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Increased MSIV Leakage Tech Spec Change Submittal - Seismic Evaluation Rept.
	ML18039A882
Person / Time
Site:	Browns Ferry
Issue date:	08/31/1999
From:	; EQE, INC.
To:	;
Shared Package
ML18039A879	List: ML18039A878; ML18039A881; ML18039A882;
References
	200918-R-002, 200918-R-002-R00, NUDOCS 9910120261
	Download: ML18039A882 (240)
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20091 8-R-002 Revision 0 August 31, 1999 Page 1 of 75 Seismic Evaluation Repert Pregeredfor:

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200918-R-002 Revision 0 August 31, 1999

~ Page 2 of 75 APPROVAL COVER SHEET tmmNWmOm t.

Browns Ferry Nuclear Plant Increased MSIV Leakage

Title:

Tech Spec Change Submittal Seismic Evaluation Report Report Number: 200918-R-002 Client: Tennessee Valley Authority Project Number: 200918.01

, 'evisi'on A'pproval

'N'umber. Date Prepared Reviewed Approved; 0 8/31/99

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,200918-R-002 Revision 0 August 31, 1999 Page 1 of 75 TABLE OF REVISIONS 0 Initial Issue August 31, 1999 1999'by EQE International, Inc.

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200918-R-002 Revision 0 August 31, 1999 Page 4 of 75 TABLE'F CONTENTS Pacae INTRODUCTION .

SEISMIC EXPERIENCE DATABASE COMPARISONS 2;1 Seismic Ground Motions 9 2.2 Piping, Equipment, and Other Plant Features 11

3. SEISMIC VERIFICATION-WALKDOWNS 24 3.1 Seismic Verification Review Guidelines 24 3.1.1 Piping, Pipe Support and'Equipment Design Attributes ..... 25 3.1.2 Seismic Anchor Movement Issues 26 3.1.3 Seismic Interaction Issues (II/I and Proximity) .................... 26 3;1.4 Valve Design Attributes 26 3.2 Seismic Verification Boundary . 26 3.3 Walkdown Results 28 3.3.1 Unit 3 Seismic Walkdown 28 3.3.2 Unit 2 Seismic Walkdown 29 3.3.3 Additional Seismic Walkdown 30

4. SEISMIC ASSESSMENTS 41 4.1 Outlier Resolution 41 4.1.1 Seismic Demand 41 4.1.2 Seismic Capacity. 42 4.1.3 Summary of Results 42 4.2 Alternate Leakage Treatment Piping and Supports ~..... 43 4.3 Turbine Building . 44 4.4 Condenser 46

5. REFERENCES 75 P 5200918.R.001'tsvbrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page.5 of 75 TABLES

~acae 3-1 Browns Ferry MSIV'Leakage Boundary Flow Diagrams 32 3-2 BFN MSIV Leakage Boundary Points 33 3-3 Browns Ferry Unit 3 MSIV Walkdown Outliers. 36

.3-4 Browns Ferry Unit 2 MSIV Walkdown Outliers 38 4-1 Browns Ferry Unit 2 MSIV Outliers Resolution Summary ... 48 4-2 Browns Ferry Unit 3 MSIV Outliers Resolution Summary 50 4-3 Design Basis for Browns Ferry ALT Related Piping and Supports 53 4-4 Seismic Experience Database Piping Data 56 4-5 Comparison of Browns Ferry and Selected Database Piping Parameter 62

'-6 Bounding, Evaluation of Typical Support Configurations 63 4-7 Browns Ferry Turbine Building Design Basis 64 4-8 Comparison of Browns'Ferry and,Selected Database Condensers.... 65 F(GU RES 2-1 Comparison of Browns Ferry DBE Ground Spectrum and Selected Database Site Spectra . 13 2-2 Comparison of Browns Ferry DBE and Valley Steam'Plant Ground Spectra 14 2-3 Comparison. of Browns Ferry DBE and Burbank Power Plant Ground Spectra 15 2-4 Comparison of Browns Ferry DBE and El Centro Steam Plant Ground Spectra . 16 2-5 Comparison of.Browns Ferry DBE and Moss Landing Power Plant Ground Spectra . 17

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0 200918-R-002 Revision 0 August 31, 1999 Page 6 of 75 FIGURES (CONT.)

Pacae 2-6 Comparison of Browns Ferry DBE and Humboldt Bay Nuclear Power Plant Ground Spectra 2-7 Comparison of Browns Ferry DBE and Coolwater Power Plant Ground Spectra . 19 2-8 Comparison of Browns Ferry DBE and Commerce Refuge to Energy Plant Ground Spectra ~ I~ ~ 20 2-9 Comparison of Browns Ferry DBE and Grayson Power Plant Ground Spectra 21 2-10 Comparison of Browns Ferry DBE and Las Ventanas Power Plant Ground Spectra 22

. 2-11 Comparison of Browns Ferry DBE and PALCO Cogeneration Plant Ground Spectra . 23 3-1:Browns Ferry MSIV Seismic Verification Boundary. 40 4-1 Comparison of Browns Ferry and Selected Database Piping D/t Ratios 67 4-2 Size Comparison of Browns Ferry Condenser with Selected Database Condensers 68 4-3 Weight Comparison of Browns Ferry Condenser with Selected Database Condensers 69 4-4 Height Comparison of Browns Ferry Condenser with Selected Database Condensers 70 4-5 Plan Dimension Comparison of Browns Ferry Condenser with Selected-Database Condensers 71 4-6 Schematic. Plan View of Browns Ferry Condenser Anchorage .. ~...~..........

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200918-R-002 Revision 0 August 31, 1999 Page 7 of 75 FiGURES (CONT.)

Pacae 4-7 Comparison of Browns Ferry and Selected Database Condenser Anchorage to Seismic Demand for Direction Parallel to the Turbine Generator Axis 73 4-8 Comparison of Browns Ferry and Selected Database Condenser Anchorage to Seismic Demand for Direction Transverse to the Turbine Generator Axis 74 P A200918-R.001'tsubrpt.doc

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200918-'R-002 Revision 0 August 31, 1999 Page 8 of 75

1. INTRODUCTlON This report summarizes the engineering activities performed. for. the supplemental plant specific Main Steam piping seismic verification to support the increased Main Steam Isolation Valve (MSIV) leakage tech spec change. at Browns Ferry Nuclear Plant (BFN).

The verification program was performed in accordance with the recommendations of the General Electric Boiling Water Reactor Owners Group (BWROG) Report for Increasing MSIV Leakage Rate Limits and Elimination of Leakage Control Systems (Reference 1).

The U.S. Nuclear, Regulatory Commission (NRC) has reviewed the BWROG report and issued a safety. evaluation report (SER) on its application for addressing the MSIV leakage issues (Reference 2), subject to certain limitations.

Engineering activities associated with the supplemental plant specific seismic verification program,.as recommended in the BWROG report, consist of the following

~ key elements:

g Seismic Experience Database Comparisons Seismic Verification Walkdowns Seismic Assessments of Selected Components Detailed discussions of each of these activities are presented in the following sections of the report.

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200918-R-002 Revision 0 August 31, 1999 Page 9 of 75

2. SEISMIC EXPERIENCE DATABASE COMPARISONS The seismic experience data are derived from an extensive database on the performance of power plants and industrial facilities in past strong-motion earthquakes.

These performance data are compiled by EQE for the Seismic Qualification Utility Group, the Electric Power Research Institute and others, and included over 100 facilities in more than 60 earthquakes that have occurred around the world from 1934 to present.

Of interest to the MSIV leakage issues are the performance of the non-seismically analyzed main steam system piping, related components and supports, and condensers.

The BWROG Report (Reference 1) summarizes data on the performance of main steam piping and condensers in past strong-motion earthquakes and compares these piping and condensers with those in typical U.S. GE Mark I, II', and III nuclear plants. The

. earthquake experience data and similarity comparisons are then used to draw conclusions on how the GE piping and condensers would perform in a design basis earthquake (DBE).

The following sections present experience database comparisons that are plant-specific to Browns Ferry Nuclear Plant for use to support the increased MSIV leakage tech spec change submittal.

2.1 SEISMIC GROUND MOTIONS Ground motion estimates of 13 database sites were reviewed and accepted by the NRC staff for inclusion in the BWROG's earthquake experience database, and are presented in the referenced NRC Safety Evaluation Report (SER, Reference 2). To establish applicability of the BWROG's earthquake experience-based methodology for demonstrating the seismic ruggedness of non-seismically analyzed main steam piping and associated components at Browns Ferry, comparisons of the ground response spectra of selected database facilities with BFN design basis ground spectrum were made.

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200918-R-002 Revision 0 August 31, 1999 0 Page 10 of,75 The majority, of the MSIV alternate leakage treatment (ALT):path and associated piping systems and the condensers at Browns Ferry are located in the lower elevations of the Turbine Building. BFN Turbine Building is classified as a Class II structure,.hence, no dynamic analysis of the building was performed. The. building below the operating floor is a reinforced concrete framed structure supported on steel H-piles to bedrock. The horizontal ground. spectrum is. conservatively taken as the BFN 5% damped design basis DBE input spectrum (0.2g Housner spectrum defined at rock outcrop) and scaled by 1.6'to account for soil amplification.

A composite comparison of the ground. response spectra of selected earthquake experience database facilities with:the Browns Ferry design basis DBE ground spectrum is shown'in Figure 2-1. The selected ground motions include the following 10 sites from among the 13 database facilities reviewed and accepted by the NRC:

Valley Steam Plant - USGS estimate 1971 San Fernando Earthquake (M6.6)

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El Centro Steam Plant - N/S direction 1979 Imperial Valley Earthquake (M6.6)

Moss Landing Power Plant - PG&E estimate 1989 Lorna Pri'eta Earthquake (M7. 1)

Humboldt Bay Nuclear Power Plant - Average 1975 Ferndale Earthquake (M5.5)

Coolwater Power Plant - Transverse direction 1992 Landers. Earthquake (M7.3)

Commerce Refuge to Energy Plant (LA Bulk Mail) - E/W direction 1987Whittier Narrows Earthquake (M5.9)

Grayson Power Plant (Glendale) N110E direction 1971 San Fernando Earthquake (M6.6)

Las Ventanas Power Plant Transverse direction 1985 Chile Earthquake (M7.8)

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200918-R-002 Revision 0 August 31, 1999 Page 11 of 75

~ PALCO Cogeneration Plant (Rio Dell) -Average 1992 Petroii'a Earthquake (M8.9)

The individual comparison plots of the 5% damped ground spectra of the above 10 database facilities with the Browns Ferry DBE ground spectrum are shown in Figures 2-2 to 2-11. In general, the earthquake experience database sites have experienced strong ground motions that are in excess of the Browns Ferry DBE at the frequency range of interest (i.e., about 1 Hz. and above for piping and rigid range for equipment).

Many of the database site ground motions envelope the conservatively estimated BFN DBE ground spectrum by large factors in various frequency bands within the 1 Hz. and above range.

Based on the above observations and comparison, it is concluded that the'Browns Ferry DBE ground spectrum is generally bounded by those of the earthquake experience database sites at the frequencies of interest. Hence, the use of earthquake experience-based approach for demonstrating the seismic ruggedness of non-seismically analyzed main steam piping and associated components at Browns Ferry, consistent with the BWROG's recommendations and limitations of the SER, is appropriate.

2.2 PIPING, EQUIPMENT AND OTHER PLANT FEATURES The main steam piping and condensers in the earthquake experience database exhibited substantial seismic ruggedness, even when they are typically not designed to resist earthquakes. This is a common conclusion in studies of this type on other plant items such as welded steel piping in general, anchored equipment such as motor control centers, pumps, valves, structures, and so forth. That is, with limited exceptions, normal industrial construction and equipment typically have substantial inherent seismic ruggedness, even when they are not designed for earthquakes. No failures of the main steam piping were found. Anchored condensers have also performed well in past earthquakes with damage limited to minor internal tube leakage.

The BWROG Report (Reference 1) contains detailed discussions and comparisons of main steam piping and condenser design in several earthquake experience database P:500918-R-001isubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 12 of 75 sites.and example GE Mark I, II, and ill plants in the U.S. The general conclusions of these comparisons are as follows:

GE plant designs are similar to or more rugged than those in the earthquake experience database that exhibited good earthquake performance; The possibility of significant failure in GE BWR main steam piping or condensers in the event of an eastern U.S. design basis earthquake is highly unlikely; and that Any such failure would also be contrary to a.large body of historical earthquake experience data,'nd thus unprecedented. ~

Plant-specific comparisons of the main steam piping,.related components and,supports, and condensers at Browns Ferry with those in the selected earthquake experience database facilities are provided in Section 4 of this report.

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200918-R-002 Revision 0 August 31, 1999 Page 15 of 75 Burbank Power Plant, CA (1971 San Fernando Earthquake) 2.4 BFN (1.6XDBE)

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0 200918-R-002 Revision 0 August 31, 1999 Page 16 of 75 El Centro Steam Plant, CA (1979 Imperial Valley Earthquake) 2.4 8fN (1.6XD8E)

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200918-R-002 Revision 0 August 31, 1999 Page 18 of 75 Huinbotdt Bay Nuclear Power Plant, CA ($ 975 Ferndale Earthquake) 2.4 BFN (1.6XDBE)

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200918-R-002 Revision 0 August 31, 1999 Page 20 of 75 Commerce Refuge to Energy Plant, CA (1987 V/hittier Narrows Earthquake) 2.4 BFN (1.6XDBE)

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200918-R-002 Revision 0 August 31, 1999 Page 21 of 75 Grayson Power Plant, Glendale, CA (1971 San Fernanado Earthquake) 2.4 BFN (1.6XDBE)

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200918-R-002 Revision 0 August 31, 1999 Page 22 of 75 Las Ventanas Power Plant, Chile (1985 Chile Earthquake) 2.4 BFN (1.6XDBEJ

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Revision 0 August 31, 1999 Page 23 of 75 PALCO Cogeneration Plant, CA (1992 Petrolia Earthquake) 2.4 BFN (1.6XDBE)

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200918-R-002 Revision 0 August 31, 1999 Page 24 of 75

3. SEISMIC VERIFICATION WALKDOWNS Very few components of nuclear plant systems are unique to the nuclear facilities.

Nuclear plant systems include equipment, piping, tubing, conduit, and many other items that are common components of conventional power plants and industrial facilities.

Seismic experience data based methods have been developed to address seismic issues associated with the adequate performance of these equipment and commodities not designed, procured and installed to current nuclear seismic criteria. By reviewing the performance of the database facilities that contain equipment similar to that found in nuclear plants, conclusions can be drawn about the performance of nuclear plant equipment during and after earthquake events.

