ML18039A756

Bfnp Risk-Informed Inservice Insp (RI-ISI) Program Submittal.

ML18039A756
Person / Time
Site:	Browns Ferry
Issue date:	04/23/1999
From:	TENNESSEE VALLEY AUTHORITY
To:
Shared Package
ML18039A755	List: ML18039A754 ML18039A756
References
NUDOCS 9905030118
Download: ML18039A756 (60)

Text

TENNESSEE VALLEYAUTHORITY BROWNS FERRY NUCLEAR PLANT RISK-INFORMED INSERVICE INSPECTION (RI-ISI)

PROGRAM SUBMITTAL 99050M PDR ii8'90423 ADQCK 05000296 8 POR E-2

I 4l 1

RISK-INFORMED INSERVICE INSPECTION PROGRAM PLAN Table of Contents 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 of Program 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 Relief Requests 3.10 Change in Risk

4. Implementation and Monitoring Program

5. Proposed ISI Program Plan Change

6. References/Documentation E-3

II I

l

~I A

1. IPl'RODUCTION Inservice inspections (ISI) for Browns Ferry Nuclear Plant are currently performed on piping welds to the requirements of the 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 of this submittal is to request a change to the ISI program plan for piping through the use of a 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 BFNU3M was used to evaluate the consequences of pipe 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 TVA response 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 of detail requested in NUREG-1335. Revision 1 to the BFN PSA model then incorporated numerous individual changes, primarily in the area of plant response to loss of offsite power. The Unit 3 PSA used in this analysis (BFNU3M) is based on the Unit 2'PSA with well-documented differences.

Each of these risk models use the proprietary RISKMAN computer 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 of the initiating events to be quantified. For those quantifications that are based on failure of plant 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 of top 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

ii Qi I

. I

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 it would 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% of CDF, 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 of the normally assigned pump; however, for those scenarios which resulted in loss of EECW, no credit was taken for the start of the swing pump.

The PSA Update Report is evaluated for updating every other. refueling outage. The administrative guidance for this activity is contained in TVA Standard Engineering practice SEP-9.5.8.

During November 1997, TVA participated in a PSA Peer Review Certification of the BFN PSA administered under the auspices of the BWROG Peer Certification Committee. The purpose of the PSA peer review process is to establish a method of assessing the. technical quality of the PSA for the spectrum of its potential applications.

The BFN PSA Peer Review Certification team consisted of six individuals with a combined 134 man-years of nuclear experience including 97 man-years in PSA related applications. These engineers and analysts provided both an objective review of the 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 of standard checklists that allowed for a detailed review of the elements and the sub-elements of the 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 of a "grade" of 1 through 4 on a PSA sub-element level. To reasonably span the spectrum of potential PSA applications, the four grades of certification 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.

E-5

li I \

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 of certification would serve as an industry standard.

Grade 2 - seful for Risk Rankin with Deterministic In ut This grade of certification requires a review of the 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 of systems, 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 of certification extends the requirements to assure that risk significant determinations made by PSA using absolute risk insights are adequate to support a broader range of regulatory applications, when combined with deterministic insights.

Grade 4 - Useful as a Prima Basis for Decision Makin This grade of certification requires a comprehensive, intensively reviewed study, which has the scope, level of detail, and documentation to assure the highest quality of results. Routine reliance on the PSA as the basis for certain changes is expected as a result of this grade. It is expected that few plants would currently be eligible for this grade of certification.

It should be noted that while each of the 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 of sharp boundaries is due in part to the fact that varying degrees of supplementary deterministic considerations or focused PSA studies may be used with any of the four grades of PSA 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% of all the graded sub-elements were at Grade 3 or above; 8%

of the sub-elements were assessed at Grade 4 providing a very solid evaluation. The following Table summarizes the results of the BFN Peer Review performed at the element level for the BFN PSA.

E-6

I t

I4 l 4

RESULTS, OF BFN PEER REVIEW PSA ELEMENT CERTIFICATION GRADE 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 AND UPDATE PROCESS 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 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. Additionally, the alternative program will not be limited to ASME Class 1 or Class 2 piping but will encompass the high safety significant piping segments regardless of ASME Class. Other non-related portions of the ASME Section XI Code will be unaFected.

E-7

I I I

\

2.2 Augmented Programs

/

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 of IGSCC susceptible welds are detailed in'NUREG-0313.

Inspection schedules are comparable to those specified in ASME Section XI in 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 of IGSCC 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 of IGSCC Category "A" welds, remain unchanged.

3. RISK-INFORMED ISI 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 of Failure Rate WCAP-14572 uses the Westinghouse Structural Reliability and Risk Assessment Model (SRRA) to calculate failure rates. TVAuses WinPRAISE, a Microsoft Windows based version of the PRAISE code used as the benchmark for SRRA in WCAP-14572 Supplement l.

E-8

I 4l 4l ~ ~

Determination of Failure 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 of the WCAP reference is made to uncertainty analyses to address uncertainty in. failure probabilities and consequence. As modified by the WOG letter of September 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 of performing the sensitivity study.

Structural Element Selection In WCAP-14572, selection of elements in Region 2 of the Structural Element Selection Matrix shown in Figure 3.7-1 of the WCAP is determined by a statistical evaluation process. According to paragraph 3.7.2 of the WCAP, this statistical. model is used to ensure that an acceptable level of reliability is achieved. At TVA, 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 of the WCAP (as modified by the WOG letter of September 30, 1998)'additional rationale must be developed when a statistical model cannot be applied to determine the minimum number of examination locations for a given segment. Since a calculated failure probability is a necessary input to a statistical evaluation, an alternative which would provide assurance of an acceptable level of reliability was used. The existing examination requirements of Section XI have provided such an acceptable level; therefore, the existing Section XI criteria were used; i.e., 25% for Class 1 and 7.5% for Class 2.

3.1 Scope of Program The system scoping rules were applied to all systems using existing Browns Ferry Nuclear Plant documentation. Inclusion of systems in the scope of current Section XI programs was determined by reviewing 3-SI-4.6.G, Inservice Inspection Program and the current examination isometric drawings. Determination of those 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 of the system were utilized in determining what portion of a system should be included. Separate documentation was prepared for each of the identified systems and is provided as support information. Specific, applicability to each included system is provided in that system's section of Appendix 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.

