L-2002-142, Inservice Inspection Program Second Ten-Year Interval Relief Request 29 Risk-Informed Inservice Inspection Program
| ML022070024 | |
| Person / Time | |
|---|---|
| Site: | Saint Lucie  |
| Issue date: | 07/23/2002 |
| From: | Jernigan D Florida Power & Light Co |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| L-2002-142 | |
| Download: ML022070024 (19) | |
Text
Florida Power & Light Company, 6501 South Ocean Drive, Jensen Beach, FL 34957 July 23, 2002 FPL L-2002-142 10 CFR 50.55a U. S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555 Re: St. Lucie Unit 2 Docket No. 50-389 Inservice Inspection Program Second Ten-Year Interval Relief Request 29 Risk-Informed Inservice Inspection Program Pursuant to 10 CFR 50.55a (a)(3)(i), Florida Power and Light Company (FPL) requests approval of Relief Request 29 for the second ten-year inservice inspection interval. The Inservice Inspection (ISI) Program currently requires inspections on piping in accordance with the requirements of the ASME Boiler and Pressure Vessel Code Section XI, 1989 Edition as required by 10CFR50.55a. St. Lucie Unit 2 is currently in the third period of the second inspection interval as defined by the ASME Section XI Code for Program B.
The objective of this submittal is to request a change to the ISI Program plan for Class 1 piping only, through the use of a Risk-Informed Inservice Inspection (RI-ISI) Program.
The risk-informed process used in this submittal is described in Westinghouse Owners Group WCAP-14572, Revision 1-NP-A, Westinghouse Owners Group Application of Risk-Informed Methods to Piping Inservice Inspection Topical Report. As a risk informed application, this submittal meets the intent and principles of Regulatory Guide (RG) 1.174, An Approach for Using Probabilistic Risk Assessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis, and RG 1.178, An Approach for Plant-Specific Risk-Informed Decision Making: Inservice Inspection of Piping. In accordance with 10 CFR 50.55a (a)(3)(i), FPL has determined that the proposed alternatives would provide an acceptable level of quality and safety.
FPL requests approval of the enclosed relief request by January 31, 2003 to support its use during the spring 2003 refueling outage (SL2-14). If you have any questions or require additional information, please contact George Madden at 772-467-7155.
Very;lyy yours,
/
Donald - nigan Vice President St. Lucie Plant DEJ/GRM Enclosure an FPL Group company
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 1 St. Lucie Unit 2 SECOND INSPECTION INTERVAL RELIEF REQUEST NUMBER 29 A. COMPONENT IDENTIFICATION:
Class: 1 Pressure Retaining Similar and Dissimilar Metal Piping Welds B. EXAMINATION REQUIREMENT:
Rules for Inservice Inspection of Nuclear Power Plant Components,Section XI, 1989 Edition Exam Item No. Examination Description Cat.
B5.40 Pressurizer- NPS 4 or larger, Nozzle-to-Safe End Butt Welds B5.50 Pressurizer- Less than NPS 4, Nozzle-to-Safe End Butt Welds B-F B5.130 Piping- NPS 4 or Larger, Dissimilar Metal Butt Welds B5.140 Piping- Less than NPS 4, Dissimilar Metal Butt Welds B9.1 1 Piping- NPS 4 or Larger, Circumferential Welds B9.12 Piping- NPS 4 or Larger, Longitudinal Welds B9.21 Piping- Less than NPS 4, Circumferential Welds B-J B9.22 Piping- Less than NPS 4, Longitudinal Welds B9.31 Piping- Branch Pipe Connection Welds, NPS 4 or Larger B9.32 Piping- Branch Pipe Connection Welds, Less than NPS 4 B9.40 Piping- Socket Welds C. RELIEF REQUESTED:
Pursuant to 10 CFR 50.55a (a)(3)(i), FPL requests to revise the St. Lucie Unit 2 ISI Program for Class 1 piping only, through the use of the Risk-Informed Inservice Inspection Program (RI-ISI),
Attachment 1, as an alternative to the current requirements of Class 1 examination Categories B F and B-J as specified in Table IWB-2500-1 of the 1989 Edition of ASME Section XI.
The proposed revision to the current ISI Program, for Class 1 piping only, is based on the risk informed process described in Westinghouse Owners Group WCAP-14572, Revision 1-NP-A, Westinghouse Owners Group Application of Risk-Informed Methods to Piping Inservice Inspection Topical Report.
D. BASIS FOR RELIEF:
Inservice inspections (ISI) are currently performed on piping to the requirements of the ASME Boiler and Pressure Vessel Code Section XI, 1989 Edition as required by 10CFR50.55a. St.