Extensive work has been performed documenting the performance of power plant equipment performance and the common sources of seismic damage to equipment and piping. In general, equipment, piping and tubing systems in the seismic experience database have performed very well in earthquakes, even though they were typically esigned for deadweight and operating loads only, with little or no consideration for seismic loads. Performance of piping and equipment in past earthquakes are summarized in Appendix D of the BWROG Report (Reference 1). Earthquake experience-based methods provide the basis for the seismic review of the main steam piping and equipment within the MSIV alternate leakage treatment (ALT) boundary at BFN.

3.1 SEISMIC VERIFICATION REVIEW GUIDELINES Various design attributes of the as-installed scope of equipment, piping, and tubing were reviewed and evaluated by the Seismic Walkdown Teams to ensure that the BFN installations are representative of database design practice and that components are

,free of known seismic vulnerabilities. Earthquake experience has identified conditions that have resulted in failure of piping and tubing systems and components. The conditions evaluated in the walkdown reviews included:

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200918-R-002 Revision 0 August 31, 1999 Page 25 of 75 Piping, Pipe Support and Equipment Design Attributes Seismic Anchor Movement.Issues Seismic Interaction Issues (II/I & Proximity)

Valve Design Attributes The above design attributes.and conditions are briefly discussed below.

3.1.1 Pi in Pi e Su ort and E ui ment Desi n Attributes The Seismic Walkdown reviewed the piping and tubing systems, and associated supports.to ensure that the design attributes and conditions are consistent with good design and industry standard practices. The systems were also screened to ensure that they'are free from known seismic vulnerabilities identified from earthquake experience data. These design attributes include:

Piping with dead weight support spacing greatly in excess of the B31.1 suggested spans, or tubing with excessive sagging.

Heavy, unsupported in-line components.

~ Piping constructed of non-ductile materials such as cast iron or PVC.

~ .Non-standard fittings or unusual attachments that could cause excessive localized stresses.

~ Pipe-supports that exhibit non-ductile behavior.

~ Presence of severe corrosion.

In addition, anchorage of terminal. equipment to piping and tubing systems were reviewed for adequacy.

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200918-R-002 Revision 0 August 31, 1999 Page 26 of 75 3.1.2 Seismic 'Anchor Movement Issues The experience database includes instances of seismic damage to piping, tubing and supports that were attributed to seismic anchor movement. Damage was the result of excessive movement of terminal end equipment, differential movement between supports:in adjacent buildings, and excessive movements imposed on branch lines by flexible headers. These attributes were evaluated during the piping,walkdowns.

3.1.3 Seismic Interaction Issues II/I and Proximit The seismic interaction review was a visual inspection of structures, piping, or equipment adjacent to the components under evaluation. The seismic interaction review evaluated conditions where seismically induced failures (II/I) and displacements of adjacent structures, piping; or equipment (proximity) could adversely affect the required seismic performance of the system and components under consideration.

3.1.4 Valve Desi n Attributes Screening guidelines are provided for valves that are relied upon to establish the ALT pathway or are part of the Seismic Verification Boundary. The guidelines are consistent with the SQUG Generic Implementation Procedure (GIP, Reference 5) and include provisions for air-operated diaphragm valves, spring-operated pressure relief valves, piston-operated valves of light-weight-construction, motor-operated valves, and substantial piston-operated'valves.

3.2 SEISMIC VERIFICATION;BOUNDARY The walkdown scope included the Main. Steam drain path that will be established to convey leakage past the outboard Main Steam Isolation Valves (MSIV) to the isolated condenser and includes piping, instrumentation, valves,and equipment that would be required.to.maintain the drain pathway.

The Seismic Verification Boundary for the MSIV Alternate Leakage Treatment path was developed in consultation with TVA Browns Ferry Systems Engineering, and is shown in P."ttempQ00918'eubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 27 of 75 Figure 3-1. The associated flow diagrams are listed on Table 3-1, and the piping isolation boundaries defining the seismic verification boundary are shown on Table 3-2.

The Seismic Verification Boundary generally consists of the following portions of the Main Steam (MS) system beyond the outboard MSIV's:

1. Main Steam drain path to the condenser for any leakage past the isolated outboard MSIVs.

2. Main Steam piping from the outboard MSIV to the Main. Steam Stop Valves (MSV).

3. Main Steam Bypass piping from the Main Steam lines to the Bypass Valve chest.

Main Condensers.

Additional piping and instrumentation within the Seismic Verification Boundary includes:

Stop Valve Above Seat Drains to Condenser Steam Sample System HPCI/RCIC Steam Drains to Main Steam Auxiliary Boiler Drains to Main Steam Main Steam Instrumentation Main Steam Supply to the Reactor Feed Pumps Main Steam Supply to the Steam Jet Air Ejectors Main Steam Supply to the Off-Gas Preheaters The above Seismic Verification Boundary was originally developed for Unit 3 seismic walkdown. The Unit 2 Seismic Verification Boundary was less than that shown above for Unit 3. The original Unit 2 boundary assumed the. addition of an isolation valve to isolate the steam path to the RFP Turbines and that the steam feed shutoff. valve 8-575 would be qualified as an isolation boundary to the Steam Seal system. The Unit 2 Seismic Verification Boundary will be expanded'and additional walkdown will be performed during the Unit 2 Cycle 11 outage to remove the assumptions of the isolation valves noted above, hence, eliminating the unit differences with Unit 3 Seismic Verification Boundary.

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0 200918-R-002 Revision 0 August 31, 1999 Page 28 of 75 3.3 WALKDOWN RESULTS Field walkdowns of the main steam lines, ALT drain path and associated appendages within the Seismic Verification Boundary were conducted during the Unit 3 recovery outage in April 1995, and during the. Unit 2 refueling outage in April 1996 by EQE engineers. Plant specific guidance, systems expertise and support were provided by BFN Site Engineering staff. All members of the MSIV Seismic Verification Walkdown Teams are degreed engineers, have ten to twenty years of experience in structural engineering and/or earthquake engineering application to nuclear power plants, and are familiar with the earthquake experience methodology. EQE engineers have performed the complete MSIV Seismic Verification Walkdowns in accordance with the recommendations of the GE NEDC-31858P (BWROG Report, Reference 1) at several other plants.

Results of the Seismic Verification.Walkdowns, including the identified walkdown open items or "Outliers", are discussed in detail in References 3 and 4 for Browns Ferry, Unit 3 and Unit 2, respectively. A brief summary of the walkdown results is presented below, with walkdown outliers summarized in Table 3-3 and 3-4 for Browns Ferry, Unit 3 and Unit 2, respectively.

3.3.1 Unit 3 Seismic Walkdown The main steam drain piping included in the Unit 3 MSIV alternate leakage treatment (ALT) path to the condenser generally conform to ANSI B31.1 design guidelines. Piping are typically insulated, and constructed from carbon steel, SA-106 Grade B, with butt-welded or socket-welded joints. In addition, pipe supports consist of a combination of rigid struts and U-bolt brackets, floor-mounted stanchions, and spring or rod hangers.

The as-installed configurations are inherently rugged and are similar to those found in the earthquake experience database facilities that have performed well during past earthquakes.

The piping systems within the Unit 3 MSIV Seismic Verification Boundary were divided into the following 13 portions for walkdown purposes:

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200918-R-002 Revision 0 August 31, 1999 Page 29 of 75 Main Steam drain line in the Turbine Building

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Main Steam lines in the Turbine Building

3. Main Steam and Main Steam drain lines in the Reactor Building MSIV vault

4. HPCI/RCIC/Auxiliary Boiler drains in the Reactor Building and above the Torus

5. Main Steam PT instrumentation lines

6. Main Steam sampling lines to the Sample Station

7. Main Steam bypass lines

8. Main Steam stop valve above seat drains

9. Steam supply to Steam Seal Regulators

10. Steam supply to RFP Turbines

11. Steam supply to Steam Jet Air Ejectors

12. Steam supply to Off-Gas Preheaters

13. Condensers Conditions not-meeting the Seismic Verification Review guidelines, as discussed in Section 3.1 of this report, were identified and documented as "Outliers" for further evaluation and resolution by the Seismic Walkdown Teams. These conditions included limited numbers of piping overspans, equipment anchorage or support integrity issues, proximity or falling interaction concerns, flexibilityconcerns due to seismic anchor movements or differential displacements, boundary valve integrity issues, and general maintenance or housekeeping items. Table 3-3 presents a summary of Unit 3 MSIV walkdown outliers.

3.3.2 Unit 2 Seismic Walkdown Similar to Unit 3, the main steam drain piping included in the Unit 2 MSIV alternate leakage treatment (ALT) path to the condenser generally conform to ANSI B31.1 design guidelines. Piping are typically insulated, and constructed from carbon steel, SA-106 Grade B, with butt-welded or socket-welded joints. Pipe supports consist of a combination of rigid struts and U-bolt brackets, floor-mounted stanchions, and spring or rod hangers. The as-installed configurations are inherently rugged and are similar to those found in the earthquake experience database facilities that have performed well during past earthquakes.

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200918-R-002 Revision 0 August 31, 1999 Page 30 of 75 The piping systems within the scope of the original Unit 2 MSIV Seismic Verification Walkdown Boundary were divided into the following 11 portions for walkdown purposes:

1. Main Steam drain line in'the Turbine Building

2. Main Steam lines in the Turbine Building

3. Main Steam and Main Steam drain lines in the Reactor Building MSIV vault

4. HPCI/RCIC/Auxiliary Boiler drains in the Reactor Building and above the Torus

5. Main Steam PT instrumentation lines

6. Main Steam sampling lines to the Sample Station

7. Main Steam bypass lines

8. Main Steam stop valve above seat drains

9. Steam supply to Steam Feed valve 8-575 (proposed isolation boundary)

10. Steam supply to RFP Turbines (with proposed manual isolation valve to be located on the Turbine Building operating deck, El. 617')

13. Condensers Conditions not meeting the Seismic Verification Review guidelines, as discussed in Section 3.1 of this report, were identified and documented as "Outliers" for further evaluation and resolution by the Seismic Walkdown Teams. As in the Unit 3 walkdown, these conditions included limited numbers of piping overspans, equipment anchorage or support integrity issues, proximity or falling interaction concerns, flexibilityconcerns due to seismic anchor movements or differential displacements, boundary valve integrity issues, and general maintenance or housekeeping items. Table 3-4 presents a

'ummary of the Unit 2 MSIV walkdown outliers.

As mentioned in Section 3.2 above, the original Unit 2 Seismic Verification Boundary will be expanded and additional walkdown will be performed during the Unit 2 Cycle 11 outage to remove the assumptions of the isolation valves, hence, eliminating the unit differences with Unit 3 Seismic Verification Boundary.

3.3.3 Additional Seismic Walkdown As mentioned in Section 3.2 above, the Unit 2 Seismic Verification Boundary will be expanded to include portions of the steam supply lines from the Main Steam Header to P:t200918.R.001'tsubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 31 of 75 the turbine drives for the Reactor Feed Pumps, the Steam Jet Air Ejectors, the Off-Gas Preheaters, and the Steam Seal'Regulators, i.e., extension of piping portions 9 and 10, and portions 11 and 12, as in the Unit 3 walkdown scope. The resulting Unit 2 Seismic Verification Boundary will then be consistent with that of Unit 3, hence, eliminating any unit differences between them. Additional seismic verification walkdown for the expanded scope will-be performed during the Unit 2 Cycle 11 outage to verify the

,seismic ruggedness of the MS piping and associated components, and all identified outliers will be resolved during the-same outage. Design Change Notice (DCN)-will address. any physical changes to restore the drain path into compliance.

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20091 8-R-002 Revision 0 August 31, 1999 Page 32 of 75 Table 3-1 BROWNS FERRY MSIV LEAKAGE BOUNDARY FLOW DIAGRAMS

'Drawing Number System,'Description Unit 2 2-47E801-1 Main Steam System.

2-47E801-2 Main Steam System 2-47E805-3 Heater Drains 8 Vents and Miscellaneous Piping Systems 2-47E807-1 Turbine Drains and Miscellaneous Piping Systems 2-47E807-2 Turbine Drains and Miscellaneous Piping Systems 2-47E812-1 High Pressure Coolant Injection System 2-47E813-1 Reactor Core Isolation Cooling System 0-47E815-1 Auxiliary Boiler System 2-47E815-4 2-47E610-43-1 Sampling and Water Quality System Unit 3 3-47E801-1 Main Steam System 3-47E801-2 Main Steam System 3-47E805-3 Heater Drains 8 Vents and Miscellaneous Piping Systems 3-47E807-1 Turbine Drains and Miscellaneous Piping Systems 3-47E807-2 Turbine Drains and Miscellaneous Piping Systems 3-47E812-1 High Pressure Coolant Injection System 3-47E813-1 Reactor Core Isolation Cooling System 3-47E815-5 Auxiliary Boiler System 3-47E610-43-6 Sampling and Water Quality System P 5200918.R.001'eubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 0 Table 3-2 BFN MSIV LEAKAGE BOUNDARY POINTS Page 33 of 75 Leakage: F.low:. Diagram/.

. 'Boundary,,Point'*; Drawing;* Comment 47E801-1 MSIV for Main Steam Line A 'CV-1-15 FCV-1-27 47E801-1 MSIV for Main Steam Line B FCV-1-38 47E801-1 MSIV for Main Steam Line C FCV-1-52 47E801-1 MSIV for Main Steam Line D FCV-1-56 47E801-1 Outboard Containment Isolation valve for Primary Containment steam drains 1-521 47E801-1 Normally closed Main Steam Drain manual isolatIon 1-527 valves43-631 2-47E610-43-1 Normally closed Main Steam Sample System manual 3-47E610-43-6 isolation valve 43-631 A 2-47E610-43-1 Normally closed Main Steam Sample System manual 3-47E610-43-6 isolation valve 43-632 2-47E610-43-1 Normally closed Main Steam Sample System manual 3-47E610-43-6 isolation valve 3 FCV-1-74 FCV-1-78 47E801-2 47E801-2 Main Turbine Stop Valve for Steam Line A Main Turbine Stop Valve for Steam Line B

!$ FCV-1-84 47E801-2 Main Turbine Stop Valve for Steam Line C FCV-1-88 47E801-2 Main Turbine Stop Valve for Steam Line D FCV-1-61 FCV-1-62 FCV-1-63 FCV-1-64 FCV-1-65 47E801-2 Main Steam Bypass Valve Chest FCV-1-66 FCV-1-67 FCV-1-68 FCV-1-69 FCV-73-6B 47E812-1 Normally open air operated isolation valve HPCI FCV-71-6B 47E813-1 Normally open air operated isolation valve RCIC 12-635 2-47E815-4 Normally closed manual isolation valve Aux. Boiler 3-47B815-5 P:t200918.R-001'eubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 34 of 75 Table 3-2 (CONT.)

