ML18039A756
| ML18039A756 | |
| Person / Time | |
|---|---|
| Site: | Browns Ferry  |
| Issue date: | 04/23/1999 |
| From: | TENNESSEE VALLEY AUTHORITY |
| To: | |
| Shared Package | |
| ML18039A755 | List: |
| References | |
| NUDOCS 9905030118 | |
| Download: ML18039A756 (60) | |
Text
TENNESSEE VALLEYAUTHORITY BROWNS FERRY NUCLEARPLANT RISK-INFORMEDINSERVICE INSPECTION (RI-ISI)
PROGRAM SUBMITTAL 99050Mii8'90423 PDR ADQCK 05000296 8
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RISK-INFORMEDINSERVICE INSPECTION PROGRAM PLAN Table ofContents Introduction 2.
Proposed Alternative to ISI Program 2.1 ASME Section XI 2.2 Augmented Programs 3;
Risk-Informed ISI Process I
3".1 Scope ofProgram 3.2 Segment Definitions 3.3 Consequence Evaluation 3.4 Failure Assessment
'.5 Risk Evaluation 3.6 Expert Panel Process 3.7 Expert Panel, Categorization 3.8 Structural Element and'NDE Selection 3.9 Program ReliefRequests 3.10 Change in Risk 4.
Implementation and Monitoring Program 5.
Proposed ISI Program Plan Change 6.
References/Documentation E-3
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1.
IPl'RODUCTION Inservice inspections (ISI) for Browns Ferry Nuclear Plant are currently performed on piping welds to the requirements ofthe ASME Boiler and Pressure Vessel Code Section XI, 1989 Edition as required by 10CFR50.55a.
Unit 3 is currently in the second inspection interval as defined by the Code for Program B.
The purpose ofthis submittal is to request a change to the ISI program plan for piping through the use ofa risk-informed ISI program and an alternative to the inspection requirements of IGSCC Category "A"welds as allowed by Generic Letter 88-01. The risk-informed,process used in this submittal is described in Regulatory Guide 1.174 and 1.'178 (Trial Use) and is consistent with the methodology'escribed in ASME Section XI, Code Case N-577 and WCAP-14572, revision 1, as modified by the September 30, 1998, letter to the Commission from the Westinghouse Owners Group (WOG), with the deviations listed in Section 3.
~PSA ualit The Browns Ferry probabilistic safety assessment (PSA) model BFNU3Mwas used to evaluate the consequences ofpipe ruptures.
The base core damage frequency (CDF) and base large early release frequency (LERF) are 9.19E-06 and 2.57E-06, respectively.
The original (Revision 0) BFN PSA model is described. in the TVAresponse to Generic Letter 88-20. This model and the associated documentation were extensively reviewed by TVA personnel.
In a letter dated September 28, 1994, the NRC staff concluded that TVA's Individual Plant Examination (IPE) submittal was complete with the level ofdetail requested in NUREG-1335. Revision 1 to the BFN PSA model then incorporated numerous individual changes, primarily in the area ofplant response to loss ofoffsite power. The Unit 3 PSA used in this analysis (BFNU3M) is based on the Unit 2'PSA with well-documented differences.
Each ofthese risk models use the proprietary RISKMANcomputer program for cutset generation and event tree quantification. The risk models use a small fault tree/large event tree method of quantification.
The Maintenance Rule Program developed to implement the requirements of 10CFR50.65 is also based on this PSA. In an inspection conducted April 14-18, 1997, the NRC concluded that the program was comprehensive and was being effectively implemented.
The Browns Ferry event tree model is quantified using a batch process that is based on a tabular listing ofthe initiating events to be quantified. For those quantifications that are based on failure ofplant functions, such as Residual Heat Removal (RHR) pump A, the event tree rule structure is modified prior to quantification to set this top event to guaranteed failure. In the case oftop events where a common cause term has been evaluated, such as between RHR pumps, diesel generators and High Pressure Coolant Injection (HPCI)/Reactor Core Isolation Cooling(RCIC),
the first top event questioned is set to guaranteed failure. Where an interim variable is used to
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indicate su~port systems for the impacted top event, this interim variable was failed. This effectively sets the impacted top event to a condition where itwould not be questioned; In this way, common cause does not skew the results for subsequent trains or components.
The Level 2 evaluation determines that for Unit 3, LERF comprises 28% ofCDF, except for those degradations that result in the inability to mitigate an Anticipated Transient Without Scram (ATWS) or those which bypass containment directly.
Recovery actions modeled in the PSA in general address electrical distribution, and as such do not affect this study. In a typical mechanical recovery action, the operator is able to start a "swing" Emergency Equipment Cooling Water (EECW) pump to recover from failure ofthe normally assigned pump; however, for those scenarios which resulted in loss ofEECW, no credit was taken for the start ofthe swing pump.
The PSA Update Report is evaluated for updating every other. refueling outage.
The administrative guidance for this activity is contained in TVAStandard Engineering practice SEP-9.5.8.
During November 1997, TVAparticipated in a PSA Peer Review Certification ofthe BFN PSA administered under the auspices ofthe BWROG Peer Certification Committee.
The purpose of the PSA peer review process is to establish a method ofassessing the. technical quality ofthe PSA for the spectrum ofits potential applications.
The BFN PSA Peer Review Certification team consisted ofsix individuals with a combined 134 man-years ofnuclear experience including 97 man-years in PSA related applications.
These engineers and analysts provided both an objective review ofthe PSA technical elements and a subjective assessment based on their PSA experience.
The review team had considerable.
expertise in basic PSA development and PSA applications, and in the specific PSA methodology used for the BFN PSA. The team was also knowledgeable in BWR-4 plant design and operational. practices.
The. evaluation process used a tiered approach ofstandard checklists that allowed for a detailed review ofthe elements and the sub-elements ofthe BFN PSA to identify strengths and areas that needed improvement. A review system was used that allowed the Peer Review team to focus on technical issues and to issue their assessment results in the form ofa "grade" of 1 through 4 on a PSA sub-element level. To reasonably span the spectrum ofpotential PSA applications, the four grades ofcertification as defined by the BWROG document "Report to the Industry on PSA Peer Review Certification Process: Pilot Plant Results," were employed.
These are repeated below for reference.
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Grade I - Useful for Identi in Severe Accident Vulnerabilities Accident Mana ement Insi hts and General Prioritization'ofIssues This grade requires the minimum standard and has satisfied NRC expectations for responding to Generic Letter 88-20. Most PSAs are expected to be capable of meeting these requirements.
This grade ofcertification would serve as an industry standard.
Grade 2 -
seful for Risk Rankin with Deterministic In ut This grade ofcertification requires a review ofthe PSA model, documentation, and maintenance program.
Certification at this grade would provide assurance that, on a relative basis, the PSA methods and models yield meaningful rankings for the assessment ofsystems, structures, and components, when combined with deterministic insights (i.e., a blended approach).
Grade 3 - Useful for Risk Si nificance with Deterministic In ut This grade ofcertification extends the requirements to assure that risk significant determinations made by PSA using absolute risk insights are adequate to support a broader range ofregulatory applications, when combined with deterministic insights.
Grade 4 - Useful as a Prima Basis for Decision Makin This grade ofcertification requires a comprehensive, intensively reviewed study, which has the scope, level ofdetail, and documentation to assure the highest quality ofresults.
Routine reliance on the PSA as the basis for certain changes is expected as a result ofthis grade. It is expected that few plants would currently be eligible for this grade ofcertification.
It should be noted that while each ofthe four application oriented grades have different characteristics as previously delineated, the boundaries between the grades are not sharp.
This leaves, in some cases, an element ofjudgment to be applied when assigning a specific application to a specific grade.
This lack ofsharp boundaries is due in part to the fact that varying degrees of supplementary deterministic considerations or focused PSA studies may be used with any ofthe four grades ofPSA to effectively support an application.
The BFN PSA Peer Review resulted in a consistent evaluation across all the PSA elements and sub-elements.
Approximately 72% ofall the graded sub-elements were at Grade 3 or above; 8%
ofthe sub-elements were assessed at Grade 4 providing a very solid evaluation.
The following Table summarizes the results ofthe BFN Peer Review performed at the element level for the BFN PSA.
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RESULTS, OF BFN PEER REVIEW PSA ELEMENT INITIATINGEVENTS ACCIDENT SEQUENCE EVALUATION(AS)
THERMALHYDRAULICANALYSIS T SYSTEMS ANALYSIS S DATAANALYSIS A
HUMANRELIABILITYANALYSIS DEPENDENCY ANALYSIS E
STRUCTURAL RESPONSE ST UANTIFICATION Q CONTAINMENTPERFORMANCE ANALYSIS 2
hQQNTENANCE ANDUPDATE PROCESS CERTIFICATIONGRADE Since Risk-Informed ISI is a Grade 2 (risk-ranking) application and all elements are graded at or above a Grade 2, the BFN PSA model used for evaluating the RI-ISI program is considered appropriate and adequate to support this application.
