1.41E-07 INCLIN7-A1 6.00E-08 INCLIN7-A1 PER YR PER YR HOT LEG LRG LOCA (A)

HOT LEG LRG LOCA (A)

INIT A

3.98E-03 PROB 1*c 3.18E-09 5.61E-10 2.39E-10

~*

• ~ ;:"'4JJ n

b"-.l 'i!GJullGlli)S ,

RCS7-A3 2" DRAIN HEADER RC-53 1.50E-09 PER YR HOT LEG SML LOCA (A) INIT 52 4.23E-04 PROB re 6.35E-13 t4~11ii:Mr CiE RCS7-A4 8" LOOP BYPASS RC-11 INCL IN7-A1 INCL IN 7-A1 INCL IN 7-A1 PER YR HOT LEG LRG LOCA (A) - -

RCS7-A5 2" RC-45 3.60E-09 PER YR HOT LEG SML LOCA (A) INIT 52 4.23E-04 PROB re 1.52E-12 RCS7-81 VLV 1592 TO PIPE WELD 29" 8.00E-07 1.41E-07 6.00E-08 PER YR HOT LEG LRG LOCA (B) INIT A 3.98E-03 PROB re 3.18E-09 5.61E-10 2.39E-10 RCS7-82 29" ELBOW TO SG B WELD INCL IN7-81 INCLIN 7-81 INCLIN 7-81 PER YR HOT LEG LRG LOCA (B) -

RCS7-83 2" DRAIN HEADER RC-57 1.50E-09 PER YR HOT LEG SML LOCA (B) INIT 52 4.23E-04 PROB re 6.35E-13 RCS7-84 8" LOOP BYPASS RC-12 INCL IN7-81 INCLIN7-81 INCLIN 7-81 PER YR HOT LEG LRG LOCA (B) -

RCS7-C1 VLV 1594 TO PIPE WELD 29" 8.00E-07 1.41E-07 6.00E-08 PER YR HOT LEG LRG LOCA (C) INIT A 3.9BE-03 PROB re 3.18E-09 5.61E-10 2.39E-1D RCS7-C2 29" ELBOW TO SG C WELD INCL IN 7-C1 INCL IN7-C1 INCLIN7-C1 PER YR HOT LEG LRG LOCA (C) -

RCS7-C3 2" DRAIN HEADER RC-SB 1.5DE-09 PER YR HOT LEG SML LOCA (C) INIT S2 4.23E-04 PROB re 6.35E-13 RCS7-C4 8" LOOP BYPASS RC-13 INCLIN7-C1 INCLIN7-C1 INCLIN7-C1 PER YR HOT LF.G LRG LOCA (C) -

RCS7-C5 2" RC-44 3.60E-09 PER YR HOT LEG SML LOCA (C) INIT 52 4.23E-04 PROB re 1.52E-12 SUM 9.55E-09 1.69E-09 7.16E-10 RCS.a RCP TO LOOP STOP VLV (CL) RCS8-A1 RCP A TO PIPE WELD 27" 5.DDE-07 7.75E-08 2.DDE-08 PER YR COLD LEG LRG LOCA (A) INIT A 3.98E-03 PROB re 1.99E-09 3.08E-10 7.96E-11 9.31E-10 RCS8-A2 27" PIPE TO VLV 1591 WELD INCLIN8-A1 INCLIN8-A1 INCLIN 8-A1 PER YR COLD LEG LRG LOCA (A) - -

RCS8-A3 1.5" RTD TAKE OFF RC-125 4.DDE-09 PER YR COLD LEG SML LOCA (A) INIT S2 4.23E-04 PROB re 1.69E-12 RCS8-A4 SEAL INJECT TO RCP A 2.11E-10 PER YR POTEN. SEAL LOCA INIT 52 4.23E-04 PROB re 8.93E-14 RCS8-81 RCP B TO PIPE WELD 27" 5.00E-07 7.75E-08 2.00E-08 PER YR COLD LEG LRG LOCA (B) INIT A 3.98E-03 PROB re 1.99E-09 3.08E-10 7.96E-11 RCS8-82 27" PIPE TO VLV 1593 WELD INCL IN 8-81 INCLIN 8-81 INCLIN 8-81 PER YR COLD LEG LRG LOCA (B) - -