BFN MSIV LEAKAGE BOUNDARY POINTS Leakage';;

'oundary, Point:"

.'lowDrawing Diagram/

Comment 12-637 2-47E815-4 Normally closed manual isolation valve Aux. Boiler 3-47B815-5 12-623 2-47E815-4 Normally closed manual isolation valve Aux. Boiler 3-47B815-5 12-625 2-47E815-4 Normally closed manual isolation valve Aux. Boiler 3-47B815-5 2-12-822 0-47E815-1 Normally closed manual isolation valve Aux. Boiler (Unit 2 onIy)

FCV-6-100 47E807-1 Normally closed motor operated isolation valve - Stop valve above seat drains FCV-6-101 47E807-1 Normally closed motor operated isolation valve - Stop valve above seat drains FCV-6-102 47E807-1 Normally closed motor operated isolation valve - Stop valve above seat drains FCV-6-103 47E807-1 Normally closed motor operated isolation valve - Stop valve above seat drains FCV-1-127 47E801-2 Reactor Feed Pump Turbine A Stop Valve FCV-1-135 47E801-2 Reactor Feed Pump Turbine B Stop Valve FCV-1-143 47E801-2 Reactor Feed Pump Turbine C Stop Valve FCV-6-153 47E807-2 Normally closed motor operated isolation valve - RFP

~ I FCV-6-155 47E807-2 Normally closed motor operated isolation valve - RFP FCV-6-157 47E807-2 Normally closed motor operated isolation valve - RFP FCV-6-122 47E807-2 Normally closed motor operated isolation valve - RFP FCV-6-127 . 47E807-2 Normally closed motor operated isolation valve - RFP FCV-6-132 47E807-2 Normally closed motor operated isolation valve - RFP PCV-1-151 47E801-2 Normally open air operated isolation valve - SJAE PCV-1-166 47E801-2 Normally open air operated isolation valve - SJAE PCV-1-153 47E801-2 Normally open air operated isolation valve - SJAE PCV-1-167 47E801-2 Normally open air operated isolation valve - SJAE 6-826 47E805-3 Check valve SJAE 6-822 47E805-3 Check valve SJAE

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200918-R-002 Revision 0 August 31, 1999 Page 35 of 75 Table 3-2 (CONT.)

BFN MSIV LEAKAGE BOUNDARY POINTS L'eakage -." -

Flow..Diagram/

'oundary Point'* 'rawing

Comment FCV-1-145 47E807-2 Normally closed motor operated isolation valve Steam Seal Regulator FCV-1-154 47E807-2 Normally closed motor operated isolation valve Steam Seal Regulator FCV-1-147 47E807-2 Air operated pressure regulating valve Steam Seal Regulator CKV-1-742 47E801-2 Check valve (NEW) Off-Gas Preheater A CKV-1-744 47E801-2 Check valve (NEW) -Off-Gas Preheater B CondenserA The condenser is the ultimate boundary for the MSIV leakage path.

Condenser B The condenser is the ultimate boundary for the MSIV leakage path.

Condenser C The condenser is the ultimate boundary for the MSIV leakage path.

Miscellaneous test, 47E801-1 vent, drain and 47E801-2 instrument connections NOTE:

Boundary component ID's and flow diagram/drawing nos. are generally applicable to both Units 2 and 3, unless noted otherwise specifically (i.e., 2- for Unit 2; 3- for Unit 3; and O-.for common)

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20091 8-R-002 Revision 0 August 31, 1999 Page 36 of 75 Table 3-3 BROWNS FERRY UNIT 3 MSIV WALKDOWN "OUTLIERS"

'YSTEM DESCRIPTION'ain

, ID1 OUTL'IER2 F P D Steam Drain Line-Turbine Bldg.

MS Drain Taps 1-1 MS Line differential motion MS Drain Taps 1-2 Impact with conduit supports FCV 1-58 1-3 Extended valve operators FCV 1-58/59 Conduit 1-4 Unknown routing at TB/RB joint Main Steam Lines Turbine Bldg.

MS Stop Valves 2-1 Valve performance X MSH-17 2-2 Missing eyebolt nut X MSH-17,18 & 19 2-3 Grating clearance Main Steam Drain Line- MSIV Vault FCV 1-15, 27, 38 & 52 3-1 Valve performance X FCV 1-56 3-2 Manual operator X HPCIIRCIC Drain 4 HPCI Drain at MS drain 4-1 Inadequate bending leg connection MS PT / 72'6'2'6 8 93 5 MS instrument tubing 5-1 Overspan on 1" pipe to PT 1-86 1/2 Line to PT 1-86 5-2 Interaction with steel & pipe Main Steam Sample to Station 6 Sample lines B &.D 6-1 Missing tubing support clamps X, Sample lines A, B, C, D 6-2 Inadequate flex legs at MS line X PT 16A/B 6-3 Inadequate flex legs at MS line X Sample Station 6-4 Temperature bath anchorage Main Steam Bypass 7 Main. Steam Bypass Valve 7-1 Valve performance SV Above Seat Drains 8

- FCV 6-100, 101, 102, 103 8-1 Short rod hangers Steam.to Steam Seal Regulator 9 MS to FCV 1-146 9-1 Overspan piping PCV 1-147 9-2 Handwheel proximity to WF X PCV 1-147 airline 9-3 Inadequate flexibility& blockwall X PCV 1-147 9-4 Extended valve o erator P:ttemp40091Steubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 37 of 75 Table 3-3 (CONT.)

BROWNS FERRY UNIT 3 MSIV WALKDOWN"OUTLIERS" SYSTEM DESCRIPTION; ID1 OUTLIER2 "A F D ', V Steam Supply to RFP Turbines 10 Steam supply line 10-1 Inadequate flex Ieg at MS header Steam supply. line 10-2 Stanchion supports Steam supply line 10-3 TB crane overhead RFP Stop Valve above seat 10-4 Large mass on the 1/2 8 3/4 drains inch lines Tubing to Pl 1-126 10-5 Missing tubing ciamps- X' overspan Steam Supply to SJAE 11 SJAE 3NB 11-1 Anchorage SJAE 3B 11-2 Loose anchor bolt nut X Drain to Condenser 11-3 Drain ties to multi system collector Steam to Off-Gas Preheaters 12 PCV 1-175NB 12-1 Masonry wall Steam supply line to FCV 12-2 Vert. restraint of line at 1-178A/B FCV 1.-178 PCV 1-175NB, FCV 1-178NB 12-3 Valve performance Condenser 13 Condenser and anchorage 13-1 Evaluate condenser/anchorage X ade uac KEY TO ISSUES:

A Anchorage or Support Capacity F Failure and Falling (II/I)

P Proximity and Impact D Differential Displacement V Valve Screening NOTES:

- ID - Refers to MSIV Walkdown 1 package identifier.

2 "Outliers" are plant conditions which require further evaluation.

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200918-R-002 Revision 0 August 31, 1999 Page 38 of 75 Table 3-4 BROWNS FERRY UNIT 2 MSIV WALKDOWN"OUTLIERS" SYSTEM'DESCRIPTION: ID1 OUTLIER2 .A F P D Main Steam Drain Line-Turbine

, Bldg.

MS Drain Taps 1-1: MS Line differential motion FCV-1-58 1-2: Extended valve operators Main Steam Lines Turbine Bldg.

MS Stop Valves 2-1: Valve performance RB MSIV Vault - MS and MS Drain FCV-1-15, -27, -38 & -52 3-1: Valve performance HPCIIRCICIAux. Boiler Drains 4A HPCI Drain at MS drain connection 4-1: Inadequate bending leg X HPCI Drain in RB Steam Vault 4-2: Piping overspan X HPCI Drain in RB SE Corner Rm 4-3: Piping overspan. X HPCIIRCICIAux. Boiler'Drains 4B

, HPCI 8 Aux. Boiler drain lines 4-4: Miscellaneous maintenance suppotis items X

7 HPCI Drain above the Torus RCIC Drain above the Torus 4-5: Piping overspan 4-6: Inadequate support X MS PT-'1-72,,-76, -82 & -86 1/2" PT Piping from Steam Lines 5-1: Interaction with platform steel Main Steam Sampling PT-16NB Piping 6-1: Interaction with Feedwater piping Sample lines A, B, C, D 6-2: Inadequate flex legs at MS line PT-16NB 6-3: Inadequate flex legs at MS line Sample Station 6-4: Temperature bath anchorage PT-16NB 6-5: Interaction with oil drum Main Steam Bypass Main Steam Bypass Valve 7-1: Valve performance SV Above Seat Drains FCV-6-100, -101, -102 8 -103 8-1: Short rod hangers 1" Drain Piping from Steam Line D 8-2: Interaction with MS i in /steel

)

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200918-R-002 Revision 0 August 31, 1999 Page 39 of 75 Table 3-4 (CONT.)

BROWNS FERRY UNIT 2 MSIV WALKDOWN"OUTLIERS" SYSTEM DESCRIPTION ID1 OUTLIER2 A,F D V Steam to Steam Feed Va/ve Rod Hanger Downstream of Valve 9-1: Disengaged rod hanger 8-575 Verification Boundary Valve 8-575 9-2: Normally open manual (Proposed in the Original Scope) valve Steam Supp/y to RFP 7urbines 10 Steam supply line 10-1: Inadequate flex leg at MS header Steam supply line 10-2: Stanchion supports X Steam supply line 10-3: TB overhead crane X Verification Boundary Valve 1-RFPT 10-4: Installation of valve (Proposed in the Original Scope)

Condensers 13 Condenser anchora e 13-1: Evaluate anchora e KEY TO ISSUES' Anchorage or Support Capacity F,Failure and Falling (II/I)

P Proximity and Impact D Differential Displacement V Valve Screening NOTES:

1 - ID - Refers to MSIV Walkdown package identifier.

2 - "Outliers" are plant conditions which require further evaluation.

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200918-R-002 Revision 0 August 31, 1999 Page 40 of 75 Reactor Turbine Building Building P

-7 FCV 1-74 FCV I 75 FCV 1 ~ 15 MS-Une A P

.7 FCV 1-78 FCV 140 FGV 1.27 MS.Line B FCV 14)4 FCV 14)5 FCV 148 MS-Une C P

FCV 1-52 MS.Line 0 -9 FCV NI8 FCV 14)9 FCV 141 FCV 1-127 FCV 1.168 FCV 1 170 to 149 FCV 6.122 FGV 6.1 Steam FCV t-t35 Seal

~r FCV 1-154 Leak Otfs RFP. FCV6.127 ttl Turbines FGV 6.1 PCV M47 FCV FCV 1-143 6.100.103 FCV 6 122 FCV 1-171 FCV 6 15 ol 4)

FGV I ~ 169 826 V 1-1 FCV 1-146 FCV 1-145 PCV I ~ 151 Steam Seat Condenser PCV 1-167 PCV 1.1 CKV 1-744 SHV 1.743 CKV 1-742 SHV 1.741 FCV 1-57 Ott Gas Ceodrrrate Ofarrl Tarrr Preheaters

~h SIAE Srrel Orarrr PNrrt Oritr RFp Turrrrte Orral erc.

FCV-1-56 FCV 1.58 FCV 1-59 FCV 734B (HPCI)12-822 AUX. BOILER FCV 71418 623r625 (Unn 2 only) (RCIC)

Figure 3-1 Browns Ferry MSIV Seismic Verification Boundary P:)200918.R-001'IsubrpLdoc

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200918-R-002 Revision 0 August 31,. 1999 Page 41 of 75

4. SEISMIC ASSESSMENTS As part of the supplemental plant specific seismic verification program to support the increased MSIV leakage tech-spec change at BFN, various engineering evaluations and assessments were performed to verify the seismic adequacy of the Alternate Leakage Treatment (ALT) piping, related components and supports, and condensers. The following sections discuss the technical bases and methods used in these evaluations and assessments. Results of the seismic evaluations are also presented.

4.1 OUTLIER RESOLUTION Conditions which did not meet the walkdown screening guidelines (Section 3.1) or which were judged by the Seismic Walkdown Team to require further review were documented as "Outliers" during the Units 2 and 3 Seismic Verification Walkdowns at Browns Ferry Nuclear Plant. For BFN Unit 3, the walkdown outliers have been resolved on a deterministic basis and dispositioned as described in more detail below. The proposed resolution for Unit 2 outliers will follow similar Unit 3 approaches and/or utilize existing Unit 3 analyses, as applicable. The Unit 3 outlier resolution are documented in BFN calculations (References 6 and'7).

4.1.1 Seismic Demand The BFN Turbine Building is classified as a Class II structure, hence, no dynamic analysis of the building was performed and no in-structure response spectra were available for the structure. For seismic evaluations and outlier resolution, the horizontal seismic. demand for components located within about 40 feet of the Turbine Building effective grade elevation (EL. 568') is conservatively taken as the'BFN 5% damped design basis DBE input spectrum (0.2g Housner curve) scaled by 1.6 to account for soil amplification per BFN General Design Criteria (Reference 8) for soil founded structures, and 1.5 for building amplification per GIP. For components located above 40 feet of the Turbine Building effective grade elevation, an additional amplification factor of 1.5 is conservatively applied. In the vertical direction, seismic demand is taken as 2/3 that of the horizontal. direction, with a soil amplification factor of 1.1 instead of 1.6.

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200918-R-002 Revision 0 August 31, 1999 Page 42 of 75 4.1.2 'Seismic Ca acit For outlier resolution and evaluation of ALT piping, and related components and supports, the following load combinations and stress allowables, as applicable, were used:

Component Load Combination Stress Allowables Piping D+ P+ I+A 2.0 Sy (Primary + Secondary)

Pipe Supports D+ T+ I+ A AISC Equipment D+ I AISC, GIP Anchorage Valve 3g load check GIP'here, D- Dead load P Pressure load T Thermal load I Seismic (DBE) inertial load A Load due to seismic anchor movement Sy Material yield strength at temperature

.AISC American Institute of Steel Construction GIP Generic Implementation Procedure 4.1.3 Summa of Results Table 4-1 provides a summary of the proposed resolution methods for the outliers associated with the Unit 2 MSIV Seismic Verification Walkdown. Similarly, the results of the resolution of outliers associated with the. Unit 3 MSIV Seismic Verification Walkdown are summarized in Table 4-2.