Lucie Unit 2 is currently in the third inspection period of the second interval as defined by the Code for Program B. The current inspection interval for St. Lucie Unit 2 began August 8, 1993
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 2 St. Lucie Unit 2 SECOND INSPECTION INTERVAL RELIEF REQUEST NUMBER 29 and ends August 7, 2003. The current inspection period for St. Lucie Unit 2 began August 8, 2000.
The objective of this submittal is to request a change to the ISI Program plan for Class 1 piping only through the use of a Risk-Informed Inservice Inspection (RI-ISI) Program. The risk-informed process used in this submittal is described in Westinghouse Owners Group WCAP-14572, Revision 1-NP-A, Westinghouse Owners Group Application of Risk-Informed Methods to Piping Inservice Inspection Topical Report, (referred to as 'WCAP-14572, A-version' for the remainder of this document).
St. Lucie Unit 2 is currently in the third period of the second ten-year interval and has completed 90% of the B-F welds and 71% of the B-J welds scheduled under Program B. The population of B-F and B-J welds that will be included under the risk informed program will be subdivided into three periods, with the third period examinations of the new program scheduled and completed to close out the current second ten year interval. The B-F and B-J welds scheduled for examination during the third period include welds that have been selected under the risk informed process and were also originally slated for examination under the current Program B schedule. These welds have not been examined during the first and second periods of the second ten-year interval. The maximum percentage that will be credited for the risk informed program during the third period will be 34% of the B-F and B-J risk informed population.
The attached Risk-Informed Inservice Inspection Program supports the conclusion that the proposed alternative provides an acceptable level of quality and safety.
Additionally, this submittal meets the intent and principles of Regulatory Guides 1.174 and 1.178.
E. ALTERNATIVE:
ASME Section XI Class 1 Categories B-F and B-J currently contain the requirements for examining (via non-destructive examination (NDE)) Class 1 piping components. This current program submittal is limited to ASME Class 1 piping, including piping currently exempt from requirements. The alternative RI-ISI Program for piping is described in WCAP-14572, Revision 1 NP-A. FPL will substitute the Class 1 RI-ISI for the current examination program on piping.
Other non-related portions of the ASME Section XI Code will be unaffected.
WCAP-14572, Revision 1-NP-A, provides the requirements defining the relationship between the risk-informed examination program and the remaining unaffected portions of ASME Section Xl.
F. IMPLEMENTATION SCHEDULE:
This Request for the Alternative RI-ISI is applicable to the Second Inservice Inspection Interval.
FPL will update and resubmit the alternative in conjunction with the update to the existing ISI Program at the expiration of the current ten-year interval and during periodic ten-year updates.
G. ATTACHMENTS TO THE RELIEF:
Attachment 1- Florida Power and Light Company, St. Lucie Unit 2, Risk-Informed Inservice Inspection Piping Program Submittal Using the Westinghouse Owners Group (WOG)
Methodology (WCAP-14572, Revision 1-NP-A, February 1999)
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 3 Attachment 1 St. Lucie Unit 2 Relief Request 29 Florida Power and Light Company St. Lucie Unit 2 Risk-Informed Inservice Inspection Piping Program Submittal Using the Westinghouse Owners Group (WOG) Methodology (WCAP-14572, Revision 1-NP-A, February 1999)
June 2002
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 4 Attachment 1 St. Lucie Unit 2 Relief Request 29 RISK-INFORMED INSERVICE INSPECTION PROGRAM PLAN Table of Contents
- 2. Proposed Alternative to Current Inservice Inspection Programs 2.1 ASME Section XI 2.2 Augmented Programs
- 3. Risk-Informed ISI Process 3.1 Scope of Program 3.2 Segment Definitions 3.3 Consequence Evaluation 3.4 Failure Assessment 3.5 Risk Evaluation 3.6 Expert Panel Categorization 3.7 Identification of High Safety Significant Segments 3.8 Structural Element and NDE Selection 3.9 Program Relief Requests 3.10 Change in Risk
- 4. Implementation and Monitoring Program
- 5. Proposed ISI Program Plan Change
- 6. Summary of Results and Conclusions
- 7. References/Documentation
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 5 Attachment 1 St. Lucie Unit 2 Relief Request 29
- 1. INTRODUCTION/RELATION TO NRC REGULATORY GUIDE RG-1.174 1.1 Introduction Inservice inspections (ISI) are currently performed on piping to the requirements of the ASME Boiler and Pressure Vessel Code Section XI, 1989 Edition as required by 10CFR50.55a. St. Lucie Unit 2 is currently in the second inspection interval as defined by the Code for Program B.
