ML053560186

Response to NRC Round 2 Request for Additional Information Related to Technical Specifications Change No. TS-418-Request for Extended Power Uprate Operation

ML053560186
Person / Time
Site:	Browns Ferry
Issue date:	12/19/2005
From:	O'Grady B Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
TAC MC3743, TAC MC3744, TVA-BFN-TS-418
Download: ML053560186 (171)

Text

Tennessee Valley Authority, Post Office Box 2000, Decatur, Alabama 35609-2000 Brian O'Grady Vice President, Browns Ferry Nuclear Plant TVA-BFN-TS-418 December 19, 2005 10 CFR 50.90 U.S. Nuclear Regulatory Commission ATTN: Document Control Desk Mail Stop: OWFN, P1-35 Washington, D.C. 20555-0001 Gentlemen:

In the Matter of ) Docket Nos. 50-260 Tennessee Valley Authority ) 50-296 BROWNS FERRY NUCLEAR PLANT (BFN) - UNITS 2 AND 3 - RESPONSE TO NRC ROUND 2 REQUEST FOR ADDITIONAL INFORMATION RELATED TO TECHNICAL SPECIFICATIONS (TS) CHANGE NO. TS-418- REQUEST FOR EXTENDED POWER UPRATE OPERATION (TAC NOS. MC3743 AND MC3744)

This letter provides TVA's response to the NRC Staffs request for additional information, which was submitted to TVA by letter dated October 3, 2005 (Reference 1), in order to support review of the BFN Units 2 and 3 Extended Power Uprate (EPU) license amendment applications.

TVA submitted the BFN Units 2 and 3 EPU applications to the NRC by letter dated June 25, 2004 (Reference 2). TVA supplemented those applications by letters dated February 23, 2005 (Reference 3), April 25, 2005 (Reference 4) and June 6, 2005 (Reference 5). The enclosure to this letter provides TVA's responses to the questions contained in Reference 1.

As discussed with the NRC Project Manager for BFN Units 2 and 3 EPU, TVA is deferring its response to two of the Round 2 requests to ensure TVA's response to these items provides sufficient information for the Staff to PRhd I recyiedpa

U.S. Nuclear Regulatory Commission Page 2 December 19, 2005 complete its review of those subject areas. Specifically, NRC Request EMEB-B.7 requested information concerning TVA's plans for vibration monitoring, procedures, hold points, evaluations, and decision criteria during and following power ascension at EPU conditions. TVA's vibration monitoring program is not yet sufficiently developed to provide the level of detail the NRC Staff requires to complete its review of this item. Accordingly, TVA is deferring its complete response to this item until the program is further developed. TVA will provide the complete response to NRC request EMEB-B.7 by February 1, 2006.

NRC Request SPSB-A. 11 requested that TVA provide an assessment of the requested credit for Containment overpressure in ensuring adequate post-accident Emergency Core Cooling System pump Net Positive Suction Head against the five key principles of risk-informed decision-making identified in NRC Regulatory Guide 1.174 and NRC Standard Review Plan Chapter 19.

TVA requires further time to prepare this response, particularly in regard to development of a quantitative risk assessment model that sufficiently characterizes the risk associated with the requested credit. TVA will provide the response to NRC question SPSB-A.1 1 by March 1, 2006.

NRC Requests EMEB-B.2 and EMEB-B.9 through EMEB-B-13 request detailed information concerning development of the acoustical analyses, BFN Steam Dryer loading definitions, Steam Dryer stress analyses, Steam Dryer modifications planned, plans for collecting and analyzing data during power ascension, and the bases for acceptability. The responses to these questions provided in the enclosure describe the work currently ongoing to ensure the integrity of the Steam Dryers at EPU conditions. In particular, the response to NRC Question EMEB-B.9 summarizes the work being performed, including work to develop the BFN-specific acoustical circuit analysis to define the Steam Dryer loading definition, and validation of that model via testing at the General Electric scale model test facility. Completion of this work is scheduled for June 2006; TVA will provide the detailed information requested in EMEB-B.2 and EMEB-B.9 through EMEB-B.13 following completion of that work. TVA expects to submit this information in July 2006. TVA will submit a status report of these efforts by March 31, 2006.

U.S. Nuclear Regulatory Commission Page 3 December 19, 2005 TVA is providing similar information regarding the Unit 1 EPU application in a separate submittal. There are no new regulatory commitments associated with this submittal. If you have any questions concerning this letter, please contact William D. Crouch, Browns Ferry Manager of Licensing and Industry Affairs, at (256) 729-2636.

I declare under penalty of perjury that the forgoing is true and correct.

Executed on this 19th day of December, 2005.

Sincerely, Brian O'Grady

References:

1. NRC letter, E. A. Brown to TVA, "Browns Ferry Nuclear Plant, Units 2 and 3

- Request for Additional Information for Extended power Uprate (TS-431)(TAC Nos. MC3743 and MC3744)," dated October 3, 2005.

2. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Units 2 and 3 - Proposed Technical Specifications (TS) Change TS - 418 -

Request for License Amendment Extended Power Uprate (EPU) Operation,"

dated June 25, 2004.

3. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Units 2, and 3 - Response to NRC's Acceptance Review Letter and Request for Additional Information Related to Technical Specifications (TS) Change No.

TS-418, Request for Extended Power Uprate Operation, (TAC Nos. MC3743 and MC3744)," dated February 23, 2005.

4. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Units 2, and 3 - Response to NRC's Request for Additional Information Related to Technical Specifications (TS) Change No. TS-418 - Request for Extended Power Uprate Operation (TAC Nos. MC3743 and MC3744)," dated April 25, 2005.

5. TVA letter, W. D. Crouch to NRC, "Browns Ferry Nuclear Plant (BFN) -

Units 2 and 3 - Response to NRC's Request for Additional Information Related to Technical Specifications (TS) Change No. TS - 418 - Request For License Amendment - Extended Power Uprate (EPU) Operation (TAC Nos. MC3743 and MC3744)," dated June 6, 2005.

U.S. Nuclear Regulatory Commission Page 4 December 19, 2005 Enclosure cc (Enclosure):

U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303-3415 Mr. Stephen J. Cahill, Branch Chief U.S. Nuclear Regulatory Commission Region II Sam Nunn Atlanta Federal Center 61 Forsyth Street, SW, Suite 23T85 Atlanta, Georgia 30303-8931 NRC Senior Resident Inspector Browns Ferry Nuclear Plant 10833 Shaw Road Athens, AL 35611-6970 Margaret Chernoff, Senior Project Manager U.S. Nuclear Regulatory Commission (MS 08G9)

One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852-2739 Eva A. Brown, Project Manager U.S. Nuclear Regulatory Commission (MS 08G9)

One White Flint, North 11555 Rockville Pike Rockville, Maryland 20852-2739

ENCLOSURE TENNESSEE VALLEY AUTHORITY BROWNS FERRY NUCLEAR PLANT UNITS 2 AND 3 DOCKET NOS. 50-260 AND 50-296 RESPONSE TO NRC ROUND 2 REQUEST FOR ADDITIONAL INFORMATION RELATED TO TECHNICAL SPECIFICATIONS (TS) CHANGE NO. TS - 418 -

REQUEST FOR EXTENDED POWER UPRATE OPERATION By letter dated June 25, 2004 (Reference 1), TVA submitted to the NRC license amendment applications requesting authorization for Extended Power Uprate (EPU) operation for Browns Ferry Nuclear Plant (BFN) Units 2 and 3. TVA supplemented those applications by letters dated February 23, 2005 (Reference 2), April 25, 2005 (Reference 3), and June 6, 2005 (Reference 4). By letter dated October 3, 2005 (Reference 5), the NRC Staff transmitted a request for additional information to support its review of the BFN Units 2 and 3 EPU applications. The responses to those questions are provided below, by NRC request number. References cited in the responses are listed at the end of this enclosure.

NRC Request EMCB-C.1 The FAC monitoring program includes the use of a predictive method to calculate the wall thinning of components susceptible to FAC. Provide a sample list of components for which wall thinning is predicted and measured by ultrasonic testing or other method.

Include the initial wall thickness (nominal), current (measured) wall thickness, and a comparison of the measured wall thickness to the thickness predicted by the CHECWORKSTm FAC model.

TVA Replv to EMCB-C.1 A sample list of components and measured versus predicted thickness for CHECWORKSTM modeled components at current thermal power operating conditions (prior to EPU) is provided in the table below. A total of 15 components for Units 2 and 3 were selected for this sample.

The data in the table is the measured thickness (Tmeas) and CHECWORKSTM predicted thickness (Tpred) at the time of last inspection. Predicted thickness was calculated by CHECWORKSTM using operating history and thermal conditions through Refuel Outage 13 for Unit 2 (NSS input to turbine cycle 3463 MWt) and Refuel Outage 11 for Unit 3 (NSS input to turbine cycle 3463 MWt). Also shown in the table is the nominal thickness (Tnom) taken from standard pipe dimension tables. By design, piping is manufactured with a tolerance of +/- 12.5% of Tnom so initial thickness is generally not the same as nominal thickness. Therefore, the table lists the estimated initial thickness E-1

(Tinit) determined by CHECWORKSTM in calculating wear (in CHECWORKSTM this value is termed Trep, for representative initial thickness).