2.
PROPOSED ALTERNATIVETO ISI PROGRAM 2.1 ASME Section XI ASME Section XI Categories B-F, B-J, C-F-1 and C-F-2 currently contain the requirements for examining (via NDE) piping components.
This current program is limited to ASME Class 1 and Class 2 piping. The alternative risk-informed inservice inspection (RI-ISI) program for piping is described in Code Case N-577. The RI-ISI program willbe substituted for the current examination program on piping in accordance with 10 CFR 50.55a(a)(3)(i) by alternatively providing an acceptable level ofquality and safety. Additionally, the alternative program willnot be limited to ASME Class 1 or Class 2 piping but willencompass the high safety significant piping segments regardless ofASME Class.
Other non-related portions ofthe ASME Section XICode willbe unaFected.
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2.2 Augmented Programs
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C Generic Letter 88-01 provides the NRC positions on Intergranular Stress Corrosion Cracking (IGSCC).in BWR austenitic stainless steel piping. The technical bases for these positions and requirements for categorization ofIGSCC susceptible welds are detailed in'NUREG-0313.
Inspection schedules are comparable to those specified in ASME Section XIin cases where the piping monitored is IGSCC resistant.
Varying schedules for inspections are specified for other piping. GL 88-01 allows licensees to propose alternative measures.
A risk-informed process as described in Regulatory. Guide 1.174 and 1.178 (Trial Use) and implemented in the ASME Boiler and Pressure Vessel Code,Section XI, as Code Case N-577 was utilized to develop an alternative to the inspection requirements ofIGSCC Category "A" welds as allowed by GL 88-01.
The Flow Accelerated Corrosion (FAC), Thermal Fatigue, Raw Water Fouling and Corrosion Control, and IGSCC augmented inspection programs, with the exception ofIGSCC Category "A" welds, remain unchanged.
3.
RISK-INFORMEDISI PROCESS The processes used to develop the RI-ISI program are consistent with the methodology described in ASME Section XI, Code Case N-577 and WCAP-14572,. revision l,.as modified by the September 30, 1998, letter to the Commission from the Westinghouse Owners Group, with the deviations listed below.
The process that is being applied, involves the following steps:
Scope Definition Segment Definition Consequence Evaluation Failure Assessment Risk Evaluation Expert Panel Categorization Element/NDE Selection Implement Program Feedback Loop Deviations from the process described in WCAP-14572 are as follows:
Calculation ofFailure Rate WCAP-14572 uses the Westinghouse Structural Reliability and Risk Assessment Model (SRRA) to calculate failure rates. TVAuses WinPRAISE, a Microsoft Windows based version ofthe PRAISE code used as the benchmark for SRRA in WCAP-14572 Supplement l.
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Determination ofFailure Rate for a Se ment In the WCAP process, one or more points deemed most susceptible to a postulated failure mechanism were selected for each segment, and a failure rate calculated for that point or points.
Ifmore than one point was calculated, the worst result was used to determine segment risk. At TVA,failure rates were quantified for the individual elements in a segment, and the highest individual failure rate was used to determine segment risk.
Uncertaint Anal sis In paragraph 3:6.1 ofthe WCAP reference is made to uncertainty analyses to address uncertainty in.failure probabilities and consequence.
As modified by the WOG letter ofSeptember 30, 1998, it states that a simplified uncertainty analysis should also be performed to ensure that no low safety significant segments could move into the high safety significance category when reasonable variations are considered:
As a practice, the TVAExpert Panel considered all segments in this significance range (1.005 > Risk Reduction Worth (RRW) > 1.001) to be High Safety Significant, in lieu ofperforming the sensitivity study.
Structural Element Selection In WCAP-14572, selection ofelements in Region 2 ofthe Structural Element Selection Matrix shown in Figure 3.7-1 ofthe WCAP is determined by a statistical evaluation process.
According to paragraph 3.7.2 ofthe WCAP, this statistical. model is used to ensure that an acceptable level ofreliability is achieved. AtTVA,two methods were used to select elements in Region 2. For those elements with a quantified failure rate, that failure rate was used to select the elements.
For some elements, the calculated failure rate was zero. As stated in 3.7.5 ofthe WCAP (as modified by the WOG letter ofSeptember 30, 1998)'additional rationale must be developed when a statistical model cannot be applied to determine the minimum number ofexamination locations for a given segment.
Since a calculated failure probability is a necessary input to a statistical evaluation, an alternative which would provide assurance ofan acceptable level ofreliabilitywas used.
The existing examination requirements ofSection XIhave provided such an acceptable level; therefore, the existing Section XIcriteria were used; i.e., 25% for Class 1 and 7.5% for Class 2.
3.1 Scope ofProgram The system scoping rules were applied to all systems using existing Browns Ferry Nuclear Plant documentation.
Inclusion ofsystems in the scope ofcurrent Section XIprograms was determined by reviewing 3-SI-4.6.G, Inservice Inspection Program and the current examination isometric drawings.
Determination ofthose systems modeled in the plant PSA was made from the Browns Ferry Nuclear Plant Individual Plant Examination and the various associated system notebooks.
Maintenance Rule significance was determined from O-TI-346, Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting. Appendix B and the appropriate attachments to 0-TI-346 that described the significant functions ofthe system were utilized in determining what portion of a system should be included.
Separate documentation was prepared for each ofthe identified systems and is provided as support information. Specific, applicability to each included system is provided in that system's section ofAppendix A to 3-SI-4.6.G. The systems to be included in the risk-informed ISI program are provided in Table 3.1-1.
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3.2 Segment Definition Once the systems to be included in the program are determined, the portions ofthe selected systems to be evaluated are divided into segments.
A piping segment is defined. as a run ofpiping whose failure would result in the same loss offunction, as determined from the plant PSA or other considerations (functions which do not impact CDF). In addition, consideration was given to identifying distinct segment boundaries at branching points such as flow splits or flowjoining points, locations ofsize changes, isolation valve, motor operated valve (MOV)and air operated valve (AOV)locations. Distinct segment boundaries are defined ifthe break probability is expected to be significantly different for various portions ofpiping. The number ofsegments identified per system is given in Table 3.1-1. Description ofeach system's individual segments is provided in that system's section ofAppendix A to 3-SI-4.6.G.
Syst Table 3.1-1 Systems in Risk-Informed Inservice Inspection Scope Sec XI PSA Mnt Rule if Segs risk significant 001 Main Steam 002 Condensate and Demineralized Water Portions which provide a heat sink, or provide water to mitigate accidents, or deliver water to FW 003 Feedwater 023 Residual Heat Removal Service Water 024 Raw Cooling,Water 027 Condenser Circulating Water Portion which provides cooling water to main condenser Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes
- Yes, Yes 56 36 46 20'63 Standby Liquid Control 067 Emergency Equipment Cooling Water 068 Reactor Recirculation 069 Reactor Water Cleanup 070 Reactor Building Closed Cooling Water 071 Reactor Core Isolation Cooling 073 High Pressure Coolant Injection 074 Residual Heat Removal 075 Core Spray 078 Fuel Pool Cooling 085 Control Rod Drive Hydraulics Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes Yes
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3.3 Consequence Evaluation I
The consequences ofpressure boundary failures are measured in terms ofcore damage and large early release.
The impact on these measures due to both direct and indirect effects was considered.
Direct Conse uences Direct consequences ofsegment failure were determined by reviewing the Piping and Instrumentation Drawings (P&IDs) for each system, reviewing the events trees in the PSA, and from the insights ofplant experienced personnel.
An Operational Interface Review was performed to verify that all plant effects were incorporated and to validate proper selection of Initiating Events and Mitigating System Impacts.
This review included simulating some failures on the plant operations training simulator. Impacts for instrument lines were evaluated for instrument function, as well as loss offluid effects.
Normal operator actions were considered in the Operational'Interface Review in determining the appropriate resulting initiating events and impacts.
Results both with and without operator action were identified where applicable.
Operator recovery (i.e. isolation offaulted pipe segments, etc.)
was considered and the most likely action was used as the applicable-case.-
Direct consequences include both the functional failure due to loss ofthe piping segment and secondary effects such as increased drywell pressure.
When these, consequences had been identified it was determined what surrogate events would represent each consequence in the PSA for quantification.
These surrogates fell into four categories:
- Failures that resulted in a plant trip, represented by an Initiating Event.
Operational insights were used to determine the initialinitiating event.
- Failures that impacted the operability ofmitigating systems, represented by various events or combinations ofevents
- Failures that resulted in both a plant trip and impacted operability ofmitigating systems, represented by a quantification run including both an Initiating Event and various other events
- Failures that impact the ability to provide shutdown cooling, after the reactor has been shut down.
