ML100480125

American Society of Mechanical Engineers,Section XI Inservice Inspection Program for Unit 1 Second Ten-Year Inspection Interval, Request for Relief 1-ISI-26, Risk-Informed Inservice Inspection Program

ML100480125
Person / Time
Site:	Browns Ferry
Issue date:	02/11/2010
From:	Krich R Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
Download: ML100480125 (50)

Text

Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402-2801 February 11, 2010 10 CFR 50.4 10 CFR 50.55a U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Washington, D.C. 20555-0001 Browns Ferry Nuclear Plant, Unit 1 Facility Operating License No. DPR-33 NRC Docket No. 50-259

Subject:

American Society of Mechanical Engineers, Section Xl Inservice Inspection Program for the Unit I Second Ten-Year Inspection Interval, Request for Relief 1-ISI-26, Risk-informed Inservice Inspection Program In accordance with 10 CFR 50.55a(a)(3)(i), the Tennessee Valley Authority (TVA) is requesting relief from certain inservice inspection (ISI) requirements in Section Xl of the American Society of Mechanical Engineers (ASME) Code for the Browns Ferry Nuclear Plant (BFN), Unit 1. An alternative to the Section XI requirements is requested for the BFN Unit 1 Second Ten-Year Inspection Interval. The enclosure to this letter contains the BFN Unit 1 request for relief 1-ISI-26, Risk-Informed Inservice Inspection Program, for NRC review and approval. The proposed BFN Unit1 Risk-Informed Inservice Inspection Program is an alternative to the current ASME Section Xl requirements for Class 1 and 2 piping.

The proposed Risk-Informed Inservice Inspection Program has been developed in accordance with the Westinghouse Owners Group Topical Report WCAP-14572, Revision 1-NP-A, "Westinghouse Owners Group Application of Risk-Informed Methods to Piping Inservice Inspection Topical Report." The enclosed request for relief (Enclosure 1) supports the conclusion that the proposed alternative provides an acceptable level of quality and safety as required by 10 CFR 50.55a(a)(3)(i). Enclosure 2 provides a summary of the BFN Probabilistic Risk Assessment Quality Upgrade Initiative.

Printed on recycled paper

U.S. Nuclear Regulatory Commission Page 2 February 11, 2010 This request for relief is similar to requests submitted for the BFN Units 2 and 3 by letters dated June 1, 2000, for BFN Unit 2, and April 23, 1999, for BFN Unit 3. These requests were approved by NRC as documented in safety evaluations dated January 19, 2001, for BFN Unit 2, and February 11, 2000, for BFN Unit 3.

TVA requests approval of this request for relief by September 2, 2010, to support the BFN Unit 1 fall refueling outage.

There are no new regulatory commitments in this letter. If you have any questions, please contact Dan Green at (423) 751-8423.

Respectfully, R. M. Krich Vice President Nuclear Licensing

Enclosures:

1. Browns Ferry Nuclear Plant, Unit 1 Request for Relief 1-ISI-26, Risk-Informed Inservice Inspection Program

2. Summary of Browns Ferry Nuclear Plant Probabilistic Risk Assessment Quality Upgrade Initiative cc (Enclosures):

NRC Regional Administrator - Region II NRC Senior Resident Inspector - Browns Ferry Nuclear Plant

Enclosure 1 Tennessee Valley Authority Browns Ferry Nuclear Plant Unit 1 American Society of Mechanical Engineers,Section XI Inservice Inspection Program, Unit I Second Ten-Year Inspection Interval Request for Relief 1-ISI-26, Risk-Informed Inservice Inspection Program E1-1

RISK-INFORMED INSERVICE INSPECTION PROGRAM PLAN Table of Contents

1. Introduction

2. Proposed Alternative to ISI Program 2.1 ASME Section XI 2.2 Augmented Programs

3. Risk-Informed ISI Process 3.1 Scope of Program 3.2 Segment Definitions 3.3 Consequence Evaluation 3.4 Failure Assessment 3.5 Risk Evaluation 3.6 Expert Panel Process 3.7 Expert Panel Categorization - Identification of High Safety Significant Segments 3.8 Structural Element and NDE Selection 3.9 Additional Examinations 3.10 Program Relief Requests 3.11 Change in Risk

4. Implementation and Monitoring Program

5. Proposed ISI Program Plan Change

6. References CDF, LERF, and RRW for each segment E1-2

1. INTRODUCTION Inservice inspections (ISI) for Browns Ferry Nuclear Plant (BFN) are currently performed on piping welds to the requirements of the American Society of Mechanical Engineers (ASME)

Boiler and Pressure Vessel Code Section Xl, 2001 Edition with 2003 Addenda, as required by 10CFR50.55a, "Codes and standards." BFN Unit 1 is currently in the second ten-year inspection interval as defined by the ASME 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. The risk-informed process used in this submittal is described in Regulatory Guides 1.174 (Ref. 6.7) and 1.178 (Ref. 6.8) and is consistent with the methodology described in ASME Section Xl, Code Case N-577 (Ref. 6.12) and WCAP-14572, Revision 1-NP-A (Ref. 6.4), with the deviations listed in Section 3.

As a risk-informed application, this submittal meets the intent and principles of Regulatory Guide 1.174 (Ref. 6.7). Further information is provided in Section 3.11 relative to defense-in-depth.

PRA Quality The scope, level of detail, and quality of the BFN probabilistic risk assessment (PRA) is sufficient to support a technically defensible and realistic evaluation of the risk change for this proposed application.

The BFN PRA model, dated December 7, 2009 was used to evaluate the consequences of pipe ruptures during operation in Mode 1. The base core damage frequency (CDF) and base large, early release frequency (LERF) from this version of the PRA model are 7.18E-06 /yr and 2.60E-06 /yr, respectively.

PRA model updates are scheduled for 24-month intervals to coincide with the refueling outages.

The administrative guidance for this activity is contained in Tennessee Valley Authority (TVA) administrative procedures.

The Risk-Informed Inservice Inspection (RI-ISI) evaluation included a determination that the PRA model and supporting documentation accurately reflects the current plant configuration and operational practices consistent with its intended application.

After an extensive upgrade effort of the PRA for BFN, the BFN Units 1, 2 and 3 Internal Events PRA Peer Review was performed in May 2009 at the TVA offices in Chattanooga, TN, using the NEI 05-04 (Ref. 6.13) process, the ASME PRA Standard, and Regulatory Guide 1.200, Rev. 2 (Ref. 6.9). A separate review was performed for the Internal Flooding portion of the BFN PRA in September 2009. The Internal Flooding Peer Review also used the NEI 05-04 (Ref. 6.13) process, the ASME PRA Standard (Ref. 6.10), and Regulatory Guide 1.200, Rev. 2 (Ref. 6.9).

A team of independent PRA experts from nuclear utility groups and PRA consulting organizations carried out these Peer Review Certifications.

The purpose of these reviews was to provide a method for establishing the technical adequacy of the PRA for the spectrum of potential risk-informed plant licensing applications for which the E1-3

PRA may be used. The 2009 BFN PRA Peer Reviews provided a full-scope review of the Technical Elements of the internal events, at-power PRA.

These intensive peer reviews involved over two person-months of engineering effort by the review team and provided a comprehensive assessment of the strengths and limitations of each element of the PRA model. The Peer Review Certification of the BFN PRA model performed by Boiling Water Reactor Owners Group (BWROG) resulted in a total 125 findings for the three unit model for internal events and internal flooding. All findings from these assessments have been dispositioned. This resulted in a number of enhancements to the PRA model prior to its use to support these proposed changes. The certification team determined that with these proposed changes incorporated, the quality of all elements of the PRA model is sufficient to support "risk significant evaluations with deterministic input." As a result of the effort to incorporate the latest industry insights into the PRA model upgrades and certification peer reviews, TVA has concluded that the results of the risk evaluation are technically sound and consistent with the expectations for PRA quality set forth in Regulatory Guides 1.174 (Ref. 6.7) and 1.177 (Ref. 6.8).

2. PROPOSED ALTERNATIVE TO ISI PROGRAM 2.1 ASME Section Xl ASME Section Xl Categories B-F, B-J, C-F-1 and C-F-2 currently contain the requirements for examining (via NDE) piping components. The 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 (Ref. 6.12). 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. Other non-related portions of the ASME Section Xl Code will be unaffected.

2.2 Augmented Programs Generic Letter 88-01 (Ref. 6.14) and NUREG-0313 (Ref. 6.1) (subsequently modified by BWRVIP-75 (Ref. 6.2)) provide 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 BWRVIP-75 (Ref.

6.2). The selection and inspection frequency specified in BWRVIP-75 (Ref. 6.2) is unaffected by this submittal, except for the deviation identified in Section 3.

All other augmented programs listed in BFN Surveillance Instruction 1-SI-4.6.G (Ref. 6.7) are unaffected by this submittal and all examinations committed in those programs will continue.

None of those examinations are included in any of the tables in the submittal. The programs include:

- Feedwater nozzles (NUREG-0619 (Ref. 6.16))

- CRD return line reroute (NUREG-0619)

- Reactor vessel internal examinations

- Weld inspection for pipe whip protection The BFN Flow Accelerated Corrosion (FAC) and Raw Water Fouling and Corrosion Control programs remain unchanged.

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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 (Ref. 6.2) and WCAP-14572 (Ref. 6.4), as modified by the September 30, 1998 letter to the NRC from the Westinghouse Owners Group (WOG), 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 0 Element/NDE Selection

• Implement Program

• Feedback Loop Deviations from the process described in WCAP-14572 are as follows:

Calculation of Failure Rate WCAP-14572 (Ref. 6.4) uses the Westinghouse Structural Reliability and Risk Assessment Model (SRRA) to calculate failure rates. TVA uses WinPRAISE (Ref. 6.5), a Microsoft Windows based version of the PRAISE code used as the benchmark for SRRA in WCAP-14572 Supplement 1. In the BFN Unit 3 Safety Evaluation Report (SER) received February 11, 2000 (Ref. 6.18), the NRC stated that the WinPRAISE and SRRA codes are based on similar methods and have been shown in past studies to predict similar values of failure probabilities if input parameters are assigned the same values for each code. For welds which have been subject to mid-life changes, WinPRAISE allows calculation of a failure rate based on the conditions following such a change, as was determined to be necessary during the review of the original BFN Unit 3 submittal. While the WCAP requires a range of failure modes be used, that is, leaks, disabling leak, and rupture, TVA only used Leak (for any indirect or spatial effects) and Disabling Leak (for all direct effects). In the BFN Unit 2 SER received January 19, 2001 (Ref. 6.19), the NRC references the fact that RG 1.178 (Ref. 6.8) and NUREG-0800 (Ref. 6.17)

Section 3.9.8 allow for the use of a single break size, as long as all possible spatial effects are included, and the BFN evaluation was considered an acceptable deviation from the WCAP methodology.

Determination of Failure Rate for a Secqment 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. If more 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. In the BFN Unit 2 SER received January 19, 2001 (Ref. 6.19), the NRC references studies performed for the BFN Unit 3 RI-ISI program which indicated that the TVA method produced results equivalent to those of the approved WCAP methodology.

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Structural Element Selection In WCAP-14572 (Ref. 6.4), 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 BFN, two methods were derived 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 to the NRC 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 that would provide assurance of an acceptable level of reliability was required. The existing examination requirements of Section Xl have provided such an acceptable level; therefore, the existing Section XI criteria are used; i.e., 25% for Class 1 and 7.5% for Class 2. In the BFN Unit 2 SER received January 19, 2001 (Ref. 6.19), the NRC found the location selection process to be consistent with the process approved for the WCAP and, therefore, acceptable.

Deviation from the Inspection Schedule described in BWRVIP-75 (Ref. 6.2) is as follows:

Examination of Cateqory A welds Section 4.2 of BWRVIP-75 (Ref. 6.2) states that for Category A welds the inspection sample size can be reduced to that being recommended by the risk-informed process. During the BFN Unit 1 restart effort, a large portion of the piping subject to IGSCC was replaced by resistant materials or was subjected to mitigative measures, such that the failure rates were greatly reduced. As a result, some segments whose failure could result in a Large Loss of Coolant Accident (LOCA) were determined to be Low Safety Significant. For defense in depth, it was decided that any segment whose failure could result in a Large LOCA would continue to be examined under the requirements of BWRVIP-75 (Ref. 6.2), with no reduction due to the risk-informed process.