P 3200918.R.001'eubrpt.doc

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200918-'R-002 Revision 0 August 31, 1999 Page 43 of 75 As mentioned in Section 3.3.3 above, additional Unit 2 Seismic Verification Walkdown for the expanded, scope will be performed during its Cycle 11 outage to verify the seismic ruggedness of the MS piping and associated components. Any additional outliers identified during this walkdown will be addressed and resolved within the same outage period. Design Change Notice (DCN) will address any physical changes to restore the drain path into compliance.

4.2 ALTERNATE LEAKAGE'TREATMENTPIPING AND SUPPORTS Majority of the MSIV alternate leakage treatment (ALT) piping systems and related components at Browns Ferry, i.e., those portions downstream of the outboard Main Steam Isolation Valves (MSIV's) and the outboard Main Steam Drain Isolation Valve (MSDIV), are located in the Turbine Building and are not.designated as Seismic Class I systems. In general, these piping systems are not seismically analyzed, and are typically designed to the requirements of USAS B31.1-1967.

As part of the plant specific seismic verification of the non-seismic ALT piping, related supports and components using the earthquake experience-based approach as outlined in the BWROG Report, the following reviews were performed to demonstrate that the piping and related supports fall within the bounds of the experience database:

Review of the design codes and standards, piping design parameters, and support configurations.

Seismic verification walkdown to identify potential piping concerns.

The Browns Ferry ALT piping systems consist of welded steel pipe and standard support components. Support spacing generally meets the B31.1 recommended span.

The design bases for the portions of piping associated with the ALT pathway to the condensers are tabulated in Table 4-3. Table 4-4 presents a general summary of the piping data that constitute the seismic experience data. Comparison of'Browns Ferry and selected database piping parameters is presented in Table 4-5, along with Figure 4-1, which presents a comparison of D/t ratios of the BFN ALT drain piping with those PM00918 R.001'tsubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Paae 44 of 75 found in the database. Overall, the BFN piping design is similar to and well represented by those found in the experience database sites that have shown to perform well in past earthquakes.

Browns Ferry FSAR does not reference Appendix A to 10 CFR Part 100. The seismic adequacy of the ALT piping is addressed by performing seismic verification walkdowns to identify specific design attributes associated with poor seismic performance, following the guidelines outlined in Section 3.1 of this report. Bounding evaluations were performed for typical support configurations using evaluation criteria as discussed in Section 4.1. Table 4-6 summarizes the results of the support and anchorage

,evaluations for the selected bounding configurations (Reference 10).

The seismic evaluations, consisting of verification walkdowns, bounding support evaluations, and.resolution of the identified walkdown outliers, provide reasonable assurance that the ALT drain path piping, related supports and components will remain functional in the event of a Design Basis Earthquake (DBE) at Browns Ferry.

4.3 TURBINE BUILDING Performance of the turbine building and other non-seismic structures during a seismic event is of interest to the MSIV leakage issue only to the extent that the building structure and its internal components should survive and not degrade the capabilities of the selected main steam.and condenser pathways. A BWROG (Reference 1).survey of this type of industrial structures has, in general, confirmed that excellent past seismic performance exists. There are no known cases of structural collapse of either turbine buildings at power stations or structures of similar construction.

The majority of the MSIV alternate leakage treatment (ALT) piping and the condensers at Browns Ferry are located in the Turbine Building, while small portions of the ALT piping are located in the Reactor Building which is a seismically designed, Class I structure. BFN Turbine Building is classified as a Class II structure in the BFN FSAR. The BFN Design Criteria for Class II structures are that they shall not degrade the integrity of any Class I structure. Those portions of Class II structures required to remain structurally competent in order to support the operation of Class I P %200918.R-0018 ubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 45 of 75 structures or equipment shall be designed for earthquake in accordance to the Uniform Building Code. Table 4-7 provides the design basis of the BFN Turbine Building and the applicable design codes. used.

BFN Turbine Building below the operating floor at El. 617 feet is a reinforced concrete framed structure supported on steel H-piles to the bedrock at El. 519,feet. Piles are spaced far enough apart within each cluster to ensure that the maximum average unit bearing stress on the rock area is limited to 500 psi. Stresses in the piles are limited to one third of the yield stress. The concrete beams and slabs are designed to ACI 318-63 code using the working stress method. Similarly, the columns are also designed to ACI 318-63 code using the working stress method and checked by the ultimate strength design method using a load factor-of 1.8.

The superstructure. above the operating deck consists of transverse welded steel rigid frames spanning approximately 107 feet. An expansion joint is provided between a two-bay frame for Units 1 and 2, and a.single-bay frame for Unit 3. For longitudinal expansion, the superstructure is provided with joints by using double rows of frames spaced at 4 feet apart. The steel frames, which form the Turbine Building structure above the concrete structure, are braced to provide rigidity in the direction of the Reactor Building as well as to provide support for the turbine cranes. These frames are designed to resist lateral forces from the overhead cranes.and wind loads, in addition to supporting the vertical dead and live loads. The design of the steel superstructure is U

based on 1963 AISC code. All material conforms to ASTM-36, except for anchor rods which are ASTM A-307 steel. Shop connections are ASTM A-502 Gr. 1 rivets or welded, and field connections are ASTM A-325 high-strength bolts.

Based on the above design bases for the BFN Turbine Building, and the excellent seismic performance of this-similar type of industrial structure in past strong-.motion earthquakes as documented, in the BWROG Report, the Browns Ferry Turbine Building is expected to remain structurally intact following a DBE.

PAtemp2009188ubrp!.doc

i 200918-R-002 Revision 0 August 31, 1999 Page 46 of 75 4.4 CONDENSER The BFN condensers consist of three singie-pass, single pressure, radial flow type surface condensers. Each condenser is located beneath each of the three low pressure turbines, and is structurally independent. Table 4-8 lists the design data for BFN condensers and for the Moss Landing experience database site listed in the BWROG Report. In addition, design characteristic comparisons of the BFN condensers with the selected database condenser is shown in Figures 4-2 to 4-5. The BFN condenser design data is comparable to the data for the database site. The BFN condensers were also evaluated for structural integrity subject to seismic DBE loads. Results of the evaluation indicate that the condenser shell stresses are small. Maximum stress ratios, based on AISC allowables, are 0.12 for combined axial and bending and 0.10 for shear

,(Reference 10).

The condenser support anchorage consists of a center key and six support feet that are arranged as shown in Figure 4-6. The center support is a fixed anchor, and consists of a built-up wide flange H section embedded 4 feet into the concrete pedestal which is connected to the Turbine Building base mat, and welded to the bottom plate of the condenser. The support plates consist of 2 to 3 anchors of 2- to 2-1/2- inch diameter bolts. Each anchor bolt has greater than 5 feet nominal length with approximately 48 inches of embedment into the concrete pedestal which is connected to the Turbine Building base mat. These supports are designed to resist vertical operating loads, and are slotted radially from the center.,key to allow for thermal growth. Shear forces are transferred to the wide flange shaped anchor in the center and to the anchor bolts and shear keys to the support feet and.carried through the concrete pedestal to.the Turbine Building base mat.

The BFN condenser anchorage was compared with the performance of condensers in the earthquake experience database. The shear areas of. the condenser anchorage, in the directions parallel and'transverse to the turbine generator axis, divided by the seismic demand, were used to compare with those presented in the BWROG Report (Reference 1), and are shown in Figures 4-7 and.4-8, respectively. The BFN condenser anchorage shear area to seismic demand is substantially greater than the selected database sites. The condenser. support anchorage was also evaluated and the results PM00918-R-001'tsubrpt.doc

0 200918-R-002 Revision 0 August 31, 1999 Page 47 of 75 evaluated and the results indicate'that-the combined seismic DBE and operational demand'is less than the. anchorage capacity based on the AISC allowables. Maximum stress ratios are 0.70 for bolt tension in the perimeter support feet, and 0.86 for shear in the center support'built-up section (Reference 7).

The above comparisons of the condenser seismic experience data and the anchorage capacity evaluations demonstrate that the conclusions presented in the BWROG Report (Reference 1) can be. applied to the BFN condensers. That is, a significant failure of the condenser in the event of a DBE at BFN is highly unlikely and contrary to the large body of historical earthquake experience data.

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200918-R-002 Revision 0 August 31, 1999 Page 48 of 75 Table 4-1 BROWNS FERRY UNIT 2 MSIV "OUTL'IERS" RESOLUTION

SUMMARY

SYSTEM OUTLIER OUTLIER RESOLUTION DESCRIPTION DESCRIPTION METHOD Main Steam Drain Line-Turbine Bid .

MS Drain Taps MS line differential Modify supports per motion DCN FCV 1-58 1-2 Extended valve To be resolved per BFN o erators Gale. CD-N0001-980038 Main Steam Lines MS Stop Valves 2-1 Valve performance To be resolved per BFN Gale. CD-N0001-980038 Main Steam Drain Line- MSIV Vault FCV 1-15, 27, 38 L 52 3-1 Valve performance To be resolved per BFN Gale. CD-N0001-980039 HPCIIRCICIAux. Boiler Drains MSIV Pit HPCI Drain at MS drain 4-1 Inadequate bending Modify supports per connection le DCN HPCI Drain'in RB Steam Vault 4-2 Piping overspan Install new supports per 4

'DCN HPCI Drain in RB SE Corner 4-3 Piping overspan Install new supports per Room DCN HPCI/Aux. Boiler drain line 4-4 Misc. maintenance Misc. maintenance items supporls items to be addressed by WR C340989 HPCI Drain above the Torus 4-5 Piping overspan Install new supports per DCN RCIC Drain above the Torus 4-6 Inadequate support Modify support per DCN RCIC-09 MS PT 1-72 76 82 86893 1/2 in. PT Piping from 5-1 Interaction with Re-route Steam Lines platform steel piping/instrumentation line er DCN Main Steam.Sam le to Station PT-16A/B Piping 6-1 Interaction with Re-route piping and Feedwater i in modif su ort er DCN Sample lines A, B, C, D 6-2 Inadequate flex legs Remove existing at MS line supports and install new sup orts er DCN P5200918 R-001bubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 49 of 75 Table 4-1 (CONT.)

,BROWNS FERRY UNIT 2 MSIV "OUTLIERS" RESOLUTION

SUMMARY

SYSTEM OUTLIER OUTLIER RESOLUTION DESCRIPTION DESCRIPTION METHOD Main Steam Samp/e to Station cont.

PT 16A/B 6-3 Inadequate flex legs Modify supports per at MS line DCN Sample Station 6-4 Temperature bath Provide equipment anchora e anchora e er DCN PT-16A/B 6-5 Interaction with oil Initiate Work Request to drum relocate the oil drum Main Steam B ass Main Steam Bypass Valve 7-1 Valve performance To be resolved per BFN Gale. CD-N0001-980038 SV Above Seat Drains

,FCV 6-100, 101, 102, 103 8-1 Short rod hangers Modify rod hangers per DCN 1" Drain piping from Steam 8-2 Interaction with MS Re-route drain piping Line D piping/steel and modify support per DCN Steam to Steam Seal Re ulator Rod hanger downstream 9-1 Disengaged rod Maintenance item to be of Valve 8-575 hanger addressed by WR C341864 Verification Boundary 9-2 Valve performance Walkdown scope to be Valve 8-575 (Proposed) expanded to remove the assum tion Steam Supp/y to RFP Turbines Steam supply line 10-1 Inadequate flex leg at Modify supports per MS header DCN Steam supply line 10-2 Stanchion supports Modify supports per DCN Steam supply line 10-3 TB overhead crane To be resolved per BFN Gale. CD-N0001-980039 Verification Boundary 10-4 Installation of Walkdown scope to be Valve 1-RFPT (Proposed) boundary valve expanded to remove the assum tion Condenser Condenser and anchorage 13-1 Evaluate To be resolved per BFN ade uac condenser/anchora e Gale. CD-N0001-980038 PA200918.R 001tsubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 50 of 75 Table 4-2 BROWNS FERRY UNIT 3 MSIV "OUTLIERS" RESOLUTION

SUMMARY

SYSTEM DESCRIPTION OUTLIER OUTLIER RESOLUTION DESCRIPTION METHOD Main Steam Drain Line-Turbine Bid .

MS Drain Taps 'MS line differential Relocated three motion supports per and BFN Gale.

DCN'40871A No. CD-N0001-980039 MS Drain Taps 1-2 Impact with conduit Resolved per BFN Gale.

su orts No. CD-N0001-980038 FCV 1-58 1-3 Extended valve Resolved per BFN Calc.

o erators No. CD-N0001-980038 FCV 1-58/59 Conduit 1-4 Unknown routing at Resolved per BFN Gale.

TB/RB 'oint No. CD-N0001-980038 Main Steam Lines MS Stop Valves 2-1 Valve performance Resolved per BFN Gale.

No. CD-N0001-980038 MSH-17 2-2 Missing eyebolt nut Nut replaced per WR C1 64362 MSH-17,18 & 19 2-3 Grating clearances Modified grating clearances per DCN T40871A Main Steam Drain Line-MSIV Vault FCV 1-15, 27, 38 & 52 3-1 Valve performance Resolved per BFN Calc.

No. CD-N0001-980039 FCV 1-56 3-2 Manual operator Valve replaced by DCN W17935A HPCVRCIC/Aux. Boiler Drains - MSIV Pit HPCI Drain at MS drain 4-1 Inadequate bending Modified two supports connection leg per DCN T40871A and BFN Gale. No.

CD-N0001-980039 MS PT 1-72 76 82 86 4 93 MS instrument-tubing 5-1 Overspan on 1" pipe to Missing clamp replaced PT 1-86 er DCN T40871A 1/2 in. Line to PT 1-86 5-2 Interaction with steel & Re-route pipe pipingfinstrumentation, line per DCN T40871A and BFN Gale. No. CD-N0001-980039 P:t200918.R'001'tsubrpt.doc

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20091 8-R-002 Revision 0 August 31, 1999 Page 51 of 75 Table 4-2 (CONT,.)