For those pipe breaks that resulted in only a plant trip, the Conditional Core Damage Probability (CCDP) for the associated initiating event was used.
To estimate failure probability for a standby component, the following equation is used:
/2 (FR) Ts + (FR)T~
where FR is the Failure Rate (in events per unit time), Ts is the interval between surveillances, and T~ is the total defined mission time (24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br />). Due to the short mission time, the second term is usually small and is disregarded.
'Since calculations in the RI-ISI program are based on annual
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CCDF/P, the FP is expressed in terms ofone year. When the expression
/~ Ts is converted to an annual basis, it is referred to as the Surveillance Interval Adjustment. For instance, for a quarterly surveillance, the factor is:
'l~(1 yr/4 quarters) = 1/8 = 0.125 Similarly, for a monthly surveillance, the factor is 1/24 = 4.17E-02. For operator observation on one round,per shift, the mission time has significance.
The calculation is:
~/~(1 shift/round)(12hr/shift)(1 day/24 hrs)(lyr/365 days) + (1 yr/365 days)
= 1/1460+ 1/365 = 3.42E-03 Table 3.3-1 summarizes the results ofthe individual cases evaluated where a pipe segment could impact operability ofa mitigating system.
Since a mitigating system may be called for in the case ofany initiating event, the quantification runs were made including all initiating events.
The calculated CDF was then adjusted to remove the base CDF of9.19E-06, such that the result reflects the increase in CDF associated with the segment failure.
Support to core spray pump A Support to core spray, pump C Supportto HPCI Support to RHR pump A Support to RHR pump B Support to RHR pump C Support to RHR pump D The followingPSA model macro terms are used in the "Other Impacts or Failures" shown in Table 3.3-1:
Yl1 Y12 HPISUP RPASUP RPB SUP RPCSUP RPD SUP Diesel generator failures are modeled as being bounded by failure ofdiesel generator 3A fuel oil (top event FE), which is the limitingfunction.
The impact on core spray was modeled by setting interim variables Yl1 and Y12 in event tree module LPGTET and interim variable CSISUP in event tree modules MLOCA2 and LLOCA1 to conditions that cannot exist (i.e., DE=S~DE=F, etc.).
The impact on HPCI was modeled by setting interim variable HPISUP to conditions that cannot exist in HPGTET and MLOCA2event tree modules.
Unit 2 has the ability to cross connect RHR to Unit 1 or to Unit 3, while Unit 3 can only cross connect to Unit 2. For this reason, the A and C pumps are not symmetric to the B and D pumps for Unit 3. Failure for A or C is modeled by failing A, and failure for B or D is modeled by failing B. The impacts are incorporated be setting the representative interim variable or variables to conditions that cannot exist in the LI'GTET, MLOCA2, and LLOCA1 event tree modules.
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Tab e 3.3-1 Summary of Quantification Runs Where Segment Failure does not result in Plant Trip Initiating Event All All All All All AII AII AII All AII All'll All Mitigating System impact Core Spray loop I CRD HPISUP failed RPASUP failed RPBSUP failed RPASUP, RPCSUP RPBSUP, RPDSUP RPBSUP, RPDSUP, CS Diesel Generator RHR Div I Heat Exchangers RHR Div 2 Heat Exchangers RCI Suppression Pool Cooling Calculated CDF 1.265 E-05 6.082E-05 1.910E-05 3.244E-05 7.782 E-05 2.120E-04 1.359E-04 2.668 E-04 1.665 E-05 3.724 E-05 3.919E-05 1.960 E-05 1.103E-05 CDF Increase (Annual) 3.46E-06 5.163E-05 9.91E-06 2.33E-05 6.86E-05 2.03E-04 1.27E-'04 2.58E-04 7.46E-06 2.81E-05 3.00E-05 1.04E-05 1.84E-06 Surv Interval qtrly shift (op round) qtrly mthly mthly mthly mthly shift (op round) mthly qtrly qtrly qtrly qtrly The surveillance interval referenced in the table represents the period between surveillance tests or physical observation ofthe affected system or component.
This is used to determine the appropriate Surveillance Interval Adjustment factor.
Table 3.3-2 summarizes the results ofthe individual cases evaluated where failure ofa pipe segment could result in an initiating event and also impact operability ofa mitigating system or systems.
RISKMANcalculations were made for the listed combinations ofcircumstances, and the resultant Core Damage Frequency was normalized to an annual CCDP by dividing by the initiating event frequency.
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Table 3.3-2 Summary of Quantification Runs Where Segment Failure Results in Plant Trip with Mitigating System Impact Initiating Event CIV Mitigating System impact HPI Calculated CDF 1.965E-06 4.53E-06 4.340E-01 IE Freq for Normalization CCDP (normalized)
CIV LLO LRCW RCI, CRD subsumes HPI, RCI, CRD 250V RMOV 3C 2.971E-05 4.050E-08 3.653 E-06 4.340E-01 1.070E-04 3.220 E-02 6.85E-05 3.79E-04 1.13E-04 PLFW RCI, CRD RXINST incl LM, LV, LVP (calc as Ul)
SCRAMR CRD SCRAMR CRDY12 SCRAMR RPB, RPD, HPI SCRAMR SL S LOCA RCI 3.007 E-06 5.039E-09 5.374E-07 8.054 E-07 1.426 E-06 5.711 E-06 7.475 E-08 3.310E-01 6.580E-04 2.740 E-01 2.740 E-01 2.740 E-01 2.740E-01 4.010E-03 9.08E-06 7.66E-06 1.96E-06 2.94E-06 5:20E-06 2.08E-05 1.86E-05 The loss ofshutdown cooling is represented by Top Event SDC which has an Achievement Worth of 1.215, which results in a calculated CDF of 1.117E-05 per year.
Based on operating history, this mode ofoperation is applicable for seven days per refueling outage.
For an 18 month cycle, this was an exposure time of7/548 days, resulting in an adjustment factor of 1.28E-02. For the future 24.month cycles, this adjustment factor willbe 9.58E-03.
This change has no impact on the significance ofany segment.
The direct consequences and Conditional Core Damage Probabilities/Frequencies for all pipe segments are described in each system's section ofAppendix Ato 3-SI-4.6.G.
Indirect Conse uences The effects ofHigh Energy Postulated Pipe Ruptures both inside and outside containment were evaluated for Unit 3. The purpose ofthese evaluations was to ensure that. the systems, structures, and components required to assure safe shutdown and the ability to maintain a cold shutdown condition were not impaired as the result ofpostulated pipe failures. Any effects initially identified as a result ofthese evaluations were reconciled either by analysis or modification as part ofthe overall effort.
The Browns Ferry PSA identifies five distinct Initiating Events. that address component failures due to flooding effects from various plant systems.
Since potential effects ofpipe whip orjet impingement were treated by the referenced High Energy Pipe Rupture Evaluations and flooding effects are included as initiating events, only potential scenarios in which low pressure piping failure results in spray required evaluation.
Results are given in Table 3.3-3.
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Table 3.3-'3 Se mentswithLowPressure S ra Potential S stem Raw Coolin Water RC Emergency Equipment Coolin Water EEC Pipe Se ment 3-024-002 3-067-005 3-067-006, 007, 008 Indirect Im acts 250V RMOV 3C 480V RMOV3C Cores ra, RHR um s B&D 3.4 Failure Assessment Failure estimates were generated utilizing industry failure history, plant specific failure history, and other relevant information.
Evaluation ofthe frequency ofpiping failure was performed using the WinPRAISE program where possible. IfWinPRAISE was not applicable, deterministic methods were used.
The implementation ofthese programs and results ofthis evaluation are described in the following sections ofAppendix Ato 3-SI-4.6.G.
5.1 5.2 5.3 5.4 5.5 Review ofPlant Failure History Determination ofDegradation Mechanisms Screening Failure Rate Determination Segment Failure Rates The failure history ofpiping systems at BFN was reviewed for system leakage and other piping failures. This failure history review identified approximately 200 records for detailed analysis.
In addition, the TVATracking and Reporting ofOpen Items (TROI) database was searched and generated 937 items for review.
Each system was also analyzed for the parameters indicative ofparticular degradation mechanisms.
Identified mechanisms were utilized to assure proper failure rates were determined.
Results ofthese reviews and analyses along with the determined failure rates are incorporated in each system's section ofAppendix A to 3-SI-4.6.G.
TVAperformed two sensitivity studies to bound failure rates due to FAC. The first increased the failure rate by an order ofmagnitude to assure no additional FAC-affected segment became significant; the second eliminated FAC as a failure mechanism to ensure no other segments were masked by the failure due to FAC. Another sensitivity study was performed to assure all socket welds requiring VT-2 examination were identified.