The objective of this submittal is to request a change to the ISI Program plan for Class 1 piping only through the use of a Risk-Informed Inservice Inspection (RI-ISI) Program. The risk-informed process used in this submittal is described in Westinghouse Owners Group WCAP-14572, Revision 1-NP-A, Westinghouse Owners Group Application of Risk-Informed Methods to Piping Inservice Inspection Topical Report, (referred to as 'WCAP-14572, A-version' for the remainder of this document).
As a risk-informed application, this submittal meets the intent and principles of Regulatory Guides 1.174 and 1.178. Further information is provided in Section 3.10 relative to defense-in-depth.
1.2 PRA Quality The St. Lucie Unit 2 Probabilistic Safety Assessment (PSA) baseline model was used to evaluate the consequences of pipe ruptures. The base core damage frequency (CDF) and the base large early release frequency (LERF) are 1.25E-05 and 6.OOE-06, respectively.
The baseline model used for this RI-ISI evaluation was generated using the IPE model developed in response to Generic Letter (GL) 88-20, Individual Plant Examination for Severe Accident Vulnerabilities, and associated supplements. The original development work was classified and performed as 'Quality Related' under the FPL 10 CFR 50 Appendix B Quality Assurance Program. The revision and applications of the PRA models and associated databases continue to be handled as quality-related.
Administrative controls include written procedures, independent review of all model changes, data updates and risk assessments performed using PSA methods and models. Risk assessments are performed by one PSA engineer, independently reviewed by another PSA engineer, and approved by the department head or designee. The PSA group falls under the FPL Engineering Quality Instructions (QI) with written procedures derived from those QIs. Procedures, risk assessment documentation, and associated records are controlled and retained as QA records.
Since the approval of the IPE, the FPL Reliability and Risk Assessment Group (RRAG) has maintained the PSA models consistent with the current plant configuration such that they are considered 'living' models. The PSA models are updated for different reasons, including plant changes and modifications, procedure changes, accrual of new plant data, discovery of modeling errors, advances in PSA technology, and issuance of new industry PSA standards. The update process ensures that the applicable changes are implemented and documented timely so that risk analyses performed in support of plant operation reflect the plant configuration, operating philosophy, and transient and component failure history. The PSA maintenance and update process is described in FPL RRAG Standard PSA Update and Maintenance Procedure. This standard defines two different types of periodic updates: 1) a data analysis update, and 2) a model update. The data analysis update is performed at least every five years. Model updates consisting of either single or multiple PSA changes are performed at a frequency dependent on the estimated impact of the accumulated changes. Guidelines to determine the need for a model update are provided in the standard. The Maintenance Rule Program developed to implement the requirements of 10CFR50.65 is also based on this PSA. The PSA model was also used to justify risk informed evaluations to support technical specification change requests to extend the diesel generator and low-pressure safety injection allowed outage times (AOT).
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 6 Attachment 1 St. Lucie Unit 2 Relief Request 29 The St. Lucie Unit 2 PSA model uses a large fault tree/small event tree method of quantification. Event tree models were developed to define the logic for core damage sequences. The event tree models were converted to equivalent fault tree logic and linked to the frontline and support system fault tree models.
The core damage sequence gates were combined into a single-top core damage gate using 'OR' logic.
The single-top core damage gate was quantified to obtain core damage cutsets in terms of basic events.
The core damage cutsets were used to obtain the CDF values. Each quantification involves post-process operations on the quantified 'raw' cutsets. Cutsets containing pre-defined mutually exclusive event combinations were removed from the final cutset listing. Finally, recovery events were applied to selected cutsets based on pre-defined recovery rules. EPRI's Risk & Reliability Software Package and the NURELMCS code were used to perform the quantification of CDF values.
For this RI-ISI application, the impact of pipe breaks were simulated by defining surrogate basic event in the fault tree models and using the events to configure the fault tree models prior to the quantification process. If a pipe break did not result in an initiating event, the appropriate basic event(s) were set to a logical 'TRUE' state prior to each fault tree quantification to simulate failure of a mitigation system or function due to the pipe break. If a pipe break resulted in an initiating event, the appropriate basic event(s) was set equal to the initiating event prior to each fault tree quantification to simulate the impact of the pipe break initiating event on mitigation systems or functions. Existing basic events in the model were used as the preferred method of simulating the postulated pipe break. New surrogate basic events were added to the model, as required, to properly simulate the impact of the postulated pipe break when existing events were not adequate.