3.1 Scope of Program The systems to be evaluated include piping (i.e., piping which contains water, steam, or radioactive material exclusive of radwaste), which is Class 1 or Class 2 within the scope of current ASME Section Xl programs.

These system scoping rules are applied using existing BFN documentation. Inclusion of systems in the scope of current Section Xl programs is determined by reviewing BFN Surveillance Instruction 1-SI-4.6.G, "Inservice Inspection Program," (Ref. 6.3) and the current examination isometric drawings. The BFN Unit 1 systems to be included in the RI-ISI program are provided in Table 3.1-1.

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 PRA 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 E1-6

operated valve (AOV) locations. The number of segments identified per system is given in Table 3.1-1. Description of each system's individual segments is provided in site maintained documentation.

TABLE 3.1-1 System Systems in Risk-Informed Inservice Inspection Scope Segment Count 001 Main Steam (MS) 30 003 Feedwater (FW) 32 063 Standby Liquid Control (SLC) 5 068 Reactor Recirculation (RWR) 16 069 Reactor Water Cleanup (RWCU) 4 070 Reactor Building Closed Cooling Water (RBCCW) 2 071 Reactor Core Isolation Cooling (RCIC) 11 073 High Pressure Coolant Injection (HPCI) 10 074 Residual Heat Removal (RHR) 28 075 Core Spray (CS) 15 085 Control Rod Drive Hydraulics (CRD) 14 TOTAL SEGMENTS 167 3.3 Consequence Evaluation 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 Consequences 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 PRA, and from the insights of plant experienced personnel. Impacts for instrument lines were evaluated for instrument function, as well as loss of fluid effects.

Normal operator actions were considered 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 PRA 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.

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- 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 = 1/2/ (FR) Ts + (FR)TM where FR is the Failure Rate (in events per unit time), Ts is the interval between surveillances, and TM 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 />). Since calculations in the RI-ISI program are based on annual Conditional Core Damage Probabilities/Frequencies (CCDP/F), the FP is expressed in terms of one year. When the expression 1/2 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:

1/2(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:

1/2(1 shift/round)(12hr/shift)(1 day/24 hrs)(1yr/365 days) + (1 yr/365 days)

= 1/1460 + 1/365 = 3.42E-03 This Surveillance Interval Adjustment is only applied when there is no specific associated Initiating Event.

The direct consequences and CCDP/F for all pipe segments are described in supporting calculations located on site.

Indirect Consequences The effects of High Energy Postulated Pipe Ruptures both inside and outside containment were evaluated for BFN Unit 1 prior to restart. The purpose of this evaluation 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.

Since potential effects of pipe whip or jet impingement are treated by the referenced High Energy Pipe Rupture Evaluations, only potential scenarios in which low pressure piping failure results in spray required evaluation. Walkdowns were conducted and it was determined that no segments in the analysis scope resulted in indirect effects.

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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 (Ref. 6.5) program where possible. If WinPRAISE (Ref. 6.5) was not applicable, deterministic methods were used.

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 supporting calculations located on site.

The failure rate due to FAC was developed deterministically. For this reason, a sensitivity study was performed to gain assurance that the assumptions which went into the deterministic process did not produce inaccurate or misleading results. Since failure rates due to IGSCC were determined by specific analysis of each weld for the conditions affecting that weld rather than by assuming conditions, no sensitivity study was required to validate assumptions.

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 as described in site maintained documentation. Normal Operator actions are considered in determining the appropriate resulting consequence. The Expert Panel considered whether the consequence with or without operator action (OA and noOA, respectively) was appropriate, and that was designated as the Controlling Case.

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 CDF due to piping failure based on the Controlling Case is 3.3393E-06. The LERF due to piping failure based on the Controlling Case is 3.7577E-08. The core damage frequency due to piping failure without operator action is 3.3396E-06, and with operator action is 3.3393E-06. The large early release frequency due to piping failure without operator action is 3.7627E-08 and with operator action is 3.7561 E-08.

To assess safety significance, the risk reduction worth (RRW) was calculated for each piping segment. Risk Achievement Worth (RAW) was not calculated. Per WCAP-14572 (Ref. 6.4) section 3.6.1, RAW measures the increase in core damage frequency when the component of interest is guaranteed to fail. Piping failure probabilities (especially for elements subject to IGSCC but treated by mitigative measures) are extremely small compared to other component failures modeled in a PRA. When this piping is guaranteed to fail, such large RAW values typically result that they provide little value in determining safety significance, but do provide a measure of sensitivity to consequences to failure. In the BFN Unit 2 SER issued January 19, 2001 (Ref. 6.19), the NRC indicated that TVA did not calculate RAW and provide it to the Expert Panel. In the BFN Unit 2 SER (Ref. 6.19), the NRC stated the following.

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"The WCAP states that the RAW should be calculated and provided to the expert panel, but there are no guidelines in the WCAP on what value of RAW constitutes an HSS segment. The TVA submittal stated that the expert panel classified any segment that would result in a large LOCA if failed as an HSS segment, regardless of the RRW. The staff finds that this is sufficient evidence that the expert panel was sensitive to the potential consequences of segment failure, and sensitivity to the consequences was the reason the WCAP includes the RAW estimate for consideration by the expert panel."

For BFN Unit 1, the decision by the Expert Panel to continue the examination of Category A welds in any segment that could result in a Large LOCA regardless of the RRW is sufficient evidence that the Expert Panel was sensitive to the potential consequences of segment failure.

Table 3.5-1 PIPING RISK CONTRIBUTION BY SYSTEM System CDF- CDF- CoDF -  % LERF- LERF LERF -  %

OA noOA Controlling CDF OA -noOA Controlling LERF Case Case 001 MS 3.72E-09 3.72E-09 3.72E-09 0.11% 1.56E-09 1.56E-09 1.56E-09 4.15%

003 FW 1.55E-08 1.55E-08 1.55E-08 0.46% 8.05E-09 8.05E-09 8.05E-09 21.41%

063 SLC 1.49E-14 1.49E-14 1.49E-14 0.00% 1.89E-16 1.89E-16 1.89E-16 0.00%

068 RECIRC 0.OOE+00 0.OOE+00 0.OOE+00 0.00% 0.00E+00 0.OOE+00 0.OOE+00 0.00%

069 RWCU 9.14E-21 9.14E-21 9.14E-21 0.00% 8.41E-23 8.41E-23 8.41E-23 0.00%

070 RBCCW 4.29E-20 4.29E-20 4.29E-20 0.00% 4.21E-20 4.21E-20 4.21E-20 0.00%

071 RCIC 2.31E-11 5.56E-11 5.56E-11 0.00% 1.10E-13 1.64E-11 1.64E-11 0.04%

073 HPCI 1.55E-09 1.79E-09 1.55E-09 0.05% 1.96E-11 6.94E-11 1.96E-11 0.05%

074 RHR 3.30E-06 3.30E-06 3.30E-06 98.76% 2.26E-08 2.26E-08 2.26E-08 60.19%

075 CS 2.04E-08 2.04E-08 2.04E-08 0.61% 5.32E-09 5.32E-09 5.32E-09 14.15%

085 CRD 2.17E-12 2.17E-12 2.17E-12 0.11% 2.13E-12 2.13E-12 2.13E-12 0.01%

Total: 3.34E-06 3.34E-06 3.34E-06 100.00% 3.76E-08 3.76E-08 3.76E-08 100.00%

Calculations performed include initial calculations to rank all the segments, change in risk calculations for all systems and for the plant, and RRW calculations that identify which welds to inspect within each High Safety Significant (HSS) segment.

WCAP-14572 (Ref. 6.4), paragraph 4.4.2, risk/safety evaluation criteria are met.

3.6 Expert Panel Process The final safety determination (i.e., high and low safety significance) of each piping segment was made by the expert panel using both probabilistic and deterministic insights. Development of the BFN RI-ISI 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, and is the same Expert Panel that reviewed the BFN Unit 2 and Unit 3 RI-ISI programs.

In an NRC inspection conducted April 14 through 18, 1997 to inspect the implementation of the Maintenance Rule, the conduct of the Expert Panel meetings at BFN 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 (Ref. 6.15) on motor operated valves.

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The expert panel had the following positions represented by either the permanent or alternate member at all times during an expert panel meeting.

• Probabilistic Risk Assessment

• Operations

• Engineering/Inservice Inspection (ISI)

• Maintenance A minimum of the chairperson and three members or alternates filling the above positions constituted a quorum. This core team of panel members was supplemented by other experts, including a metallurgist and piping stress engineer, as required for the piping system under evaluation.

The chairperson conducted and ruled on the proceedings of the meeting. The chairperson appointed an alternate chairperson 17 from the panel if he was unable to attend a meeting.

Members and alternates received training and indoctrination in the risk-informed inservice inspection selection process. They were indoctrinated in the application of risk analysis techniques for ISI.

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.

3.7 Expert Panel Categorization - Identification of High Safety Significant Segments Per ASME Code Case N-577 (Ref. 6.12), all segments with either CDF RRW or LERF RRW >

1.005 are considered High Safety Significant. These segments are shown in Table 3.7-1 and account for 99.92% of total core damage frequency due to pipe failures.

Any segment with 1.005 > RRW > 1.000 is considered Medium Safety Significant. This segment is shown in Table 3.7-2 and accounts for 0.08% of total core damage frequency due to pipe failures.

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Table 3.7-1 High Safety Significant segments Segment  % Cum % CDF Segment  % Cum % LERF Segment Description CDF CDF CDF RRW LERF LERF LERF RRW 1-074-013 24" discharge line from penetration X-13B to recirculation line"A" 2.0742E-06 62.18% 62.18% 2.639 1.4234E-08 38.10% 38.10% 1.609 1-074-005 24" discharge line from penetration X-13Ato recirculation line "B" 1.1980E-06 35.91% 98.10% 1.559 8.2243E-09 22.02% 60.12% 1.280 1-074-007 20" line from recirculation line "A" to penetration X-12 2.4765E-08 0.74% 98.84% 1.007 1.5314E-10 0.41% 60.53% 1.004 1-075-001 1-12" discharge line from penetration X-16B and penetration X-27C to 2.0441E-08 0.61% 99.45% 1.006 5.3166E-09 14.23% 74.76% 1.164 reactor (N5B) 1-003-009 24" supply line from steam tunnel wall to penetration X-9B 5.3339E-09 0.16% 99.61% 1.001 4.3558E-09 11.66% 86.42% 1.131 1-001-036 26" discharge line from Reactor to penetration X-7A including valves PCV- 7.4102E-10 0.02% 99.63% 1.000 3.5763E-10 0.96% 87.38% 1.009 1-4, 179, 5 and penetrations X-34A and X-30A 1-001-037 26" discharge line from Reactor to penetration X-7B including valves PCV- 7.4102E-10 0.02% 99.66% 1.000 3.5763E-10 0.96% 88.34% 1.009 1-18, 19, 22, 23 and penetrations X-34B and X-30B 1-001-038 26" discharge line from Reactor to penetration X-7C including valves 7.4102E-10 0.02% 99.68% 1.000 3.5763E-10 0.96% 89.29% 1.009 PCV-1-30, 31, 34, and penetrations X-34C and X-30C 1-001-039 26" discharge line from Reactor to penetration X-7D including valves 7.4102E-10 0.02% 99.70% 1.000 3.5763E-10 0.96% 90.25% 1.009 PCV-1-41, 180, 42 and penetrations X-34D and X-30D 1 1-003-006 24" supply line from penetration X-9A to HCV-3-67 7.4102E-10 0.02% 99.72% 1.000 3.5763E-10 0.96% 91.21% 1.009 1-003-007 24" supply line from penetration X-9B to HCV-3-66 7.4102E-10 0.02% 99.74% 1.000 3.5763E-10 0.96% 92.17% 1.009 1-003-036 24" supply line from HCV-3-67 to 12" inlet piping - ring header 7.4102E-10 0.02% 99.77% 1.000 3.5763E-10 0.96% 93.12% 1.009 1-003-037 12" supply line from 20" ring header to Reactor (N4A) 7.4102E-1 0 0.02% 99.79% 1.000 3.5763E-10 0.96% 94.08% 1.009 1-003-038 12" supply line from 20" ring header to Reactor (N41) 7.4102E-10 0.02% 99.81% 1.000 3.5763E-10 0.96% 95.04% 1.009 1-003-039 12" supply line from 20" ring header to Reactor (N4C) 7.4102E-1 0 0.02% 99.83% 1.000 3.5763E-10 0.96% 96.00% 1.009 1-003-040 24" supply line from HCV-3-66 to 12" inlet piping - ring header 7.4102E-10 0.02% 99.86% 1.000 3.5763E-10 0.96% 96.95% 1.009 1-003-041 12" supply line from 20" ring header to Reactor (N4F) 7.4102E-1 0 0.02% 99.88% 1.000 3.5763E-10 0.96% 97.91% 1.009 1-003-042 12" supply line from 20" ring header to Reactor (N4E) 7.4102E-1 0 0.02% 99.90% 1.000 3.5763E-10 0.96% 98.87% 1.009 1-003-043 12" supply line from 20" ring header to Reactor (N4D) 7.4102E-1 0 0.02% 99.92% 1.000 3.5763E-1 0 0.96% 99.82% 1.009 Table 3.7-2 Medium Safety Significant segments Segment Description Segment  % Cum % CDF Segment  % Cum % LERF CDF CDF CDF RRW LERF LERF LERF RRW 1-003-008 24" supply line from steam tunnel wall to penetration X-9A 2.6030E-09 0.08% 100.00 1.000 4.6581E-11 0.12% 99.94 1.001 E1-12

After consideration of the sensitivity studies, the Expert Panel also classified segment 1-003-008 as High Safety Significant. With this addition, the High Safety Significant segments account for 100.00% of total core damage frequency due to piping failures. An additional Low Safety Significant segment (1-073-004) was also classified High Safety Significant based on a sensitivity study, but had no impact on total CDF or LERF.