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3.5 Risk Evaluation Each piping segment-within the scope ofthe program was evaluated to determine its core damage frequency (CDF) and large early release frequency (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 ofthese calculations are presented in Table 3.5-1. The Applicable CDF due to piping failure based on. the applicable case is 1.16E-OS.
The Applicable LERF due to piping failure based on the applicable case is 3.25E-06.
The core damage frequency due to piping failure without operator action is 1.44E-05, and with operator action is 1.16E-05.
The large early release frequency due to piping failure without operator action is 5.62E-06 and with operator action is 3.25E-06 Table 3.5-1 PIPING RISK CONTRIBUTION BY SYSTEM
+-S stem 001 MS CDF-OA 2.45E-07 CDF-noOA 2.45E-07 Applicable Applicable LERF-CDF CDF OA 2.45E-07 2.11%
7.03E-08 LERF-noOA 7.03E-08 Applicable Applicable LERF LERF 7.03E-08 2.16%
002 CDW 1.12E-08 1.23E-08 1.12E-08 0.10%
3.13E-09 3.45E-09 3.13E-09 0.10%
003 FW 6.69E-07 6.69E-07 6.69E-07 5.77%
1.87E-07 1.87E-07 1 87E-07 5 75%
063 SLC 1.06E-08 067 EECW 1.91E-08 068 RECIRC 3.33E-06 069 RWCU 1.52E-06 070 RBCCW 1.91E-08 071 RCIC 1.30E-09 073 HPCI 1.45E-08 023 RHRSW 1.59E-09 024 RCW 5.30E-09 027 CCW 2.00E-09 1.77E-09 5.32E-09 2.46E-09 1.06E-08 1.95E-07 3.34E-06 1.53E-06 1.91E-08 3.28E-07 1.45E-08 1.59E-09 0.01%
4.45E-10 5.30E-09 0.05%
1.48E-09 2.46E-09 0.02%
5.61E-10 1 06E-08 0 09%
2 98E-09 1.96E-08 0.17%
5.34E-09 3 34E 06 28 81%
9 34E 07 1.52E-06 13.11%
4.26E-07 1.91E-08 0.16%
5.36E-09 1.97E-09 0.02%
4.01E-10 1 45E-08 0.13%
4.07E-09 4.96E-10 1.49E-09 6.89E-10 2.97E-09 5.45E-08 9.34E-07 4.30E-07 5.36E-09 3.26E-07 4.08E-09 4.45E-10 0.01%
1 48E-09 0 05%
6.89E-10 0.02%
2 98E-09 0 09%
5.48E-09 0.17%
9.34E-07 28.72%
4.26E-07 13.10%
5.36E-09 0.17%
6.27E-10 0.02%
4.08E-09 0.13%
074 RHR 1.77E-06 4.02E-06 1.77E-06 15.27%
4.96E-07 2.40E-06 4.97E-07 15.28%
075 CS 078 FPC 3.95E-06 O.OOE+00 085 CRD 1.16E-08 Total:
1.16E-05 4.04E-06 0.00E+00 1.22E-09 1.44E-05 3.95E-06 34.08%
1.11E-06 0 OOE+00 0.00%
0.00E+00 1.16E-08 0.10%
3.25E-09 1.16E-05 100.00%
3.25E-06 1.20E-06 O.OOE+00 3.40E-10 5.62E-06 1.11E-06 34.13%
0 OOE+00 0.00%
3 25E-09 0.10%
3 25E-06 100.00%
3.6 Expert Panel Process Development ofthe Browns Ferry Risk-Informed program was reviewed and approved by an Expert Panel.
The Expert Panel included members ofthe expert panel that had been established to implement the Maintenance Rule. In an NRC inspection conducted April 14-18, 1997, to inspect the implementation ofthe Maintenance Rule, the conduct ofthe Expert Panel meetings
I
was noted as a strength.
In addition, the same expert panel is responsible for the risk-ranking study performed to support implementation ofGL 89-10 on motor operated valves.
To increase efficiency ofthe review process, it was decided to conduct the reviews in a phased manner, validating results ofeach phase prior to continuing. This had two advantages:
First, any changes to early stages could be made before the action was carried through the later stages; and, secondly, review ofindividual portions rather than the entire program at once spread the time requirement for the panel members over several months, rather than in one concentrated period.
Itwas recognized that due to elapsed time and possible change in panel members, it would be recommended to conduct periodic refresher sessions in the techniques being reviewed.
The Unit 2 Risk-Informed program was reviewed first. Two initial sessions were held in which the principal investigators gave an overview ofthe entire process and answered questions.
Atthe next meeting ofthe RI-ISI project with the Expert Panel, a review ofactions taken to that time, along with preliminary results, was given to the panel for study prior to actually reviewing and approving the actions.
Each member was provided with a notebook outlining the techniques used and the results determined for each individual system and its segments.
Three sessions were devoted to reviewing and approving segment definition, consequence determination, and PSA impact. As support to their decisions, the Expert Panel called for a review ofsegment failure consequences and degradation mechanisms by the respective system engineers.
In addition, the panel called for a systems interface review by a former Browns Ferry Operations (Senior Reactor Operator) and Maintenance Manager.
This review included simulating some scenarios on the Operations Training simulator to ascertain that plant response had been properly determined.
One session was devoted to a re-briefing on the determination ofpiping segment failure probability.
Atthe next session, the individual failure rates were reviewed and approved.
In a final session, the segment significances and the element examinations were reviewed and approved. It should be noted that as a rule ofthumb, the panel decided that each segment with a contribution to risk signified by a RRW > 1.001 would be selected for examination (those segments generally regarded as "medium" consequence segments).
In addition, for defense in depth it was decided that all segments which could result in a large loss ofcoolant accident (LOCA), regardless of actual risk value, would also be selected.
The philosophy ofthe panel was not to just select those segments which contributed significantly to risk, but conversely, to only eliminate those segments which clearly did not contribute to risk.
The Unit 3 Risk-Informed Program was reviewed in two sessions.
The primary thrust of.these meetings was to analyze and understand the differences between Unit 2 and Unit 3, and how those differences affected the comparative results ofthe two studies.
The chairperson appointed someone to record the minutes ofeach meeting.
The minutes included the names ofmembers and alternates in attendance and whether a quorum was present.
The minutes contained relevant discussion summaries and the results. ofmembership voting. These minutes are available as program records.
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3.7 Expert Panel Categorization Per ASME Code Case N-577, all segments with RRW > 1.005 should be considered High Safety Significant. These segments are shown in Table 3.7-1 and account for 97.04% oftotal core damage frequency due to pipe failures.
Table 3.7-1 High Safety Significant segments Segment Description Segment CDF
%Applicable Cum %
CDF CDF RRW 34I7$402 1"-12" discharge line from penetration -1 6A and penetration X-27D to reactor (N5A) 2.39E4I6 20.60%
20.60%
1.260 3-075401 1"-12" discharge line from penetration X-168 and penetration X-27C to reactor (N58) 3469-001 6" discharge line from 20" RHR line to penetration X-14 3474407 24" line from recirculation line "A"to penetration X-12'4M8-006 12" discharge line from Recirc ring header "A"to Reactor (N2H) 1.55E%6 1.52E~
'.17E46 6.57E7 13.36%
3396%
1 154 5.66%
62.81%
1.060 13.10%
47.06%
1.151 10.09%
57.15%
1.112 3401%36 3-001-037 26" discharge line from Reactor to penetration X-7Aincluding valves PCV-1<, 179, 5 and penetrations X<4Aand BOA 26" discharge line from'Reactor to penetration X-78 Including valves PCV-1-18, 19, 22, 23 and penetrations X448 and X-308 3468O11 12" discharge line from Recirc ring header "8"to Reactor (N2C) 34)74-013 24" discharge line from penetration X-138 to recirculation line "A" 3-068-012 12" discharge line from Recirc ring header "8"to Reactor (N28) 3<68-013 12" discharge line from Recirc ring header "8"to Reactor (N2A) 3-068-007 12" discharge line from Recirc ring header "A"to Reactor (N2J) 5468-001 28" suction line from Reactor (N1A) to Recirculation pump "A" 34)68-005 12" discharge line from Recirc ring header "A"to Reactor (N2G) 3468-008 12" discharge line from Recirc ring header "A"to Reactor (N2K) 3468-010 12" discharge line from Reclrc ring header "8"to Reactor (N2D)
$474405 24" discharge line from penetration X-13A to recirculation line "8" 5.66')7 5.17E<7 4.59')7 4.03E<7 3.86E%7 2.80E4)7 1.82E4)7 1.66E<7 1.54')7 6.13E<8 5.65')8 5.65E48 4.88%
4.46%
3.96 ok 3.47%
3.33%
2.41%
1 57ok 1A3%
1.33 ok 0.53%
0.49%
0.49%
67.69%
1.051 72.15%
1 047 76 11ok 1 041 79.58%
1.036 82.91%
1.034 85.32%
1.025 86.89%
1.016 88.32%
1.015 89.65%
1.013 90.18%
1.005 90.67%
1.005 91.16%
1.005 3401-038 26" discharge line from Reactor to penetration X-7C including valves PCV-1 QO, 31, 34, and penetrations X44C and XQOC 5.65E48 0.49%
91.65%
1.005 3401-039 26" discharge line from Reactor to penetration X-7D including valves PCV-1-41, 180, 42 and penetrations X44D and X-30D 3403-006 24" supply line from penetration X-9Ato HCV-3-67 3-003407 24" supply line from penetration X-98 to HCV-3-66 3-003-036 20" supply line from HCV-3-67 to 12'nlet piping - ring header 3403437 12" supply line from 20" ring header to Reactor (N4A) 3-003438, 12" supply line from 20" ring header to Reactor (N48) 3403439 12" supply line from 20" ring header to Reactor (N4C) 3403440 20" supply line from HCV-346 to 12" inlet piping - ring header 34I03Z41 12" supply line from 20" ring header to Reactor (N4F) 34)03442 12" supply line from 20" ring header to Reactor (N4E) 3403443 12" supply line from 20" ring header to Reactor (N4D) 5.65E48 5.65E<8 5.65E48 5.65E48 5.65EZ8 5.65E48 5.65E48 5.65E48 5.65E48 5.65E48 5.65')8 0.49'k 0.49%
0.49'k 0.49%
0.49%
0.49%
0.49%
0.49%
0.49%
0.49%
0.49%
92 14ok 1.005 92 63%
1 005 93 12ok 1.005 93.61 ok 1.005 94 10%
1 005 94.59%
1.005 95.08 ok 1.005 95.57%
1 005 96.06%
1.005 96 55%
1.005 97.04%
1.005 E-18
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For defense in depth all additional'segments with RRW > 1.001 and those segments which could result in a large LOCA(initiating events LLC, LLD,LLO, or LLS) are considered for examination.