E-9

I

~

J

~

3.2 Segment Definition Once the systems to be included in the program are determined, the portions of the selected systems to be evaluated are divided into segments. A piping segment is defined. as a run of piping whose failure would result in the same loss of function, 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 flow joining points, locations of size 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 of piping. The number of segments identified per system is given in Table 3.1-1. Description of each system's individual segments is provided in that system's section of Appendix A to 3-SI-4.6.G.

Table 3.1-1 Systems in Risk-Informed Inservice Inspection Scope Syst Sec XI PSA Mnt Rule if Segs risk significant 001 Main Steam Yes Yes Yes 56 002 Condensate and Demineralized Water Yes Yes 36 Portions which provide a heat sink, or provide water to mitigate accidents, or deliver water to FW 003 Feedwater Yes Yes Yes 46 023 Residual Heat Removal Service Water Yes Yes Yes 024 Raw Cooling, Water Yes Yes Yes 027 Condenser Circulating Water Yes, Yes 20'63 Portion which provides cooling water to main condenser Standby Liquid Control Yes Yes Yes '5 067 Emergency Equipment Cooling Water Yes Yes Yes 28 068 Reactor Recirculation Yes Yes 16 069 Reactor Water Cleanup Yes Yes 19 070 Reactor Building Closed Cooling Water Yes Yes 17 071 Reactor Core Isolation Cooling Yes Yes Yes 12 073 High Pressure Coolant Injection Yes Yes Yes 074 Residual Heat Removal Yes Yes 31 075 Core Spray Yes Yes Yes 15 078 Fuel Pool Cooling Yes 085 Control Rod Drive Hydraulics Yes Yes Yes 31 E-10

ll 4i ,p

~

'W

3.3 Consequence Evaluation I

The consequences of pressure boundary failures are measured in terms of core damage and large early release. The impact on these measures due to both direct and indirect effects was considered.

Direct Conse uences Direct consequences of segment 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 of plant 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 of fluid 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 of faulted 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 of the 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 initial initiating event.

- Failures that impacted the operability of mitigating systems, represented by various events or combinations of events

- Failures that resulted in both a plant trip and impacted operability of mitigating 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:

FP /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

I I J'

CCDF/P, the FP is expressed in terms of one 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 of the individual cases evaluated where a pipe segment could impact operability of a mitigating system. Since a mitigating system may be called for in the case of any initiating event, the quantification runs were made including all initiating events. The calculated CDF was then adjusted to remove the base CDF of 9.19E-06, such that the result reflects the increase in CDF associated with the segment failure.

The following PSA model macro terms are used in the "Other Impacts or Failures" shown in Table 3.3-1:

Yl 1 Support to core spray pump A Y12 Support to core spray, pump C HPISUP Supportto HPCI RPASUP Support to RHR pump A RPB SUP Support to RHR pump B RPCSUP Support to RHR pump C RPD SUP Support to RHR pump D Diesel generator failures are modeled as being bounded by failure of diesel generator 3A fuel oil (top event FE), which is the limiting function.

The impact on core spray was modeled by setting interim variables Yl 1 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 MLOCA2 event 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.

E-12

I J

Tab e 3.3-1 Summary of Quantification Runs Where Segment Failure does not result in Plant Trip Initiating Mitigating System impact Calculated CDF CDF Increase Surv Interval Event (Annual)

All Core Spray loop I 1.265 E-05 3.46E-06 qtrly All CRD 6.082E-05 5.163E-05 shift (op round)

All HPISUP failed 1.910E-05 9.91E-06 qtrly All RPASUP failed 3.244E-05 2.33E-05 mthly All RPBSUP failed 7.782 E-05 6.86E-05 mthly AII RPASUP, RPCSUP 2.120E-04 2.03E-04 mthly AII RPBSUP, RPDSUP 1.359E-04 1.27E-'04 mthly AII RPBSUP, RPDSUP, CS 2.668 E-04 2.58E-04 shift (op round)

All Diesel Generator 1.665 E-05 7.46E-06 mthly AII RHR Div I Heat Exchangers 3.724 E-05 2.81E-05 qtrly All'll RHR Div 2 Heat Exchangers 3.919E-05 3.00E-05 qtrly RCI 1.960 E-05 1.04E-05 qtrly All Suppression Pool Cooling 1.103E-05 1.84E-06 qtrly The surveillance interval referenced in the table represents the period between surveillance tests or physical observation of the affected system or component. This is used to determine the appropriate Surveillance Interval Adjustment factor.

Table 3.3-2 summarizes the results of the individual cases evaluated where failure of a pipe segment could result in an initiating event and also impact operability of a mitigating system or systems. RISKMAN calculations were made for the listed combinations of circumstances, and the resultant Core Damage Frequency was normalized to an annual CCDP by dividing by the initiating event frequency.

g I

J

Table 3.3-2 Summary of Quantification Runs Where Segment Failure Results in Plant Trip with Mitigating System Impact Initiating Mitigating System impact Calculated IE Freq for Normalization CCDP Event CDF (normalized)

CIV HPI 1.965E-06 4.340E-01 4.53E-06 CIV RCI, CRD 2.971E-05 4.340E-01 6.85E-05 LLO subsumes HPI, RCI, CRD 4.050E-08 1.070E-04 3.79E-04 LRCW 250V RMOV 3C 3.653 E-06 3.220 E-02 1.13E-04 PLFW RCI, CRD 3.007 E-06 3.310E-01 9.08E-06 RXINST incl LM, LV, LVP 5.039E-09 6.580E-04 7.66E-06 (calc as Ul)

SCRAMR CRD 5.374E-07 2.740 E-01 1.96E-06 SCRAMR CRDY12 8.054 E-07 2.740 E-01 2.94E-06 SCRAMR RPB, RPD, HPI 1.426 E-06 2.740 E-01 5:20E-06 SCRAMR SL 5.711 E-06 2.740E-01 2.08E-05 S LOCA RCI 7.475 E-08 4.010E-03 1.86E-05 The loss of shutdown 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 of operation is applicable for seven days per refueling outage. For an 18 month cycle, this was an exposure time of 7/548 days, resulting in an adjustment factor of 1.28E-02. For the future 24.month cycles, this adjustment factor will be 9.58E-03. This change has no impact on the significance of any segment.