The Controlling Case CDF and LERF together with the CDF and LERF both with and without operator action for each segment and the corresponding RRW values are provided in .

The contribution of each system to CDF and to LERF was calculated and was shown in Table 3.5-1. The predominant contributor to CDF is RHR, with Core Spray and Feedwater 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 that contribute to the risk distribution described above were selected by the Expert Panel. The Medium Risk Category segment * (associated with the FW system) and an additional Low Safety Significant segment ** (associated with the HPCI system) were designated as High Safety Significant based on Sensitivity Study considerations. It should be noted that Table 3.7-3 indicates that there were 10 Low Safety Significant segments in HPCI, but the Expert Panel considered one of them to be High Safety Significance.

Table 3.7-3 SEGMENT CATEGORIZATION System # Segs Consequence category Risk category High Medium Low High Medium Low Expert CCDP CCDP CCDP RRW RRW RRW Panel

>1E-04 >1E-06, <1E-06 >1.005 >1.001, <1.001 HSS

<1E-04 <1.005 001 MS 30 0 17 13 4 0 26 4 003 FW 32 1 29 2 11 *1 20 12 063 SLC 5 1 0 4 0 0 5 0 068 RECIRC 16 16 0 0 0 0 16 0 069 RWCU 4 2 2 0 0 0 4 0 070 RBCCW 2 0 0 2 0 0 2 0 071 RCIC 11 1 10 0 0 0 11 0 073 HPCI 10 4 6 0 0 0 **10 1 074 RHR 28 10 17 1 3 0 25 3 075 CS 15 5 4 6 1 0 14 1 085 CRD 14 0 0 14 0 0 14 0 total: 167 40 89 38 I 19 1 147 21 E1-13

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 initial program being submitted addresses the HSS piping components placed in regions 1 and 2 of Figure 3.7-1 in WCAP-14572 (Ref. 6.4). Region 3 piping components, which are low safety significant, are to be considered in an Owner Defined Program and are 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 Xl program. For the 167 piping segments that were evaluated in the RI-ISI program, Region 1 contains 20 segments (16 subject to FAC, 4 subject to IGSCC), Region 2 contains 1 segment, Region 3 contains 27 segments (6 subject to FAC, 21 subject to IGSCC), and Region 4 contains 119 segments.

Table 1 of ASME Code Case N-577 (Ref. 6.12) provides the specific requirements for Category R-A, Risk-Informed Piping Examinations. This category is sub-divided into Item Numbers R1.11 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 as follows.

R1.11 Elements Subject to Thermal Fatigue R1.16 Elements Subject to Intergranular Stress Corrosion Cracking (IGSCC)

RI. 18 Elements Subject to Flow Accelerated Corrosion Paragraph 1-6.1 of the ASME Code Case N-577 (Ref. 6.12) 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 ASME Code Case N-577 (Ref. 6.12), 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 BFN Surveillance Instruction 1-SI-4.6.G.

The examinations determined for the BFN Unit 1 RI-ISI Program are listed in Table 3.8-1. All locations identified for examination are locations already identified under existing programs, i.e.,

ASME Section Xl, IGSCC, or FAC.

Frequency of examination is specified in Table 1 of ASME Code Case N-577 (Ref. 6.12). The examinations shall be scheduled such that the requirements of Table IWB-2412-1 of ASME Section Xl are satisfied.

Per paragraph 1-6.1 of ASME Code Case N-577 (Ref. 6.12), 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 BFN Unit 1 RI-ISI Program is listed in Table 3.8-1. In addition, examinations shall be scheduled such that the requirements of IWB-2412 of ASME Section Xl are satisfied. The schedule will be documented in BFN Surveillance Instruction 1-SI-4.6.G (Ref. 6.3).

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Table 3.8-1 Examinations Segment Boundary Description Plant ID Degl Mode Item # Exam Freq 1-001-036 12" discharge line from penetrations X-16B and X-27C to FAC locations FAC R1.18 Note 1 Note 2 reactor (N5B) 1-001-037 26" discharge line from Reactor to penetration X-7A FAC locations FAC R1.18 Note 1 Note 2 1-001-038 26" discharge line from Reactor to penetration X-7B FAC locations FAC R1.18 Note 1 Note 2 1-001-039 26" discharge line from Reactor to penetration X-7C FAC locations FAC R1.18 Note 1 Note 2 1-003-006 26" discharge line from Reactor to penetration X-7D FAC locations FAC R1.18 Note 1 Note 2 1-003-007 24" supply line from penetration X-9A to HCV-3-67 FAC locations FAC R1.18 Note 1 Note 2 1-003-008 24" supply line from penetration X-9h to HCV-3-66 FAC locations FAC R1.18 Note 1 Note 2 1-003-009 24" supply line from HCV-3-67 to ring header FAC locations FAC R1.18 Note 1 Note 2 1-003-036 12" supply line from 20" ring header to Reactor (N4A) FAC locations FAC R1.18 Note 1 Note 2 1-003-037 12" supply line from 20" ring header to Reactor (N4B) FAC locations FAC RI. 18 Note 1 Note 2 1-003-038 12" supply line from 20" ring header to Reactor (N4C) FAC locations FAC RI.18 Note 1 Note 2 1-003-039 24" supply line from HCV-3-66 to 12" inlet piping FAC locations FAC R1. 18 Note 1 Note 2 1-003-040 12" supply line from 20" ring header to Reactor (N4F) FAC locations FAC R1. 18 Note 1 Note 2 1-003-041 12" supply line from 20" ring header to Reactor (N4E) FAC locations FAC R1. 18 Note 1 Note 2 1-003-042 12" supply line from 20" ring header to Reactor (N4D) FAC locations FAC R1.18 Note 1 Note 2 1-003-043 24" discharge line from penetration X-13B to recirc line "A" FAC locations FAC R1.18 Note 1 Note 2 1-073-004 10W-14" discharge line from HPCI pump PMP-73-54 to THPCI-1-1 Stress R1.11 Xl Vol Interval FCV-73-35 and 24" Feedwater line THPCI-1-3 Stress R1.11 Xl Vol Interval THPCI-1-4 Stress R1.11 Xl Vol Interval HPCI-1-014-001 Stress R1.11 Xl Vol Interval HPCI-1-014-002 Stress Ri.11 Xl Vol Interval HPCI-1-014-003 Stress R1.11 Xl Vol Interval THPCI-1-7 Stress RI.11 Xl Vol Interval THPCI-1-22 Stress RI.11 Xl Vol Interval THPCI-1-23 Stress R1.11 Xl Vol Interval HPCI-019-005 Stress R1.11 Xl Vol Interval THPCI-1-38D Stress R1.11 Xl Vol Interval THPCI-1-40A Stress R1.11 Xl Vol Interval THPCI-1-40C Stress R1.11 Xl Vol Interval THPCI-1-40D Stress R1.11 Xl Vol Interval THPCI-1-40L Stress R1.11 Xl Vol Interval 1-074-005 24" discharge line from penetration X-1 3A to recirculation DRHR-1-3B IGSCC-G R1.16 VT-2 Cycle line "B" 1-074-007 20" line from recirculation line "A" to penetration X-12 RHR-1-013-001 IGSCC-A R1.16 IGSCC Vol Interval RHR-1-013-002 IGSCC-A R1.16 IGSCC Vol Interval 1-074-013 24" supply line from steam tunnel wall to penetration X-9B DRHR-1-13B IGSCC-G R1.16 VT-2 Cycle 1-075-001 24" supply line from steam tunnel wall to penetration X-9A CS-1-002-033A 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 schedule is a function of previous exam results and predicted wear rate.

IGSCC Vol Volumetric examination per NUREG-0313 capable of detecting IGSCC. Competency requirements of NUREG-0313 are applicable.

Xl Vol Volumetric examination per Section Xl of the Boiler and Pressure Vessel Code as implemented by 1-SI-4.6.G.

Interval Examined once per ten-year interval per the requirements of Section Xl and the requirements of NUREG-0313 as amended by BWRVIP-075 for IGSCC Category A and C welds.

Cycle Examined every cycle per the requirements of NUREG-0313 as amended by BWRVIP-075 for IGSCC Category G welds.

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3.9 Additional Examinations Additional examinations will be performed in accordance with Section -2430 of ASME Code Case N-577 (Ref. 6.12).

3.10 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 ASME Code Case N-460 (Ref. 6.11)) 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. 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 (Ref. 6.4) will be followed.

3.11 Change in Risk The RI-ISI program has been developed in accordance with Regulatory Guide 1.174 (Ref. 6.7),

and the risk from implementation of this program is expected to decrease when compared to that estimated from current requirements including both ASME Section Xl and augmented inspections.

A comparison between the proposed RI-ISI program and the current ASME Section Xl ISI program was made to evaluate the change in risk.

The risk (both CDF and LERF) addressed by current programs and addressed by the Risk-Informed program was calculated for each segment and the results tabulated by system, as shown in Table 3.11-1. The predominant contributor to CDF is RHR, with Core Spray and Feedwater 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).