These segments are shown in Table 3.7-2. With the addition ofthese segments, 97.75% oftotal core damage frequency due to pipe failures is accounted for.
Table 3.7-2 Defense in Depth Segments Segment Description 3~$ 416 28" suction line from Reactor (N18) to Recirculation pump "8" 3468402 28" discharge line from Recirculation pump "A"to Recirc ring header
~8-004 12'ischarge line from Recirc ring header "A"to Reactor (N2F) 3468409 12'ischarge line from Recirc ring header "8" to Reactor (N2E) 3-068%14 28" discharge line from Recirculation pump "8" to Recirc ring header 3-073-001 10" supply line from 26" MS line "8" to penetration X-11 3~8~3 22" line Recirc ring header "A" 3~8%15 22" line Recirc ring header "8" Segment CDF 2.83E<8 2.68 EBS 1.52M)8 7ASE<9 3.20E%9 2.82E-09 O.OOE+00 O.OOE+00
%Applica Gum%
97.28%
1.002 0.23%
97.51%
'.002 0.13%
97.64%
1.001 0.06%
97.70%
1.001 0 03%
97 73%
1 000 0.02%
97.75%
1.000 0.00%
97.75%
1.000 0.00%
97.75%
1.000 Large Early Release Frequency (LERF) was also considered in determining segment significance.
Allsegments with a LERF RRW >1.001 were already selected for examination based on CDF RRW.
The contribution ofeach system to CDF and to LERF was calculated and was shown in Table 3.5-1. The predominant contributors to CDF are Core Spray, Reactor Recirculation, Residual Heat'Removal, and Reactor Water Clean Up with Feedwater and Main Steam also contributing. The same systems also contribute to LERF. The significance ofall ofthese systems is due to the possibility ofa'large LOCA, in combination with active degradation mechanisms (FAC and IGSCC).
Table 3.7-3 shows the distribution-of system segments by both consequence and risk categories, along with the final designation as High Safety Significant by the. Expert Panel. Allofthe segments which contribute to the risk distribution described above were selected by the Expert Panel.
Since the Expert Panel decided to,include all Medium Risk Category segments, no further re-consideration was needed.
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Table 3.7-3 SEGMENT CATEGORIZATION
'ystem
¹ Segs Consequence category Risk category 001 MS 002 CDW 003 FW 56 36 46 High CCDP
>1E-004 10 Medium CCDP
>1E-06,
<1E-04 38'6 31 Low CCDP
<1E-06 14 10 High RRW
>1.005 10 Medium RRW
>1.001,
<1.005 Low RRW
<1.001 52 36 36 Expert Panel HSS 10 023 RHRSW '5 024 RCW 20 027 CCW 063 SLC 067 EECW 28 068 RECIRC 16 069 RWCU 19 070 RBCCW 17 071 RCIC 12 16 12 18 17 33 17 15
,3 45 20 28 18 17 12 16 073 HPCI 074 RHR 075 CS 078 FPC 085 CRD 31 15 31 16 4
=
2 24 28 13 31 total:
392 47 207 138 29 360 37 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 (NDE) methods were defined.
The iriitialprogram being submitted addresses the high safety significant (HSS) piping components placed in regions 1 and 2 ofFigure 3.7-1 in WCAP-14572, revision 1. Region 3 piping components, which are low safety significant, are to be considered in an Owner Defined Program and'is not considered part ofthe program requiring approval.
Region 1, 2, 3 and 4 piping components willcontinue to receive Code required pressure testing, as part ofthe current ASME Section XI-program For the 392 piping segments that were evaluated in the RI-ISI program, Region 1 contains 35 segments, Region 2 contains 2 segments, Region 3 contains 56
- segments, and Region 4 contains 299 segments.
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Table 1, ofCode Case N-577 provides the specific requirements for Category R-A, Risk-Informed Piping Examinations.
This category is sub-divided into Item Numbers Rl. 1 1 through R1.18.
These sub-divisions are. based on degradation modes, and provide the specific requirements for each identified mode.
The Item Numbers determined to be applicable to this program are:
Rl. 1 1 Elements Subject to Thermal Fatigue Rl.16 Elements Subject to Intergranular Stress Corrosion Cracking (IGSCC)
R1.18 Elements Subject to Flow A'ccelerated Corrosion Paragraph I-6.1 ofthe Code Case states that when a postulated failure mode for a element is being addressed by a program already in place, that program may be used to satisfy the requirements ofTable 1, subject to certain conditions.
As such, the existing FAC and IGSCC programs willbe utilized to meet these requirements.
Per paragraph -2500 (b) ofthe Code Case, pressure testing and VT-2 visual examinations shall be performed on Class 1, 2, and 3 piping systems in accordance with the Inservice-Inspection Program implemented by 3-SI-4.6.G.
The examinations determined for the Browns Ferry Unit 3 Risk-Informed ISI Program are listed in Table 3.8-1. Alllocations identified for examination are locations already identified under existing programs, either Section XI, IGSCC, or FAC.
Frequency ofexamination is specified in Table 1 ofCode Case N-577. The examinations shall be scheduled such that the requirements ofTable IWB-2412-1 ofSection XIand NMG-0313 are satisfied.
Per paragraph I-6.1 as referenced above, when an existing program is used to satisfy the requirements ofTable 1, examinations shall be scheduled per that program.
The examination frequency determined for the Browns Ferry Unit 3 Risk-Informed ISI Program are listed in Table 3.8-1. The schedule is documented in 3-SI-4.6.G.
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Table 3.8-1 Examinations Se ment Bounda Descri tion Plant ID De Mode Item ¹ Exam Fre 3-001-036 3-001437 3-001438 3401-039 3-003406 3-003407 3403409 3403436 3403437 3403438 3403439 3403440 3403441 3403442 3403443 MSLA Inside containment MSL 8 inside containment MSL C Inside containment MSL D Inside containment FW line from X-9Ato HOVE FW line from X-98 to HCV<%6 FW line from steam tunnel wall to X-98 FW ring header A FW Riser A FW Riser 8 FW Riser C FW ring header 8 FW Riser F FW Riser E FW Riser D FAC FAC FAC FAC FAC FAC FAC FAC FAC FAC FAC FAC FAC FAC FAC R1.18 R1.18 R1.18 R1.18 R1.18 R1.18 R1.18 R1.18 R1.18 R1.18 R1.18 R1.18 R1.18 R1.18 R1.18 Note 1 Note 1 Note 1 Note 1 Note 1 Note 1 Note 1 Note 1 Note 1 Note 1 Note 1 Note 1 Note 1 Note 1 Note 1 Note 2 Note 2 Note 2 Note 2 Note 2 Note 2 Note 2 Note 2 Note 2 Note 2 Note 2 Note 2 Note 2 Note 2 Note 2 3-068401 Recirculation pump "A"Suction GRW53(OL)
GRW54(OL)
GR4-57(OL)
IGSCC-E R1.16 IGSCC-E R1.16 IGSCC-E R1.16 IGSCC Vol IGSCC Vol IGSCC Vol Altcycle.