The stated accuracy of the CHECWORKSTM predictive model is +/- 50% on predicted wear rate and +/- 20% on wall thickness (from section 6.3.1 of EPRI document 1009599, "CHECWORKSTM Steam/Feedwater Application Guidelines for Plant Modeling and Evaluation of Component Inspection Data"). The last column in the table lists the variance between Tpred and Tmeas (Tpred/Tmeas variance), where a positive value indicates that Tmeas is less than Tpred and a negative value indicates that Tmeas is greater than Tpred. Note that for nearly all components listed in the table (27 of 30) the variance between Tpred and Tmeas is within the stated accuracy of the CHECWORKSTM predictive model (+/- 20% on wall thickness). The three components outside the accuracy of the CHECWORKSTM predictive model are due to an initial thickness greater than +/- 12.5%

of Tnom tolerance (2CON1 1A-4E Tnom=0.438" and Tinit=0.630"; 3CON1 1B-1 3E Tnom=0.438" and Tinit=0.630; 3HDV4A4-5E Tnom=0.375" and Tinit=0.445").

Table EMCB-C.1-1 Predicted Versus Measured Wall Thickness at Current BFN Operating Conditions Tp,.j Tn.om Tift Ts Tped Tm.

Unit Item System Component (in.) (In.) (in.) (in.) Variance 2 1 Heater Drains: 3FWH to 4FWH 2HDV6A3-4E 0.365 0.444 0.385 0.330 -14%

2 2 Heater Drains: 3FWH to 4FWH 2HDV6B3-5P 0.365 0.437 0.359 0.338 -6%

2 3 Heater Drains: 3FWH to 4FWH 2HDV6C3-8E 0.365 0.412 0.350 0.330 -6%

2 4 Condensate: 4FWH to 3FWH 2CON11 A-3P 0.438 0.480 0.399 0.409 3%

2 5 Condensate: 4FWH to 3FWH 2CON11A-4E 0.438 0.630 0.535 0.374 -30%

2 6 Condensate: 4FWH to 3FWH 2CON11 A-5P 0.438 0.501 0.413 0.390 -6%

2 7 Heater Drains: 4FWH to Flash Tank 2HDV9A4-2EX 0.375 0.422 0.363 0.309 -15%

2 8 Heater Drains: 4FWH to Flash Tank 2HDV8B4-15E 0.375 0.550 0.313 0.294 -6%

2 9 Heater Drains: 4FWH to Flash Tank 2HDV9C4-6P 0.375 0.468 0.349 0.345 -1%

2 10 Feedwater: 2FWH to 1FWH 2RFW4A2-2P 1.031 1.092 0.995 0.993 0%

2 11 Feedwater: 2FWH to 1FWH 2RFW4B2-5P 1.031 1.090 1.004 0.945 -6%

2 12 Feedwater: 2FWH to 1FWH 2RFW4C2-8P 1.031 1.097 1.011 0.941 -7%

2 13 Heater Drains: 1FWH to 2FWH 2HDV2A1 -5P 0.322 0.348 0.314 0.288 -8%

2 14 Heater Drains: 1FWH to 2FWH 2HDV2B1 -3P 0.322 0.363 0.312 0.340 9%

2 15 Heater Drains: 1FWH to 2FWH 2HDV2C1-3P 0.322 0.361 0.314 0.273 -13%

3 1 Heater Drains: 3FWH to 4FWH 3HDV3A3-3P 0.365 0.420 0.369 0.332 -10%

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Table EMCB-C.1-1 Predicted Versus Measured Wall Thickness at Current BFN Operating Conditions Tpred Tnom Timi Tme.s Torgd TmeaS Unit Item System Component (in.) (in.) (in.) (in.) Variance 3 2 Heater Drains: 3FWH to 4FWH 3HDV3A3-4E 0.365 0.384 0.330 0.280 -15%