RCS8-83 1.5" RTD TAKE OFF RC-oD 4.00E-09 PER YR COLD LEG SML LOCA (B) INIT S2 4.23E-04 PROB re 1.69E-12 RCS8-84 SEAL INJECT TO RCP B 2.11E-10 PER YR POTEN. SEAL LOCA INIT S2 4.23E-04 PROB 1*c 8.93E-14 RCS8-C1 RCP C TO PIPE WELD 27" 5.DOE-07 7.75E-08 2.00E-08 PER YR COLD LEG LRG LOCA (C) INIT A 3.98E-03 PROB 1*c 1.99E-09 3.0BE-10 7.96E-11 RCS8-C2 27" PIPE TO VLV 1595 WELD INCLIN8-C1 INCLIN8-C1 INCLIN 8-C1 PER YR COLD LEG LRG LOCA (C) -

RCS8-C3 1.5" RTD TAKE OFF RC-141 4.00E-09 PER YR COLD LEG SML LOCA (C) I.NIT 52 4.23E-04 PROB re 1.69E-12 RCS8-C4 SEAL INJECT TO RCP C 2.11E-1D PER YR POTEN. SEAL LOCA INIT 52 4.23E-04 PROB 1*c 8.93E-14 SUM 5.97E-09 9.31E-1D 2.39E-10 NUREG/CR-6181, Rev. 1

r**

J Appendix B Review of the Risk Importance Approaches Which have been Developed by the Pacific Northwest National Laboratory

AppendixB REVIEW OF THE RISK ThlPORT ANCE APPROACHES WHICH HAVE BEEN DEVELOPED BY PACIFIC NORTHWEST NATIONAL LABORATORY W. E. Vesely November 17, 1995

SUMMARY

On November 8-10, 1995 I traveled to Pacific Northwest National Laboratory (PNNL)* to review the risk importance *prioritization approaches which have been developed by PNNL for Inservice Inspection (ISI) applications. Before the meeting at PNNL, I spent one day reviewing NUREG/CR-6151 (1) and NUREG/CR-6181 (2) which describe the risk importance methodology originally applied by PNNL. At the November 9, 1995 meeting at PNNL, I also reviewed the extended risk importance methodology which has recently been developed by PNNL to respond to the reviews and comments on NUREG/CR-6151 and NUREG/CR-6181. At the full day meeting on November 9, 1995, Truong Vo, Bryan Gore, and Hahn Phan of PNNL went

,... over additional details of PNNL's risk importance approaches which they have developed and have recently extended.

I was interested in carrying out this review because I was the originator of the risk importance methodology (3, 4, 5) which is being applied and being extended by PNNL. I was also interested in PNNL's risk importance methocl,ology because of its potential role in complementing the draft risk importance guidelines which I have recently helped to develop for the Office of Nuclear Reactor Regulation (NRR). Fmally, since I am an advisor to the AS1\1E on risk importance methods, I wanted to review PNNL's methodology as a basis for AS1\1E applications.

As a summary of my review, I found that the PNNL methodology described in NUREG/CR-6151 and NUREG/CR-6181, which I will call the 6151/6181 methodology for short, is a valid methodology. However, the application of the 6151/6181 methodology requires that the PRA. satisfy certain constraints. The PNNL staff are aware of these constraints, but these constraints are not as clearly spelled out in the NUREG/CRs as they could be.

• Pacific Northwest National Laboratory is the recently expanded name for Pacific Northwest Laboratory in recognition of the Laboratory being fonnally designated a National Laboratory.