BROWNS FERRY UNIT 3 MSIV "OUTLIERS" RESOLUTION

SUMMARY

SYSTEM DESCRIPTION OUTLIER OUTLIER RESOLUTION METHOD DESCRIPTION Main Steam Sample to Station Sample lines B & D 6-1 Missing tubing support Missing clamps replaced per clam s WR C193204 Sample lines A, B, C, D 6-2 Inadequate flex legs at Added four supports and MS line removed four supports per DCN T40871A and BFN Gale. No. CD-N0001-980039 PT 16NB 6-3 Inadequate flex legs at Modified two supports per MS line DCN T40871A and BFN Gale. No. CD-N0001-980039 Sample Station 6-4 Temperature bath Anchorage provided per anchorage DCN T40871A and BFN Gale. No. CD-N0001-980039 Main Steam B ass Main Steam Bypass Valve 7-1 Valve performance Resolved per BFN Gale. No.

CD-N0001-980038 SV Above Seat Orains FCV 6-100, -1 01, 102,.103 8-1 Short rod hangers Modified rod hangers per DCN T40871A and BFN Gale. No. CD-N0001-980039 Steam to Steam Seal Re viator MS to FCV 1-146 9-1 Overspan piping Resolved per BFN Gale. No.

CD-N0001-980039 PCV 1-147 9-2 Hand wheel in proximity Resolved per BFN Gale. No.

to.WF section CD-N0001-980039 PCV 1-147 air line 9-'3 Inadequate flexibility& Resolved per BFN Gale. No.

blockwall interaction CD-N0001-980039 PCV 1-147 9 4 Extended valve Resolved per BFN Gale. No.

o erator CD-N0001-980039 PA200918.R.001tsubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 52 of 75 Table 4-2 (CONT.)

BROWNS FERRY UNIT 3 MSIV "OUTLIERS" RESOLUTION

SUMMARY

SYSTEM DESCRIPTION OUTLIER OUTLIER RESOLUTION METHOD DESCRIPTION Steam Supply to RFP Turbines Steam supply line 10-1 Inadequate flex leg at Remove hanger per DCN MS header T40871A and BFN Gale. No.

CD-N0001-980039 Steam supply line 10-2 Stanchion supports Replace two spring hangers per DCN T40871A and BFN Gale. No. CD-N0001-980039 Steam supply line 10-3 TB crane overhead Resolved per BFN Gale. No.

CD-N0001-980039 RFT Stop Valve above 10-4 Lass mass on 1/2 and Resolved per BFN Gale. No.

seat drains 3/4 inch lines CD-N0001-980039 Tubing to PI 1-126 10-5 Missing tubing clamps Missing clamps'replaced per overs an WR-C193201

'Steam Su I to SJAE's SJAE 3A/B Anchorage and cracked Anchorage resolved per BFN pedestal Gale. No. CD-N0001-980039; Cracked concrete pedestal re aired er WR-C193206 SJAE 3B 11-2 Loose anchor bolt nut Re-torqued loose nut per WR-C1 93205 Drain to Condenser 11-3 Drain ties to multi- Re-route piping per DCN system collector T40871A and BFN'Gale. No.

CD-N0001-980039 Steam Supply to Off-Gas Prehea ters PCV 1-175A/B 12-1 Masonry wall To be resolved by the proposed installation of NEW boundary valves to Preheaters A & B Steam supply line to 12-2 Vertical restraint of line Resolved per BFN Gale. No.

FCV 1-178A/B at FCV 1-178 CD-N0001-980039 PCV 1-175A/B, 12-3 Valve performance To be resolved by the FCV 1-178A/B proposed installation of NEW boundary valves to Preheaters A & B Condenser Condenser and anchorage 13-1 Evaluate Resolved per BFN Gale. No.

ade uac condenser/anchora e CD-N0001-980038 P:t2009 t B-R-001tsubrpt,doc

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200918-R Revision 0 August 31, 1999 Page 53 of 75 Table 4-3 Design Basis for Browns Ferry ALT Related Piping and Supports Piping Design Design Pipe Pipe Piping Typical Piping Description Temp. Press. Size Sch. D/t Material SupportTypes Design

('F) (psig) (NPS) Basis MS Lines from outboard MSIV's to 562 1146 24 80 20 ASTM A-106 Spring hangers USAS MS Header and to Turbine Stop 1 160 5 Grade B Vertical struts B31.1- 1967 Valves Main Steam Header 562 1146 24 80 20 ASTM A-155 Spring hangers USAS Grade KC-70 B31.1- 1967 MS Stop Valve Above Seat 562 1146 1 160 ASTM A-106 Rod hangers USAS Leak-off Grade B B31.1- 1967 Turbine Bypass Valve Header 562 1146 18 80 19 ASTM A-106 Rigid supports USAS Grade B Rod and Spring hangers B31.1- 1967 MS Steam Supply to RFP Turbine 562 1146 80 15 ASTM A-106 Rod and Spring hangers USAS Stop Valves 80 13 Grade B Stanchion supports B31.1- 1967 MS Steam Supply from MS Header 562 1146 3 160 ASTM A-'106 Rod and Spririg hangers USAS to SJAE's to the Condenser 2 160 Grade B B31.1- 1967 1-1/2 160 1 160 P;600918.R 00thutwpbdoc

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200918-R-0 Revision 0 August 31, 1999 Page 54 of 75 Table 4-3 (CONT.)

Design Basis for Browns Ferry ALT Related Piping and Supports Piping Design Design Pipe Pipe Piping Typical Piping Description Temp. Press. Size Sch. D/t Material Support Types Design

('F) (psig) (NPS) Basis MS Steam Supply to Steam Seal 562 1146 80 13 ASTM A-106 Rod hangers USAS Regulators Grade B B31.1- 1967 MS Steam Supply from MS Header 562 1146 2 160 ASTM A-106 Rod hangers USAS to the Off-Gas Preheaters A 8 B Grade B B31.1- 1967 160 ASTM A-335 New piping associated with the Grade P11 proposed installation of new boundary valves to Preheaters A 8 B MS Outboaid Drains from MS Lines 562 1146 ~ 160 ASTM A-106 Stanchion supports USAS to the Main Drain Line 160 Grade B B31.1- 1967 160 160 ASTM A-333 160 Grade 1 Main Drain Line to the Condenser 562/ 1146/ 80 13 ASTM A-106 Rod and Spring USAS 450 400 160 8 Grade B hangers B31.1- 1967 160 5 Stanchion supports P 200918.R.OOlbubrpbdoc

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200918-R-O Revision 0 August 31, 1999 Page 55 of 75 Table 4-3 (CONT.)

Design Basis for Browns Ferry ALT Related Piping and Supports Piping Design Design Pipe Pipe Piping Typical Piping Description Temp. Press. Size Sch. D/t Material SupportTypes Design

('F) (psig) (NPS) Basis HPCI Drain to MS Drain; 450 400 160 ASTM A-106 Rigid supports USAS RCIC Drain to HPCI Drain; 160 Grade 8 B31.1- 1967 Aux. Boiler Drains to HPCI/RCIC/

Reactor Building Drain Line 270 415 160 5 Misc. PT Instrument Lines 562 1146 160 5 ASTM A-106 Rigid supports USAS Sample Lines to Sample Station Grade B 831.1- 1967 g/ N .049" ASTM A-213 Rigid supports tubing (wall t) SS Gr. TP-304 (tube clamps)

PM00918-R.001'hubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 56 of 75 Table 4-4 Seismic Experience Database Piping Data Pipe Size Pipe Wait Facility (NPS) O.D. Schedule Thickness D/t (inch) (inch) 24 24.0 20 0.375 64 20 20.0 20 0.375 53 18 18.0 30 0.437 41 16 16.0 30 0.375 43 14 14:0 30 0.375 37 12 12.75 40 0.406 31 12 12.75 30 0.330 39 10 10.75 160 1.125 10 8.625 1'60 0.906 10 Valley Steam Plant 6.625 40 0.280 24 Units1 8 2 4.50 160 0.531 4.50 40 0.237 19 3.50 160 0.437 3.50 80 0.300 12 3.50 40'60 0.216 16 2.375 0.343 2.375 40 0.154 15 11/2 1.90 160 0.281 1 1/2 1.90 40 0.145 13 1.315 40 0.133 10 1.05 160 0.218 1.05 40 0.113 P:t20091 8.R.001tsubrpt.doc

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200918-R-002 Revision 0 August'31, 1999 Page 57'of 75 Table 4-4 (CONT.)

Seismic Experience Database Piping Data Pipe Size Pipe Wall Facility (NPS) O.D. Schedule Thickness D/t (inch) (inch) 20 20.0 STD 0.375 53 18 18.0 160 1.781 10 18 18.0 XS 0.500 36 18 18.0 STD 0.375 48 14 14.0 40 0.437 32 14 14.0 STD 0.375 37 12 12.75 160 1.312 10 12 12.75 STD 0.375 34 10 10.75 40 0.365 29 8.625 160 0.906 10 8.625 120 0.718 12 8.625 40 0.322 27 6.625 120 0.562 12 6.625 40 0.280 24 El Centro 4.50 80 0.337 13 Steam Plant 4.50 40 0.237 19 3.50 160 0;437 3.50 80 0.300 12 3.50 40 0.216 16 2.375 160 0.343 2.375 80 0.218 2.375 40 0.154 15 1.90 160 0.281 11/2 1.90 80 0.200 10 1.90 40 0.145 13 1.315 80 0.179 1.315 40 0.133 10 3/4 1.05 80 0.154 1.05 40 0.113 PA200918.R.001'hubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 58 of 75 Table 4-4 (CONT.)

Seismic Experience Database Piping Data Pipe Size Pipe Wail Facility (NPS) O.D. Schedule Thickness D/t (inch) (inch) 16.0 1.394 12 12.75 1.148 8.625 160 0.906 10 8.625 30 0.277 31 6.625 160 0.562 12 6.625 40 0.280 24 4.50 160 0.531 '8 4 4.50 80 0.337 13 4.50 40 0.237 19 Moss Landing 3.50 160 0.437 Units 1,2 & 3 3.50 80 0.300 12 3.50 40 0.216 16 2.375 160 0.343 2.375 80 0.218 2.375 40 0.154 15 11/2 1.90 160 0.281 1.90 80 0.200 1.315 160 0.250 1.315 80 0.179 3/4 1.05 160 0.218 1.05 80 0.154 10':ttempQ00918'eubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 59 of 75 Table 4-4 (CONT.')

Seismic Experience Database Piping Data Pipe Size Pipe Wall Facility (NPS) O.D. Schedule Thickness D/t (inch) (inch) 24 24.0 40 0.687 35 24 24.0 1.066 23 18.8 2.287 16.0 40 0.500 32 16 16.0 0.902 18 13.2 1.668 8.625 160 0.906 10 8.625 40 0.322 27 6.625 160 0.562 12 6.625 40 0.280 24 4.50 160 0.531 4.50 80 0.337 13 4.50 40 0.237 19 Moss Landing 3.50 160 0.437 Units 4' 5 3.50 80 0.300 12 3.50 40 0.216 16 2.375 160 0.343 2.375 80 0.218 2.375 40 0.154 15 1.90 160 0.281 1 1/2 1.90 80 0.200 10 1 1/2 1.90 40 0.145 13 1.315 160 0.250 1.315 80 0.179 1.315 40 0.133 10 e/4 1.05 160 0.218 1.05 80 0.154 1.05 40 0.113 P.ttemp'200918'eubrpt.doc

4l 200918-R-002 Revision 0 August 31, 1999 Page 60 of 75 Table 4-4 (CONT.)

Seismic Experience Database Piping Data Pipe Size Pipe Wali Facility (NPS) O.D. Schedule Thickness D/t (inch) (inch) 30 30.0 0.632 47 26 26.0 1.128 23 18 18.0 3.444 12 12.75 2.444 12 12.75 0.601 21 8.625 1.650 8.625 40 0.322 27 6.625 1.268 6.625 40 0.280 24 4.50 0.861 4.50 80 0.337 13 4.50 40 0.237 19 3.50 80 0.300 12 3.50 40 0.216 16 21/2 2.875 0.550 21/2 2.875 80 0.276 10 Moss Landing 21/2 2.875 40 0.178 16 Units 68 7 2.375 0.519 2.375 80 0.218 2.375 40 0.154 15 11/2 1.90 0.428 1 '/2 1.90 80 0.200 10 1 '/2 1.90 40 0.145 13 1.315 0.301 1.315 80 0.179 1.315 40 0.133 10 3/4 1.05 160 0.218 3/4 1.05 80 0.154 1.05 40 0.113 1/2 1.05 0.210

'/4 0.54 0.153 PhtempQ00918bubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 61 of 75 Table 4-4 (CONT;)

Seismic Experience Database'Piping Data, I

P,i pe Size:.: ', Ptpe:-. . 'ail Facility, '.- "...: '(NPS) : '"-O.'D',,', -.Schedule., , Thickness.' D/t

, (inch)';'- (iiich)

IP ~

Humboldt Say 12 12.75 80 0.687 Unit 3 80 0.593 18 10 10.75 6.625 80 0.432 15 PA200918 R.001<subrpt.dcc

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200918-R-002 Revision 0 August 31, 1999 Page 62 of 75 Table 4-5 Comparison of Browns Ferry and Selected Database Piping Parameters Piping, Parameter Browns,Ferry Database Sites.

Pipe Diameter 1.315 24.0 1.05 30.0 (inch)

Wall Thickness 0.25 1.218 0.113 3.444 (inch)

Diameter-to-Thickness Ratio 5-20 4 64 (D/t)

PA200918.R-001<subrpt.doc

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200918-R-002 Revision'0 August 31, 1999 Page 63 of 75 Table 4-6 Bounding Evaluations of Typical Support Configurations SupportType Critical Component Stress Ratio Cantilever bracket Anchor bolts .73

Rod hanger Overhead weld .70 attachment PA200918 R.001tsubrpt.doc

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2009.1 8-R-002 Revision 0 August 31, 1999 Page 64 of 75 Table 4-7 Browns Ferry Turbine'Building Design Basis Design Attribute :Description Lateral Force Resisting The Turbine Building above the operating deck'is framed by Syst'm Above the 'ransverse welded steel'rigid frames with fixed. bases and Operating Deck braced in, the direction of. the Reactor Building to provide the resistance to lateral forces.

Lateral Force Resisting The Turbine-Building below the operating deck is a reinforced

, System Below the concrete structure. Concrete walls serve as shear walls;for Operating Deck the lateral loads in the direction of the Reactor Building.