The direct consequences and Conditional Core Damage Probabilities/Frequencies for all pipe segments are described in each system's section of Appendix A to 3-SI-4.6.G.

Indirect Conse uences The effects of High Energy Postulated Pipe Ruptures both inside and outside containment were evaluated for Unit 3. The purpose of these 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 of postulated pipe failures. Any effects initially identified as a result of these evaluations were reconciled either by analysis or modification as part of the 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 of pipe whip or jet 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.

0 4l L '

, , ~

Table 3.3-'3 Se mentswithLowPressure S ra Potential Pipe Indirect S stem Se ment Im acts Raw Coolin Water RC 3-024-002 250V RMOV 3C Emergency Equipment 3-067-005 480V RMOV 3C Coolin Water EEC 3-067-006, 007, 008 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 of the frequency of piping failure was performed using the WinPRAISE program where possible. IfWinPRAISE was not applicable, deterministic methods were used. The implementation of these programs and results of this evaluation are described in the following sections of Appendix A to 3-SI-4.6.G.

5.1 Review of Plant Failure History 5.2 Determination of Degradation Mechanisms 5.3 Screening 5.4 Failure Rate Determination 5.5 Segment Failure Rates The failure history of piping 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 TVA Tracking and Reporting of Open Items (TROI) database was searched and generated 937 items for review.

Each system was also analyzed for the parameters indicative of particular degradation mechanisms. Identified mechanisms were utilized to assure proper failure rates were determined.

Results of these reviews and analyses along with the determined failure rates are incorporated in each system's section of Appendix 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 of magnitude 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.

~)

4l I

3.5 Risk Evaluation Each piping segment-within the scope of the 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 of these 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 CDF- CDF- Applicable Applicable LERF- LERF- Applicable Applicable

+-S stem OA noOA CDF CDF OA noOA LERF LERF 001 MS 2.45E-07 2.45E-07 2.45E-07 2.11% 7.03E-08 7.03E-08 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%

023 RHRSW 1.59E-09 1.77E-09 1.59E-09 0.01% 4.45E-10 4.96E-10 4.45E-10 0.01%

024 RCW 5.30E-09 5.32E-09 5.30E-09 0.05% 1.48E-09 1.49E-09 1 48E-09 0 05%

027 CCW 2.00E-09 2.46E-09 2.46E-09 0.02% 5.61E-10 6.89E-10 6.89E-10 0.02%

063 SLC 1.06E-08 1.06E-08 1 06E-08 0 09% 2 98E-09 2.97E-09 2 98E-09 0 09%

067 EECW 1.91E-08 1.95E-07 1.96E-08 0.17% 5.34E-09 5.45E-08 5.48E-09 0.17%

068 RECIRC 3.33E-06 3.34E-06 3 34E 06 28 81% 9 34E 07 9.34E-07 9.34E-07 28.72%

069 RWCU 1.52E-06 1.53E-06 1.52E-06 13.11% 4.26E-07 4.30E-07 4.26E-07 13.10%

070 RBCCW 1.91E-08 1.91E-08 1.91E-08 0.16% 5.36E-09 5.36E-09 5.36E-09 0.17%

071 RCIC 1.30E-09 3.28E-07 1.97E-09 0.02% 4.01E-10 3.26E-07 6.27E-10 0.02%

073 HPCI 1.45E-08 1.45E-08 1 45E-08 0.13% 4.07E-09 4.08E-09 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 3.95E-06 4.04E-06 3.95E-06 34.08% 1.11E-06 1.20E-06 1.11E-06 34.13%

078 FPC O.OOE+00 0.00E+00 0 OOE+00 0.00% 0.00E+00 O.OOE+00 0 OOE+00 0.00%

085 CRD 1.16E-08 1.22E-09 1.16E-08 0.10% 3.25E-09 3.40E-10 3 25E-09 0.10%

Total: 1.16E-05 1.44E-05 1.16E-05 100.00% 3.25E-06 5.62E-06 3 25E-06 100.00%

3.6 Expert Panel Process Development of the Browns Ferry Risk-Informed program was reviewed and approved by an Expert Panel. The Expert Panel included members of the expert panel that had been established to implement the Maintenance Rule. In an NRC inspection conducted April 14-18, 1997, to inspect the implementation of the Maintenance Rule, the conduct of the 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 of GL 89-10 on motor operated valves.

To increase efficiency of the review process, it was decided to conduct the reviews in a phased manner, validating results of each 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 of individual 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.

It was 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 of the entire process and answered questions. At the next meeting of the RI-ISI project with the Expert Panel, a review of actions 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 of segment 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 of piping segment failure probability.

At the 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 of thumb, 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 of coolant accident (LOCA), regardless of actual risk value, would also be selected. The philosophy of the 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 of the two studies.

The chairperson appointed someone to record the minutes of each meeting. The minutes included the names of members and alternates in attendance and whether a quorum was present. The minutes contained relevant discussion summaries and the results. of membership voting. These minutes are available as program records.

E-17

~ <

l

<Qi f

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% of total core damage frequency due to pipe failures.