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Table 3.11-1 COMPARISON BY SYSTEM OF CDF/LERF UNDER CURRENT PROGRAMS AND UNDER RI-ISI PROGRAM CDF-OA System # segs Total Current ASME Section Current Augmented Proposed RI-ISI System ___ # segs Total Xl Inspection ProposedRI-ISI 001 MS 30 3.7228E-09 3.7228E-09 3.7228E-09 3.7228E-09 003 FW 32 1.5491 E-08 1.5491E-08 1.5491 E-08 1.5491E-08 063 SLC 5 1.4860E-14 1.4860E-14 1.4860E-14 1.4860E-14 068 RECIRC 16 0.0000E+00 0.0000E+00 O.0000E+00 0.0000E+00 069 RWCU 4 9.1394E-21 9.1394E-21 9.1394E-21 9.1394E-21 070 RBCCW 2 4.2893E-20 4.2893E-20 4.2893E-20 4.2893E-20 071 RCIC 11 2.5639E-11 2.5639E-11 2.5639E-11 2.5639E-11 073 HPCI 10 2.0840E-10 2.0750E-10 2.0750E-10 2.4525E-11 074 RHR 28 3.2981E-06 3.2980E-06 2.9948E-06 2.9949E-06 075 CS 15 2.0441E-08 2.0441E-08 1.5413E-08 1.5413E-08 085 CRD 14 2.1679E-12 2.1679E-12 2.1679E-12 2.1679E-12 Total: 167 3.3380E-06 3.3379E-06 3.0297E-06 3.0296E-06 CDF-noOA System # segs Total Current ASME Section Current Augmented Proposed RI-ISI XI Inspection ProposedRI-ISI 001 MS 30 3.7228E-09 3.7228E-09 3.7228E-09 3.7228E-09 003 FW 32 1.5491E-08 1.5491E-08 1.5491E-08 1.5491 E-08 063 SLC 5 1.4860E-14 1.4860E-14 1.4860E-14 1.4860E-14 068 RECIRC 16 0.OOOOE+00 0.OOOOE+00 0.OOOOE+00 0.OOOOE+00 069 RWCU 4 9.1394E-21 9.1394E-21 9.1394E-21 9.1394E-21 070 RBCCW 2 4.2893E-20 4.2893E-20 4.2893E-20 4.2893E-20 071 RCIC 11 5.5618E-11 5.5618E-11 5.5618E-11 5.5618E-11 073 HPCI 10 1.7891 E-09 1.7882E-09 1.7882E-09 2.6323E-10 074 RHR 28 3.2981E-06 3.2980E-06 2.9948E-06 2.9949E-06 075 CS 15 2.0442E-08 2.0442E-08 1.5413E-08 1.5413E-08 085 CRD 14 2.1679E-12 2.1679E-12 2.1679E-12 2.1679E-12 Total: 167 3.3396E-06 3.3395E-06 3.0313E-06 3.0298E-06 El-17

Table 3.11-1 COMPARISON BY SYSTEM OF CDF/LERF UNDER CURRENT PROGRAMS AND UNDER RI-ISI PROGRAM LERF-OA System I # segs Total Current ASME Xl Section Current Augmented Inspection Proposed RI-ISI 001 MS 30 1.5594E-09 1.5594E-09 1.5594E-09 1.5594E-09 003 FW 32 8.0464E-09 8.0464E-09 8.0464E-09 8.0464E-09 063 SLC 5 1.8887E-16 1.8887E-16 1.8887E-16 1.8887E-16 068 RECIRC 16 0.0000E+00 0.0000E+00 0.OOOOE+00 0.0000E+00 069 RWCU 4 8.4055E-23 8.4055E-23 8.4055E-23 8.4055E-23 070 RBCCW 2 4.2136E-20 4.2136E-20 4.2136E-20 4.2136E-20 071 RCIC 11 4.9236E-13 4.9236E-13 4.9236E-13 4.9236E-13 073 HPCI 10 3.9898E-12 3.5573E-12 3.5573E-12 6.8632E-13 074 RHR 28 2.2617E-08 2.2616E-08 2.0536E-08 2.0536E-08 075 CS 15 5.3167E-09 5.3167E-09 4.0088E-09 4.0088E-09 085 CRD 14 2.1297E-12 2.1297E-12 2.1297E-12 2.1297E-12 Total: 167 3.7546E-08 3.7545E-08 3.4157E-08 3.4154E-08 LERF-noOA System # segs Total Current ASME Section Current Augmented Proposed RI-ISI XI Inspection ProposedRI-ISI 001 MS 30 1.5594E-09 1.5594E-09 1.5594E-09 1.5594E-09 003 FW 32 8.0464E-09 8.0464E-09 8.0464E-09 8.0464E-09 063 SLC 5 1.8887E-16 1.8887E-16 1.8887E-16 1.8887E-16 068 RECIRC 16 0.OOOOE+00 0.OOOOE+00 0.OOOOE+00 0.OOOOE+00 069 RWCU 4 8.4055E-23 8.4055E-23 8.4055E-23 8.4055E-23 070 RBCCW 2 4.2136E-20 4.2136E-20 4.2136E-20 4.2136E-20 071 RCIC 11 1.6355E-11 1.6355E-11 1.6355E-11 1.6355E-11 073 HPCI 10 6.9379E-11 6.8947E-11 6.8947E-11 5.0498E-11 074 RHR 28 2.2617E-08 2.2616E-08 2.0536E-08 2.0536E-08 075 CS 15 5.3169E-09 5.3169E-09 4.0089E-09 4.0089E-09 085 CRD 14 2.1297E-12 2.1297E-12 2.1297E-12 2.1297E-12 Total: 167 3.7628E-08 3.7626E-08 3.4238E-08 3.4220E-08 E1-18

Table 3.11-2 provides a comparison of CDF/LERF for the current and Risk-Informed programs, utilizing the different failure rates with or without inspection. Both the Augmented and Risk-Informed inspection programs represent a risk reduction when compared to the Base Case and Section Xl inspection program. The RI-ISI program would result in a reduction of 3.096E-07 with respect to the ASME Section XI program in regards to CDF and a reduction of 3.406E-09 in regards to LERF. The Augmented inspection program is not impacted by the Risk-Informed program and the contributions of each with regards to risk as measured by CDF and LERF are almost equivalent. The primary basis for this risk reduction is that examinations are now being placed on elements that are high safety significant and which are not inspected by NDE in the current ASME Section Xl ISI program.

Table 3.11-2 COMPARISON OF APPLICABLE CDF/LERF FOR CURRENT PROGRAMS AND FOR RI-ISI PROGRAM Program Piping CDF Piping LERF Without ISI 3.3393E-06 3.7577E-08 Current ASME Section XI 3.3392E-06 3.7576E-08 Current Augmented Inspection 3.0311 E-06 3.4188E-08 RI-ISI 3.0296E-06 3.4170E-08 Defense-In-Depth 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 PRA used as the basis of this analysis models these redundant functions. Individual quantifications were performed in this PRA 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 were evaluated for their contribution to reducing risk of core damage frequency. Specifically, piping which could potentially result in a large LOCA was evaluated, even if the risk associated with the segment was minimal or nonexistent. It was determined that all such segments subject to active degradation mechanisms are examined under augmented programs, thereby assuring their integrity. Reactor coolant pressure boundary integrity is also maintained by continued implementation of pressure testing and visual examination per ASME Section X1.

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4. IMPLEMENTATION AND MONITORING PROGRAM TVA BFN Surveillance Instruction 1-SI-4.6.G (Ref. 6.3) will be revised to implement and monitor the RI-ISI Program. That revision will comply with the guidelines described in Regulatory Guides 1.174 (Ref. 6.7) and 1.178 (Ref. 6.8) and implemented in the ASME Boiler and Pressure Vessel Code, Section Xl, as ASME Code Case N-577 (Ref. 6.12). Upon implementation of the RI-ISI program, that revision will be implemented. No changes to the BFN Updated Final Safety Analysis Report are necessary for program implementation.

The applicable aspects of the ASME 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 Xl 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.

The proposed monitoring and update program will contain the following elements:

A. Identify B. 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. Significant changes to basis documents such as the plant PRA will be evaluated for impact on the risk ranking of piping segments when such changes are identified. 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.

Most U.S. nuclear power plants have now implemented similar risk-informed inservice inspection programs, with similar review and update commitments. A task force was formed by the Nuclear Energy Institute (NEI) to formulate consistent guidance for maintaining these programs. The task force included representatives from reactor operating companies, ASME committees, Electric Power Research Institute, and Westinghouse. The result of this effort is document NEI 04-05 (Ref. 6.6). While not specifically approved by the NRC, the NRC staff reviewed the document as it was being developed and provided comments.

The RI-ISI Monitoring Program will be conducted in accordance with the recommendations of NEI 04-05 (Ref. 6.6). The requirements of BFN Surveillance Instruction 1-SI-4.6.G (Ref. 6.3) will be consistent with NEI 04-05 (Ref. 6.6).

NEI 04-05 (Ref. 6.6) provides a list of RI-ISI unique inputs and references that could be used in typical RI-ISI applications. It also contains a list of categories to review that would provide insight to which of those inputs have changed and could impact the previous RI-ISI analysis.

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Only changes made to these inputs since the previous RI-ISI re-evaluation (i.e., those in the "period of evaluation") need to be evaluated. The review to be performed is the same regardless of whether or not it is the end of an Interval. If the evaluations indicate that additional piping structural elements, systems, or portions of systems may now be HSS and therefore need to be updated, the RI-ISI program should be updated by either adding examination selections in accordance with the requirements for HSS piping structural elements, or by using the applicable portions of the same risk-informed selection process that originally established the risk-informed inspection program. If the evaluations indicate that piping structural elements, systems, or portions of systems may now be Low Safety Significant (LSS) then the RI-ISI program may remain unchanged, or examination selections may be deleted by using the applicable portions of the same risk-informed selection process that originally established the risk-informed inspection program. This reevaluation of the selections shall be performed by inserting the new information at the appropriate level of the analysis. It may not be necessary to re-perform the entire risk-informed selection process, but the evaluation for the changes to the piping selections that do occur shall be documented.

If changes occur during the periodic updates that are based on qualitative reevaluation results then those changes shall be cumulatively evaluated for inclusion in the subsequent inspection interval update. The subsequent inspection interval update shall include a reevaluation using the applicable portions of the same risk-informed selection process that originally established the risk-informed inspection program. This reevaluation of the selections shall be performed by inserting the new information at the appropriate level of the analysis. It may not be necessary to re-perform the entire risk-informed selection process, but the evaluation for the changes to the piping selections that do occur shall be documented.

The RI-ISI program will be updated, if required, before the last refueling outage of the next ASME Period. The Maintenance Rule Expert Panel will review proposed RI-ISI program changes and provide program oversight. The following provides an overview of the RI-ISI program inputs.

Changes to Plant Desiqn Features Design changes have the potential to change piping configuration and alter stress calculations which were used as input to the calculations performed in support of the RI-ISI program. New systems and branch piping will be evaluated for inclusion into the scope of the RI-ISI program.

Consequently, the design control program will be revised to recognize RI-ISI and to ensure impact is appropriately evaluated during design preparation, review, and implementation.

The existing design impact review process will also be used to ensure the impact of design changes on RI-ISI has been appropriately considered prior to final approval. The calculations supporting the RI-ISI program will be entered into TVA's calculation tracking program to ensure appropriate predecessors and inputs are identified and considered during design change preparation and review.

Chan-ges to PRA Since the PRA forms the basis for the RI-ISI program, any changes to the PRA or risk significance determination will be evaluated for impact on the RI-ISI program. This would also include changes to risk significance categories mandated by the Maintenance Rule Expert Panel. The PRA and design control procedures will be revised to ensure PRA changes also consider changes to the RI-ISI program and that RI-ISI changes are initiated as required.

E1-21

Chan.qes to Plant Procedures Changes to plant procedures that affect ISI, such as system operating parameters, test interval, or the ability of plant operations to perform actions associated with accident mitigation will be evaluated for effect on the program.

Equipment Performance Chanqes Equipment performance changes will be reviewed with appropriate plant personnel (e.g.,

system engineers, maintenance personnel, etc.,) to ensure that changes in performance parameters (e.g., valve leakage, increased pump testing, vibration problems) are considered in the RI-ISI update. Adverse equipment performance will be evaluated for changes to the RI-ISI inspection scope.

Information on Individual Plant and Industry Failures TVA will consider applicable piping failures or degradations identified by the site's corrective action program. Industry awareness will be maintained through the sites Operating Experience program, NRC Generic Letters and Bulletins, site participation in BWROG initiatives, and participation in the ASME Section Xl Code committee activities.

Examination Results NDE examinations, pressure tests, and corresponding VT-2 visual examinations for leakage that are determined to have unacceptable flaws, evidence of service related degradation or indications of leakage will be evaluated for effect to the program.

The Maintenance Rule Expert Panel will provide the oversight role for the RI-ISI program. The Expert Panel will review proposed changes to the program. As with past reviews, personnel possessing expertise in RI-ISI evaluation and ISI inspection/evaluation will be present during presentation and review of the above items.

E1-22

5. PROPOSED ISI PROGRAM PLAN CHANGE The locations selected for examination in the RI-ISI program and augmented programs were compared to the locations examined under the current programs. The results are tabulated in Table 5-1. The current ASME Section XI program selects a total of 219 locations for non-destructive examinations, while the proposed RI-ISI program and BWRVIP-75 augmented inspection program for IGSCC selects 66 locations for examinations and credits 16 FAC segments, which results in a reduction of 153 non-destructive examination locations (69.8%).

The proposed RI-ISI program and BWRVIP-075 augmented inspection program for IGSCC selects 56 of 415 Class 1 locations for examinations (13.5%).