The Level 2 evaluation determines that for Unit 2, LERF comprises 1% of CDF, except for those degradations that result in the inability to mitigate steam generator tube ruptures or interfacing systems LOCAs.
Since the St. Lucie Unit 2 PSA model has been used for Maintenance Rule risk ranking applications and Risk-Informed Technical Specification requests, it is concluded that, on a relative basis, the PSA method and model would yield meaningful rankings for RI-ISI evaluations when combined with deterministic insights.
- 2. PROPOSED ALTERNATIVE TO CURRENT INSERVICE INSPECTION PROGRAMS 2.1 ASME Section XI ASME Section XI Class 1 Categories B-F and B-J currently contain the requirements for examining (via non-destructive examination (NDE)) Class 1 piping components. This RI-ISI Program is limited to ASME Class 1 piping, including piping currently exempt from requirements. The alternative RI-ISI Program for piping is described in WCAP-14572, A-Version. The Class 1 RI-ISI Program will be substituted for the current examination program on piping in accordance with 10 CFR 50.55a(a)(3)(i) by alternatively providing an acceptable level of quality and safety. Other non-related portions of the ASME Section XI Code will be unaffected. WCAP-14572, A-Version, provides the requirements defining the relationship between the risk-informed examination program and the remaining unaffected portions of ASME Section XI.
2.2 Augmented Programs There are no augmented inspection programs for the St. Lucie Unit 2 Class 1 piping systems.
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 7 Attachment 1 St. Lucie Unit 2 Relief Request 29
- 3. RISK-INFORMED ISI PROCESS The processes used to develop the RI-ISI Program are consistent with the methodology described in WCAP-14572, A-Version.
The process that is being applied, involves the following steps:
- Scope Definition
- Segment Definition
- Consequence Evaluation
- Failure Assessment
- Risk Evaluation 0 Expert Panel Categorization
- Element/NDE Selection 0 Implement Program 9 Feedback Loop Deviations There are two deviations to the process described in WCAP-14572, A-Version:
WCAP-14572 uses the Westinghouse Structural Reliability and Risk Assessment Model (SRRA) to calculate failure rates. Since SRRA is a Westinghouse product and St. Lucie is a CE plant, FPL uses WinPRAISE, a Microsoft Windows based version of the PRAISE code used as the benchmark for SRRA in WCAP-14572 Supplement 1.
In WCAP-14572, selection of elements in Regions 1B and 2 of the Structural Element Selection Matrix shown in Figure 3.7-1 of the WCAP is determined by a statistical evaluation process. Since the statistical model used in the WCAP is a proprietary Westinghouse product and St. Lucie is a CE plant, an alternative selection process was used. The alternative is based on that described in EPRI Topical Report TR-112657 Rev. B-A, approved in a Safety Evaluation Report dated October 28, 1999 and on current ASME Section XI criteria. The alternative process selected 25% of the elements in each high safety significance segment. This resulted in the selection of 27.7% of the total population of elements in the high safety significance segments.
3.1 Scope of Program The scope of this program is limited to the Class 1 piping, including piping exempt from current requirements. The Class 1 piping systems included in the risk-informed ISI Program are provided in Table 3.1-1.
3.2 Segment Definitions Once the scope of the program is determined, the piping for these systems is divided into segments.
The numbers of pipe segments defined for the Class 1 piping systems are summarized in Table 3.1-1.
The as-operated piping and instrumentation diagrams were used to define the segments.
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 8 Attachment 1 St. Lucie Unit 2 Relief Request 29 3.3 Consequence Evaluation The consequences of pressure boundary failures are measured in terms of core damage and large early release frequency. The impact on these measures due to both direct and indirect effects was considered.
A review of the license basis of St. Lucie (Final Safety Analysis Report Amendment No. 13) and the IPE Internal Events Methodology was performed to determine the potential impact of the indirect effects of pipe leak or rupture inside containment. As a result of the review, it was concluded that the containment structure and the safety related components inside containment are adequately protected from pipe failures such that the effects of a failure are limited to direct effects. Table 3.3-1 summarizes the postulated consequences for each system.
3.4 Failure Assessment Failure estimates were generated utilizing industry failure history, plant specific failure history, and other industry relevant information.
The engineering team that performed this evaluation used WinPRAISE, a Microsoft Windows based version of the PRAISE code used as the benchmark for SRRA in WCAP-14572 Supplement 1. The failure rate for each segment was based on an aggregate condition, utilizing a combination of the highest individual values of each parameter input to the calculation.
Table 3.4-1 summarizes the failure probability estimates for the dominant potential failure mechanism(s)/combination(s) by system. Table 3.4-1 also describes why the failure mechanisms could occur at various locations within the system. Full break cases are shown only when pipe whip is of concem.