Design Codes , General: 'Uniform'Building Code (UBC)

'oncrete: American Concrete Institute (ACI 318-1963)

'teel: American Institute of Steel Construction (AISC) -1963 Seismic Design Basis, .UBC zone 1 Wind Design Basis 'ind speed of 100'mph P:t200918.R.OOt'tsubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 67 of 75 65 64 25 B Browns Ferry Cl Database 20 20 19 16 15 15 D/t 13 13 10 5 5 4 4 1 1 ~/2 2 3 18 and Above Pipe Size (NPS)

Figure 4-1 Comparison of Browns Ferry and Selected Database Piping D/t Ratios PA200918-R-00'I'e Ubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 68 of 75 Size Comparison of Browns Ferry Condenser with Database Condensers

.8FNP.3 1 <~ ~ ~ ~ ~ ~

"vah 435,000 0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000 450,000 500,000 Heat Transfer Area (ft2)

Figure 4-2 Size Comparison of. Browns Ferry Condenser with Selected Database Condensers PA200918-R.001hubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 Page 69 of,75 Comparison of Browns Ferry Condenser with,Database Condensers e

BFNP-3 2,070,000 s

Moss Landing 3,1 15,000 0 500.000 1.000.000 1,500.000 2.000.000 2,500.000 3.000.000 3,500.000 4000.000 Weight (Ibs)

Figure 4-3 Weight Comparison of Browns Ferry Concfenser with Selected Database Condensers PA20091 B.R.001 tsubrpt.doc

!I 200918-R-002 Revision 0 August 31, 1999'age 70 of,75 Comparison of Browns Ferry Condenser with Database Condensers BFNP-3 Moss Landing, ',,-.-.,',,:, .-'- . ",-.-.--.. -,=.. -;="..:- - 47 0 ,10 20 30 40 50 60 Height (ft)

Figure 4-4 Height Comparison of Browns Ferry Condenser with Selected Database Condensers P 5200918-R-001hubrpt.doo

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200918-R-002 Revision 0 August 31, 1999 Page 71 of 75 Moss Landing 68 7 (65ftx 36 ft)

Browns Ferry (50ft x 32ft)

Figure 4-5 Plan Dimension Comparison of Browns Ferry Condenser with Selected Database Condensers P 5200918.R-001tsubrpt.doc

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200918-R-002 Revision 0 August 31, 1999 P,age 72 of 75

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Anchor bolts with slotted holes directed from center anchor plate Anchor bolts with slotted holes perpendicular Fixed anchor plate Figure 4-6 Schematic Plan View of Browns Ferry Condenser Anchorage 0.

P:hternp'2009188ubrpt.doc

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200918-R-002 Revision:0

.August 31, 1999 Page 73 of 75 Corn parison of Browns Ferry Condenser Anchorage with Selected Database Condensers 0.0002 O

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0.0001 QUpper Bound mo Lower Bound i0 Moss Landing El Centro Browns Ferry

'arallel to Turbine Generator Axis Figure 4-7 Comparison of Browns Ferry and Selected Database Condenser Anchorage to Seismic Demand for Direction Parallel to the Turbine Generator Axis PAtempQ00918'eubrpt.doc

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200918-R-002 Revtston 0 August 31, 1999 Page 74 of 75 0

Comparison of Browns Ferry Condenser Anchorage with Selected Database Condensers 0.00014 I 0.00012 CI 0.0001 O

E 0.00008 OUpper Bound 0.00006 IILower Bound e 0.00004 0.00002 0

Moss Landing EI Centro Browns Ferry

'ransverse to Turbine Generator Axis Figure 4-8 Comparison of Browns Ferry and Selected Database Condenser Anchorage.to Seismic Demand for Direction Transverse to the Turbine Generator Axis OP:'ttemp'200918'subrpt.doc

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200918-R-002 Revision 0 August 31, 1999 0 5. REFERENCES Page 75 of 75