3 3 Heater Drains: 3FWH to 4FWH 3HDV3B3-8E 0.365 0.392 0.343 0.326 -5%

3 4 Condensate: 4FWH to 3FWH 3CON1 1 B-7P 0.438 0.473 0.423 0.356 -16%

3 5 Condensate: 4FWH to 3FWH 3CON11 B-13E 0.438 0.630 0.551 0.361 -34%

3 6 Condensate: 4FWH to 3FWH 3CON1 1 C-3P 0.438 0.444 0.390 0.365 -6%

3 7 Heater Drains: 4FWH to Flash Tank 3HDV4A4-5E 0.375 0.445 0.378 0.298 -21%

3 8 Heater Drains: 4FWH to Flash Tank 3HDV4A4-1 1 E 0.375 0.444 0.352 0.333 -5%

3 9 Heater Drains: 4FWH to Flash Tank 3HDV4B4-9E 0.375 0.439 0.366 0.311 -15%

3 10 Feedwater: 2FWH to 1FWH 3RFW2A2-2P 1.031 1.106 0.981 0.900 -8%

3 11 Feedwater: 2FWH to 1 FWH 3RFW2B2-5P 1.031 1.085 0.907 0.906 0%

3 12 Feedwater: 2FWH to 1FWH 3RFW2C2-8P 1.031 1.078 0.936 0.894 -4%

3 13 Heater Drains: 1FWH to 2FWH 3HDV1A1-8P 0.322 0.378 0.317 0.288 -9%

3 14 Heater Drains: 1FWH to 2FWH 3HDV1B1-13N 0.500 0.568 0.424 0.441 4%

3 15 Heater Drains: 1FWH to 2FWH 3HDV1C1-2E 0.322 0.365 0.312 0.272 -13%

NRC Request EMCB-C.2 EPU will affect several process variables that influence FAC. Identify the systems that are expected to experience the greatest increase in wear as a result of EPU and discuss the effect of individual process variables (i.e., moisture content, temperature, oxygen, and flow velocity) on each system identified.

TVA Reply to EMCB-C.2 The EPU implementation at BFN will change a number of systems water and steam flow rates, temperatures, and enthalpies, in turn changing dissolved oxygen concentration. All these factors affect Flow Accelerated Corrosion (FAC) susceptibility status and FAC wear rates. As a result of the EPU operating conditions, some lines will experience accelerated rates of FAC, while others will have reduced rates. It is noted that no lines that were previously non-susceptible to FAC became susceptible due to post-EPU operating conditions.

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The relationship between each of these parameters and FAC is as follows:

Steam Quality (moisture content): Curve with maximum FAC at -50% and decreasing FAC away from peak.

Temperature: Curve with maximum FAC for single phase at -275 0 F (3000 F for two-phase) and decreasing FAC away from peak.

Flow Rate: FAC increases with increasing flow rate.

Dissolved Oxygen: FAC decreases with increasing dissolved oxygen.

The table below identifies the Unit 2 and 3 systems that are expected to experience the greatest increase in wear rate as a result of EPU operating conditions. The change in wear rate was determined based on percent change as opposed to magnitude of change. Those systems that have the greatest increase in CHECWORKSTM predictive wear rate would also have the greatest increase in CHECWORKSTM predicted wear.

For each unit, a comparison was performed between pre-EPU operating conditions at the current operating cycle and post-EPU operating conditions at the cycle EPU is anticipated. For Unit 2, the analysis is based on a comparison of pre-EPU CHECWORKSTM predictions at Cycle 14 (NSS input to turbine cycle 3463 MWt) and post-EPU CHECWORKSTM predictions at Cycle 15 (NSS input to turbine cycle 3964.4 MWt). For Unit 3, the analysis is based on a comparison of pre-EPU CHECWORKSTM predictions at Ftcle 12 (NSS input to turbine cycle 3463 MWt) and post-EPU CHECWORKS predictions at Cycle 14 (NSS input to turbine cycle 3964.4 MWt).

The top five systems from each unit are included and the entries are ordered in decreasing order of percent change. The BFN FAC Program has accounted for these changes by modeling the post-EPU operating conditions in the CHECWORKSTM predictive model thereby ensuring that the model correctly reflects pre-EPU and post-EPU operating conditions when generating wear rate and remaining life predictions. In addition, the BFN FAC Program has evaluated the effect post-EPU operating conditions will have on the remaining life of previously inspected components and has adjusted the planned scheduled inspections to account for changes in remaining life based on post-EPU conditions.

Table EMCB-C.2-1 Piping Segments at EPU Conditions With Greatest Predicted Increase in Wear Avg Wear Rate Unit Item System Change' Notes 2 1 Heater Drains: 19.4% This is due to an 11OF temperature increase towards the 3FWH to 4FWH FAC peak (to 2620 F) and a 20% increase in flow rate (to 4.1 Mlb/hr). The steam quality remained unchanged at 0%.

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Table EMCB-C.2-1 Piping Segments at EPU Conditions With Greatest Predicted Increase in Wear Avg Wear Rate Unit Item System Change 1 Notes 2 2 Condensate: 18.5% This is due to an 80F temperature increase towards the FAC 4FWH to 3FWH peak (to 249 0F) and a 16% increase in flow rate (to 16.4 Mlb/hr). The steam quality remained unchanged at 0%.

2 3 Heater Drains: 7.9% This is due to an 120 F temperature increase towards the 4FWH to Flash FAC peak (to 205 0F) and a 17% increase in flow rate (to 4.9 Tank Mlb/hr). The steam quality remained unchanged at 0%.

2 4 Feedwater: 6.6% This is due to a 16% increase in flow rate (to 16.4 Mlb/hr).

2FWH to 1FWH The steam quality remained unchanged at 0%. The temperature increased away from the FAC peak by 10F (to 3440F); however, this was overshadowed by the flow rate increase.

2 5 Heater Drains: 5.1% This is due to a 20% increase in flow rate (to 1.1 Mlb/hr).