No augmented inspections are performed for the Class 1 piping.
3.5 Risk Evaluation Each piping segment within the scope of the program was evaluated to determine its CDF and LERF due to the postulated piping failure. Calculations were also performed with and without operator action.
Once this evaluation was completed, the total pressure boundary core damage frequency and large early release frequency were calculated by summing across the segments for each system. The results of these calculations are presented in Table 3.5-1. The expected value for core damage frequency due to piping failure without operator action is 9.365E-05/year, and with operator action is 9.364E-05/year. The expected value for large early release frequency due to piping failure without operator action is 9.365E and with operator action is 9.364E-07/year. This evaluation also included a 5 and 951h 07/year, percentile uncertainty analysis.
To assess safety significance, the risk reduction worth (RRW) and risk achievement worth (RAW) importance measures were calculated for each piping segment.
3.6 Expert Panel Categorization The final safety determination (i.e., high and low safety significance) of each piping segment was made by the expert panel using both probabilistic and deterministic insights. The expert panel was comprised of personnel who have expertise in the following fields: probabilistic safety assessment, inservice examination, nondestructive examination, stress, and material considerations, plant operations, plant and
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 9 Attachment 1 St. Lucie Unit 2 Relief Request 29 industry maintenance, repair, and failure history, system design and operation, and SRRA methods including uncertainty. Maintenance Rule Expert Panel members were used to ensure consistency with the other PSA applications.
The expert panel had the following positions represented during the expert panel meeting.
- Probabilistic Safety Assessment (PSA engineer)
- Maintenance Rule (Chairman)
- Operations (Senior Reactor Operator)
- Inservice Inspection (ISI&NDE)
- Plant & Industry Maintenance, Repair, and Failure History (System Engineer)
- Materials Engineer
- Stress Engineer A minimum of four members filling the above positions constituted a quorum. This core team of panel members was supplemented by other experts, including a piping stress engineer, as required for the piping system under evaluation.
The System and Component Engineering Manager is the chairman of the expert panel. The Maintenance Rule Administrator may act as altemate chairman.
Members received training and indoctrination in the risk-informed inservice inspection selection process.
They were indoctrinated in the application of risk analysis techniques for ISI. These techniques included risk importance measures, threshold values, failure probability models, failure mode assessments, PSA modeling limitations and the use of expert judgment. Training documentation is maintained with the expert panel's records.
Worksheets were provided to the panel containing information pertinent to the panel's selection process.
This information, in conjunction with each panel member's own expertise and other documents, as appropriate, were used to determine the safety significance of each piping segment.
Meeting minute records were generated. The minutes included the names of members in attendance and whether a quorum was present. The minutes contained relevant discussion summaries and the results of membership voting.
3.7 Identification of High Safety Significant Segments The number of high safety significant segments for each system, as determined by the expert panel, is shown in Table 3.7-1 along with a summary of the risk evaluation identification of high safety significant segments.
3.8 Structural Element and NDE Selection The structural elements in the high safety significant piping segments were selected for inspection and appropriate non-destructive examination methods were defined.
The program being submitted addresses the high safety significant (HSS) piping components placed in regions 1 and 2 of Figure 3.7-1 and described in Section 3.7.1 in WCAP-14572, A-Version. Region 3 piping components, which are low safety significant, are to be considered in an Owner Defined Program
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 10 Attachment 1 St. Lucie Unit 2 Relief Request 29 and is not considered part of the program requiring NRC approval. Region 1, 2, 3 and 4 piping components will continue to receive Code required pressure testing, as part of the current ASME Section XI Program. For the 205 piping segments that were evaluated in the RI-ISI Program, Region 1B contains 9 segments, Region 2 contains 2 segments, no segments are contained in Region 3, and Region 4 contains 194 segments.
The number of locations to be inspected in applicable HSS segments was determined using a selection process based on that described in EPRI Topical Report TR-112657 Rev. B-A, approved in a Safety Evaluation Report dated October 28, 1999 and on current ASME Section XI criteria. The process selected 25% of the elements in each high safety significance segment. This resulted in the selection of 27.7% of the total population of elements in the high safety significance segments.
Table 4.1-1 in WCAP-14752, A-Version, was used as guidance in determining the examination requirements for the HSS piping segments. VT-2 visual examinations are scheduled in accordance with the station's pressure test program, which remains unaffected by the risk-informed inspection program.