1. "BWROG Report for Increasing MSIV Leakage Rate Limits and Elimination of Leakage Control Systems", GE NEDC-31858P, Revision 2, September 1993.
2. Safety Evaluation of GE Topical Report, NEDC-31858P, Revision 2, "BWROG Report for Increasing MSIV Leakage Rate Limits and Elimination of Leakage Control Systems",
U.S. Nuclear Regulatory Commission, March 3, 1999.
3. "Browns Ferry - Unit 3, MSIV Seismic Verification Summary Report", EQE Report No.
200621-R-001, Revision 0, September 1998.
4. "Browns Ferry - Unit 2, MSIV Seismic Verification Summary Report", EQE Report No.
200918-R-001, Revision 0, August 1999.
5. "Generic Implementation Procedure {GIP) for Seismic Verification of Nuclear Plant Equipment", Rev. 2A, March 1993, Prepared by Winston & Strawn, EQE, et al., for the Seismic Qualification Utility Group {SQUG).
6. BFN Calculation'No. CD-N0001-980039, "Main Steam Seismic Ruggedness Verification".
7. BFN Calculation No. CD-N0001-980038, "Main Steam Seismic Ruggedness Evaluation".
8. BFN General Design Criteria, BFN-50-C-7102, "Seismic Design", Revision 3.
9. BFN Detailed Design Criteria, BFN-SO-C-7306, "Qualification Criteria for Seismic Class II Piping, Pipe Supports, and Components", Revision 1.
10. BFN Calculation No. CD-N0001-990113, "MSIV Seismic Evaluation Report".
PA20091 S.R.001 tsubrpt.doc
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ENCLOSURE'5 TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT (BFN)
UNITS 2 and 3 PROPOSED TECHNICAL SPECIFICATIONS'TS) CHANGE TS-399 INCREASED MAIN STEAM ISOLATION VALVE '(MSIV) LEAKAGE COMMITMENT LISTING On implementation of the proposed TS, plant operating procedures will be revised, to provide procedural requirements to establish the ALT path to the condenser.
2. FCV 1-58 and FCV 1-59 will be added to the In-Service Test (IST) program and will be periodically stroke tested'.
l 3.. For consistency, the Unit 2 seismic verification boundary will be expanded to match the Unit 3 scope. Therefore, additional Unit 2 seismic verification walkdowns will be performed during or prior to the next Unit 2 refueling outage (Sprang 2001).
4. Any new Unit 2 outliers will be resolved prior to complete.'on of the next Unit 2 outage.
5. The remaining Unit 3 outliers will be addressed in the next Unit 3 refueling outage scheduled for the Spring- of 2000. This includes qualification of 3-PCV-1-147 and the addition of in-line check valves to the Offgas Preheaters.
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RISK-INFORMED,INSPECTION NOTEBOOK.
FOR'ROWNS FERRY NUCLEAR POWER STATION UNIT 2 BWRP, GE, WITH MARK I CONTAINMENT Prepared by Brookhaven National Laboratory Department of Advanced Technology Contributors M. A. Azarm J. Carbonaro T. L. Chu A. Fresco J. Higgins G. Martinez-Guridi P.,K. Samanta NRC Technical Review Team John Flack RES Morris Branch NRR Doug. Coe NRR Gareth Parry NRR:
Peter Wilson NRR Jim Trapp Region I Michael Parker, Region III William,B. Jones Region IV Prepared, for U. S. Nuclear Regulatory Commission Office of Nuclear Regulatory Research Division of Risk Analysis & Applications
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NOTICE This notebook was developed for the NRC's inspection teams to support risk-informed inspections.
The activities involved in these inspections are discussed in: "Reactor Oversight Process Improvement," SECY-99-007A, March 1999. The user of this notebook is assumed to be an inspector with an extensive understanding of plant-specific design features and operation.
Therefore, the notebook is'not a sland-alone document, and may not be suitable for use by non-specialists. This notebook will be periodically updated with new or replacement gages incorporating additional information on this plant. Technical errors in, and- recommended updates to, this document should be brought to the attention of the following person:
Mr. Jose G'Ibarra U. S. Nuclear Regulatory Commission RES/DSARE/REAHFB TWFN T10: E46 11545 Rockville Pike Rockville, MD 20852 Browns Feny 2 Rev. Q.Var.6 2COA P 'iDOCS)BFN2 sdpnb.wpd
0 0 ABSTRACT This notebook. contains summary information to support the Significance, Determination Process (SDP) in risk-informed inspections for the Browns Ferry Nuclear Power Sation, Unit 2.
SDP worksheets support the significance determination process in risk-informed inspections and are intended to be used by the NRC's inspectors in'identifying the significance of their findings, i.e.,
.in screening risk-significant findings, consistent with Phase-2 screening in SECY99-007A. To support the SDP, additional information is given in an Initiators and.System Dependency hble, and as simplified event-trees, called SDP event-trees, developed in preparing the SDP worksheets.
The information contained herein is based on the licensee's IPE submittal. The information is revised based on IPE updates or other licensee or review. comment providing updated information and/or additional details.
8'owns Ferry 2 Rev 0 Mar 6 2 "GQ
II e CONTENTS Page Notice Abstract
1. Information. Supporting Significance Determination Process (SDP) 1.1 'Initiators and System. Dependency Table 3 1.2 SDP Worksheets 8 1.3 SDP EventTrees .. 26
2. Resolution and Disposition of.Commences . 35 References 36 0 Brains Ferry 2 - IV- Rev 0, Mar.6,2t',00
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FIGURES Page SDP'Event Tree Transients-(Reactor Trip) 27 SDP Event Tree Transients (without PCS) 28 SDP Event Tree Small LOCA 29 SDP Event'Tree SORV 30 SDP Event Tree Medium LOCA . 31 SDP Event Tree Large LOCA .. 32 SDP Event'Tree LOOP 33 SDP Event Tree Anticipated Transients Without Scram (ATWS) . 34
8) owris Ferf)' -v- Rev. 0, Mar6, 200Q
n TABLES Page 1 Initiators and System Dependency for Browns Ferry. Nuclear Power Sation, Unit 2 4 2.1 SDP Worksheet Transients (Reactor Trip) 9 2.2 SDP Worksheet Transients (without PCS) 11 2.3 SDP Worksheet' Small LOCA . 13 2.4 SDP Worksheet SORV .. 15 2.5 SDP Worksheet Medium LOCA . 17 2.6 SDP Worksheet Large,LGCA 19 2.7 :SDP Worksheet LOOP ..... i 21 2.8 SDP Worksheet Anticipated Transients Without Scram (ATWS) 23 Biowns Ferry 2 - VI- Rev, Q. Ma.'. 2GOG
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0 1. INFORMATION SUPPORTING SIGNIFICANCE DETERMINATION. PROCESS (SDP)
SECY-99-007A (NRC, March 1999) describes the, process for making a Phase-2 evaluation. of the inspection findings. In Phase 2,.the. first step is to identify the pertinent core damage scenarios that require further evaluation based on the specifics of the inspection findings. b aid in this process, this notebook provides the following,information:
1. Initiator and System Dependency Table
2. Significance. Determination Process (SDP) Nbrksheets
3. SDP Event Trees The initiator and system dependency table shows the major dependencies between front-line- and support-systems, and identifies their involvement in. diferent types of initiators. The information in this table identifies the most risk-significant front-line- and support-systems; it is not an exhaustive nor comprehensive compilation of, the dependency matrix as known in Probabilistic Risk Assessments. (PRAs). This table is used to identify the SDP worksheets to 'be evaluated, corresponding to the inspection's findings on systems and component .
To evaluate the impact of the inspection's, finding, on the core-damage scenarios, the SDP worksheets are developed and provided. They contain two parts. The first part. identifies the functions,,the systems, or combinations thereof that can perform mitigating functions, the number of trains in each system, and the number of trains required (success criteria) for each class of initiators. The second part of the,SDP worksheet contains the core-damage accident. sequences associated with each initiator class; these sequences are based on SDP event trees. In the parenthesis next to each of the sequence, the corresponding event tree branch number(s) representing the sequence is included. Multiple branch numbers indicate that the diferent accident sequences identified by the-event tree are merged into one. through the'boolean reduction: The classes of initiators that are considered. in this. notebook are: 1) Transients;.both Reactor Trip and without PCS, 2).a generic Small Loss of Coolant Accident:(LOCA) and specifically a Buck Open Relief Valve (SORV), 3) Medium LOCA, 4) Large LOCA, 5) Loss of Ofsite Power (LOOP), and 6)
Anticipated Transients Without Scram (ATWS). Main Steam Line Break (MSLB) events are included separately if.they are treated as such in the licensee's Individual Plant Examination,(IPE) submittal.
Following the SDP worksheets,,the SDP event trees corresponding to each of the worksheet; are presented. The SDP event trees are-simplified. event trees developed to define the accident sequences identified in the SDP worksheets.
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The following:items were considered in establishing the SDP event trees and the. core-damage sequences in the SDP worksheets:
1. Event trees and sequences were developed such that the worksheet conhins all the ma~or accident sequences identified by the plant-specific IPEs. In cases where a plant-specific feature introduced a sequence:that is not fully captured by our existing set of initiators and event trees, then a separate worksheet is included.
2. The event trees and sequences for each plant took into account the IPE models and event trees for all similar plants. Any major deviations in one plant from similar plant typically are noted at the:end of the worksheet.
3. The event trees and the sequences were designed'to capture core-damage scenarios, without including:containment-failure probabilities and.consequences. Therefore, branches of event trees that are only for the purpose. of a Level II PRA analysis are not considered. The resulting sequences are merged using Boolean logic.
4. The simplified event-trees focus on classes of initiators, as defined above. In so doing, many separate event trees in the IPEs:olten are represented by a single tree., For example, some IPEs define four classes of LOCAs rather than the three classes considered here. Such differentiations generally are not considered:in the SDP worksheeh unless they could not be accounted for. by the Initiator and System Dependency able.
5. Major operator actions during accident scenarios are assigned as high stress operator action or an operator action using simple, slandard criteria among:a class of plants. This approach, resulted in the designation of some actions as high stress operator actions, even though the PRA may have assumed an operator action; hence, they have been assigned an error probability less than 5E-2 in the IPE. 'In such cases, a.note is given at the end of the worksheet.
6. The NRC expressed concerns regarding the sharing of many imporhnt systems between the three units at BF and the control of these systems to ensure availability As. a result TVA performed.a.multi-unit analysis (PRA) to evaluate these issues. This PRA was submitted on April 14, 1995. The multi-unit PRA was not used for this Notebook.
The three sections that follow include the. initiators and dependency able, SDP worksheets, and the SDP event-trees for the'Browns'Ferry Nuclear Power Station, Unit 2.
Brains Ferry 2 Rev. 0, Mar. 6 2C J".
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1.1 INITIATORS AND SYSTEM DEPENDENCY Table 1 provides the,list'of the systems included in the SDP worksheet, the major components in the systems, and the, support system dependencies. The system involvement in diferent initiating events are noted in the last column.
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Table 1 Initiators and System Dependency for Browns Ferry Nuclear Power Station, Unit 2 Affected System Major Components Support Systems Initiating Event Scenarios Code Name PCS Power Conversion System MDP, TDP, MOV AC, RCP Transient (Reactor Trip),
SLOCA, SORV, ATWS HPCI High Pressure Coolant TDP DC, ACT All but LLOCA Injection RCIC Reactor Core Isolation TDP DC, ACT All but MLOCA 8 LLOCA Cooling SRVs Safety Relief Valves RV, Accumulators DC, DNV Containment Air All but LLOCA LPCI Low Pressure Coolant MDP, MOV AC, DC, EEC, RCP, ACT, All Injection HVAC RHR Residual Heat Removal MDP, MOV, Heat Exchanger AC, DC, RHRSW, EEC, All HVAC CS Core Spray MDP, MOV AC, DC, EEC, RCP, ACT, All HVAC AC AC Power (non-EDG) Breakers, Transformers AC, DC, HVAC All but LOOP EDGs AC Power (EDGs) Engine, Generator DC, EEC, HVAC LOOP DC DC Power, 125 V and 24 V Battery Charger None (Short term- All 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months ) Chargers and AC (long term)
RHR SW RHR Service Water MDP, MOV AC, DC All CRD Control Rod Drive Hydraulic MDP, MOV AC DC PlantContainment Transient (Reactor Trip 8 System Air, RCP (EEC)" W/0 PCS), SLOCA, SORY
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Table 1 (Continued)
Affected System Major Components Support Systems Initiating Event Scenarios Code Name ACT Shared Actuation Instruments, Relays AC, DC All Instrumentation Plant Plant Control Air Air Compressor, Valves AC, DC, RCP (EEC) All but LLOCA Containment Air D/W Containment Drywell Control Air Compressor, Valves AC, Plant Containment Air, All but LLOCA Air RBCCW SLC Standby Liquid Control MDP, MOV, Explosive Valve AC, DC ATWS RBCCW Reactor Building Closed MDP, MOV, Heat Exchanger AC, DC, Plant Containment AII but LLOCA Cooling Water Air, RCP (EEC)
EEC Emergency Equipment MDP, MOV, Heat Exchanger AC, DC, ACT All Cooling Water System RCP Raw Cooling Water MDP, MOV, Heat Exchanger AC All CST Condensate Transfer MDP, CST, MOV AC, DC, Plant Containment Transient (Reactor Trip),
Air, RCP SLOCA, SORV CV Containment Vent Rupture Disc, Manual Valve None None FP Firewater Injection Pump MDP, Diesel-driven Pump None None HVAC Heating, Ventilation and Air Coolers, Dampers AC, DC, EEC All Conditioning
$ Notes:
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(1) Transient scenarios should be developed from those transient initiators that could have the greatest risk significance. For example, develop loss of DC bus transient scenarios for degraded 125 V-DC or AC power equipment, as well as, other transient initiators that may depend on
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Table 1 (Continued) equipment being supplied from degraded power sources. The choice of which transient scenarios to develop should generally be apparent from the specific given condition.
(2) Information herein was developed from the BF-2 IPE dated Sept. 1, 1992 and RAI responses dated 9/21/93 & 12/23/93.
(3) The baseline BF-2 IPE core damage frequency (CDF) from internal events was 4.5 x 10-5 events/Reactor year and the Large Early Release Frequency (LERF) was 2.2 x 10-5 events/Reactor year. At BF-2 internal floods (in the Unit 2 Reactor Building) constitute about 10% of CDF.
(4) Where we have indicated AC in the Support system column, this means that power can be supplied by one or both of the EDG System or the non-EDG AC power system. Typically for BF-.2 the safety-related AC equipment can be supplied by either, while the non-safety can only be supplied by non-EDG power. The EDGs are only specifically credited in the LOOP Event Tree.
(5) There are two divisions of emergency power at Browns Ferry Unit 2 and 4 EDGs (A, B, C, 8 D) for Units 1 & 2, and four EDGs (3A through 3D) at Unit 3, for a total of 8 EDGs on the site.
(6) For BF-2 a stuck open relief or safety valve is treated as equivalent to a small break steam LOCA. A separate worksheet is included for an SORV.
(7) SRVs: There are 13 SRVs, of which 6 are used for ADS. All 13 can be used for manual DEP, provided the Plant Control Air System/Drywell Control Air System are operable. If not, then only 6 can be used for DEP via their accumulators.
(8) PCS: At BF-2, the TBVs have 25% bypass capacity.
(9) RHR System: both RHR and CS Systems have pump room coolers (HVAC), supplied by EEC; there are RHR cross-ties between U1 and U2 for suppression pool cooling.
(10) In the RHRSWSystem, there are 12 RHRSW pumps-4 for RHRSW, 4 for EEC, and 4 swing pumps. RHRSWcan be cross-tied to RHR for late injection (LI), however no credit is taken in the IPE for this action.
(11) RCP normally cools Plant Control Air, RBCCW, and CRD. During an accident/transient RCP cooling is replaced by the safety-related EEC system. This is indicated in the above Table by RCP (EEC).
(12) In their 12/23/93 response letter to RAls, TVA notes that they installed a hardened vent after the IPE was submitted and that updates to the PRA will take credit for the vent, that were not credited in the IPE.
CD C)
Table 1 (Continued) o (13) BF-2 does not take credit for late injection (e.g., with a fire pump or cross connect from RHR SW). The NRC SER on the BF-2 IPE questioned this and TVA resporided in their 4/14/95 submittal of their multi-unit PRA. They stated that sensitivity studies showed that use of the fire pump for late injection had a relatively small impact on CDF. They also noted that use of the fire pump an'd the hardened wetwell vent was discussed in the BF emergency procedures.
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1.2 SDP WORKSHEETS This section presents the SDP worksheets to be used in the Phase 2 evaluation of the inspection findings. for, the. Browns Ferry Nuclear Power Station, Unit 2; The, SDP worksheels are presented for the following initiating event categories:
1. Transients (Reactor Trip) 2; Transients:(without PCS)
3. Small, LOCA
4. SORV
5. Medium LOCA 6; Large LOCA
7. LOOP
8. Anticipated Transients Without Scram (ATWS) 0 Brogans Ferry 2 Rev.O, fear.6 2CQQ'
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rl Table 2.1 SDP Worksheet for Browns Ferry Nuclear Power Station, Unit 2 Transients (Reactor Trip)
CCI
!V Estimated Frequency (Table 1 Row) Exposure Time Table 1 Result (circle): A 8 C D E F G H Safe Functions Needed: Fu//Creditable Miti ation Ca abili 'or Each Safet .Function:
Power Conversion System (PCS) 1/4 steam lines, condenser, circ. water pump, 1/3 condensate pumps, 1/3 cond. booster pumps, 1/3 reactor feed pumps (operator action)
High Pressure Injection (HPI) HPCI (1 ASD train) or RCIC (1 ASD train) or 1/2 CRD pumps (operator action)
Depressurization (DEP) 2/13 SRVs manually opened or 9/9 Turbine Bypass Valves (TBVs) (operator action)
Low Pressure Injection (LPI) 1/4 RHR trains in LPCI Mode (1 multi-train system); or 1/2 CS trains with 2/2 pumps per train (1 multi-train system); or 1/3 trains of condensate/hotwell makeup or 1/2 CRD pumps (operator action)
Containment Heat Removal (CHR) 1/4 RHR pumps, 1/4 RHR heat exchangers, and 1/4 RHRSW pumps in either the suppression pool cooling (SPC) mode or the shutdown cooling (SDC) mode (1 multi-train system); or 1 train of PCS (operator action)
Containment Venting (CV) Venting not credited for BF-2 Late Inventory, Makeup (LI) Late injection not credited for BF-2 Circle Affected Functions Racouerii of Remafnin Miti ation Ca abiiit Ratin for Each Affected Se uence Setiuence Failed Train Color 1Trans-PCS-CHR (3i 5) 2Trans- PCS-HPI- DEP (7) 3Trans-PCS-HPI-LPI (6)
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Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:
If operator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: t) sulicient time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.
Notes:
(1) We have grouped together with Reactor Scram any transients that do not involve a loss of offsite power or the pCS.
(2) Transients (with the reactor not isolated), such as in this woiksheet, constitute 9% of CDF at BF-2.