Table 3.7-1 High Safety Significant segments Segment Description Segment %Applicable Cum % RRW CDF CDF CDF 34I7$ 402 1"-12" discharge line from penetration -1 6A and penetration X-27D 2.39E4I6 20.60% 20.60% 1.260 to reactor (N5A) 3-075401 1"-12" discharge line from penetration X-168 and penetration X- 1.55E%6 13.36% 3396% 1 154 27C to reactor (N58) 3469-001 6" discharge line from 20" RHR line to penetration X-14 1.52E~ 13.10% 47.06% 1.151 3474407 24" line from recirculation line "A" to penetration '.17E46 10.09% 57.15% 1.112 12" discharge line from Recirc ring header "A"to Reactor (N2H)

X-12'4M8-006 6.57E7 5.66% 62.81% 1.060 3468O11 12" discharge line from Recirc ring header "8" to Reactor (N2C) 5.66')7 4.88% 67.69% 1.051 34)74-013 24" discharge line from penetration X-138 to recirculation line "A" 5.17E<7 4.46% 72.15% 1 047 3-068-012 12" discharge line from Recirc ring header "8" to Reactor (N28) 4.59')7 3.96 ok 76 11ok 1 041 3<68-013 12" discharge line from Recirc ring header "8" to Reactor (N2A) 4.03E<7 3.47% 79.58% 1.036 3-068-007 12" discharge line from Recirc ring header "A" to Reactor (N2J) 3.86E%7 3.33% 82.91% 1.034 5468-001 28" suction line from Reactor (N1A) to Recirculation pump "A" 2.80E4)7 2.41% 85.32% 1.025 34)68-005 12" discharge line from Recirc ring header "A" to Reactor (N2G) 1.82E4)7 1 57ok 86.89% 1.016 3468-008 12" discharge line from Recirc ring header "A" to Reactor (N2K) 1.66E<7 1A3% 88.32% 1.015 3468-010 12" discharge line from Reclrc ring header "8" to Reactor (N2D) 1.54')7 1.33 ok 89.65% 1.013

$ 474405 24" discharge line from penetration X-13A to recirculation line "8" 6.13E<8 0.53% 90.18% 1.005 3401%36 26" discharge line from Reactor to penetration X-7A including 5.65')8 0.49% 90.67% 1.005 valves PCV-1<, 179, 5 and penetrations X<4A and BOA 3-001-037 26" discharge line from'Reactor to penetration X-78 Including 5.65E48 0.49% 91.16% 1.005 valves PCV-1-18, 19, 22, 23 and penetrations X448 and X-308 3401-038 26" discharge line from Reactor to penetration X-7C including 5.65E48 0.49% 91.65% 1.005 valves PCV-1 QO, 31, 34, and penetrations X44C and XQOC 3401-039 26" discharge line from Reactor to penetration X-7D including 5.65E48 0.49'k 92 14ok 1.005 valves PCV-1-41, 180, 42 and penetrations X44D and X-30D 3403-006 24" supply line from penetration X-9A to HCV-3-67 5.65E<8 0.49% 92 63% 1 005 3-003407 24" supply line from penetration X-98 to HCV-3-66 5.65E48 0.49'k 93 12ok 1.005 3-003-036 20" supply line from HCV-3-67 to 12'nlet piping - ring header 5.65E48 0.49% 93.61 ok 1.005 3403437 12" supply line from 20" ring header to Reactor (N4A) 5.65EZ8 0.49% 94 10% 1 005 3-003438, 12" supply line from 20" ring header to Reactor (N48) 5.65E48 0.49% 94.59% 1.005 3403439 12" supply line from 20" ring header to Reactor (N4C) 5.65E48 0.49% 95.08 ok 1.005 3403440 20" supply line from HCV-346 to 12" inlet piping - ring header 5.65E48 0.49% 95.57% 1 005 34I03Z41 12" supply line from 20" ring header to Reactor (N4F) 5.65E48 0.49% 96.06% 1.005 34)03442 12" supply line from 20" ring header to Reactor (N4E) 5.65E48 0.49% 96 55% 1.005 3403443 12" supply line from 20" ring header to Reactor (N4D) 5.65')8 0.49% 97.04% 1.005 E-18

~ ~

Qi ~

C

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 of these segments, 97.75% of total core damage frequency due to pipe failures is accounted for.

Table 3.7-2 Defense in Depth Segments Segment Description Segment %Applica Gum% RRW CDF ble CDF CDF 3~$ 416 28" suction line from Reactor (N18) to Recirculation pump "8" 2.83E<8 0.24% 97.28% 1.002 3468402 28" discharge line from Recirculation pump "A" to Recirc ring header 2.68 EBS 0.23% 97.51% '.002

~8-004 12'ischarge line from Recirc ring header "A" to Reactor (N2F) 1.52M)8 0.13% 97.64% 1.001 3468409 12'ischarge line from Recirc ring header "8" to Reactor (N2E) 7ASE<9 0.06% 97.70% 1.001 3-068%14 28" discharge line from Recirculation pump "8" to Recirc ring header 3.20E%9 0 03% 97 73% 1 000 3-073-001 10" supply line from 26" MS line "8" to penetration X-11 2.82E-09 0.02% 97.75% 1.000 3~8~3 22" line Recirc ring header "A" O.OOE+00 0.00% 97.75% 1.000 3~8%15 22" line Recirc ring header "8" O.OOE+00 0.00% 97.75% 1.000 Large Early Release Frequency (LERF) was also considered in determining segment significance.

All segments with a LERF RRW >1.001 were already selected for examination based on CDF RRW.

The contribution of each 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 of all of these systems is due to the possibility of a'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. All of the 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.

'E-19

4

~

~

4

~s v ~

Table 3.7-3 SEGMENT CATEGORIZATION

'ystem ¹ Segs Consequence category Risk category High Medium Low High Medium Low Expert CCDP CCDP CCDP RRW RRW RRW Panel

>1E-004 >1E-06, <1E-06 >1.005 >1.001, <1.001 HSS

<1E-04 <1.005 001 MS 56 38 14 52 002 CDW 36 '6 10 36 003 FW 46 10 31 10 36 10 023 RHRSW '5 12 33 45 024 RCW 20 18 20 027 CCW 063 SLC 067 EECW 28 17 28 068 RECIRC 16 16 ,3 16 069 RWCU 19 15 18 070 RBCCW 17 17 17 071 RCIC 12 12 073 HPCI 074 RHR 31 16 28 075 CS 15 4 = 2 13 078 FPC 085 CRD 31 24 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 iriitial program being submitted addresses the high safety significant (HSS) piping components placed in regions 1 and 2 of Figure 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 of the program requiring 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 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.