Additional Examinations The Risk-Informed Inspection Program in all cases will determine, through an engineering evaluation, the root cause of any unacceptable flaw or relevant condition found during examination. The evaluation will include the applicable service conditions and degradation mechanisms to establish that the element(s) will still perform their intended safety function during subsequent operation. Elements not meeting this requirement will be repaired or replaced.
The evaluation will include whether other elements on the segment or segments are subject to the same root cause and degradation mechanism. Additional examinations will be performed on these elements up to a number equivalent to the number of elements initially required to be inspected on the segment or segments. If unacceptable flaws or relevant conditions are again found similar to the initial problem, the remaining elements identified as susceptible will be examined. No additional examinations will be performed if there are no additional elements identified as being susceptible to the same service related root cause conditions or degradation mechanism.
3.9 Program Relief Requests An attempt shall be made to provide a minimum of >90% coverage criteria (per ASME Code Case N-460) when performing an exam. Some limitations will not be known until the examination is performed, since some locations will be examined for the first time by the specified techniques.
In instances where it may be found at the time of the examination that a location does not meet >90%
coverage, the process outlined in Section 4.0 (Inspection Program Requirements) of WCAP-14572, A-Version will be followed.
3.10 Change in Risk The risk-informed ISI Program has been done in accordance with Regulatory Guide 1.174, and the risk from implementation of this program is expected to remain constant when compared to that estimated from current requirements.
A comparison between the proposed RI-ISI Program and the current ASME Section XI ISI Program was made to evaluate the change in risk. The approach evaluated the change in risk with the inclusion of
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 11 Attachment 1 St. Lucie Unit 2 Relief Request 29 inservice inspections with a 'good' probability of detection in the WinPRAISE model and followed the guidelines provided on page 213 of WCAP-14572.
The results from the risk comparison are shown in Table 3.10-1. As seen from the table, the overall RI ISI Program maintains the risk associated with piping CDF/LERF, with respect to the current Section XI Program, while reducing the number of examinations. The primary basis for being able to maintain risk with a reduced number of examinations is that exams are now being placed on piping segments that are high safety significant, and in some cases, elements are inspected that are not inspected by NDE in the current ASME Section XI ISI Program.
Defense-In-Depth The reactor coolant piping will continue to receive a system leakage test and visual VT-2 examination as currently required by the Code. Volumetric examinations will also continue on the main reactor coolant piping as part of the RI-ISI Program (segments categorized HSS). These locations, which include main loop and pressurizer surge line piping welds determined by the RI-ISI Program for St. Lucie Unit 2, assure that 'defense-in-depth' is maintained. No additional inspection locations are required to meet 'defense-in depth'.
- 4. IMPLEMENTATION AND MONITORING PROGRAM Upon approval of the RI-ISI Program, procedures that comply with the guidelines described in WCAP 14572, A-Version, will be prepared to implement and monitor the program. The new program will be integrated into the existing ASME Section XI interval. No changes to the Technical Specifications or the Final Safety Analysis Report are necessary for program implementation.
The applicable aspects of the Code not affected by this change would be retained, such as inspection methods, acceptance guidelines, pressure testing, corrective measures, documentation requirements, and quality control requirements. Existing ASME Section XI program implementing procedures would be retained and would be modified to address the RI-ISI process, as appropriate. Additionally, the procedures will be modified to include the high safety significant locations in the program.
The proposed monitoring and corrective action program will contain the following elements:
A. Identify B. Characterize C. Evaluate (1) Evaluate, determine the cause and extent of the condition identified (2) Evaluate, develop a corrective action plan or plans D. Decide E. Implement F. Monitor G. Trend The RI-ISI Program is a living program requiring feedback of new relevant information to ensure the appropriate identification of high safety significant piping locations. As a minimum, risk ranking of piping segments will be reviewed and adjusted on an ASME Section XI inspection period basis. Significant changes may require more expedited adjustment as directed by NRC Bulletin or Generic Letter requirements, or by plant specific feedback.
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 12 Attachment 1 St. Lucie Unit 2 Relief Request 29
- 5. PROPOSED ISI PROGRAM PLAN CHANGE A comparison between the RI-ISI Program and the current ASME Section Xl Program requirements for piping is given in Table 5-1. The plant will be performing examinations on elements not currently required to be examined by ASME Section XI. The current ASME Section Xl Program selects a prescribed percentage of examinations without regard to safety significance. The RI-ISI Program focuses examinations on those high safety significant segments and subsequently, examinations are required on inspection elements not currently scheduled for examination by the ASME Section XI Program.
The program will be retroactively started in the third period of the second interval, starting in the outage scheduled to begin November 19, 2001. Currently, 68% of the exams in the Section XI Program have been performed, meeting the 50% requirement for the end of the second inspection period of the current interval.