B.l NUREG/CR-6181, Rev. 1

'\

L Appendix B To apply the 6151/6181 methodology, the PRA has to be structured so that system importances are obtainable. If a system has different failure modes in the PRA, then the system importances for the different failure modes need to be probabilistically weighted. Alternatively, the different system importances can be bounded by the maximum system importance corresponding to a given failure mode.

If the component appears in different systems then the systems should not interact and should not appear in the same minimal cutset. When the systems do not interact then the system importances are additive as modeled in the 6151/6181 methodology. If the systems do interact, e.g. can provide the same* function, then the user needs to treat the redundant systems as a common system, i.e. must "AND" the system failures. Alternatively, the user can check if one system is a dominant contributor and use this system as the system containing the component The 6151/6181 methodology can thus be difficult to apply with current PRAs since the standard PRA output consists of component level information (component level minimal cutsets).

System level information and system importances are not directly produced as part of the outputs.

If the PRA output is not processed and restructured to satisfy the above constraints then erroneous results can be obtained from the 6151/6181 methodology. This is not a problem with the methodology per se but with the application of the methodology.

The extended risk importance methodology which PNNL has recently developed uses component level information directly and does not have the constraints of the 6151/6181 methodology. Component prioritizations are not defined in terms of system importances but in terms of their direct contribution to core damage frequency or to another risk measure of interest.

The component level minimal cutsets can thus be used directly, which incorporate the different possible system failure modes and system interactions. The appropriate component level failure probabilities need to be used in the formulas, however this is required for all PRA methods.

Further details of my review of the 6151/6181 methodology and PNNL's extended methodology are described in the following paragraphs.

NUREG/CR-6181, Rev. 1 B.2

Appendix B l

RISK IMPORTANCE METHODOLOGY IN NUREG/CR-6151 AND NUREG/CR-6181 In NUREG/CR-6151 and NUREG/CR-6181 the importance Iw of a given component, such as a pipe segment, in a given system is defined as (1) where IB is the importance of the system and Pr is the probability of failure of the component.

The system *importance IB is defined to be the increase in core damage frequency when the system is failed, which is more formally called the Birnbaum importance. The importances Iw are used to initially identify the potentially risk important components and systems for which more detailed risk importance evaluations are then carried out.

The above formula is a conservative screening formula, as the NUREG/CRs state, which assumes that the component failure will cause system failure, i.e. that the component failure is a single failure of the system. For certain pipe segments, e.g. a single inlet supply line, this can be true. However, for other components which require additional component failures to fail the system, the importance calculation given by Equation (1) will overstate the true component importance. However, this formula is only used to screen potentially important components for more detailed analysis. Hence, the formula is a valid screening equation.

The problem with applying the above equation is that PRAs do not generally provide the system importances IB. Furthermore, the system importances cannot be directly obtained from the component level information, i.e. component level minimal cutsets*, which do not give system contributions to core damage frequency but only the individual component contributions. The user must separate out these minimal cutsets which contain failures of components in the given system and then fail the appropriate components which cause the system failure. The minimal cutsets must then be requantified with these components set to a failed condition after eliminating logical redundancies in the minimal cutsets.

The above tasks which the user must carry out are not simple or direct. Furthermore, if different system failure modes are modeled in the PRA then the user must separate the minimal cutsets according to the different system failure modes. The highest system importance for the different system failure modes can then be used as the bounding system importance. If the

• A minimal cutset is a smallest combination of component failures resulting in core damage frequency.

B.3 NUREG/CR-6181, Rev. 1

L AppendixB component appears in multiple systems, then the above process must be repeated for the different systems, and the highest system importance across the different systems can be used as the bounding system importance.