E-20

4i C' Fl 1i

Table 1, of Code 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 of the 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 of Table 1, subject to certain conditions. As such, the existing FAC and IGSCC programs will be utilized to meet these requirements.

Per paragraph -2500 (b) of the 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 of examination is specified in Table 1 of Code Case N-577. The examinations shall be scheduled such that the requirements of Table IWB-2412-1 of Section XI and NMG-0313 are satisfied.

Per paragraph I-6.1 as referenced above, when an existing program is used to satisfy the requirements of Table 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.

E-2I

~, ~-

,t 4>. I

Table 3.8-1 Examinations Se ment Bounda Descri tion Plant ID De Mode Item ¹ Exam Fre 3-001-036 MSL A Inside containment FAC R1.18 Note 1 Note 2 3-001437 MSL 8 inside containment FAC R1.18 Note 1 Note 2 3-001438 MSL C Inside containment FAC R1.18 Note 1 Note 2 3401-039 MSL D Inside containment FAC R1.18 Note 1 Note 2 3-003406 FW line from X-9A to HOVE FAC R1.18 Note 1 Note 2 3-003407 FW line from X-98 to HCV<%6 FAC R1.18 Note 1 Note 2 3403409 FW line from steam tunnel wall to X-98 FAC R1.18 Note 1 Note 2 3403436 FW ring header A FAC R1.18 Note 1 Note 2 3403437 FW Riser A FAC R1.18 Note 1 Note 2 3403438 FW Riser 8 FAC R1.18 Note 1 Note 2 3403439 FW Riser C FAC R1.18 Note 1 Note 2 3403440 FW ring header 8 FAC R1.18 Note 1 Note 2 3403441 FW Riser F FAC R1.18 Note 1 Note 2 3403442 FW Riser E FAC R1.18 Note 1 Note 2 3403443 FW Riser D FAC R1.18 Note 1 Note 2 3-068401 Recirculation pump "A" Suction GRW53(OL) IGSCC-E R1.16 IGSCC Vol Alt cycle.

GRW54(OL) IGSCC-E R1.16 IGSCC Vol Alt cycle GR4-57(OL) IGSCC-E R1.16 IGSCC Vol Alt cycle 3468402 Recirculation pump "A" Discharge GR443(OL) IGSCC-E R1.16 IGSCC Vol Alt cycle 3468403 Recirc ring header "A" RWR4401-G019 IGSCC-A R1.16 IGSCC Vol Interval 3-068404 Recirc riser F RWRQ401-G001 IGSCC-A R1.16 IGSCC Vol Interval RWRQ401-G016 IGSCC-A R1.16 IGSCC Vol Interval 3468405 Recirc riser G RWR4-001-G004 IGSCC-A R1.16 IGSCG Vol Interval RWR4-001-G006 IGSCC-A R1.16 IGSCC Vol Interval 3468406 Recirc riser H RWR-3-001-G007 IGSCC-A R1.16 IGSCC Vol Intewal RWR4401-G009 IGSCC-A R1.16 IGSCG Vol Interval RWR4401-G020 IGSCC-A R1.16 IGSCC Vol Interval 3468-007 Recirc riser J RWRN401-G010 IGSCC-A R1.16 IGSCC Vol Interval RWR4401-G012 IGSCC-A R1.16 IGSCC Vol Interval RWR4401-G022 IGSCC-A R1.16 IGSCC Vol Interval

'468-008 Recirc riser K RWR4401-G013 IGSCC-A R1.16 IGSCC Vol Interval RWR4401-G015 IGSCC-A R1.16 IGSCC Vol Interval RWR~1-G024 IGSCC-A R1.16 IGSCC Vol Intewal 3468409 Recirc riser E RWR~2-G023 IGSCC-A R1.16 IGSCC Vol Interval 3468410 Recirc riser D RWR4402-G010 IGSCC-A R1.16 IGSCC Vol Interval RWR4402-G012 IGSCC-A R1.16 IGSCC Vol Interval RWR4402-G022 IGSCC-A R1.16 IGSCC Vol Interval 3468411 Recirc riser C RWRD402-G007 'GSCC-A R1.16 IGSCC Vol Interval RWR-3402-G009 IGSCC-A R1.16 IGSCC Vol Interval RWR-3402-G020 IGSCC-A R1.16 IGSCC Vol Intewal 3468412 Recirc riser 8 . RWR-3402-G004 IGSCC-A R1.16 IGSCC Vol Interval RWR-3402-G006 IGSCC-A R1.16 IGSCC Vol Intewal RWR-3402-G018 IGSCC-A R1.16 IGSCC Vol Interval 3-068413 Recirc riser A RWR-3-002-G001 IGSCC-A R1.16 IGSCC Vol Interval RWR4402-G003 IGSCC-A R1.16 IGSCC Vol Interval RWR4402-G016 IGSCC-A R1.16 IGSCC Vol Interval 3-068414 Recirculation pump "8" Discharge GR4-27(OL) IGSCC-E R1.16 IGSCC Vol Alt cycle 3-068-015 Recirc ring header "8" RWR4402-G019 IGSCC-A R1.16 IGSCC Vol interval 3-068-016 Recirculation pump "8" Suction GRW59(OL) IGSCC-E R1.16 IGSCC Vol Alt cycle E-'22

0

~

~

~. 1 IP ~ '