- 6.
SUMMARY
OF RESULTS AND CONCLUSIONS A partial scope Class 1 risk-informed ISI application has been completed for Unit 2. Upon review of the proposed risk-informed ISI examination program given in Table 5-1, an appropriate number of examinations are proposed for the high safety significant segments across the Class 1 portions of the plant piping systems. Resources to perform examinations currently required by ASME Section XI in the Class 1 portions of the plant piping systems, though reduced, are distributed to address the greatest amount of risk within the scope. Thus, the change in risk principle of Regulatory Guide 1.174 is maintained. Additionally, the examinations performed will address specific damage mechanisms postulated for the selected locations through appropriate examination selection and increase volume of examination.
The construction permit for St. Lucie Unit 2 was issued May 1977. The plant is designed to ASME Section III for the Class 1 piping. The ASME Section III design provides an improved level of fatigue analysis and operating conditions scrutiny when compared to older vintage plants. This results in a larger percentage of the reactor coolant system piping constructed with butt welds as opposed to socket welds and more detailed information is available for input to the estimation of the failure probability.
From a risk perspective, the PRA dominant accident sequences include: small LOCA; loss of offsite power; and large LOCA.
For the RI-ISI Program, appropriate sensitivity and uncertainty evaluations have been performed to address variations in piping failure probabilities and PRA consequence values along with consideration of deterministic insights to assure that all high safety significant piping segments have been identified.
As a risk-informed application, this submittal meets the intent and principles of Regulatory Guide 1.174.
- 7. REFERENCES/DOCUMENTATION WCAP-14572,Revision 1-NP-A, , Westinghouse Owners Group Application of Risk-Informed Methods to Piping Inservice Inspection Topical Report, February 1999 Calculation Number PSL-BFJR-98-004, Revision 2, St. Lucie Units 1 & 2 Baseline EOOS Models.
St. Lucie Units 1 & 2 Individual Plant Examination Submittal, Revision 0, dated December 1993.
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 13 Attachment 1 St. Lucie Unit 2 Relief Request 29 Procedure STD-R-002, PSA Update and Maintenance Procedure, Revision 5, Dated February 26, 2001.
St. Lucie Plant Unit 2 Updated Final Safety Analysis Report, Amendment 13.
Risk & Reliability Software developed for the Electric Power Industry under sponsorship of EPRI, the Electric Power Research Institute.
NURELMCS, SCIENTECH, Version 2.20, Revision 1.8 Supoortinq Onsite Documentation The onsite documentation is contained within the following Engineering Evaluations:
PSL-ENG-SEOS-01-002, St. Lucie Unit 2 Risk-Informed ISI Program Development Analysis PSL-ENG-SEOS-01-003, St. Lucie Unit 2 Risk-Informed ISI Program - Failure Analysis PSL-ENG-SEOS-01-004, St. Lucie Unit 2 Risk-Informed ISI Program - Consequence Quantification
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 14 Attachment 1 St. Lucie Unit 2 Relief Request 29 Table 3.1-1 System Selection and Segment Definition for Class I Piping System Description PRA Section XI Number of Segments CH - Chemical & Volume Yes Yes 20 Control RC - Reactor Coolant Yes Yes 126 SI - Safety Injection Yes Yes 59 Total 205 Notes:
- 1. Includes flow paths for high pressure safety injection, low pressure safety injection, and the passive accumulator in portions of SI.
Table 3.3-1
~I~mmnrv nf Pn~t.Ilatnd Cnnnseuences by System System Summary of Consequences CH - Chemical & Volume The direct consequences postulated from piping failures in this system are:
Control loss of auxiliary pressurizer spray flow path; loss of one or more trains for charging; and small-small loss of coolant accident (LOCA).
RC - Reactor Coolant The direct consequences associated with piping failures are: large,loss small, and/or small-small LOCAs; loss of safety injection tank flow path; of cold or hot injection leg flow path; loss of alternate injection flow path; loss of auxiliary pressurizer spray flow path; loss of one or more charging flow paths; and loss of identified instrumentation.
SI - Safety Injection The direct consequences associated with piping failures are: loss of safety injection tank flow path; loss of low pressure safety injection (LPSI) flowpath; loss of cold or hot leg injection flow path; loss of alternate injection flowpath; piping break outside primary containment; large and/or small small LOCAs; loss of suction to LPSI pump; loss of identified instrumentation.