1FWH to 2FWH The steam quality remained unchanged at 0%. The temperature increased away from the FAC peak by 130 F (to 3570F); however, this was overshadowed by the flow rate increase.

3 1 Heater Drains: 19.0% This is due to an 11 OF temperature increase towards the 3FWH to 4FWH FAC peak (to 2620F) and a 21% increase in flow rate (to 4.1 Mlb/hr). The steam quality remained unchanged at 0%.

3 2 Condensate: 17.8% This is due to a 70F temperature increase towards the FAC 4FWH to 3FWH peak (to 2490F) and a 16% increase in flow rate (to 16.4 Mlb/hr). The steam quality remained unchanged at 0%.

3 3 Heater Drains: 10.1% This is due to an 11°F temperature increase towards the 4FWH to Flash FAC peak (to 205 0F) and a 19% increase in flow rate (to 4.9 Tank Mlb/hr). The steam quality remained unchanged at 0%.

3 4 Feedwater: 7.0% This is due to a 16% increase in flow rate (to 16.4 Mlb/hr).

2FWH to 1FWH The steam quality remained unchanged at 0%. The temperature increased away from the FAC peak by 10°F (to 344 0F); however, this was overshadowed by the flow rate increase.

3 5 Heater Drains: 4.5% This is due to a 20% increase in flow rate (to 1.1 Mlb/hr).

1FWH to 2FWH The steam quality remained unchanged at 0%. The temperature increased away from the FAC peak by 13°F (to 357°F); however, this was overshadowed by the flow rate increase.

1. These predicted wear rates are based on BFN Units 2 and 3 FAC program predictions from current power levels (105% of Original Licensed Thermal Power [OLTP]) to EPU conditions (120% of OLTP).

NRC Request EMCB-C.3 TVA's (the licensee's) February 23, 2005, response states:

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Previous testing was performed which bounded peak accident conditions for all but one specific coating configuration. Therefore, TVA is performing confirmatory testing to ensure that all qualified coating configurations have been tested.

In regards to this statement provide a discussion explaining what the specific coating configuration is, how large the affected area is, what specific testing was performed, the results of the confirmatory testing, and how the confirmatory testing is correlated to the coating's original design basis accident qualification.

TVA Reply to EMCB-C.3 The specific coating configuration referred to in the February 23, 2005, response was the feather edge overlap of Ameron 400NT over existing coating. This configuration had not been used in the BFN Units 2 and 3 containments. Results of the qualification testing performed indicated that this configuration was not qualified for use at BFN.

Therefore, this configuration will not be used in the BFN Units 2 and 3 containments.

NRC Request EEIB-B.1 Address and discuss the following points:

NRC Request EEIB-B.1.a Identify the nature and quantity of Mega volt-amp reactive (MVAR) support necessary to maintain post-trip loads and minimum voltage levels.

TVA Reply to EEIB-B.1.a The Browns Ferry Extended Power Uprate Grid Adequacy and Stability Study credits a capability of + 200/-150 MVAR per generator for Units 2 and 3 and a capability of +360/-

150 MVAR for Unit 1 as the basis for analyzing the adequacy of the BFN to grid interface. This data was provided to TVA's Transmission Planning organization along with plant post-trip load data and voltage acceptance criteria so that the proper stability and loadflow/voltage studies could be run as part of the Browns Ferry Extended Power Uprate Grid Adequacy and Stability Study. This study establishes that grid voltages (both pre- and post-unit trip) satisfy the acceptable voltage ranges for the 500 kV system.

NRC Request EEIB-B.1.b Identify what MVAR contributions the BFN Units are credited for providing to the grid.

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TVA Reply to EEIB-B.1.b Both units' manufacturer's reactive capability curves along with uprated MW ratings were provided to TVA's Transmission Planning Organization so that the units can be properly modeled for use in their planning and stability studies. This study credits a post-event contribution from BFNP generators of + 300/-150 MVAR per unit generator for pre-uprate and +200/-150 MVAR for post-uprate on Units 2 and 3.

NRC Request EEIB-B.1.c After the power uprate, identify any changes in MVAR associated with Items a and b above.

TVA Reply to EEIB-B.1.c As discussed in the response to EEIB-B.1.a and EEIB-B.1.b above, for post-event capability the transmission study credits a contribution from BFN generators of + 300/-

150 MVAR per unit generator for pre-uprate and +200/-150 MVAR for post-uprate on Units 2 and 3.

NRC Request EEIB-B.1.d Address the compensatory measures that the licensee would take to compensate for the depletion of the nuclear unit MVAR capability on a grid-wide basis.

TVA Reply to EEIB-B.1.d TVA's Transmission Planning Organization has determined that no compensatory measures are required.