Altcycle Altcycle 3468402 3468403 3-068404 Recirculation pump "A"Discharge Recirc ring header "A" Recirc riser F GR443(OL)
IGSCC-E R1.16 RWR4401-G019 IGSCC-A R1.16 IGSCC-A R1.16 RWRQ401-G001 IGSCC Vol IGSCC Vol IGSCC Vol Altcycle Interval Interval 3468405 3468406 Recirc riser G Recirc riser H RWRQ401-G016 RWR4-001-G004 RWR4-001-G006 RWR-3-001-G007 IGSCC-A R1.16 IGSCC-A R1.16 IGSCC-A R1.16 IGSCC-A R1.16 IGSCC Vol IGSCG Vol IGSCC Vol IGSCC Vol Interval Interval Interval Intewal 3468-007
'468-008 3468409 3468410 Recirc riser J Recirc riser K Recirc riser E Recirc riser D RWR~1-G024 IGSCC-A R1.16 RWR~2-G023 IGSCC-A R1.16 RWR4402-G010 IGSCC-A R1.16 RWR4402-G012 IGSCC-A R1.16 IGSCC-A R1.16 RWR4402-G022 RWR4401-G009 IGSCC-A R1.16 RWR4401-G020 IGSCC-A R1.16 RWRN401-G010 IGSCC-A R1.16 RWR4401-G012 IGSCC-A R1.16 RWR4401-G022 IGSCC-A R1.16 RWR4401-G013 IGSCC-A R1.16 RWR4401-G015 IGSCC-A R1.16 IGSCG Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol Interval Interval Interval Interval Interval Interval Interval Intewal Interval Interval Interval Interval 3468411 3468412 Recirc riser C Recirc riser 8 RWRD402-G007 RWR-3402-G009 RWR-3402-G020
. RWR-3402-G004 RWR-3402-G006
'GSCC-A R1.16 IGSCC-A R1.16 IGSCC-A R1.16 IGSCC-A R1.16 IGSCC-A R1.16 IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol Interval Interval Intewal Interval Intewal 3-068413 3-068414 3-068-015 3-068-016 Recirc riser A Recirculation pump "8" Discharge Recirc ring header "8" Recirculation pump "8" Suction RWR-3402-G018 RWR-3-002-G001 IGSCC-A R1.16 IGSCC-A R1.16 GR4-27(OL)
IGSCC-E R1.16 RWR4402-G019 IGSCC-A R1.16 GRW59(OL)
IGSCC-E R1.16 RWR4402-G003 IGSCC-A R1.16 RWR4402-G016 IGSCC-A R1.16 IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol Interval Interval Interval Interval Altcycle interval Altcycle E-'22
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Table 3.8-1 Examinatfdns
'e ment Bounda Descri tion Plant ID GRQ~(OL)
GR4-63 GR-344(OL)
D Mode Item If IGSCC-E R1.16 IGSCC-E R1.16 IGSCC-E R1.16 IGSCC Vol IGSCC Vol IGSCC Vol Fr Altcycle Altcycle Altcycle 3-069-001 RWCU from RHR to X-14 RWCU44X11-G011 IGSCC-A R1.16 RWCUQ-001-GOI6 IGSCC-A R1.16 RWCUQ-001-G017 IGSCC-A R1.16 RWCU-3-001-G018 IGSCC-A R1.16 RWCU-3~1-G019
'GSCC-A R1.16 RWCU-3-001-G024 IGSCC-A R1.16 RWCU-3-001-G025 IGSCC-A R1.16 RWCU-3-001-G026 IGSCC-A R1.16 IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol Interval Interval interval Interval Interval Interval Interval Interval 373401 HPCI steam supply from MSL"B"to X-11 THPCI-3-073A Stress R1.11 XI Vol Interval 3%74005 3-074-007 3-074-013 3-075-001 3%75402 RHR from X-13A to recirc line "B" RHR from recirc line "A"to X-12 RHR from X-13B to recirc line "A" CS line B to reactor (N5B)
CS line A to reactor (N5A)
DRHRC-03B DSRHR-3%4A DRHRD-19 DRHR4-21 DSRHR-348 DSRHR-3%9 DSRHR-3-10 DSRHRD-11(OL)
TRHR4-191 DRHR4-13B DSCS~7 DSCS~8 DSCS~9 TC8-M1 TSCSW402 TOST~
TOST~
TCSZP10 DOSE)4 DSCS~1 DSCS~2 TCS4417 TC8-3422 TSCSQ-41 8 IGSCC-G R1.16.
IGSCC-C R1.16 IGSCC-C R1.16 IGSCC-C R1.16 IGSCC-C R1.16 IGSCC-C R1.16 IGSCC-C R1.16 IGSCC-E R1.16 IGSCC-C R1.16 IGSCC-G R1.16 IGSCC-C R1.16 IGSCC-C R1.16 IGSCC-C R1.16 IGSCC-A R1.16 IGSCC-A R1.16 IGSCC-C R1.16 IGSCC-C R1.16 IGSCC-C R1.16 IGSCC-C R1.16 IGSCC-C R1.16 IGSCC-C R1.16 IGSCC-A R1.16 IGSCC-C R1.16 IGSCC-A R1.16 IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol IGSCC Vol Cycle Interval Interval Interval Interval Interval Interval Altcycle Interval Cycle Interval Interval Interval Interval Interval Interval Interval interval interval interval'nterval Interval Interval Interval Notes:
Note 1 Note 2 Examination to be performed per FAC program.
Examinations to be scheduled per the FAC program. This schedu'ie is a function of previous exam results and predicted wear rate.
IGSCC Vol'olumetric examination per NUREG-0313 capable of detecting IGSCC. Competency requirements of NUREG4)313 are applicable.
XI Vol Volumetric examination per Section XIof the Boiler and Pressure Vessel Code as implemented by 3-SIP.6.G.
Interval
.Examined once per ten-year interval per the requirements of Section XI and the requirements of NUREG<313 for IGSCC Category A and C welds.
Altcycle Examined every two cycles (50% per alternate cycle) per the requirements of Section XI and the requirements of NUREG4313 for IGSCC Category D and E welds.
Cycle Examined every cycles per the requirements of NUREG4313 for IGSCC Category G welds.
Examinations shall be scheduled such that the requirements of IWB-2412 of Section XI are satisfied.
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Additional Examinations Additional examinations willbe performed in accordance with Section -2430 ofCode Case N-577, as implemented in Section 7.12.5.4-I ofTVABFN Surveillance Instruction 3-SI-4.6.G.
3.9 Program Relief Requests Alternate methods are specified to ensure structural integrity in cases where examination methods cannot be applied due to limitations such as inaccessibility or radiation exposure hazard.
An attempt has been made to provide a minimum of)90% coverage (per Code Case N-460) when performing the risk-informed examinations.
However, some limitations willnot be known until the examination is performed, since some locations willbe examined for the first time by the specified techniques.
Atthis time, the risk-informed examination locations that have been selected provide )90%
coverage.
In instances where a location may be found at the time ofthe examination to not meet
)90% coverage, the process outlined in Section 4.1 ofWCAP-14572, revision 1 willbe 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 ofthis program is expected to decrease when compared to that estimated from current Section XIrequirements and to be neutral when compared to that estimated from current requirements including both Section XIand augmented.
A comparison between the proposed RI-ISI program and the current ASME Section XIISI program was made to evaluate the change in risk.
Change in risk (both CDF and LERF) was calculated for each segment and the results tabulated by system, as shown in Table 3.10-1. The predominant contributors to CDF are Core Spray, Reactor Recirculation, Residual Heat Removal, and Reactor Water Clean Up with Feedwater and Main Steam also contributing. The same systems also contribute to LERF. The significance ofall ofthese systems is due to the possibility ofa large LOCA, in combination with active degradation mechanisms'(FAC and IGSCC).