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 15 Attachment 1 St. Lucie Unit 2 Relief Request 29 Table 3.4-1 ra;I., r5.J Do.J.;Ith .c:...,at* .~th,aI1 System Dominant Potential Failure Probability Range (Small Comments Degradation Mechanism(s)/ Leak Probability @ 40 years, no Combination(s) ISI)
CH -Fatigue 2.01E 6.80E-09 The charging path to the applicable RCS loop is potentially susceptible to thermal fatigue RC -Fatigue 1.66E 4.82E-06 Fatigue at instrument line connections to main loop.
-Thermal Transients 5.67E 2.85E-03 Piping where large thermal transients could occur:
pressurizer surge line and charging nozzles
-Thermal and Vibratory 1.4E 4.6E-05 The piping is located on the Fatigue RCP pump or seal housing and is potentially subject to vibration.
SI - Fatigue 1.85E-1 5 - 2.07E-1 1 Piping in flow path of alternate injection and SIT is potentially susceptible to thermal fatigue.
- Thermal Transients 8.21 E 5.83E-14 Potential piping locations where thermal transients could occur in injection lines.
Table 3.5-1 Number of Segments and Piping Risk Contribution b System (witho ISI)
System # of CDF CDF LERF LERF Segments without with without with Operator Action Operator Action Operator Action Operator Action
(/yr) (/yr) (/yr) (/yr)
CH 20 4.041E-11 3.963E-11 4.041E-13 3.963E-13 RC 126 9.365E-05 9.364E-05 9.365E-07 9.364E-07 SI 59 1.954E-16 1.954E-16 1.954E-18 1.954E-18 TOTAL 205 9.365E-05 9.364E-05 9.365E-07 9.364E-07
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 16 Attachment 1 St. Lucie Unit 2 Relief Request 29 Table 3.7-1 Summary of Risk Evaluation and Expert Panel Categorization Results System Number of Number of Number of Number of Number of Total segments with segments segments segments segments number of any RRW > with any with all RRW with any with all RRW segments 1.005 RRW < 1.001 RRW < 1.001 selected for between between selected for inspection 1.005 and 1.005 and inspection (High Safety 1.001 1.001 placed Significant in HSS Segments)
CH 0 0 20 0 0 0 RC 9 2 115 2 0 11 SI 0 0 59 0 0 0 Total 9 2 194 2 0 11
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 17 Attachment 1 St. Lucie Unit 2 Relief Request 29 Table 3.10-1 COMPARISON OF CDFILERF FOR CURRENT SECTION XI AND RISK-INFORMED ISI PROGRAMS Case Current Section XI Risk-Informed CDF No Ooerator Action 8.03E-05 8.03E-05
- CH 2.46E-11 4.04E-11
- RC 8.03E-05 8.03E-05
- CH 2.39E-11 3.96E-11
- RC 8.03E-05 8.03E-05
- CH 2.46E-13 4.04E-13
- RC 8.03E-07 8.03E-07
- CH 2.39E-13 3.96E-13
- RC 8.03E-07 8.03E-07
- SI 1.60E-20 1.60E-20
St. Lucie Unit 2 Docket No. 50-389 L-2002-142 Enclosure Page 18 Attachment 1 St. Lucie Unit 2 Relief Request 29 Table 5-1 STRUCTURAL ELEMENT SELECTION RESULTS AND COMPARISON TO ASME SECTION XI 1989 EDITION REQUIREMENTS System Number of High Degradation Class ASME Weld Count ASME Xl RI-ISI Safety Significant Mechanism(s) Code Examination Methods Segments (No. of Category (Volumetric (Vol) and HSS in Aug. Surface (Sur))
Program / Total Butt Socket Vol & Sur Sur Only SES Matrix Number of No. of Segments Region Exam in Aug. Program) _ Locations CH 0 Thermal 1 B-F 3 0 0 3 - 0 Fatigue B-J 30 115 0 81 RC 11 (0/0) Thermal 1 B-F 20 0 12 8 1B, 2 3 Fatigue, volumetric Thermal Transients, B-J 202 20 50 24 20 Vibration volumetric Fatigue SI 0 Thermal 1 B-F 6 0 6 0 0 Fatigue, Thermal B-J 143 22 18 5 Transients TOTAL 11 (0/0) CL. 1 B-F 29 0 18 11 3 NDE B-J 375 157 68 110 20 NDE TOTAL 404 157 86 121 23NDE Summary: Current ASME Section XI selects a total of 86 non-destructive exams (surface only exams not included), while the proposed RI-ISI Program selects a total of 23 non-destructive exams. This results in a 73% reduction of non-destructive exams.
General Note:
System pressure test requirements and VT-2 visual examinations shall continue to be performed in ASME Class I systems.