Table 5-1 STRUCTURAL ELEMENT SELECTION RESULTS AND COMPARISON TO ASME SECTION Xl SELECTION BASED ON 2001 EDITION with 2003 ADDENDA REQUIREMENTS AND GL 88-01 REQUIREMENTS Current Proposed (a) (b) (c) (e)

ASME XI Elements Augmented Elements RI-ISI Examinations (d) (e)

System Segs B-F B-J C-F A C D E G R1.11 R1.16 R1.18 A C D E G 001 MS 30 38 10 4 003 FW 32 26 12 063 SLC 5 068 RECIRC 16 14 18 79 29 069 RWCU 4 4 13 2 1 4 1 1 070 RBCCW 2 071 RCIC 11 2 7 Cli1 5 10 6 16 CI2 105 073 HPCI 074 RHR 28 8 35 22 2 4 2 2 A (2) 1 4 2 G (2) 075 CS 15 2 8 18 12 2 1 A 3(1) 1 085 CRD 14 1 6 4 2 Total 17 110 92 39 15 7 0 10 Cl 1 5 5() 16 36 5 0

-Examinations Cl 2 10 (392)

Total Elements 1499 17 398 1024 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.

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

(c) Augmented program for IGSCC Categories A through G (BWRVIP-75) continues. Welds selected for RI are shown parenthetically.

(d) The current ASME Section Xl ISI Program examines a minimum of 25% of the Class 1 and a minimum of 7.5% of the Class 2 elements.

(e) The FAC Augmented Program examines approximately 10% of the identified locations each refueling outage.

(f) 3 Category A and 2 Category G examinations are counted in R1.16.

BFN Unit 1 is currently in the first period of the second ISI interval. It is desired to implement the RI-ISI program for this Inspection Interval. This would require program approval prior to the BFN Unit 1 Cycle 8 refueling outage scheduled for October 2010.

E1-23

6. REFERENCES 6.1 NUREG-0313, "Technical Report on Material Selection and Processing Guidelines for BWR Coolant Pressure Boundary Piping," Revision 2, January 1988.

6.2 BWRVIP-75-A, "BWR Vessel and Internals Project, Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules", EPRI TR-1 012621, October 2005.

6.3 Browns Ferry Nuclear Plant Surveillance Instruction 1-SI-4.6.G, "Inservice Inspection Program."

6.4 WCAP-14572, 'Westinghouse Owner's Group Application of Risk-Informed Methods to Piping Inservice Inspection Topical Report," Westinghouse Electric Corporation, Revision 1-NP-A, February 1999.

6.5 Engineering Mechanics Technology Technical Report TR-98-4-1, "WinPRAISE 98 -

PRAISE Code in Windows," April 1998.

6.6 NEI 04-05, "Living Program Guidance to Maintain Risk-Informed Inservice Inspection Programs For Nuclear Piping Systems", Nuclear Energy Institute, April, 2004 6.7 Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk Assessment In Risk-Informed Decisions On Plant-Specific Changes to the Licensing Basis," Revision 1, November 2002.

6.8 Regulatory Guide 1.178, "An Approach for Plant-Specific Risk-Informed Decisionmaking for Inservice Inspection of Piping," Revision 1, September 2003.

6.9 Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 2, March 2009.

6.10 ASME/ANS RA-Sa-2009, "Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications," 2009 6.11 ASME Code Case N-460, "Alternative Examination Coverage for Class 1 and 2 Welds,"

Section Xl, Division 1, July 27, 1988.

6.12 ASME Code Case N-577, "Risk-Informed Requirements for Class 1, 2, and 3 Piping, Method A,"Section XI, Division 1, September 2, 1997.

6.13 NEI 05-04, "Process for Performing Follow-on PRA Peer Reviews Using the ASME PRA Standard," January 2005.

6.14 Generic Letter 88-01, "NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping," January 25, 1988.

6.15 Generic Letter 89-10, "Safety-Related Motor-Operated Valve Testing and Surveillance,"

June 28, 1989.

El-24

6.16 NUREG-0619, "BWR Feedwater Nozzle and Control Rod Driven Return Line Nozzle Cracking," November 1980.

6.17 NUREG-0800, "Standard Review Plan for the Review of Safety Analysis Reports for Nuclear Power Plants: LWR Edition."

6.18 NRC Letter to TVA, "Browns Ferry Unit 3, ASME Code Relief for Risk-Informed Inservice Inspection of Piping (TAC No. MA5335)," February 11, 2000.

6.19 NRC Letter to TVA, "Browns Ferry Unit 2, ASME Code Relief for Risk-Informed Inservice Inspection of Piping (TAC No. MA8873)," January 19, 2001.

El-25

Attachment I CDF, LERF and RRW Main Steam Segment

[ OPERATOR ACTION CDF LERF NO OPERATOR ACTION rnpF I I Pop I

I OA CDF RISK REDUCTION WORTH OA LERF NOA CDF NOA LERFI I RRW CONTROLLING CASE CDF I LERF l I 1-001-001 1.2180E-10 2.0855E-1 1 1.0000 1.0006 1.0000 1.0006 ]10o 0 0*006]

1-001-002 1.2180E-10 2.0855E-11 1.0000 1.0006 [ 1.0000 1.0006 1-001-036 7.4102E-10 3.5763E-10 1.0002 1.0096 1.0002 1.0096 1-001-037 7.4102E-10 3.5763E-10 1.0002 1.0096 1.0002 [ 1.0096 1-001-038 7.4102E-10 3.5763E-10 1.0002 1.0096 1.0002 1.0096 1-001-039 7.4102E-10 3.5763E-10 1.0002 1.0096 1.0002 1.0096 1-001-040 8.1481E-14 1.3952E-14 1.0000 1.0000 1.0000 1.0000 1-001-041 8.1481E-14 1.3952E-14 1.0000 1.0000 1.0000 1.oooo jUo00o 96*~o~uI 1.0000 1.0000 1-001-042 1.0423E-1 1 7.2223E-13 1.0000 1.0000

• Uo~o~oo IUOOOo 1-001-043 8.1481E-14 1.3952E-14 1.0000 1.0000 1.0000 1.0000 1-001-044 8.1481E-14 1.3952E-14 1.0000 1.0000 1.0000 1.0000 1-001-045 1.2180E-10 2.0855E-11 1.0000 1.0006 1.0000 1.0006 winolo 9s.I-,oo 1-001-046 1.2180E-10 2.0855E-11 1.0000 1.0006 1.0000 1.0006 - 'I1mI 1-001-047 8.5640E-12 1.4664E-12 1.0000 1.0000 1.0000 1.0000 1-001-048 1.2180E-10 2.0855E-11 1.0000 1.0006 1.0000 1.0006 1-001-049 1.2180E-10 2.0855E-11 1.0000 1.0006 1.0000 1.0006 1-001-050 0.O000E+00 0.O000E+00 1.0000 1.0000 1.0000 1.0000 1-001-051 O.OOOOE+00 O.OOOOE+00 1.0000 1.0000 1.0000 1.0000 I I 1-001-052 O.OOOOE+00 O.OOOOE+00 1.0000 1.0000 1.0000 I _ _ _-_I__ _ _ _ _ 1.0000 1-001-053 0.O0OOE+00 O.OOOOE+00 1.0000 1.0000 1.0000 1.0000 I*~o0] ~ ]

1-001-054 O.OOOOE+O0 0.O000E+0 1.0000 1.0000 1.0000 1.0000 1-001-055 O.OOOOE+00 O.OOOOE+00 1.0000 1.0000 1.0000 1.0000 *.,~oo,* 0*o 1-001-056 O.OOOOE+00 O.OOOOE+00 1.0000 1.0000 1.0000 } 10000 1-001-057 0.O0OOE+00 O.OOOOE+00 1.0000 1.0000 1.0000 1.0000 Page 1

Attachment 1 CDF, LERF and RRW Main Steam OPERATOR ACTION NO OPERATOR ACTION RISK REDUCTION WORTH RRW CONTROLLING CASE Segment CDF LERF CDF LERF OA CDF OA LERF NOA CDF NOA LERF CDF LERF 1-001-058 1-001-059 0.OOOOE+00 0.OOOOE+00 0.OOOOE+00 0.OOOOE+00 J0000OE.0O j.OOO00E( 00 0.0000E+00 dOO -6oE+oo 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1 0000 1.0*0.

1 0000

_______L I --- Ioý ooooi-o

_____f___ F -10OE+0 ooo 1-001-060 0.OOOOE+00 0.OOOOE+00 0,E00O.00E,00 1.0000 1.0000 1.0000 1.0000 1.o00.00 1-0-6 0.OOOOE+00 0.OOOOE+00 1-O.000OE:+-00 ooo66O.oo0 1.0000 1.0000 1.0000 1.0000 1.0 000 1-001-062 0.OOOOE+00 0.OOOOE+00 ] .0'0000E+00 00000E 00 1.00000000 1.0000 1.0000 1 00 1 0000, 1-001-063 8.5640E-12 1.4664E-12 8 5640E 12 1.4664E-12' 1.0000 1.0000 1.0000 1.0000 1.0000 1 0000 Page 2

Attachment 1 CDF, LERF and RRW Feedwater J OPERATOR ACTION CDF I NO OPERATOR ACTION I I RISK REDUCTION WORTH OA LERF NOA CDF I RRW CONTROLLI I I I Segment I LERF CDF LERF OA CDF NOALERF CDF LERF 1-003-001 1.1058E-12 2.1396E-14 1.0000 1.0000 1.0000 1.0000 1-003-002 2.3022E-13 1.3720E-14 1.0000 1.0000 1.0000 1.0000 1-003-003 1.0736E-12 2.1396E-14 1.0000 1.0000 1.0000 1.0000 1-003-004 1.5377E-11 1.0655E-12 1.0000 1.0000 1.0000 1.0000 1-003-005 1.5377E-11 1.0655E-12 1.0000 1.0000 1.0000 1.0000 1-003-006 7.4102E-10 3.5763E-10 1.0002 1.0096 1.0002 1.0096 1-003-007 7.4102E-10 3.5763E-10 1.0002 1.0096 1.0002 1.0096 1-003-008 2.6030E-09 4.6581E-11 1.0008 1.0012 1.0008 1.0012 1-003-009 [ 5.3339E-09 4.3558E-09 1.0016 1.1312 1.0016 1.1309 1-003-010 1.5736E-12 4.0454E-13 1.0000 1.0000 1.0000 1.0000 1-003-011 1.5736E-12 4.0454E-13 1.0000 1.0000 1.0000 1.0000 10002 1-003-012 6.3300E-13 3.9573E-13 1.0000 1.0000 1.0000 1.0000 1-003-013 6.3300E-13 3.9573E-13 1.0000 1.0000 1.0000 1.0000 1-003-014 4.9157E-1 1 3.0731E-11 1.0000 1.0008 1.0000 1.0008 1-003-015 4.9157E-11 3.0731E-11 1.0000 1.0008 1.0000 1.0008 1-003-016 1.4848E-14 1.4585E-14 1.0000 1.0000 1.0000 1.0000 1-003-017 7.2578E-13 7.1297E-13 1.0000 1.0000 1.0000 1.0000 1-003-018 1.0819E-12 2.1396E-14 1. 10 1.0000 1.0000 1.0000 1-003-019 2.0636E-13 1.3720E-14 1.0000 1.0000

(( 1.0000 1.0000 j 1.0000 1.0000 j 1.0000 1.0000 1-003-020 1.0736E-12 2.1396E-14 1.0000 1.0000 1.0000 1.0000 1-003-021 1.5262E-12 4.0434E-13 1.0000 1.0000 1.0000 1.0000 1-003-022 1.5262E-12 4.0434E-13 1.0000 1.0000 1.0000 1.0000 1-003-023 6.4284E-13 3.9573E-13 1.0000 l 1.0000 1.0000 1.0000 1-003-024 l 1.5232E-12 4.0434E-13 1.00 100 .00 100 Page 3