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Table 3.10-1, COMPARISON BY SYSTEM OF CDF/LERF DETECTED BY CURRENT PROGRAMS AND DETECTED BY RISK-INFORMED PROGRAM Applicable CDF System
¹ segs Total Current-XI Current Aug Proposed Rl+ Aug 001 MS 56 2.45E-07 0.00E+00 2.35E-07 2.35E-07 002 003 023 024 027 063 067 068 069 070 071 073 FW 46 RHRSW 45 RCW 20 CCW 3
SLC EECW 28 RECIRC 16 RWCU 19 RBCCW 17 RCIC 12 HPCI 11 CDW 36 1.12E-08 6.69E-07 1.59E-09 5.30E-09 2.46E-09 1.06E-08 1.96E-08 3.34E-06 1.52E-06 1.91E-08 1.97E-09 1.45E-08 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 O.OOE+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 2.82E-09 8.57E-09
'.79E-07 0.00E+00 O.OOE+00 O.OOE+00 0.00E+00 0.00E+00 3.34E-06 1.52E-06 0.00E+00 O.OOE+00 O.OOE+00 8.57E-09 5.79E-07 0.00E+00 O.OOE+00 O.OOE+00 0.00E+00 0.00E+00 3.34E-06 1.52E-06 O.OOE+00 O.OOE+00 2.82E-09 074 075 078 085 RHR CS FPC CRD Total:
31 15 31 392 1.77E-06 3.95E-06 0.00E+00 1.16E-08 1.16E-05 1.44E-09 0.00E+00 0.00E+00 0.00E+00 4.26E-09 1.76E-06 3.94E-06 0.00E+00 0.00E+00 1.14E-05 1.76E-06 3.94E-06 0.00E+00 0.00E+00 1.14E-05 001 MS Applicable LERF System
¹ segs 56 Total 7.03E-08 Current XI 0.00E+00 Current Aug 6.72E-08 Proposed Rl+ Aug 6.72E-08 002 003 023 024 027 063 067 068 069 070 071 073 074 075 078 085 FW 46 RHRSW 45 RCW 20 CCW 3
SLC EECW 28 RECIRC 16 RWCU 19 RBCCW 17 RCIC 12 HPCI'HR 31 15 CS FPC CRD 31 CDW 36 3.13E-09 1.87E-07 4.45E-10 1.48E-09 6.89E-10 2.98E-09 5.48E-09 9.34E-07 4.26E-07 5.36E-09 6.27E-10 4.08E-09 4.97E-07 1.11E-06 0.00E+00 3.25E-09 0.00E+00 0.00E+00 O.OOE+00 O.OOE+00 O.OOE+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 7.89E-10 4.04E-10 O.OOE+00 0.00E+00 0.00E+00 2.40E-09 1.62E-07 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 9.34E-07 4.25E-07 O.OOE+00 0.00E+00 0.00E+00 4.93E-07 1.10E-06 0.00E+00 0.00E+00 2.40E-09 1.62E-07 O.OOE+00 0.00E+00 0.00E+00 O.OOE+00 O.OOE+00 9.34E-07 4.25E-07 O.OOE+00 O.OOE+00 7.89E-10 4.93E-07 1.10E-06 0.00E+00 0.00E+00 Total:
392 3.25E-06 1.19E-09 3.19E-06 3.19E-06 E-25
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Table 3.10-1, COMPARISON BY SYSTEM OF CDF/LERF DETECTED BY CURRENT PROGRAMS AND DETECTED BY RISK-INFORMED PROGRAM CDF-OA System 001 002
¹ segs 56 MS CDW 36 Total Applicable 2.45E-07 1.12E-08 Current XI O.OOE+00 O.OOE+00 Current Aug 2.35E-07 8.57E-09 Proposed RI+ Aug 2.35E-07 8.57E-'09 003 FW 46 6.69E-07 0.00E+00 5.79E-07 5.79E-07 023 024 027 063 067 068 069 070 RHRSW 45 RCW 20 CCW 3
SLC EECW '8 RECIRC 16 RWCU 19 RBCCW 17 1.59E-09 5.30E-09 2.01E-09 1.06E-08 1.91E-08 3.34E-06
. 1.52E-06 1.91E-08 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 O.OOE+00, 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 3.34E-06
. 1.52E-06 0.00E+00 O.OOE+00 O.OOE+00 O.OOE+00 0.00E+00 O.OOE+00 3.34E-06 1.52E-06 O.OOE+00 071 RCIC 12 1.30E-09 0.00E+00 0.00E+00 O.OOE+00 073 074 075 RHR CS 31 15 HPCI 11 1.45E-'08 1.77E-06 3.95E-06 2.82E-09 1.44E-09 4.63E-10 1.76E-06 3.94E-06 1.76E-06 3.94E-06 0.00E+00
~
2.82E-09 078 085 FPC CRD Total:
31 392 0.00E+00 1.16E-08 1.16E-05 O.OOE+00 O.OOE+00 4.72E-09 O.OOE+00 0.00E+00 1.14E-05 0.00E+00 0.00E+00 1.14E-05
, CDF-no OA System
¹ segs Total Applicable Current XI, Current Aug Proposed RI+ Aug 001 002 003 023 024 027 063 067 068 069 070 071 073 074 075 078 MS 56 FW 46 RHRSW 45 RCW 20 CCW 3
SLC EECW 28 RECIRC 16 RWCU 19 RBCCW 17 RCIC 12 HPCI 11 RHR 31 CS
'FPC 15 CDW 36 2.45E-07 1.23E-08 6.69E-07 1.77E-09 5.32E-09 2.46E-09 1.06E-08 1.95E-07 3.34E-06 1.53E-06 1.91E-08 3.28E-07 1.45E-08 4.02E-06 4.04E-06 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 O.OOE+00 O.OOE+00 0.00E+00 0.00E+00 0.00E+00 O.OOE+00i 0.00E+00 0.00E+00 2.82E-09 2.19E-06 0.00E+00 O.OOE+00 2.35E-07 8.57E-09 5.79E-07 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 3.34E-06 1.52E-06 0.00E+00 0.00E+00 0.00E+00 1.76E-06 3.94E-06 O.OOE+00 2.35E-07 8.57E-09 5.79E-07 0.00E+00 O.OOE+00 0:00E+00 0.00E+00 O.OOE+00 3.34E-06 1.52E-06 0.00E+00 0.00E+00 2.82E-09 1.76E-06 3.94E-06 0.00E+00 085 CRD Total:
31'92 1.22E-09 1.44E-05 0.00E+00 2.19E-06 0.00E+00 1.14E-05 0.00E+00 1.14E-05 E-26
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Table 3.10-1.
COMPARISON BY SYSTEM OF CDF/LERF DETECTED BY CURRENT PROGRAMS AND DETECTED BY RISK-INFORMED.PROGRAM LERF-OA System 001 002 003 023 024 027 063 067 068 069 070 071 073 074 075 078 085 MS CDW FW RHRSW RCW CCW SLC
¹ segs 56 36 46 45 20 28 16 19 17 12 31 15
~
31 392 Total Applicable 7.03E-08
. 3.13E-09 1.87E-07 4.45E-10 1.48E-09 5.61E-10 2.98E-09 5.34E-09 9.34E-07 4.26E-07 5.36E-09 4.01E-10 4.07E-09 4.96E-07 1.11E-06 0.00E+00 3.25E-09 3.25E-06 Current XI 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 7.89E-10 4.04E-10 0.00E+00 0.00E+00 0.00E+00 1.19E-09 Current Aug 6.76E-08 2.40E-09 1.62E-07 0.00E+00 0.00E+00 0.00E+00 O.OOE+00 0.00E+00 9.34E-07 4.25E-07 0.00E+00 0.00E+00 0.00E+00 4.93E-07 1.10E-06 0.00E+00 0.00E+00 3.19E-06 Proposed Rl+ Aug 6.76E-08 2.40E-09 1.62E-07 0.00E+00 O.OOE+00 0.00E+00 0.00E+00 0.00E+00 9.34E-07 4.25E-07 0.00E+00 0.00E+00 7.89E-10 4.93E-07 1.10E-06 O.OOE+00 0.00E+00
'.19E-06 LERF-no OA System 001 002 003 023 024 027 063 067 068 069 070 071 073 074 075 078'85 MS CDW FW RHRSW.
RCW CCW SLC EECW RECIRC RWCU RBCCW RCIC HPCI RHR CS FPC CRD Total:
¹segs 56 36 46 45 20 28 16 19 17 12 31 15 31 392 Total Applicable 7.03E-08 3.45E-09 1.87E-07 4;96E-10 1.49E-09 6.89E-10 2.97E-09 5.45E-08 9.34E-07 4.30E-07 5.36E-09 3.26E-07 4.08E-09 2.40E-06 1.20E-06 0.00E+00 3.40E-10 5.62E-06 Current XI 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 O.OOE+00 O.OOE+00 0.00E+00 7.89E-10 1.83E-06 0.00E+00 0.00E+00 O.OOE+00 1.83E-06 Current Aug 6.76E-08 2.40E-09 1.62E-07 0.00E+00 0.00E+00 0.00E+00 0.00E+00 0.00E+00 9.34E-07 4.25E-07 0.00E+00 O.OOE+00 0.00E+00 4.93E-07 1.10E-06 0.00E+00 O.OOE+00 3.19E-06 Proposed Rl+ Aug 6.76E-08 2.40E-09 1.62E-07 O.OOE+00 0.00E+00 O.OOE+00 0.00E+00 0.00E+00 9.34E-07 4.25E-07 0.00E+00 0.00E+00 7.89E-10 4.93E-07 1.10E-06 0.00E+00 0.00E+00 3.19E-06
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Table 3.10-2 provides a comparison ofCDF/LERF detected by the current and Risk-Informed programs.