I (3) BF-2 does not credit late injection (LI) or containment venting (CV).
Table 2.2 SDP Worksheet for Browns Ferry Nuclear Power Station, Unit 2 Transients (without PCS)
Estimated Frequency (Table 1 Row) Exposure Time Table 1 Result (circle): A B C D E F G H Safe Functions Needed: Ful/Creditable Miti ation Ca abilit for Each Safet Function:
High Pressure Injection (HPI) HPCI (1 ASD train) or RCIC (1 ASD train) or 1/2 CRD pumps (operator action)
Depressurization (DEP) 2/13 SRVs manually opened (operator action)
Low Pressure Injection (LPI) 1/4 RHR trains in LPCI Mode (1 multi-train system); or 1/2 CS trains with 2/2 pumps per train (1 multi-train system); or 1/2 CRD pumps (operator action)
Containment Heat Removal (CHR) 1/4 RHR pumps, 1/4 RHR heat exckangers, and 1/4 RHRSW pumps in either the suppression pool cooling (SPC) mode or the shutdown cooling (SDC) mode (1 multi-train system)
Containment Venting (CV) Venting not credited for BF-2 Late Inventory, lNakeup (LI) Late injection not credited for BF-2 Circle Affected Functions Recouerir of Remainin Miti ation Ca abiii Ratin for Each Affected Se uence Setiuence Failed Train Color 1TPCS-CHR (2,4) 2 TPCS - HPI - DEP (6) 3 TPCS - HPI - LP.I (5)
Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:
If operator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: 1) suficient time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.
Notes:
(1) This event tree and worksheet is for Transient (without PCS). It includes Main steam line break, Loss of FW, and loss of main condenser. These initiating events at BF-2 constitute about 8% total CDF. It is assumed that no aspects of the PCS are available for safety functions during the transients evaluated in this event tree and worksheet.
I (2) BF-2 does not credit late injection (LI) or containment venting (CV).
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Table 2.3 SDP Worksheet for Browns Ferry Nuclear Power Station, Unit 2 Small LOCA Estimated Frequency (Table 1 Row) Exposure Time Table 1 Result (circle): A B C D E F G H Safe Functions Needed: Full Creditable Miti ation Ca abili for Each Safe Function:
Power Conversion System (PCS) 1/4 steam lines, condenser, circ. water pump, 1/3 condensate pumps, 1/3 cond. booster pumps, 1/3 reactor feed pumps (operator action)
High Pressure Injection (HPI) HPCI (1 ASD train) or RCIC (1 ASD train)
Depressurization (DEP) 2/13 SRVs manually opened or 9/9 Turbine Bypass Valves (TBVs) (operator action)
Low Pressure Injection (LPI) 1/4 RHR trains in LPCI Mode (1 multi-train system); or 1/2 CS trains with 2/2 pumps per train (1 multi-train system); or 1/3 trains of condensate/hotwell makeup or 1/2 CRD pumps (operator action)
Containment Heat Removal (CHR) 1/4 RHR pumps, 1/4 RHR heat exchangers, and 1/4 RHRSW pumps in either the suppression pool cooling (SPC) mode or the shutdown cooling (SDC) mode (1 multi-train system); or 1 train of PCS (operator action)
Containment Venting (CV) Venting not credited for BF-2 Late Inventory, Makeup (LI) Late injection not credited for BF-2 Circle Affected Functions Recovere of Remainin Mitt ation Ca abiiit Ratin for Each Affected Ee uence ~Se uence Failed Train Color 1 SLOCA -PCS - CHR (3, 5) 2 SLOCA - PCS - HPI - LPI (6) 3 SLOCA- PCS - HPI - DEP (7)
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Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:
If operator actions are required to credit piacing mitigation equipment in service or for recovery actions, such credit should be given only if the foilowing criteria are met:
1) suficient time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is availabie and ready for use.
Note:
(1) BF-2 does not credit late injection (LI) or containment venting (CV).
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Table 2e4 SDP Worksheet for Browns Ferry Nuclear Power Station, Unit 2 SORY Estimated Frequency (Table 1 Row) Exposure Time Table 1 Result (circle): A B C D E F G H Safe Functions Needed: Full Creditable Miti ation Ca abili for Each Safe Function:
Power Conversion System (PCS) 1/4 steam lines, condenser, circ. water pump, 1/3 condensate pumps, 1/3 cond. booster pumps, 1/3 reactor feed pumps (action)
High Pressure Injection (HPI) HPCI (1 ASD train) or RCIC (1 ASD train)
Depressurization (DEP) 2/13 SRVs manually opened or 9/9 Turbine Bypass Valves (TBVs) (operator action)
Low Pressure Injection (LPI) 1/4 RHR trains in LPCI Mode (1 multi-train system); or 1/2 CS trains with 2/2 pumps per train (1 multi-train system); or 1/3 trains of condensate/hotwell makeup or 1/2 CRD pumps (operator action)
Containment Heat Removal (CHR) 1/4 RHR pumps, 1/4 RHR heat exchangers, and 1/4 RHRSW pumps in either the suppression pool cooling (SPC) mode or the shutdown cooling (SDC) mode (1 multi-train system); or 1 train of PCS (operator action)
Containment Venting (CV) Venting not credited for BF-2 Late Inventory, Makeup (LI) Late injection not credited for BF-2 Circle Affected Functions Recovererof Remainfn Mitt ation Ca abiiit Ratin for Each Affected Setiuence Failed Train ~Se uence Color 1 SORY - PCS - CHR (3, 5) 2 SORV - PCS - HPI - LPI (6) 3 SORV - PCS - HP I- DEP (7)
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Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:
If operator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: 1) suficient time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.
0 Table 2.5 SDP Worksheet for Browns Ferry Nuclear Power Station, Unit 2 Medium LOCA Estimated Frequency (Table 1 Row) Exposure Time Table 1 Result (circle): A B C D E F G H Safe Functions Needed: Ful/Creditable Miti ationCa abili forEachSafet Function:
Power Conversion System (PCS) No credit for PCS in MLOCA.
Early Containment Control (EC) Passive operation of SP with all vacuum breakers closed (1 train system)
High Pressure Injection (HPI) No credit for HPI in MLOCA.
Depressurization (DEP) 2/13 SRVs manually opened or HPCI operation (operator action)
Low Pressure Injection (LPI) 1/4 RHR trains in LPCI Mode (1 multi-train system); or 1/2 CS trains with 2/2 pumps per train (1 multi-train system)
Containment Heat Removal (CHR) 1/4 RHR pumps, 1/4 RHR heat exchangers, and 1/4 RHRSW pumps in the suppression pool cooling (SPC) mode (1 multi-train system)
Containment Venting (CV) Venting not credited for BF-2 Late Inventory, Makeup (LI) Late injection not credited for BF-2 Circle Affected Functions Recoveref of Remainin N/iti ation Ca abi/it Ratin for Each Affected Se uence Seceuence Failed Train Color 1 MLOCA- EC (5) 2 MLOCA-CHR (2) 3 MLOCA- LPI (3) 4 MLOCA- DEP (4)
0 Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:
If operator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: 1) suficient time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.
Note:
(1) In their MLOCA analysis, BF-2 takes credit for HPCI assisting the LOCA in depressurization, but does not credit HPCI or RCIC for high pressure injection. Thus (similar to the LLOCA) there is no credit for any HPI in the MLOCA scenario.
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th rl Table 2.6 SDP Worksheet for Browns Ferry Nuclear Power Station, Unit 2 Large LOCA u}
Estimated Frequency (Table 1 Row) Exposure Time Table 1 Result (circle): A B C D E F G H Safe Functions Needed: Fu//Creditable Miti ation Ca abilit for Each Safe Function:
Early Inventory (El) 1/4 RHR trains in LPCI Mode (1 multi-train system); or 1/2 CS trains with 2/2 pumps per train (1 multi-train system)
Early Containment Control (EC) Passive operation of SP with all vacuum breakers closed (1 train system)
Containment Heat Removal (CHR) 1/4 RHR pumps, 1/4 RHR heat exchangers, and 1/4 RHRSW pumps in the suppression pool cooling (SPC) mode (1 multi-train system)
Containment Venting (CV)1 Venting not credited for BF-2 Circle Affected Functions Recovere ot Rematnin Mitt a'lionCa abiiit Ralin forEachAffectedSe uence ~Se uence I Failed Train Color ro e
1 LLOCA - EC (4) 2 LLOCA- CHR (2) 3 LLOCA- EI (3)
Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:
Q C>
07 Ifoperator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: t) suficient time is avaiiable to impiement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.
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Brow:ns Ferry 2 Rev 0, Mar 6,2000 0
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Table 2.7 SDP Worksheet for Browns Ferry Nuclear Power Station, Unit 2 LOOP Estimated Frequency (Table 1 Row) Exposure Time Table 1 Result (circle): A B C D E F G H Safe Functions Needed: Ful/Creditable ziti ationCa abili for.EachSafe Function:
Emergency Power (EAC) 1/8 EDGs (1 multi-train system)
Recovery of LOOP in 30 min (RLOOP30M) High stress operator action Recovery of LOOP in 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months (RLOOP6H) High stress operator action High Pressure Injection (HPI) HPCI (1 ASD train) or RCIC (1 ASD train)
Depressurization (DEP) 2/13 SRVs manually opened (operator action)
Low Pressure Injection (LPI) 1/4 RHR trains in LPCI Mode (1 multi-train system); or 1/2 CS trains with 2/2 pumps per train (1 multi-train system) - requires AC power Containment Heat Removal (CHR) 1/4 RHR pumps, 1/4 RHR heat exchangers, and 1/4 RHRSW pumps in either the suppression pool cooling (SPC) mode or the shutdown cooling (SDC) mode (operator action)
Containment Venting (CV) Not credited in IPE.
Circle Affected Functions ~Recove of Rema/nin Miti ation Ca abi%t Ratin for Each Affected Seceuence Failed Train ~Se uence Color 1 LOOP - EAC - RLOOP6H (16) 2 LOOP - EAC - RLOOP30M - HPI (15) 9 LOOP - CHR (2, 4, 8, 10, 14) 10 LOOP - HPI - DEP (6, 12)
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11 LOOP - HPI - LPI (5, 11)
Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:
lf operator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: 1) suficient time is available to implement these actions, 2) environmental conditions allow access where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.,
Note:
(1) There are two divisions of emergency power at Browns Ferry Unit 2 and 4 EDGs (A, B, C, 8 D) for Units 1 8 2, and four EDGs (3A through 3D) at Unit 3, fora total of8 EDGs on the site.
(2) BF-2 models two recovery times (30 min and 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months ). On an SBO, HPCI and RCIC can last for 4 hours4.62963e-5 days 0.00111 hours 6.613757e-6 weeks 1.522e-6 months . After this time they are assumed to fail due to battery depletion and loss of control power. However, Core Damage (CD) does not occur until after 6 hours6.944444e-5 days 0.00167 hours 9.920635e-6 weeks 2.283e-6 months , thus allowing added time for recovery of LOOP. BF-2 does not credit recovery of failed EDGs.
(3) At BF-2, a LOOP (non SBO) constitutes 42% of total CDF, while a LOOP (SBO) constitutes 27% of total CDF. Together LOOP is 69% of CDF.
ll Table 2.8 SDP Worksheet for Browns Ferry Nuclear Power Station, Unit 2 ATWS Estimated Frequency (Table 1 Row) Exposure Time Table 1 Result (circle): A B C D E F G Safe Functions Needed: Full Creditable Miti ation Ca abili for Each Safet Function:
Overpressure Protection (OVERP) 9/1 3 SRVs (1 multi-train system)
Recirculation Pump Trip (RPT) Automatic trip of recirculation pumps (1 multi-train system)
Standby Liquid Control (SLC) Mechanical operation 1/2 SLC pumps (1 multi-train system)
Reactivity, Level Control and Inhibit (LC/INH) Manual initiation of SLC, level control, and operator inhibits ADS (high stress operator action)
High Pressure Injection (HPI) HPCI (1 ASD train) or RCIC (1 ASD train) or one train of PCS (operator action)
Depressurization (DEP) 2/13 SRVs manually opened (operator action)
Low Pressure Injection (LPI). 1/4 RHR trains in LPCI Mode (Operator action); or 1/2 CS trains with 2/2 pumps per train (Operator action)
Overfill (OVERFILL) Operator prevents overfill by LPI (operator action)
Containment Heat Removal (CHR) 1/4 RHR pumps, 1/4 RHR heat exchangers, and 1/4 RHRSW pumps in either the suppression pool cooling (SPC) mode or the shutdown cooling (SDC) mode (operator action)
Containment Venting (CV) Not credited in IPE.
Circle Affected Functions RecovereR of Remainin Miti ation Ca abi/it .Ratin forEach Affecte ~se uence Failed Train ~Se uence Color 1 ATWS -OVERP (11) 2ATWS- RPT (10) 3 AVOWS - SLC (9)
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4 ATWS - INH/LC (8) 5 ATWS - HPI - LPI (6) 6 ATWS - HPI - DEP (7) 7 ATWS - HPI - OVERFILL (5) 8 ATWS - CHR (2, 4)
Identify any operator recovery actions that are credited to directly restore the degraded equipment or initiating event:
If operator actions are required to credit placing mitigation equipment in service or for recovery actions, such credit should be given only if the following criteria are met: 1) suficlent time is available to implement these actions, 2) environmental conditions allowaccess where needed, 3) procedures exist, 4) training is conducted on the existing procedures under conditions similar to the scenario assumed, and 5) any equipment needed to complete these actions is available and ready for use.
Notes:
(1) ATWS scenarios at BF-2 constitute about 3% of CDF. None of the top 10 sequences are ATWS sequences.
(2) BF-2 assumes that failure of operators to manually initiate SLC implies failure of other operator actions (lowering Reactor level and controlling level at the TAF) and leads to CD. However, if SLC fails mechanically (SLC), they still allow operator actions to limit reactivity by n controlling reactor level (LC)and inhibiting ADS (INH). However, in this worksheet, it is not assumed to prevent a core damage.
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O (3) Operator action to inject boron at BF-.2 with the SLC system has different HEPs depending on the scenario; the HEPs vary from 6E-3 to 1.2E-2. It is categorized here as a high stress operator action.
(4) Controlling RPV level using LPCI or CS to prevent overfill has an HEP of 1.5E-3.
(5) Operator action to inhibit ADS has an HEP of 1.5E-3.
(6) Lowering RPV level to the TAF has an HEP range of 1 to 3 E-4 (7) Emergency depressurization has an HEP range of 2E-4 to 1E-2.
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'1.3 SDP EVENT TREES This section provides the simplified event trees called SDP,event trees used to define the accident sequences identified'in the SDP worksheels in the previous section. The event tree headings are defined in the corresponding SDP worksheels.
The following event trees are included:
1. Transients (Reactor Trip)
2. ~
Transients (without PCS)
3. Small LOCA
4. SORV Large'LOCA
5. Medium LOCA 6;
7. LOOP
8. Anticipated Transients Without Scram (ATWS) 8"owns F'erry 2 Rev Q., Ma<;62000
0 TRAN.(RX-TRIP) PCS HPI DEP LPI CHR STATUS I'K 2 OK 3 CD 4 OV 3 CD 6 CD 7 CD hl PIanIName Abbrev.: IIFRY CD C3 lD
0 ii 0
TRAN~IOWCS) HPI DEP EPI St'ATUS OK OK Plant NanaAbbrev.: BFRY
0 0
0
SLOCA PCS HPI DEP LPI CHR ¹ STAllJS 1 OK 2 OK 4 OK Plant Name Abbrev.: BFRY
II HPI DEP LPI CHR STATUS 1 OK 2 OK 4 OK Plant Name Abbrev.: BFRY
0 0
MLOCA EC DEP LPI CHR STATUS OK CD CD CD CD Plant Name Abbrev.: BFRY
II Cl
EC CHR STATUS CD CD CD 4 . CD Plant NameAbbrev.: BFRY
LOOP EAC RLOOP30 M RLOOP6 H HP.I DEP LPI STA1US OK OK OK OK 12 13 OK 14 15 16 Pl a nt Na na Abbr ev.: BFRY
A MS OV ERP RPT SLCH I NHI LC OAZLC HPI LPI OVERFIL CHR SFAlUS OK OK OK 10 12 PI ant NamAbbrev.: BFRY
2. RESOLUTION AND DISPOSITION OF COMMENTS This section documents the comments received on the material included in this report and their resolution. This section is blank until commenh are received and are addressed.
8;oi~,ns F &~re,.:, Rev 4 4'la'3 PilQG
t 0
i
REFERENCES NRC SECY-99-007A, Recommendations 'for Reactor. Oversight Process Improvements
,(Follow-up to SECY-99-007), March 22, 1999;
2. Tennessee Valley Authority, "Browns Ferry Nuclear Power Station, Unit 2, Individual, Plant Examination Transmittal Report,." dated September 1,,1992.
3. Tennessee Valley Authority, Browns Ferry Nuclear..Plant Unit 2 Responses to NRC RAls dated 9/21/93 and 12/23/93
4. Tennessee Valley Authority, Browns Ferry Nuclear Plant - Multi-.Unit Probabilistic Risk ~
Assessment (PRA), submitted to NRC via letter dated April 14, 1995
-.36-
v 0
Mr. J. A. Scalice BROWNS FERRY NUCLEAR PLANT Tennessee Valley Authority CC:
Mr. Karl W. Singer, Senior Vice President Mr. Mark J. Burzynski, Manager Nuclear Operations Nuclear Licensing Tennessee Valley Authority Tennessee Valley Authority 6A Lookout Place 4X Blue Ridge 1101 Market Street 1101 Market Street Chattanooga, TN 37402-2801 Chattanooga, TN 37402-2801 Mr. Jack A. Bailey, Vice President Mr. Timothy E. Abney, Manager Engineering 8 Technical Services Licensing and Industry Affairs Tennessee Valley Authority Browns Ferry Nuclear Plant 6A Lookout Place Tennessee Valley Authority 1101 Market Street P.O. Box 2000 Chattanooga, TN 37402-2801 Decatur, AL 35609 Mr. John T. Herron, Site Vice President Senior Resident Inspector Browns Ferry Nuclear Plant U.S. Nuclear Regulatory Commission Tennessee Valley Authority Browns Ferry Nuclear Plant P.O. Box 2000 I0833 Shaw Road Decatur, AL 35609 Athens, AL 35611 General Counsel State Health Officer Tennessee Valley Authority Alabama Dept. of Public Health ET 10H RSA Tower - Administration 400 West Summit Hill Drive Suite 1552 Knoxville, TN 37902 P.O. Box 303017 Montgomery, AL 36130-3017 Mr. N. C. Kazanas, General Manager Nuclear Assurance Chairman Tennessee Valley Authority Limestone County Commission 5M Lookout Place 310 West Washington Street 1101 Market Street Athens, AL 35611 Chattanooga, TN 37402-2801 Mr. Robert G. Jones, Plant Manager Browns Ferry Nuclear Plant Tennessee Valley Authority P.O. Box 2000 Decatur, AL 35609
lC e
<trpb 4 1I
'"" g't:l 0
~Ck
J. Scalice 'March 30, 2000 As a result of the recently concluded.Pilot:Plant review effortthe NRC has determined that site-specific risk data is needed in order to provide a repeatable. determination of the significance of an issue. Therefore, the NRC has contracted with Brookhaven National Lab (BNL) to develop site-specific worksheets.to'be used, in, the SDP review. These enclosed worksheets were developed based on your Individual Plant Examination (IPE) submittals that were requested by Generic Letter 88-20; The NRC plans to use this site-specific information in evaluating the significance of issues identified'at your facility when the revised reactor oversight process is implemented industry wide. It'is recognized that the IPE utilized during this effort may not contain current information. Therefore, the.NRC or its contractor will conduct a site visit to discuss with your staff any changes that may be appropriate. Specific dates for the site visit have not been determined, but will be communicated to you in the near future. The NRC is not requesting a written response or comments on the enclosed worksheets developed by BNL.
We will coordinate our efforts through your licensing or risk organizations as appropriate. If you have any questions, please contact me at 301-415-3026.
Sincerely,
/m/
William O. Long, Senior Project Manager, Section 2 Project Directorate-II Division of Licensing Project Management Office of Nuclear Reactor Regulation Docket Nos. 50-259, 50-260 and 50-296
Enclosure:
As Stated cc w/encl: See next page DISTRIBUTION
'File Cent~er PUBLIC PDII-2 Reading RCorreia B Clayton WLong PKoltay WDean DCoe ACRS OGC PFredrickson, Rll UMENT NAME: G:)PDII-2<BFN<a6544 sdp.wpd e a copy of this document, indicate In the box: C ~ Copy without attachment/enclosure op with attachment e c OFFICE PDII-2/PM P DI 1-2/LA PDII-2>SC NAME WLon BCla ton RCorreia DATE 3/ /00 3/> /00 3/2 f/00 OFFICIAL RECORD'COPY
II 1
0 0
~O

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