Attachment 1 CDF, LERF and RRW Feedwater OPERATOR ACTION INO OPERATOR ACTIO RISK REDUCTION WORTH RRW CONTROLLING CASE Segment J CDF 7J LERF CDF J LERF OACDF OA LERF NOA CDF NOA LERF CDF LERF 1-003-036 7.4102E-10 3.5763E-10 7.4102E-10, 3.5763E-10 1.0002 1.0096 1.0002 1.0096 1.0002, 1.0096 1-003-037 7.4102E-10 3.5763E-10 7.4!02Ek-10 3.5763E-10 1.0002 1.0096 1.0002 1.0096 1.0002 1.0096 1-003-038 7.4102E-10 3.5763E-10 7.4102E-10 3.5763E-10 1.0002 1.0096 1.0002 1.0096 1.0002 1.0096 1-003-039 7.12-0 17.4102E-10 3.5763E-10 30 ] 7:410.022Ei*02 E-410 0002 1.0096 1.0002 1.0096 i *;**§ ii 1-003-040 7.4102E-10 3.5763E-10 7:.2-0 3 .5763E-1 1.0002 1.06.021002 109 1-003-041 7.4102E-10 3.5763E-10 7.4102E-10 3.5763E-10 1.0002 1.0096 1.0002 1.0096 1,0002 - ,.096 1-003-042 7.4102E-10 3.5763E-10 7.4102E-10 3.5763E-10 1.0002 1.0096 1.0002 1.0096 1.0002 ] 1.0096 1-003-043 7.4102E-10 3.5763E-10 7.4102E-i0 3.5763E-10 1.0002 1.0096 1.0002 1.0096 1.0002 1.0096 Page 4

Attachment I CDF, LERF and RRW tandby Liquid Control OPERATOR ACTION NO OPERATOR ACTION RISK REDUCTION WORTH RRW CONTROLLING CASE Segment CDF I LERF CDF IZ LERF OA CDF OA LERF NOA CDF NOA LERF CDF ] LERF 1-063-001 1.4752E-14 1.3567E-16 1.4752E-14 1.3567EE-16 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1-063-002 2.5333E-17 1.2448E-17 ] 2.5333E-17 244W-ý 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1-063-003 3.8931E-17 1.9129E-17 ]3.8931E-17 1.9129E-17 1.0000 1.0000 j 1.0000 1.000 000 ]

1.0000 i 1-063-004 4.3722E-17 2.1484E-17 [43722E17, 2.1484E-171 1.0000 1.0000 1.0000 1.0000 ] 1.o0000 j 1t0000 1-063-005 2.8844E-19 1.4173E-19 19 11o8844E-19 oo0000 o1000 10 1 000 1.0000 Page 5

Attachment 1 CDF, LERF and RRW Recirculation OPERATOR ACTION NO OPERATOR ACTION RISK REDUCTION WORTH RRW CONTROLLING CASE Segment CDF LERF CDF LERF OA CDF OA LERF NOA CDF NOA LERF I JCDFI LERF 1-068-001 o.OOOOE,+ 0 OOOOEoo[0 0.0'00oE+ O 0. E00 1.0000 1.0000 1.0000 1.000 1 0010000 1-068-002 0.OOOOE+00 0.OOOOE+00 0E*00O 00O000E ] 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1-068-003 0.O0OOE+O0 0 0OOOE +0 0 O .00 I 0 100 1.0000 1 1.00000 .000 11 0000 1.0000 0000~~~ 1.0000

• ,00

_0o_9ooE 1-068-004 o0.OOOOE+00 ooooEoo 0O000E+00 OOOEOOOOE0 0.000Et0O 1.0000

.00 10001.0000 - .0000

.00 1.0000 100 :0000

.- 0 1-1-068-005 0.OOOOE+00 0.OOOOE+00 ;oo0*00 0 0000E000 1.0000 1.0000 1.0000 1.0000 1-068-005 .OOOOE+00 ,000-+ 01 E.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-068-007 0.OOOOE+00 0.OOOOE+00 0.0009E+00 0.0000 1.0000 1.0000 1.0000 1.0000 1.000 1.0000 1-068-008 0.0000E+00 0.0000E+00 00600LE+00 0.O000E+00 1.0000 1.0000 1.0000 1.mO0OO0 1-068-009 0.OOOOE+00 0.0000E+00 OMOOE+00] 0 00+

O.lm000000

.*00000 1OI0000 1.0000 [ Im00 000 1.0000 I

i 1.oooo 000ooo 1-068-010 0.0 0 0. E+00 0 .0 OOOOE+000 OOOOE+00 00 10001. 1.0000 1.00..

1-068-010 0.OOOOE+00 0.OOOOE+00 , ,0000E+004 00000E+00 1.0000 1.0000 1.0000 1.0000 1.0000 1-068-010 0.OOOOE+00 0.OOOOE+00 .0000OE+00 oO000E.-0 1.0000 1.0000 1.0000 1.0000 1.0000 1 0000 1-068-011 0.OOOOE+00 0.0000E0O0 I-oo O 1.oo I 1oo 1oo o 1-068-014 0.0000E+00 0.0000E+00 0...00E+00 0I0Q0qE+00 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1-068-0.14 OOOOE+00 .OOOOE+00 ..0.000E+00 O0OOOOE+00 1.0000 1.0000 1.0000 1.0000 1.0000 1 0000 1-068-016 0.OOOOE+00 0.OOOOE+00 1-068-0~~~ 16]0OOE0.OO+0 0....E+00 0pOEQ 0 OOOOE+00 000E0 1

1.0000 1.0000 [ 1.0000 { 1.0000 100

.ooo 1000 Page 6

Attachment I CDF, LERF and RRW RWCU I OPERATOR ACTION NO OPERATOR ACTIoN I RISK REDUCTION WORTH IRRW CONTROLLINGcAs Segment CDF LERF CDF I LERF OA CDF OA LERF I NOA CDF NOALERFI CDF I I

LERF II 1-069-001 0.OOOOE+00 0.OOOOE+00 0.00.OEO j0000E+E0' 1.0000 1.0000 1.0000 1.0000 1-069-002 0.-OOOOE-00 0.0000E+00 0O O I0:O000E+00 1.0000 1.0000 1.0000 1.0000 1-069-003 4.0157E-28 9.5021E-29 4,015E-28 T95021E-291 1.0000 1.0000 1.0000 1.0000 1-069-019 9.1394E-21 8.4054E-23 ~9,1394E-21 -8:4054E-23 1.0000 1.0000 1.0000 1.0000 Page 7

Attachment I CDF, LERF and RRW RBCCW OPERATOR ACTION NO OPERATOR ACTION RISK REDUCTION WORTH RRW CONTROLLING CASE Segment ZRIZCJF ,EF Z CFIZ ,RF [ OA CDF OA LERF I NOA CDF INOA LERF CDF LERF 1-070-013 2.1446E-20 2.1068E-20 .21446E,20 2.1068E-20 1.0000 1.0000 1.0000 1.0000 1 Moo 1-070-014 2.1446E-20 2.1068E-20 2 .1068E-20 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 Page 8

Attachment 1 CDF, LERF and RRW RCIC OPERATOR ACTION NO OPERATOR ACTION RISK REDUCTION WORTH _ _ RRW CONTROLLING CASE Segment CDF LERF CDF LERF OA CDF [ OA LERF_ INOA CDF NOA LERF CDF LERF 1-071-001 6.3320E-13 1.1992E-14 f6.3320E-13 1.1992E-14 1.0000 1.0000 1.0000 1.0000 .100000_ 1 0000 1-071-002 1.1337E-13 7.8551E-15 11337EA3 7.8551E*15 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1-071-003 1.9850E-11 3.7592E-137 -11 O98 3.7592E**13 1.0000 1.0000 1.0000 1.0000 [ iI'I.1 .ooijIO0 1-071-004 1.4590E-12 1.3107E-14 [ 3.1439E-151 1.5876E-11_1 1.0000 1.0000 1.0000 1.0004 [ 10000 1.0004 1-071-005 O.OOOOE+0O O.OOOOE+0O [ O.OOOO O 0 O0OOE+O0 ] 1.0000 1.0000 1.0000 1.0000 0 [10000* 00 1.0000 1-071-007 2.2385E-15 1.8517E-17 2,2385E"15 18517E17 1.0000 1.0000 1.0000 [ 1.0000

.1.0000 .*ooo0 1-071-008 2.0506E-12 [1.8421E-14 2.0506E-12 1.8421E-14 1.0000 1.0000 1.0000 1.0000 [ i.00 ,0o0o0 1-071-009 2.2793E-19 2.0476E-21

-146.5044E-14 22793E-19,

.5303E-12

.0476E-21]

6.50.4E. _4 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000

[ .o000 110000.0000 1.0000 1-071-010 1.5303E-12 *.1:33-2 65** .00! uu*'** .uu^^

1-071-011 j.OOOOE+00 [.OOOOE+00 [o0710E 17 j 18 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000A 1-071-013 1.0883E-19 9.7765E-22 10 W!08E1 9.7765E 95-22 22 100 1.0000 00 000 1mOOOo { 1"0000 10 1 000 "00 1.0000 Page 9

Attachment 1 CDF, LERF and RRW HPCI Segment

[ OPERATOR ACTION CDF LERF NO OPERATOR ACTION CDF LERF OA CDF RISK REDUCTION WORTH OA LERF NOA CDF NOALERFI I RRW CONTROLLING CASE CDF I LERF 1-073-001 8.9667E-13 4.3275E-13 6..7.-13

... 43-75E- 3 1.0000 1.0000 1.0000 1.0000 1-073-002 15584E-11 1,I56OE- 1 J 2.542,E

- -10 4.996ý7E- 11 1.0000 1.0000 1.0001 1.0013 1-073-003 { 0.0000E+00 0.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-073-004 1.8387E-10 3.3036E-12 1.0001 1.0001 1.0005 1.0005 1-073-005 1.5536E-24 1.5600E-26 1.0000 1.0000 1.0000 1.0000 1-073-006 0.OOOOE+00 0.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-073-007 0.OOOOE+00 0.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-073-008 7.9809E-12 9.6818E-14 1.0000 1.0000 1.0000 1.0000 1-073-009 6.0184E-14 6.0279E-16 1.0000 1.0000 1.0000 1.0000 1-073-011 1.1209E-16 1.1226E-18 1.0000 1.0000 1.0000 1.0000 Page 10

Attachment I CDF, LERF and RRW RHR OPERATOR ACTION NO OPERATOR ACTION RISK REDUCTION WORTH RRW CONTROLLING CASE I Segment CDF LERF CDF LERF OA CDF OA LERF NOA CDF NOA LERF I CDF I LERF I 1-074-001 0.0000E+00 0.0000E+00 1.0000 1.0000 1.0000 1.0000 1-074-002 5.3458E-10 2.0747E-12 1.0002 1.0001 1.0002 1.0001 1-074-003 0.0000E+00 0.0000E+00 1.0000 1.0000 1.0000 1.0000 1-074-004 8.2021E-14 6.0727E-17 1.0000 1.0000 1.0000 1.0000 1-074-005 1.1980E-06 8.2243E-09 1.5598 F 1.2805 1.5594 F 1.2797 1-074-006 0.OOOOE+00 0.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-074-007 2.4765E-08 1.5314E-10 1.0075 1.0041 1.0075 1.0041 1-074-008 6.1186E-17 1.1072E-17 1.0000 1.0000 1.0000 1.0000 1-074-009 [ 1.2706E-15 2.0206E-16 1.0000 1.0000 1.0000 j 1.0000 1-074-010 5.5571E-10 2.6665E-12 1.0002 1.0001 1.0002 1.0001 1-074-011 0.OOOOE+00 0.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-074-012 1.8320E-18 -5.5075E-22 1.0000 1.0000 1.0000 1.0000 1-074-013 2.0742E-06 1.4234E-08 2.6414 1.6106 2.6393 1.6085 1-074-014 [4.0332E-14 7.8752E-17 1.0000 T 1.0000 1.0000 1.0000 1-074-015 2.2065E-17 4.3084E-20 1.0000 1.0000 1.0000 1.0000 1-074-016 2.5365E-16 2.5371E-16 1.0000 1.0000 1.0000 1.0000 1-074-017 1.3985E-13 8.4131E-15 1.0000 1.0000 1.0000 1.0000 1-074-018 4.2567E-12 2.2305E-13 1.0000 1.0000 1.0000 1.0000 1-074-019 3.3922E-12 2.1776E-14 1.0000 1.0000 1.0000 1.0000 1-074-020 3.3925E-12 2.1776E-14 1.0000 1.0000 1.0000 1.0000 1-074-023 1.OOOOE-28 0.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-074-024 1.OOOOE-28 0.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-074-025 1.0271E-17 4.8503E-20 1.0000 1.0000 1.0000 1.0000 1-074-026 1.6948E-17 6.5316E-20 1.0000 1.0000 1.0000 j 1.0000 Page 11

Attachment 1 CDF, LERF and RRW RHR OPERATOR ACTION NO OPERATOR ACTION RISK REDUCTION WORTH RRW CONTROLLING CASE Segment CDF I LERF I CDF I LERF I OA CDF OA LERF NOA CDF NOALERFI CDF I LERF I 1-074-027 2.1923E-19 4.8030E-21 1.0000 1.0000 1.0000 1.0000 1-074-029 2.1445E-19 4.6675E-21 1.0000 1.0000 1.0000 1.0000 1-074-030 2.1585E-20 4.5800E-22 1.0000 1.0000 1.0000 1.0000 1-074-031 2.1706E-19 5.6571E-21 1.0000 1.0000 1.0000 1.0000 Page 12

Attachment 1 CDF, LERF and RRW Core Spray OPERATOR ACTION NO OPERATOR ACTION RISK REDUCTION WORTH RRW CONTROLLING CASE Segment CDF LERF CDF LERF OA CDF OA LERF NOA CDF NOA LERF CDF LERF 1-075-001 2.0441_E-08 5.3166E-09 -2.0441E-08 5.3166E-09 1.0062 1.1650 1.0062 1.1645 1.0062 1.1648I 1-075-002 9.0248E-19 2.3737E-19 9.0248E- 19 1.0000 ioo 1.0000 1.0000 1.0000 i .0*00 1-075-003 0.0000E+0{ 0.OOOOE+00 O.OOOOE+00 O.OOOOE+ ] _ 1.0000

__1._0000 1.0000 1.0000 1.0000 1.___0000 1-075-004 0.OOOOE+00 0.OOOOE+00 [0 -0060E+00 00000E+ 1.0000 1.0000 1.0000 1.0000 oo 0000....