NRC Request EEIB-B.1.e Evaluate the impact of any MVAR shortfall listed in Item d above on the ability of the offsite power system to maintain minimum post-trip voltage levels and to supply power to safety buses during peak electrical demand periods. The subject evaluation should document information exchanges with the transmission system operator.

TVA Reply to EEIB-B.1.e No MVAR shortfall has been identified.

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NRC Reauest EEIB-B.2 Page 6-1 of Enclosure 4 of the June 25, 2004, submittal states that the study documented that no additional changes are required for BFN's offsite power system to continue to meet Title 10 the Code of Federal Regulations (10 CFR) Part 50, Appendix A, General Design Criteria (GDC)-1 7 requirements. Because the BFN construction permits were issued prior to the May 21, 1971, effective date of the GDC, compliance to these criteria may not be required as part of the BFN Units 2 and 3 licensing basis.

State whether BFN Units 2 and 3 is consistent with GDC-1 7 or the Atomic Energy Commission Criterion 39.

TVA Replv to EEIB-B.2 BFN conforms to the offsite power requirements of GDC 17.

NRC Request EEIB-B.3 The submittal states that transmission system operating guides will be issued to the load dispatcher prior to EPU operation, detailing any system operating constraints and any actions that may be required, including prompt communication with the control room. What protocol has been established with the transmission system operator to communicate to the licensee the availability of the transmission lines to provide sufficient voltage following a plant trip or when voltages would not be adequate?

TVA Reply to EEIB-B.3 TVA owns both the transmission system and BFN. Communication protocol between the Transmission Operator and BFNP regarding offsite power availability is established through TVA Intergroup Agreement 6. Should the transmission system not provide sufficient voltage, notification is provided to BFN Operations so that appropriate action can be taken.

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NRC Request EEIB-B.4 Provide in detail and compare the existing ratings with the uprated ratings and the effect of the power uprate on the following equipment:

a. Main generator rating and power factor

b. Isophase bus, and modifications to the cooling system

c. Detailed description of the replaced main power transformers

d. Unit Auxiliary/Start-up transformers

e. Main Generator breaker TVA Reply to EEIB-B.4

a. Main Generator A comparison of the current versus the uprated generator ratings and power factors are provided below.

Table EEIB-B.4-1 BFN Units 2 and 3 Generator Ratings Parameter Current Uprated Generator Output (MWe) 1156 1265 Rated Voltage (kV) 22 22 Power Factor, 0.93 0.98 Generator Output (MVA) 1280 1280

b. Isonhase Bus & Coolina The Isophase Bus at BFN operates at 22kV. The bus is divided into several sections with ratings appropriate for each section depending on the location and use of each section. The isophase bus has been analyzed for operation at the new ratings. These sections are identified below with the pre-uprate and post-uprate ratings:

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Table EEIB-B.4-2 Isophase Bus Ratings Original New design No. Item Design (Amps) Specification (Amps) 1 Main Bus 35270 36740 2 Generator Bus 17635 18370 3 Delta Bus 20365 21212

c. Main Bank Transformers The main bank transformers at BFN are being replaced due to obsolescence issues. The Unit 1, Unit 2, and Unit 1/2 spare transformers are in place and operating at this time. The current schedule is for the Unit 3 transformers to be replaced in 2010 along with the installation of a dedicated spare Unit 3 transformer.

Table EEIB-B.4-3 Main Bank Transformers Transformer Old rating (650C) New rating (650C)

Unit 2 3 X 448 MVA FOA 3 X 500 MVA OFAF Unit 3 3 X 448 MVA FOA 3 X 500 MVA OFAF

d. Unit Auxiliarv/Start-uD Transformers The Unit Station Service Transformers (Unit Auxiliaries) and Common Station Service Transformers (Start-Up) are rated as follows:

Table EEIB-B.4-4 Unit Auxiliary/Start-up Transformers Transformer Old Rating New Rating USST 2A 24/32/40 MVA OA/FA/FOA No Change USST 2B 24/32 MVA OA/FA No Change USST 3A 24/32/40 MVA OA/FA/FOA No Change USST 3B 24/32 MVA OA/FA No Change CSST A 21.9/29.2/36.5 MVA OA/FA/FOA No Change CSST B 21.9/29.2/36.5 MVA OA/FA/FOA No Change E-10

e. Main Generator Breakers The main generator circuit breaker ratings are as follows:

Table EEIB-B.4-5 Main Generator Breakers Gen.

Breaker Old Rating New Rating Unit 2 Brown Boveri Type: DR36V1750D No Change Rated Max Voltage: 24 kV Rated Continuous Current: 36 kA Rated S.C. Current: 200 kA Rated Voltage Range: 1 Impulse Withstand V: 150 kV Rated Frequency: 60 Hz Interrupting Time: 5 Cycles Unit 3 Brown Boveri Type: DR36V1750D No Change Rated Max Voltage: 24 kV Rated Continuous Current: 36 kA Rated S.C. Current: 200 kA Rated Voltage Range: 1 Impulse Withstand V: 150 kV Rated Frequency: 60 Hz Interrupting Time: 5 Cycles NRC Request EEIB-B.5 Provide the list of loads affected by the power uprate change. Identify the motor loads before and after the power uprate change.