Table 3.8-1 Examinatfdns 'e ment Bounda Descri tion Plant ID D Mode Item If Fr GRQ~(OL) IGSCC-E R1.16 IGSCC Vol Alt cycle GR4-63 IGSCC-E R1.16 IGSCC Vol Alt cycle GR-344(OL) IGSCC-E R1.16 IGSCC Vol Alt cycle 3-069-001 RWCU from RHR to X-14 RWCU44X11-G011 IGSCC-A R1.16 IGSCC Vol Interval RWCUQ-001-GOI6 IGSCC-A R1.16 IGSCC Vol Interval RWCUQ-001-G017 IGSCC-A R1.16 IGSCC Vol interval RWCU-3-001-G018 IGSCC-A R1.16 IGSCC Vol Interval RWCU-3~1-G019 'GSCC-A R1.16 IGSCC Vol Interval RWCU-3-001-G024 IGSCC-A R1.16 IGSCC Vol Interval RWCU-3-001-G025 I GSCC-A R1.16 IGSCC Vol Interval RWCU-3-001-G026 IGSCC-A R1.16 IGSCC Vol Interval 373401 HPCI steam supply from MSL "B" to X-11 THPCI-3-073A Stress R1.11 XI Vol Interval 3%74005 RHR from X-13A to recirc line "B" DRHRC-03B IGSCC-G R1.16. IGSCC Vol Cycle DSRHR-3%4A IGSCC-C R1.16 IGSCC Vol Interval 3-074-007 RHR from recirc line "A"to X-12 DRHRD-19 IGSCC-C R1.16 IGSCC Vol Interval DRHR4-21 IGSCC-C R1.16 IGSCC Vol Interval DSRHR-348 IGSCC-C R1.16 IGSCC Vol Interval DSRHR-3%9 IGSCC-C R1.16 IGSCC Vol Interval DSRHR-3-10 IGSCC-C R1.16 IGSCC Vol Interval DSRHRD-11(OL) IGSCC-E R1.16 IGSCC Vol Alt cycle TRHR4-191 IGSCC-C R1.16 IGSCC Vol Interval 3-074-013 RHR from X-13B to recirc line "A" DRHR4-13B IGSCC-G R1.16 IGSCC Vol Cycle 3-075-001 CS line B to reactor (N5B) DSCS~7 IGSCC-C R1.16 IGSCC Vol Interval DSCS~8 IGSCC-C R1.16 IGSCC Vol Interval DSCS~9 IGSCC-C R1.16 IGSCC Vol Interval TC8-M1 IGSCC-A R1.16 IGSCC Vol Interval TSCSW402 IGSCC-A R1.16 IGSCC Vol Interval TOST~ IGSCC-C R1.16 IGSCC Vol Interval TOST~ IGSCC-C R1.16 IGSCC Vol Interval TCSZP10 IGSCC-C R1.16 IGSCC Vol interval 3%75402 CS line A to reactor (N5A) DOSE)4 IGSCC-C R1.16 IGSCC Vol interval DSCS~1 IGSCC-C R1.16 IGSCC Vol interval'nterval DSCS~2 IGSCC-C R1.16 IGSCC Vol TCS4417 IGSCC-A R1.16 IGSCC Vol Interval TC8-3422 IGSCC-C R1.16 IGSCC Vol Interval TSCSQ-41 8 IGSCC-A R1.16 IGSCC Vol Interval Notes:

Note 1 Examination to be performed per FAC program.

Note 2 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 XI of 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.

Alt cycle 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.

E-23

~.

0 Qi.

~

~

' . I,

')

t

Y ~

~

Additional Examinations Additional examinations will be performed in accordance with Section -2430 of Code Case N-577, as implemented in Section 7.12.5.4-I of TVABFN 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 will not be known until the examination is performed, since some locations will be examined for the first time by the specified techniques.

At this time, the risk-informed examination locations that have been selected provide )90%

coverage. In instances where a location may be found at the time of the examination to not meet

)90% coverage, the process outlined in Section 4.1 of WCAP-14572, revision 1 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 decrease when compared to that estimated from current Section XI requirements and to be neutral when compared to that estimated from current requirements including both Section XI and augmented.

A comparison between the proposed RI-ISI program and the current ASME Section XI ISI 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 of all of these systems is due to the possibility of a large LOCA, in combination with active degradation mechanisms'(FAC and IGSCC).

E-24

~J

~> II $

~

~

'l l

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 CDW 36 1.12E-08 0.00E+00 8.57E-09 8.57E-09 003 FW 46 6.69E-07 0.00E+00 '.79E-07 5.79E-07 023 RHRSW 45 1.59E-09 0.00E+00 0.00E+00 0.00E+00 024 RCW 20 5.30E-09 0.00E+00 O.OOE+00 O.OOE+00 027 CCW 3 2.46E-09 0.00E+00 O.OOE+00 O.OOE+00 063 SLC 1.06E-08 O.OOE+00 0.00E+00 0.00E+00 067 EECW 28 1.96E-08 0.00E+00 0.00E+00 0.00E+00 068 RECIRC 16 3.34E-06 0.00E+00 3.34E-06 3.34E-06 069 RWCU 19 1.52E-06 0.00E+00 1.52E-06 1.52E-06 070 RBCCW 17 1.91E-08 0.00E+00 0.00E+00 O.OOE+00 071 RCIC 12 1.97E-09 0.00E+00 O.OOE+00 O.OOE+00 073 HPCI 11 1.45E-08 2.82E-09 O.OOE+00 2.82E-09 074 RHR 31 1.77E-06 1.44E-09 1.76E-06 1.76E-06 075 CS 15 3.95E-06 0.00E+00 3.94E-06 3.94E-06 078 FPC 0.00E+00 0.00E+00 0.00E+00 0.00E+00 085 CRD 31 1.16E-08 0.00E+00 0.00E+00 0.00E+00 Total: 392 1.16E-05 4.26E-09 1.14E-05 1.14E-05 Applicable LERF System ¹ segs Total Current XI Current Aug Proposed Rl+ Aug 001 MS 56 7.03E-08 0.00E+00 6.72E-08 6.72E-08 002 CDW 36 3.13E-09 0.00E+00 2.40E-09 2.40E-09 003 FW 46 1.87E-07 0.00E+00 1.62E-07 1.62E-07 023 RHRSW 45 4.45E-10 O.OOE+00 0.00E+00 O.OOE+00 024 RCW 20 1.48E-09 O.OOE+00 0.00E+00 0.00E+00 027 CCW 3 6.89E-10 O.OOE+00 0.00E+00 0.00E+00 063 SLC 2.98E-09 0.00E+00 0.00E+00 O.OOE+00 067 EECW 28 5.48E-09 0.00E+00 0.00E+00 O.OOE+00 068 RECIRC 16 9.34E-07 0.00E+00 9.34E-07 9.34E-07 069 RWCU 19 4.26E-07 0.00E+00 4.25E-07 4.25E-07 070 RBCCW 17 5.36E-09 0.00E+00 O.OOE+00 O.OOE+00 071 RCIC 12 6.27E-10 0.00E+00 0.00E+00 O.OOE+00 073 HPCI'HR 4.08E-09 7.89E-10 0.00E+00 7.89E-10 074 31 4.97E-07 4.04E-10 4.93E-07 4.93E-07 075 CS 15 1.11E-06 O.OOE+00 1.10E-06 1.10E-06 078 FPC 0.00E+00 0.00E+00 0.00E+00 0.00E+00 085 CRD 31 3.25E-09 0.00E+00 0.00E+00 0.00E+00 Total: 392 3.25E-06 1.19E-09 3.19E-06 3.19E-06 E-25

~ - 'cg I.

c.