1-075-005 2.5280E-20 1.4205E-21 [ 25280E-20 ..I4205E-21 1.0000 1.0000 1.0000 1.0000 1.000.0 1.0000 1-075-006 7.9607E-19 5.0978E-20 [ 7.91607E-19 5.0978E-20 1.0000 1.0000 1.0000 1.0000 [ 0o0 1 oooo 1-075-007 2.0000E-28 -2.0000E-28 1.0000 1.0000 1.0000 1.0000 1 0000 ... 000 .

1-075-007A 1-075-007A 6.OOOOE-28 -2.OOOOE-28[ 6.99084E-23 0000 -28[ -.

0.OO28 -000E-28 699E3 1.2628E-23 1.0000 .00 1.0000 - 1.000 100 1.0000 .00 1.0000 L100 1.000 ~ 1Q0 1.O 1-075-008 -1.9000E-27 -7.3000E-27 2.9918E-21 5.4041 E-22 1.0000 1.0000 1.0000 { 1.0000 1 1.0000 j 1.00 1-075-008A 1.3200E-26 -7.3000E-27 2Z99,18E-21 5.4045E-:22 1.0000 T 1.0000 1.0000 1.000 F 1 0o 1-075-009 1.4651E-17 3.2639E-18 1.i4,6 5 E -17 3.2639E-18 { 1.0000 1.0000 1.0000 1.0000 [ i.0o00 1.0000o 1-075-012 1.7301E-13 1.5174E-13 F .1.7301E-13 1.5174E-13 1.0000 1.0000 1.0000 1.0000 1.00o0 1.0000 1-075-013 0.OOOOE+00 0.OOOOE+00 1.7-636E-13 1.5213E-13 1.0000 1.0000 1.0000 1.0000 [.... 1.0000 1-075-014 4.1264E-20 F2.6424E-21 4.1 426E-20 6424E-21 1-075-015 3.5912E-20 1 2.0181E-21 3.5912E-20 2.0181E-21 1.0000 1.0000 1.0000 1.0000 1.0000 1.0000 Page 13

Attachment 1 CDF, LERF and RRW Control Rod Drive OPERATOR ACTION I NO OPERATOR ACTION I RISK REDUCTION WORTH IRRW CONTROLLINGCAS I Segment CDF LERF I CDF I LERF I OACDF OA LERF NOA CDF NOALERF I CDF I LERF I 1-085-001 5.4198E-1 3 5.3242E-13 1.0000 1.0000 1.0000 1.0000 1-085-002 5.4198E-13 5.3242E-13 1.0000 1.0000 1.0000 1.0000 1-085-003 5.4198E-13 5.3242E-13 1.0000 1.0000 1.0000 1.0000 1-085-004 5.4198E-13 5.3242E-13 1.0000 1.0000 1.0000 1.0000 1-085-005 5.OOOOE+00 5.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-085-006 O.OOOOE+00 O.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-085-007 O.OOOOE+00 O.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-085-008 [0.O000E+00 O.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-085-022 O.OOOOE+00 O.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-085-023 O.OOOOE+00 O.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-085-024 O.OOOOE+00 O.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-085-025 O.OOOOE+00 O.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-085-026 O.OOOOE+00 O.OOOOE+00 1.0000 1.0000 1.0000 1.0000 1-085-027 00.OOOOE+00 O.OOOOE+00 1.0000 1.0000 1.0000 1.0000 Page 14

Enclosure 2 Tennessee Valley Authority Browns Ferry Nuclear Plant Unit I American Society of Mechanical Engineers,Section XI Inservice Inspection Program, Unit 1 Second Ten-Year Inspection Interval Request for Relief 1-ISI-26, Risk-Informed Inservice Inspection Program Summary of Browns Ferry Nuclear Plant Probabilistic Risk Assessment Quality Upgrade Initiative E2-1

1. Introduction The Browns Ferry Nuclear Plant (BFN) Probabilistic Risk Assessment (PRA) model was revised to support BFN Unit 1 restart and a full-scope Peer Review was completed in October 2006 on that revised model. The review identified 78 A and B level Findings and Observations (F&Os). A total of 278 F&Os were identified, including the C and D level F&Os. In addition, in a July 16, 2007 letter to the Tennessee Valley Authority (TVA), the NRC stated that they had identified a number of weaknesses with the PRA model during a January 2006 audit. The NRC also stated that until such time as the information needed to allow the NRC to reach a conclusion regarding the quality and technical adequacy of the PRA model was provided, they did not believe that the existing BFN Unit 1 PRA model should be used to support time-sensitive requests, such as notice of enforcement discretions, or emergency or exigent changes to the Technical Specifications. Considering the high cost estimated to resolve the F&Os from the Peer Review, the NRC identified weaknesses associated with the PRA model, and the fact that resolving these issues would still not produce the documentation required to meet the latest industry PRA quality standards endorsed in applicable regulatory guidance, TVA elected to perform a complete upgrade of the BFN PRA model.

The PRA Quality Upgrade Initiative effort began in July 2007. The scope of this project included transition of the PRA software from RISKMAN to CAFTA and development of a three-unit model including all supporting documentation, in accordance with the standards endorsed by Regulatory Guide 1.200, "An Approach for Determining the Technical Adequacy of Probabilistic Risk Assessment Results for Risk-Informed Activities," Revision 2.

The PRA model was developed to meet the capability Category 2 standards for analysis as described in ASME/ANS RA-Sa-2009, "Standard for Level 1/Large Early Release Frequency Probabilistic Risk Assessment for Nuclear Power Plant Applications." A full-scope Boiling Water Reactor Owners Group (BWROG) Peer Review of the new model was conducted in May 2009. The team of seven industry peers determined that the Internal Flooding analysis documentation was incomplete at the time of the review and this element was excluded from their scope of review. Subsequently, the Internal Flooding analysis was completed and a recognized industry expert was contracted to perform a focused review of this element in October 2009.

This document provides a summary of the tasks that were completed in order to upgrade the BFN PRA. The following sections provide a description of the general requirements of the project and specific details of the steps taken to ensure quality in each of the tasks performed to upgrade the BFN PRA.

21 General Aspects of the Update The previous BFN PRA included individual models for each unit that created logistical problems with maintaining the models and supporting data current. The new CAFTA model is an integrated, three-unit model that allows the update of multi-unit system models, initiating event frequencies, component failure rates, and unavailability data for all three units with one revision to the model.

Plant and system configuration changes that were field implemented at the model freeze date (i.e., January 1, 2008) were included in the upgraded model. Plant configuration changes that are implemented after the freeze date are reviewed for PRA impact and incorporated into the model as necessary for individual applications. In addition, plant and E2-2

system configuration changes resulting from security event mitigation strategies and procedures were included in the upgraded model.

All BFN PRA notebooks were developed and issued as TVA calculation documents, in accordance with TVA administrative procedures. The BFN PRA documentation is now retrievable, traceable, and reproducible.

Individuals performing tasks associated with the development of the BFN PRA models and documentation were qualified in accordance with TVA administrative procedures. BFN licensed operators were used as consultants in developing initiating events, accident progression sequences, success criteria, and human performance parameters.

Responsible BFN system engineers were involved in the development and review of initiating events and systems analyses.

3. Initiating Events Analysis The initiating event analysis has been updated to include current industry generic data reflected NUREG/CR-6928, "Industry-Average Performance for Components and Initiating Events at U.S. Commercial Nuclear Power Plants," recent plant events and multi-unit initiators. NUREG/CR-6928 was the primary source for industry data and includes data through January 1, 2003. The scope of this analysis included: 1) a review of all initiators in the RISKMAN model to ensure applicability, 2) resolution of previously identified problems including a re-evaluation of the failure modes and effects analysis to identify new initiators not previously modeled, 3) a review of any common initiators that could result in challenging all 3 units or a combination of any 2 units, 4) the Bayesian updating of the initiating event frequency uncertainty distributions with plant specific data from Licensee Event Reports,

5) and the development of an updated Initiating Event Notebook. The Initiating Event Notebook contains all information and documentation necessary to provide a single source of reference regarding initiating events treatment and allow TVA to perform all future updates.

A total of 101 new initiators were added to the three-unit model. Fifty-seven of these initiators are flooding initiators that replaced the seven initiators that were previously included in the BFN Unit 1 RISKMAN model. There are three new initiators (one for each unit) that model the plugging of the raw water intake structure. The rest of the new initiators are related to the loss of specific AC electrical boards and various combinations of the simultaneous loss of two DC boards.

4. Accident Sequence Analysis The accident sequence analysis models, chronologically (to the extent practical), are the different possible progressions of events (i.e., accident sequences) that can occur from the start of the initiating event to either successful mitigation or core damage. The accident sequences account for the systems that are used (and available) and operator actions performed to mitigate the initiator based on the defined success criteria and plant operating procedures (e.g., plant emergency and abnormal operating procedures) and training. The availability of a system includes consideration of the functional, phenomenological, and operational dependencies and interfaces between the various systems and operator actions during the course of the accident progression.

The accident sequences analysis was completely re-evaluated for the BFN PRA upgrade to CAFTA. All initiating events were grouped into classes that could be evaluated collectively.

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For each functional group of initiating events, an event tree model was developed that defines the possible plant responses, mitigating system functions, and operator actions that determine the event sequence progression. A comprehensive set of plant damage states were defined to account for important conditions that may affect containment response and possible offsite releases after a severe core damage event. These plant damage states provide the interface between the Level 1 PRA models and the Level 2 PRA models. BFN licensed operators were interviewed as part of this process to ensure realistic conditions were modeled.

A total of eight event trees were developed for the BFN PRA:

• GTRAN - General Transient event tree

• ATWS - Sub-tree for accidents involving Anticipated Transient without SCRAM

• IOOV - Sub-tree for accidents involving one stuck open relief valve

• MLOCA - Medium LOCA event tree

• LLOCA - Large LOCA event tree

• VILOCA - Interfacing System LOCA - Core Spray system discharge piping

• VRLOCA - Interfacing System LOCA - RHR system discharge piping

• VSLOCA - Interfacing System LOCA - RHR system suction piping A BFN Unit 1/2/3 Accident Sequence Notebook was produced that provides the top event descriptions, the event tree descriptions and other information as appropriate. The Accident Sequence Notebook contains all information and documentation necessary to provide a single source of reference regarding event tree and accident sequence analysis treatment.