TVA Reply to EEIB-B.5 The table below identifies the major load changes due to power uprate. These changes are limited to increased power requirements to the reactor recirculation pump, the condensate pumps and the condensate booster pumps. There are other minimal load changes but all are within the motor nameplate ratings.

Table EEIB-B.5-1 Major Changes In Browns Ferry Units 2 and 3 Onsite AC Distribution System Loads Power Uprate System/Component Pre-Uprate Condition Requirements Remarks Reactor Recirculation 6650 HP @100% core flow @ 8657 HP @ 105% core flow Pumps 1105% OLTP 120% OLTP Note_1 E-1 1

Table EEIB-B.5-1 Major Changes In Browns Ferry Units 2 and 3 Onsite AC Distribution System Loads Power Uprate SystemlComponent Pre-Uprate Condition Requirements Remarks Condensate Pumps 900 HP 1250 HP Note 2 Condensate Booster 1750 HP 3000 HP Note 2 Pum ps _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

1. Power requirement per recirculation system pump in service.

2. Power requirement per pump with combination of three reactor feedwater pumps, three condensate booster pumps, and three condensate pumps.

NRC Request EEIB-B.6 Provide the coping duration and recovery time expected from a station blackout (10 CFR 50.63).

TVA Reply to EEIB-B.6 BFN compliance to the SBO rule (10 CFR 50.63) was established in a series of docketed communications with the NRC. The NRC issued a safety evaluation report by letter dated July 11, 1991, since supplemented by letter dated September 16, 1992.

BFN Units 2, and 3 are categorized as four-hour duration plants using the methodology of NUMARC 87-00. Coping strategy is to shutdown the blacked-out unit with equipment powered from the 250-V DC battery system. Alternate AC power from diesel generators in the non-blacked-out units will be made available to power additional required HVAC and common loads. As set forth in NUMARC 87-00, Appendix B, the Alternate AC will be available within one hour through existing cross-ties. For EPU conditions, the assumptions and inputs for these assessments were evaluated and determined to have no impact on the coping duration category or alternate AC power availability for BFN.

NRC Request EEIB-B.7 Page 6-2 of Enclosure 4 of the June 25, 2004, submittal and Page 6-2 of Enclosure 5 of the June 25, 2004, submittal state that Units 1 and 2 share four independent safety-related diesel generator units coupled as an alternate source of power, to four independent 4160 volt buses. Have the design and operation changed since Unit 1 was shutdown in 1985? Describe the onsite alternating current power system for Units 2 and 3.

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TVA Replv to EEIB-B.7 Although BFN has implemented some design changes associated with the onsite electrical system, these modifications have not resulted in changes to the fundamental attributes and distribution system associated with the configuration of the offsite AC and Diesel Generator (DG) supply to the respective 4.16kV shutdown boards, 480V shutdown boards, 480V Reactor Motor Operated Valve (MOV) boards, and associated transformers since 1985. This configuration is further described in UFSAR Chapter 8.

Browns Ferry is a three unit plant, with each unit being a General Electrical Boiling Water Reactor (BWR) 4 with a Mark I containment. As shown in UFSAR Figure 8.4-1 b, the standby AC supply and distribution system for Units 1/2 consists of four diesel generators (DGs), four 4.16kV shutdown boards, two shutdown buses, four 480V shutdown boards, and eight 480-V Reactor Motor Operated Valve (RMOV) boards. The standby AC supply and distribution system for Unit 3 (UFSAR Figure 8.4-2) consists of four DGs, four 4.16kV shutdown boards, two shutdown buses, two 480-V shutdown boards, and five 480V RMOV boards. Both of these standby AC supply and distribution systems supply power to unitized Units 1/2 and Unit 3 electrical loads. The standby AC supply and distribution system for Units 1/2 and Unit 3 is divided into redundant divisions, so that loss of any one division does not prevent the minimum safety-related functions from being performed by the remaining division.

NRC Request EMCB-A.1 Section 10.7, Plant Life, in Enclosure 4 of the June 25, 2004, submittal, identifies irradiation-assisted stress-corrosion cracking (IASCC) as a degradation mechanism influenced by increases in neutron fluence and reactor coolant flow. This section indicates that the current inspection strategy for reactor internal components is expected to be adequate to manage any potential effects of EPU operating conditions.

Note 1 in Matrix 1 of Section 2.1 of RS-001, Revision 0 indicates that guidance on the neutron irradiation-related threshold for IASCC in boiling-water reactors (BWRs) is in Boiling-Water Reactor Vessel and Internals Program (BWRVIP) report BWRVIP-26.