The detailed risk importance formula to be used after components are screened is given in NUREG/CR-6181 as Pcm =Pf*LPcm/s; *PS; /Pf*Ri (2) i where the probability of core melt (core damage) resulting from (3) component failure Pr = the probability of component failure (4)

P.emfs.1 -- the"conditional probability of core melt o*

oiven system failure (5)

Ps. / Pr 1

= the conditional probability of system failure given component (6) failure

~ = the probability that the operator fails to recover given the system (7) failure Equation (2) gives the component failure contribution to core melt frequency in terms of the component failure contribution to system failure and the system failure contribution to the core melt frequency. When the conditional probabilities are taken to be the increases in probabilities due to the respective failures then the above formula is the standard formula for the contribution of the component failure to the core melt frequency. This can be seen from a simple example.

Let the core melt frequency PCMF be given in terms of the system failure probabilities as (8)

,)

NUREG/CR-6181, Rev. 1 B.4

AppendixB where A is the. initiating event frequency and Ps; are the system failure probabilities. We only consider one initiating event but the same argument would apply to different initiating events.

Assume the particular component to be prioritized is in system s 1. Call this component c 1.

Let the system failure probability Ps1 in terms of the component failure probabilities Pc; be (9) where ~ and c 3 are other *components in the system. The failure probabilities are assumed to include the nonrecovery probabilities for not restoring the system failure.

The conditional probabilities required by Equation (2) are obtained by setting the respective contributor probability to 1. The contributions containing the particular system or component are then retained to give the increase in the probability: Thus (10)

(11)

Then, using Equation (2) we have (12)

(13) which is the contribution to the core melt frequency from those minimal cutsets containing c 1*

The standard PRA outputs would also expand P52 in terms of its component failure probabilities but the same numerical result would be obtained.

If the. total conditional probabilities are used without isolating the contributions (without subtracting the probability with the contributor set to zero) then the risk importance obtained

• Note this is the same as subtracting the core melt or system failure probability with the contributor probability set to zero as described in Reference 3.

B.5 NUREG/CR-6181, Rev. 1

"\

i.

AppendixB (Pen) will be conservative. Titis conservatism will generally be small for the risk imponant contributors.

The problem with Equation (2) which is given by NUREG/CR-6181 is again its difficulty for application using current PRAs. Current PRAs do not express the core melt frequency (core damage frequency) in terms of system failure probabilities as in Equation (8) but only in terms of component failure probabilities. To obtain the system importances Pen/sl the component level minimal cutsets need to be sorted to identify those minimal cutsets containing components in the given system. If the system has different failure modes then Pen/s* needs to be determined for each system failure mode.

Equation (2) also treats different system contributions which contain the same component as being additive since the sum is over the different systems si. If the different systems interact then the systems which are redundant need to be treated as one system. In our example this means that if component c 1 appears in both system s 1 and system 52 they need to be treated as one redundant system and Psls 2 being used as its failure probability. Of course, the appropriate component failure probabilities must also be used in the formula. which are component unavailabilities for safety standby components. Thus because system importances and system contributions are not provided in current PRAs, application of Equation (2) is not necessarily simple or direct.

PNNL 'S EXTENDED RISK IMPORTANCE METHODOLOGY PNNL'S extended risk importance methodology calculates the component risk importance, e.g. the component contribution to core melt frequency, directly. System contributions and system importances are not utilized. If Pen is the contribution of the component failure to core melt frequency as in Equation (2) then Pen is calculated as Pan =Pante* Pr (14) where Pcm/c = the conditional probability of core melt given the component (15) failure NUREG/CR-6181, Rev. I B.6 *

• 1 AppendixB the probability of component failure. (16)

The nonrecovery probability for the component failure is incorporated in the conditional probability of core melt P cm/c*

Equation (14) uses the component level minimal cutsets directly in determining Pcm/c and no system importances are required. The equation thus uses standard methodology. If P cm/c is interpreted to be the increase in core melt frequency from the component failure then Pcm is the sum of minimal cutset contributions containing the component failure.

The component importance Pcm is calculated using Equation (14) since it allows a surrogate component to be failed for the given component when the given component, e.g. a pipe segment, is not explicitly modeled in the PRA. A failure of a surrogate component in the same train or line as the given component produces the same conditional core melt probability P cmJc*

The appropriate component failure probability Pr, e.g. a pipe segment failure probability, can then be used to multiply P cm/c to give the minimal cutset contributions adjusted for the particular component failure probability. Equation (14) can also be appropriately applied to give the importances of components whose failure causes an initiating event as well as causing a train or

• !"", line to be unavailable .