5. Success Criteria The success criteria analysis was completely re-evaluated for the BFN PRA upgrade to CAFTA. Success criteria analysis determines the minimum requirements for each function (and ultimately the systems used to perform the functions) to prevent core damage (or to mitigate a release) given an initiating event. The requirements defining the success criteria are based on engineering analyses that represent the design and operation of the plant under consideration. For a function to be successful, the criteria are dependent on the initiator and the conditions created by the initiator. The computer codes used to perform the analysis for developing the success criteria are validated and verified for both technical integrity and suitability to assess plant conditions for the reactor pressure, temperature, and flow range of interest, and they accurately analyze the phenomena of interest. Calculations were performed by personnel who are qualified to perform the types of analyses of interest and are well trained in the use of the codes.

The objectives of the success criteria element are to define the plant-specific measures of success and failure that support the other technical elements of the PRA in such a way that overall success criteria are defined to determine the core damage frequency and large early release frequency for each unit. Success criteria are defined for critical safety functions, supporting systems, structures, components and operator actions necessary to support accident sequence development.

During risk model development, existing safety analyses were reviewed, and specific thermal hydraulic analyses were performed to establish realistic success criteria for the mitigating systems and operator actions that are modeled in the PRA. In some cases, conservative success criteria were used to simplify the models or their supporting analyses E2-4

when the degree of conservatism was determined not to have an important impact on the overall PRA results.

6. Systems Analysis All systems that are required for accident mitigation and those systems supporting accident mitigating systems have been re-analyzed as part of the conversion from RISKMAN to CAFTA. To support this analysis, each system modeled in the PRA was walked down by a group of PRA analysts to evaluate

1. component location and operational status;

2. susceptibility to flooding and spray;

3. environmental considerations such as heat sources, ventilation, and steam/humidity sources;

4. considerations for manual operation; and

5. physical characteristics of the room/area.

Any plant design changes made since the last PRA model update were incorporated into the system models. Within the PRA model, the basic events were identified to include the BFN unique identifiers to support future applications such as online risk management. The simplified drawings for each system were re-drawn to match the current plant configuration and reference the current revision of the corresponding BFN drawings. All components included in the PRA models are represented in the simplified drawings. Any non-modeled components represented in the drawing are annotated as such. The intersystem dependency analysis was reviewed, upgraded and documented.

Documentation was provided in the form of an overall system analysis notebook with individual system notebooks, for all systems modeled. The System Analysis notebooks contain all information and documentation necessary to provide a single source of reference regarding individual system treatment to facilitate future updates.

Each system notebook was reviewed by the responsible System Engineer at BFN.

Subsequently, the PRA analyst interviewed the respective System Engineers. The purpose of the interview was to:

• ensure system modeling in the BFN PRA is consistent with the as-built, as-operated plant;

• ensure potential initiating events have not been overlooked; and

• ensure system operating experience is properly considered and documented in the BFN PRA.

7. Data Analysis The objectives of the data analysis are to provide estimates of the parameters used to determine the probabilities of the basic events representing equipment failures and unavailabilities modeled in the PRA in such a way that:

" parameters, whether estimated on the basis of plant-specific or generic data, appropriately reflect the configuration and operation of the plant;

" component or system unavailabilities due to maintenance or repair are accounted for; and

" uncertainties in the data are understood and appropriately accounted for.

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The unreliability (or failure rate) data are based on generic industry data that has undergone Bayesian updating with plant specific data. Plant specific data for the period January 1, 2003, to January 1, 2008, was evaluated and used as input to the Bayesian analysis.

The unavailability data is based on plant specific data collected in support of the Maintenance Rule or derived from plant records, generic industry data, or estimates from plant personnel such as system engineers or operations staff. Plant specific data is the preferred method for determining unavailability since it represents historical equipment unavailability. Plant maintenance unavailability data is based on the same time period as the failure data (i.e., January 1, 2003, to January 1, 2008). Generic industry data from NUREG/CR-6928 was used for components for which no plant specific data was available.

If no plant specific or generic industry data were available, estimates from plant personnel such as system engineers or operations staff was used.

Common cause failures are the failures of multiple, redundant equipment from three main causes:

• Inadequate design or equipment qualifications

• Improper maintenance or testing

• Equipment aging In the conversion of the BFN PRA from a RISKMAN model to a CAFTA model, the methodology was changed from the Multiple Greek Letter methodology to the Alpha Factor Method.

The Alpha Factor Method was chosen for the BFN PRA model to estimate CCF probability for several reasons:

• It is a multi-parameter model which can handle any redundancy level.

• The parameters used in the model are based on the ratios of failure rates which makes the assessment of its parameters easier when no statistical data are available.

• It has a simpler statistical model compared to other analytical models.

• It produces more accurate point estimates as well as uncertainty distributions compared to other analytical models (e.g., Multiple Greek Letter Model which has the first two properties listed above).

• The recommended parametric model to use in quantifying common cause failures (CCFs) is the alpha model. This is consistent with ASME PRA Standard supporting requirement DA-D5 Capability Category I1.

8. Human Reliability Analysis The purpose of the Human Reliability Analysis (HRA) is to identify human interactions that could play a role in the accident sequences, and to provide an estimate of the probabilities for failure events corresponding to these interactions. The HRA for the BFN PRA was completely re-evaluated as part of the BFN PRA upgrade.

All human error probabilities were reviewed and upgraded based on all applicable three-unit BFN operating procedures. New industry methods and philosophy for human reliability analysis were incorporated into the BFN HRA including addressing and documenting dependency between actions.

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As part of the upgrade process, BFN operations personnel were interviewed to assess the timing, level of stress, location of specific operator actions, accessibility of actuation equipment during accident conditions, and number operators required for specific tasks. In addition, simulator runs were performed by BFN licensed operators so that the HRA analysts could observe operator actions for events of interest.

9. Internal Flooding The internal flooding (IF) analysis for the BFN PRA was completely re-evaluated as part of the BFN PRA upgrade. The scope of the flooding analysis includes all floods originating within the plant boundary. It does not include floods resulting from external events (e.g.,

weather, offsite events such as upstream dam rupture, etc.). The overall objective of the internal flood PRA is to ensure that the impact of internal flood as the cause of either an accident or a system failure is evaluated in such a way that:

• the fluid sources within the plant that could flood plant locations or create adverse conditions (e.g., spray, elevated temperature, humidity, pressure, pipe whip, jet impingement) that could damage mitigative plant equipment are identified and

• the internal flood scenarios/sequences that contribute to the core damage frequency and large early release frequency are identified and quantified.

Several plant walkdowns were performed to assess the plant for partitioning into flood zones, characterize the flood sources in each zone, examine the flow propagation paths between flood areas, and determine the susceptibility of PRA equipment to flood and spray effects.

10. Large Early Release Frequency Analysis The Large Early Release Frequency (LERF) Analysis was completely re-done as part of the conversion from a RISKMAN model to a CAFTA model. The LERF Analysis describes the process used to identify core damage sequences that could lead to large early fission product releases to the environment and therefore contribute to the BFN LERF.

The LERF sequences are identified through the development of a series of containment event trees (CETs). The LERF Analysis documents the development of the CETs and the process used to quantify LERF using the CETs. Results of the LERF quantification are contained in the PRA Quantification Notebook.

Separate CETs are developed for each core damage functional class that could result in large early releases. The CET structure has been formulated to include the following features for the accurate assessment of LERF:

• to properly represent the time sequence of events and to divide the CET into major time periods;

• to incorporate all important system, human and phenomenological occurrences including possible recovery;

• to maintain a simplified representation;

• to preserve the nature of the challenge throughout the analysis;

• to explicitly recognize the effect of postulated containment failure modes;

• to allow the identification of recovery and repair actions that can terminate or mitigate the progression of a severe accident; and E2-7

to categorize the end-states of the resulting sequences into groups that can be assessed for their affect on public safety. (This grouping has been simplified to meet the guidance of Regulatory Guide 1.174, "An Approach for Using Probabilistic Risk Assessment In Risk-Informed Decisions On Plant-Specific Changes to the Licensing Basis." The end-states consist of "LERF" and "No LERF.")

The LERF analysis interfaces with the Level 1 accident sequence analysis through the appropriate definition of a set of core damage functional classes. These states are the endpoints of the sequences in the Level 1 portion of the event trees and the initiating events for the CETs. The end products of the LERF analysis include a set of release categories, which define the radionuclide releases into the environment, and a quantification of the frequency of each release category. The analysis supporting the containment failure probabilities was updated with the latest plant design information.

11. Quantification The purpose of this task is to quantify the BFN Unit 1/2/3 CAFTA model and document the results in a PRA Quantification Notebook. The purpose of this notebook is to present the results of the BFN PRA. These results include the calculated total Core Damage Frequency (CDF), uncertainties in the estimated CDF, and the key plant damage classes. This notebook also describes and documents the review of the initiating events, accident sequences, basic events, HEP, systems, and sources of uncertainty that are significant contributors to the CDF. Importances of systems, components, operator actions, and initiating events are documented in the PRA Quantification notebook.

12. BWROG Peer Certification and F&O Resolution The previous RISKMAN model underwent a peer review by the BWROG and received a total of 278 F&Os. Although many of these F&Os did not apply to the new CAFTA model because they were specific to RISKMAN modeling techniques, all were reviewed and considered in the development of the new model and PRA documentation.

The BFN Units 1, 2 and 3 Internal Events PRA Peer Review was performed in May 2009 at the TVA offices in Chattanooga, TN, using the process described in NEI 05-04 (Process for Performing Follow-on PRA Peer Reviews Using the ASME PRA Standard), the ASME PRA Standard (ASME/ANS RA-Sa-2009), and Regulatory Guide 1.200, Revision 2. A separate review was performed for the Internal Flooding portion of the BFN PRA in October 2009.

The Internal Flooding Peer Review also used the NEI 05-04 process, the ASME PRA Standard, and Regulatory Guide 1.200, Revision 2. A team of independent PRA experts from nuclear utility groups and PRA consulting organizations carried out these Peer Review Certifications.

The purpose of these reviews was to provide a method for establishing the technical adequacy of the BFN PRA for the spectrum of potential risk-informed plant licensing applications for which the BFN PRA may be used. The 2009 BFN PRA Peer Reviews provided a full-scope review of the Technical Elements of the internal events, at-power PRA.

These intensive peer reviews involved over two person-months of engineering effort by the review team and provided a comprehensive assessment of the strengths and limitations of each element of the PRA model. The Peer Review Certification of the BFN PRA model performed by BWROG in May 2009 and October 2009 resulted in a total 125 findings for the three unit model for internal events and internal flooding. All findings from these E2-8

assessments have been dispositioned. This resulted in a number of enhancements to the BFN PRA model prior to its use to support these proposed changes. The certification team determined that with these proposed changes incorporated, the quality of all elements of the BFN PRA model is sufficient to support "risk significant evaluations with deterministic input."

As a result of the effort to incorporate the latest industry insights into the BFN PRA model upgrades and certification peer reviews, TVA has concluded that the results of the risk evaluation are technically sound and consistent with the expectations for PRA quality set forth in Regulatory Guide 1.174 and Regulatory Guide 1.177, "An Approach for Plant-Specific, Risk-Informed Decisionmaking: Technical Specifications."

The PRA Update process defined in TVA administrative procedures ensures that the BFN PRA model adequately reflects the as-designed and as-operated plant configurations. The PRA Update process addresses those activities associated with maintaining and upgrading the BFN PRA model and documentation. PRA Updates include a general review of the entire BFN PRA model, incorporation of recent plant data and physical plant changes, conversion to new software versions, implementation of new modeling techniques, and a comprehensive documentation effort. The PRA Update process replaces the current BFN PRA Model of Record (MOR) with the updated BFN PRA MOR. The PRA Update process is applied to the Level 1/2, full power, internal events BFN PRA. However, the process may be applied to other risk related applications. The BFN PRA model updates are scheduled for 24-month intervals to coincide with BFN refueling outages.

13. Conclusion The BFN PRA has been converted from a RISKMAN model to a CAFTA model. During this process, all aspects of the BFN PRA were reviewed and the documentation was upgraded to be consistent with the current plant design and operation and all of the Peer Review comments from the 2006 review were incorporated into the model. Following the upgrade of the model, the internal events and internal flooding portions of the PRA were peer reviewed to the latest ASME PRA standard. All of the findings from these two peer reviews were dispositioned and incorporated as necessary. As a result of these activities, the BFN PRA is now considered to meet the requirements of Regulatory Guide 1.200, Revision 2 for Internal Events and Internal Flooding and have adequate quality to be used in support of risk-

,informed applications for BFN.

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