4l a is. Ag.

Table 3.10-1, COMPARISON BY SYSTEM OF CDF/LERF DETECTED BY CURRENT PROGRAMS AND DETECTED BY RISK-INFORMED PROGRAM CDF-OA System ¹ segs Total Current XI Current Aug Proposed Applicable RI+ Aug 001 MS 56 2.45E-07 O.OOE+00 2.35E-07 2.35E-07 002 CDW 36 1.12E-08 O.OOE+00 8.57E-09 8.57E-'09 003 FW 46 6.69E-07 0.00E+00 5.79E-07 5.79E-07 023 RHRSW 45 1.59E-09 0.00E+00 0.00E+00 O.OOE+00 024 RCW 20 5.30E-09 0.00E+00 0.00E+00 O.OOE+00 027 CCW 3 2.01E-09 0.00E+00 0.00E+00 O.OOE+00 063 SLC 1.06E-08 0.00E+00 0.00E+00 0.00E+00 067 EECW '8 1.91E-08 0.00E+00 0.00E+00 O.OOE+00 068 RECIRC 16 3.34E-06 0.00E+00 3.34E-06 3.34E-06 069 RWCU 19 . 1.52E-06 O.OOE+00, . 1.52E-06 1.52E-06 070 RBCCW 17 1.91E-08 0.00E+00 0.00E+00 O.OOE+00 071 RCIC 12 1.30E-09 0.00E+00 0.00E+00 O.OOE+00 073 HPCI 11 1.45E-'08 2.82E-09 0.00E+00 ~ 2.82E-09 074 RHR 31 1.77E-06 1.44E-09 1.76E-06 1.76E-06 075 CS 15 3.95E-06 4.63E-10 3.94E-06 3.94E-06 078 FPC 0.00E+00 O.OOE+00 O.OOE+00 0.00E+00 085 CRD 31 1.16E-08 O.OOE+00 0.00E+00 0.00E+00 Total: 392 1.16E-05 4.72E-09 1.14E-05 1.14E-05

, CDF-no OA System ¹ segs Total Current XI, Current Aug Proposed Applicable RI+ Aug 001 MS 56 2.45E-07 0.00E+00 2.35E-07 2.35E-07 002 CDW 36 1.23E-08 0.00E+00 8.57E-09 8.57E-09 003 FW 46 6.69E-07 0.00E+00 5.79E-07 5.79E-07 023 RHRSW 45 1.77E-09 0.00E+00 0.00E+00 0.00E+00 024 RCW 20 5.32E-09 O.OOE+00 0.00E+00 O.OOE+00 027 CCW 3 2.46E-09 O.OOE+00 0.00E+00 0:00E+00 063 SLC 1.06E-08 0.00E+00 0.00E+00 0.00E+00 067 EECW 28 1.95E-07 0.00E+00 0.00E+00 O.OOE+00 068 RECIRC 16 3.34E-06 0.00E+00 3.34E-06 3.34E-06 069 RWCU 19 1.53E-06 O.OOE+00i 1.52E-06 1.52E-06 070 RBCCW 17 1.91E-08 0.00E+00 0.00E+00 0.00E+00 071 RCIC 12 3.28E-07 0.00E+00 0.00E+00 0.00E+00 073 HPCI 11 1.45E-08 2.82E-09 0.00E+00 2.82E-09 074 RHR 31 4.02E-06 2.19E-06 1.76E-06 1.76E-06 075 CS 15 4.04E-06 0.00E+00 3.94E-06 3.94E-06 078 'FPC 0.00E+00 O.OOE+00 O.OOE+00 0.00E+00 085 CRD 31'92 1.22E-09 0.00E+00 0.00E+00 0.00E+00 Total: 1.44E-05 2.19E-06 1.14E-05 1.14E-05 E-26

~ oy a

~ ~

I ~

~ ~ .

Table 3.10-1.