,, B.7 NUREG/CR-6181, Rev. 1

r AppendixB REFERENCES

1. T;V. Vo, B.W. Smith, F.A. Simonen, B.F. Gore, "Feasibility of Developing Risk-Based Rankings of Pressure Boundary Systems for Inservice Inspection", NUREG/CR-6151, August 1994.

2. T. Vo, B. Gore, F. Simonen, S. Doctor, "A Pilot Application of Risk-Based Methods to Establish Inservice Inspection Priorities for Nuclear Components at Surry Unit 1 Nuclear Power Station", NUREG/CR-6181, August 1994.

3. W.E. Vesely and T.C. Davis, "Measures of Risk Importance and Their Application",

NUREG/CR-3385, July 1983.

4. W.E. Vesely, T.C. Davis, N. Saltos, "Measures of the Risk Impacts of Testing and Maintenance Activities", NUREG/CR-3541, November 1983.

5. W.E. Vesely and T.C. Davis, "Evaluations and Utilizations of Risk Importances",

NUREG/CR-4377, August 1985.

NUREG/CR-6181, Rev. 1 B.8 *

• ~ 1' NRC 1FClRM 335 U.S. NUCLEAR REGULATORY COMMISSION 1. REPORT NUMBER

,,12-891 (AaiQn<> o;.,;,;an. Off;c. Ot" R.,;on. V.S. N -

• Rfl9Ulatorv Comrn-. - m.Uing Mklrru: if conrr<<rar. proviM n--mailinf - a . I Pacific Northwest National Laboratory Richland, WA 99352

9. SPONSOR ING ORGANIZATION - NAME ANO ADO RESS (If NRC. ~I# -:S-. a*-*:* if cont,xrar. _..,. NRC OiYirion. Offa or Rt!9ion. V.S. N-.,. Rtl'i/Ul*torv Cotnmi<>ian,

.,,., ,.,.u;ng-,na,J Division of Engineering Technology Office of Nuclear Regulatory Research U.S. Nuclear Regulatory Commission Washington, DC 20555-0001

10. SUPPLEMENTARY NOTES

\l'Cl. Muscara, NRC Project Manager As part of the Nondestructive Evaluation Reliability Program sponsored by the U.S.

Nuclear Regulatory Commission, the Pacific Northwest National Laboratory has developed risk-informed approaches for inservice inspection plans of nuclear power plants. This method uses probabilistic risk assessment (PRA) results to identify and prioritize the most risk-important components for inspection. The Surry NuGlear Power Station Unit 1 was selected for pilot application of this methodology. This report, which incorporates more recent plant-specific information and improved risk-informed methodology and tools, ii Revision 1 of the earlier report (NUREG/CR-6181). The methodology discussed in the original report is no longer current and a preferred methodology is presented in this Revision. This report, NUREG/CR-6181, Rev. 1, therefore supersedes the earlier NUREG/CR-6181 published in August 1994. The specific systems addressed in this report are the auxiliary feedwater-, the low-pressure injection, and the reactor coolant systems. The results* provide a risk-informed ranking of components within these systems.

12. KEY WOROS/OESCR!PTORS (Li.r-Ot"ph,.... tt>*rw,11..;.,,.,,.*rrtrtminlat:*ringrh.,.,r,on.J 13. AVAILABII.ITY STATEMENT Unlimited nondestructive evaluation, probabilistic risk assessment, ASME 1*. SECURITY CI.ASSIFICA TION Code, inservice inspection~ welds, piping systems, Inspection (Thirl'-1 Impor,tance, pressure boundary systems, risk-based, Surry-1, Unclassified risk~informed, risk achievement worth (Thi,R.,,,,rt/

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