The current Section XIprogram only detects 0.04% CDF (4.26E-09); however, the combination ofcurrent XI and current augmented programs willdetect 98.27% CDF (1.14E-05) and 98.18% LERF (3.19E-06) and the Risk-Informed ISI and augmented programs willdetect the same.
This represents a positive change in risk detected when compared to XI only, and a risk neutral application when compared to the combination ofXIand augmented programs. Total undetected CDF is 2.0E-07 and undetected LERF is 6.0E-08.
Table 3;10-2 COMPARISON OF CDF/LERF DETECTED BY CURRENT PROGRAMS AND DETECTED BY RISK-INFORMED PROGRAM Piping CDF/LERF detected by:
Case CDF with Operator action CDF No Operator Action Applicable CDF LERF with Operator action LERF No Operator Action Applicable LERF Applicable CDF/LERF 1.16E-05 1.44E-05 1.16EW5 3.25E-06 5.62E-06 3.25E-06 Current Section XI 4.72E-09 0 04 2.19E-06 15 19%
4.26EW9 0.04%
1.19E-09 0 04%
1.83E-06 32.63%
1.19E49 0 04%
Current Section XI
+ Augmented 1.14E-05 98.27%
1.36E-05 94 11%
1.14EC5 98.27%
3.19E-06 98 24%
5.02E-06 89 37%
3.19E46 98.18%
Proposed Risk-Informed
+ Augmented 1.14E-05 98.27%
1.14E-05 78.92%
1.14EC5 98.27%
3.19E-06 98.21%
3.19E-06 56.76%
3.19E-06 98.18%
Defense-In-De th The basic concept ofdefense-in-depth is to provide multiple means to accomplish safety functions and prevent the release ofradioactive materials.
Multiple means to accomplish safety functions are provided by the functional redundancy inherent in plant design.
The PSA used as the basis ofthis analysis models these redundant functions.
Individual quantifications were performed in this PSA for each instance in which a potential pipe failure impacted a mitigating system with no specific associated initiating event.
These quantifications incorporated all potential initiating events, maintaining the system redundancy inherent to maintaining defense-in-depth.
Defense-in-depth with respect to radioactive material is maintained by assuring there are multiple barriers to release. The first barrier is the fuel cladding, whose damage is the basis for the Core Damage Frequency metric basic to this analysis.
The next barrier is reactor coolant pressure boundary integrity. To assure that this barrier is maintained, additional areas are identified for E-28
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their cqptrjbution to reducing risk ofcore damage frequency.
Specifically, piping which could potentially result in a large LOCAwas included, even ifthe risk associated with the segment was minimal or nonexistent.
Additionally, reactor coolant pressure boundary integrity is maintained by continued implementation ofpressure testing and visual examination per ASME Section XI.
4.
IMPLEMENTATIONAND MONITORINGPROGRAM A proposed revision to TVABFN Surveillance Instruction 3-SI-4.6.G has been written to implement and monitor the RI-ISI Program.
That revision complies with the guidelines described in Regulatory Guide 1.174 and 1.178 (Trial Use) and implemented in the ASME Boiler and Pressure Vessel Code,Section XI, as Code Case N-577. Upon approval ofthe RI-ISI program, that revision willbe implemented.
The new program willbe integrated into the existing ASME Section XIinterval. No changes.to the Final Safety Analysis Report are necessary for program implementation.
The applicable aspects ofthe Code not affected by this change willbe retained, such as inspection methods, acceptance guidelines, pressure testing, corrective measures, documentation requirements, and quality control requirements.
Existing ASME Section XIprogram implementing procedures willbe retained and modified to address the RI-ISI process, as appropriate.
Additionally, the procedures include the high safety significant locations in the program requirements regardless oftheir current ASME class.
r The proposed monitoring and corrective action program willcontain the following elements:
A.
C.
D.
E.
F.
G.
Identify Characterize (1) Evaluate, determine the cause and extent ofthe condition identified (2) Evaluate, develop a corrective action plan or plans Decide Implement Monitor Trend The RI-ISI program is a livingprogram requiring feedback ofnew relevant information to ensure the appropriate identification ofhigh safety significant piping locations.
As a minimum risk ranking of,piping segments willbe reviewed and adjusted on an ASME period basis.
Significant changes may require more frequent adjustment as directed by NRC bulletin or Generic Letter requirements, or by plant specific feedback.
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5.
PROPOSED ISI PROGRAM PLAN CHANGE C
The'locations selected for examination in the RI-ISI program and augmented programs were compared to the locations examined under the previous programs.
The results are tabulated in Table 5-1. The current ASME Section XIselects a total of222 locations for non-destructive exams, while the proposed RI-ISI program selects 70 locations for exams and credits 15 FAC segments, which results in a reduction of 152 non-destructive exam locations (68.5%). The current Generic Letter 88-01 augmented program for IGSCC selects a total of 164 locations for non-destructive exams while the proposed RI program selects 137 locations for exams, which results in a reduction of27 non-destructive exam locations (16.5%).
Table 5-1 STRUCTURAL ELEMENT SELECTION RESULTS AND COMPARISON TO ASME SECTION XI 1989 EDITION REQUIREMENTS AND GL 88-01 REQUIREMENTS Current ASME XI Elements Augmented Elements Proposed (a) (b)
RI-ISI
. Examinations Augmented Elements (c)
System 001.
MS B-F Se s
B-J
'8 C-F-1 C-F-2 A C
10 D
E G
R1.11 R1.16 R1.18 A
C D
E G
002 CDW 36 003 FW 46 23 023 RHRSW 45 024 RCW 20 027 CCW 3
063 SLC 5
067 EECW 28 068 RECIRC 16 14 069 RWCU 19 070 RBCCW'7 071 RCIC 12 073 HPCI 11 074 RHR 31 18 10 44 32 19 1
5 11 2
35 4
27 2
1 2
28 A
9 E
8 A
7 C
1 E
2 G
28 32 9
272 1
2 075 CS 15 2
10 6
13 19 4
A 10 C
19 078 FPC 1
085 CRD 31 1
total:
392 17 112 13 80 67 83 2
102 69 15 40 832 102 Notes:
(a)
(b)
(c)
System pressure test requirements and VT-2 visual examinations shall continue to be performed in all ASME Code Class 1, 2, and 3 systems.
I Augmented'programs including FAC and Reactor Nozzle Thermal Fatigue Cracking (NUREG-0619) continue.
Augmented program for IGSCC Categories C through G (GL88-01, NUREG-0313) continues.
Oi c'
C C
('s
6.0 QFFFcRENCES/DOCUMENTATION "Corrosion Control Program", Tennessee Valley Authority Standard Program SPP-9.7.
"Technical Report on Material Selection and Processing Guidelines for BWR Coolant Pressure Boundary Piping,'" NUREG-0313, Revision 2, January 1988.
"Inservice Inspection and Testing," Browns Ferry Nuclear Plant Updated Final Safety Analysis Report, Section 4.12, Amendment 15.
"Inservice Inspection Program," Browns Ferry Nuclear Plant Surveillance Instruction 3-SI-4.6.G.
Maintenance Rule Performance Indicator Monitoring, Trending, and Reporting," Browns Ferry Nuclear Plant Technical Instruction O-TI-346.
"Browns Ferry Nuclear Plant Unit 2 Probabilistic Safety Assessment/Individual Plant Examination Submittal," Revision 0, RIMS R11 921007 838.
"Browns Ferry Nuclear Plant Unit 2 Probabilistic Safety Assessment/Individual Plant Examination Submittal," Revision 1, Interim Order 2, RIMS R92 950912 800.
"Pipe Rupture Evaluation for Inside and Outside Primary Containment for the Browns Ferry Nuclear Plant Units 2 and 3", Revision 4, RIMS R40 980219 990.
"Pipe Rupture Evaluation for the BFNP Unit 3 restart", Revision 3, RIMS R14 980413 103 "Browns Ferry PSA Peer Certification," BoilingWater Reactor Owner's Group, Report BWROG/PSA-9710, March 1998.
"Westinghouse Owner's Group Application ofRisk-Informed Methods to Piping Inservice Inspection Topical Report," Westinghouse Electric Corporation, WCAP-14572, Revision 1, October 1997.
"WinPRAISE 98 - PSAISE Code in Windows," Engineering Mechanics Technology Technical Report TR-98-4-1, April 1998.
"ASME Section XIContainment Inservice Inspection Program", Browns Ferry Nuclear Plant Technical Instruction O-TI-376.
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