COMPARISON BY SYSTEM OF CDF/LERF DETECTED BY CURRENT PROGRAMS AND DETECTED BY RISK-INFORMED.PROGRAM LERF-OA System ¹ segs Total Current XI Current Aug Proposed Applicable Rl+ Aug 001 MS 56 7.03E-08 0.00E+00 6.76E-08 6.76E-08 002 CDW 36 . 3.13E-09 0.00E+00 2.40E-09 2.40E-09 003 FW 46 1.87E-07 0.00E+00 1.62E-07 1.62E-07 023 RHRSW 45 4.45E-10 0.00E+00 0.00E+00 0.00E+00 024 RCW 20 1.48E-09 0.00E+00 0.00E+00 O.OOE+00 027 CCW 5.61E-10 0.00E+00 0.00E+00 0.00E+00 063 SLC 2.98E-09 0.00E+00 O.OOE+00 0.00E+00 067 EECW, 28 5.34E-09 0.00E+00 0.00E+00 0.00E+00 068 RECIRC 16 9.34E-07 0.00E+00 9.34E-07 9.34E-07 069 RWCU 19 4.26E-07 0.00E+00 4.25E-07 4.25E-07 070 RBCCW 17 5.36E-09 0.00E+00 0.00E+00 0.00E+00 071 RCIC 12 4.01E-10 0.00E+00 0.00E+00 0.00E+00 073 HPCI 4.07E-09 7.89E-10 0.00E+00 7.89E-10 074 RHR 31 4.96E-07 4.04E-10 4.93E-07 4.93E-07 075 CS 15 ~ 1.11E-06 0.00E+00 1.10E-06 1.10E-06 078 FPC 0.00E+00 0.00E+00 0.00E+00 O.OOE+00 085 CRD 31 3.25E-09 0.00E+00 0.00E+00 0.00E+00 Total: 392 3.25E-06 1.19E-09 3.19E-06 '.19E-06 LERF-no OA System ¹segs Total Current XI Current Aug Proposed Applicable Rl+ Aug 001 MS 56 7.03E-08 0.00E+00 6.76E-08 6.76E-08 002 CDW 36 3.45E-09 0.00E+00 2.40E-09 2.40E-09 003 FW 46 1.87E-07 0.00E+00 1.62E-07 1.62E-07 023 RHRSW. 45 4;96E-10 0.00E+00 0.00E+00 O.OOE+00 024 RCW 20 1.49E-09 0.00E+00 0.00E+00 0.00E+00 027 CCW 6.89E-10 0.00E+00 0.00E+00 O.OOE+00 063 SLC 2.97E-09 0.00E+00 0.00E+00 0.00E+00 067 EECW 28 5.45E-08 0.00E+00 0.00E+00 0.00E+00 068 RECIRC 16 9.34E-07 0.00E+00 9.34E-07 9.34E-07 069 RWCU 19 4.30E-07 O.OOE+00 4.25E-07 4.25E-07 070 RBCCW 17 5.36E-09 O.OOE+00 0.00E+00 0.00E+00 071 RCIC 12 3.26E-07 0.00E+00 O.OOE+00 0.00E+00 073 HPCI 4.08E-09 7.89E-10 0.00E+00 7.89E-10 074 RHR 31 2.40E-06 1.83E-06 4.93E-07 4.93E-07 075 CS 15 1.20E-06 0.00E+00 1.10E-06 1.10E-06 078'85 FPC 0.00E+00 0.00E+00 0.00E+00 0.00E+00 CRD 31 3.40E-10 O.OOE+00 O.OOE+00 0.00E+00 Total: 392 5.62E-06 1.83E-06 3.19E-06 3.19E-06

r,lc l a

A ~

~ ~

~0

~ ~ ~ a

( ~'

Table 3.10-2 provides a comparison of CDF/LERF detected by the current and Risk-Informed programs. The current Section XI program only detects 0.04% CDF (4.26E-09); however, the combination of current XI and current augmented programs will detect 98.27% CDF (1.14E-05) and 98.18% LERF (3.19E-06) and the Risk-Informed ISI and augmented programs will detect 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 of XI and 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:

Current Current Proposed Applicable Section XI Section XI Risk-Informed Case CDF/LERF + Augmented + Augmented CDF 1.16E-05 4.72E-09 1.14E-05 1.14E-05 with Operator action 0 04 98.27% 98.27%

CDF 1.44E-05 2.19E-06 1.36E-05 1.14E-05 No Operator Action 15 19% 94 11% 78.92%

Applicable 1.16EW5 4.26EW9 1.14EC5 1.14EC5 CDF 0.04% 98.27% 98.27%

LERF 3.25E-06 1.19E-09 3.19E-06 3.19E-06 with Operator action 0 04% 98 24% 98.21%

LERF 5.62E-06 1.83E-06 5.02E-06 3.19E-06 No Operator Action 32.63% 89 37% 56.76%

Applicable 3.25E-06 1.19E49 3.19E46 3.19E-06 LERF 0 04% 98.18% 98.18%

Defense-In-De th The basic concept of defense-in-depth is to provide multiple means to accomplish safety functions and prevent the release of radioactive materials.

Multiple means to accomplish safety functions are provided by the functional redundancy inherent in plant design. The PSA used as the basis of this 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

)p'I

'<<ki

~

1

~ 'll

their cqptrjbution to reducing risk of core damage frequency. Specifically, piping which could potentially result in a large LOCA was included, even ifthe risk associated with the segment was minimal or nonexistent. Additionally, reactor coolant pressure boundary integrity is maintained by continued implementation of pressure 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 of the RI-ISI program, that revision will be implemented. The new program will be integrated into the existing ASME Section XI interval. No changes.to the Final Safety Analysis Report are necessary for program implementation.

The applicable aspects of the Code not affected by this change will 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 will be 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 of their current ASME class.

r The proposed monitoring and corrective action program will contain the following elements:

A. Identify Characterize C. (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 period basis. Significant changes may require more frequent adjustment as directed by NRC bulletin or Generic Letter requirements, or by plant specific feedback.

E-29

<>>Oi ~.

0 41

~)

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 XI selects a total of 222 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 of 27 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 Proposed (a) (b)

ASME XI Augmented RI-ISI Augmented Elements Elements . Examinations Elements (c)

System B-F B-J C-F-1 C-F-2 A C D E G R1.11 R1.16 R1.18 A C D E G Se s '8 001. MS 10 002 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 18 44 32 28 A 28 32 9 9 E 069 RWCU 19 19 1 8 A 070 RBCCW'7 071 RCIC 12 073 HPCI 11 5 11 074 RHR 31 10 2 35 4 27 2 1 2 7 C 272 1 2 1 E 2 G 075 CS 15 2 10 6 13 19 4 A 19 10 C 078 FPC 1 085 CRD 31 1 total: 392 17 112 13 80 67 83 2 102 69 15 40 832 102 Notes:

(a) 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 (b) Augmented'programs including FAC and Reactor Nozzle Thermal Fatigue Cracking (NUREG-0619) continue.

(c) Augmented program for IGSCC Categories C through G (GL88-01, NUREG-0313) continues.

c' Oi 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," Boiling Water Reactor Owner's Group, Report BWROG/PSA-9710, March 1998.

"Westinghouse Owner's Group Application of Risk-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 XI Containment Inservice Inspection Program", Browns Ferry Nuclear Plant Technical Instruction O-TI-376.

E-31

~ ,i~ V l <<'foal)--~