The "Final License Renewal SER [Safety Evaluation Report] for BWRVIP-26," dated December 7, 2000, states that the threshold fluence level for IASCC is 5 x 1020 n/cm 2 (E > 1 MeV).

Identify the vessel internal components whose fluence, at the end of period of operation with the EPU operating conditions will exceed the threshold level and become susceptible to cracking due to IASCC. For each vessel internals component that exceeds the IASCC threshold, either provide an analysis that demonstrates failure of the component will not result in the loss of the intended function of the reactor internals or identify the inspection program to be utilized to manage IASCC of the component.

Identify the scope, sample size, inspection method, frequency of examination and acceptance criteria for the inspection programs.

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TVA ReDIv to EMCB-A.1 TVA has a procedurally controlled program for the augmented nondestructive examination (NDE) of selected reactor pressure vessel (RPV) internal components in order to ensure their continued structural integrity. The inspection techniques utilized are primarily for the detection and characterization of service-induced, surface-connected planar discontinuities, such as IASCC in welds and in the adjacent base material. TVA is a participant to the BWRVIP organization and implementation of the procedurally controlled program is consistent with the BWRVIP issued documents. The inspection strategies recommended by the BWRVIP consider the effects of fluence on applicable components and are based on component configuration and field experience.

Fluence calculations were performed in accordance with Regulatory Guide 1.190, March, 2001, to support the BFN Units 1, 2, and 3 license renewal applications (Reference 6). These calculations were performed for the extended period of operation (60 years), and assumed operation of each BFN unit at EPU conditions. Based on these calculations, four reactor components exceeded the threshold of 5 x 1020 n/cm2 (E > 1 MeV), and were determined to be susceptible during the extended period of operation to IASCC. These components will be inspected and managed in accordance with the recommendations developed by the corresponding BWRVIP program. These components and BWRVIP Programs are identified in the table below.

Table EMCB-A.1-1 Components Susceptible to IASCC Inspection & Evaluation Period of Component Program Operation Top Guide BWRVIP-26 60 Years Shroud BWRVIP-76 60 Years Core Plate BWRVIP-25 & 6 er Core Plate BFN Chemistry Control Program 60 Years Incore Instrumentation Dry Tubes and Guide Tubes BWRVIP-47 60 Years In the BFN plant license renewal application, the core plate was determined to be a "plant-specific" Time Limited Aging Analysis (TLAA) that will be managed in accordance with the Boiling Water Reactor Vessel and Internals Project, and the BFN Chemistry Control Program. The BFN core shrouds are classified as "Category C" based on the core shroud classification criteria contained in Appendix B of the BWRVIP-76. The BFN BWR Vessel Internals Aging Management Program requires inspection of core shroud welds in accordance with "Category C" core shroud inspection requirements contained in BWRVIP-76.

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NRC Request EMEB-B.1 Discuss TVA's plans to implement Inservice Testing (IST) Programs that incorporate appropriate changes in light of applicable EPU operating conditions. In particular, discuss, with examples, the evaluation of the impact of EPU conditions on the performance of safety-related pumps, power-operated valves, check valves, and safety or relief valves, including consideration of changes in ambient conditions and power supplies (as applicable), and to indicate any resulting adjustments to the IST Programs resulting from that evaluation.

TVA Reply to EMEB-B.1 The ASME Inservice Test (IST) Program at BFN is common for all three units. All three units are on a concurrent Ten-Year Interval (the Third IST Ten-Year Interval) which began on September 1, 2002. The Code of Record is the 1995 Edition through 1996 Addenda of the ASME Code for Operation and Maintenance of Nuclear Power Plants (OM Code).

The purpose of the ASME [ST Program is to perform testing to assess the operational readiness of certain pumps and valves used in nuclear power plants. The OM Code specifies requirements for performing these tests based upon the design and safety-related functions of these components. These requirements are to trend pump and valve performance after establishing reference values when the components are known to be operating acceptably. When components performance varies from these reference values, the ASME IST program requires evaluation to determine the cause and to effect corrective actions.

Evaluation of the effect of changes in plant conditions on the performance of components in the ASME IST Program is performed as part of the design change process. The ASME IST Program takes the changes in plant conditions, establishes tests based on those conditions, and trends the test results in order to detect degrading performance.

Specific changes in pressure and temperature were previously incorporated in the ASME IST Program during the 1998 5 Percent Power Uprate for Units 2 and 3. The scope of the BFN ASME IST Program will not be affected by EPU changes for Units 2 and 3. There are no new components added or existing components deleted within the boundaries of the existing ASME IST Program. Also, no changes to any test periodicities are needed. Therefore, no changes are anticipated in the ASME IST Program as a result of EPU for Units 2 and 3.

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NRC Request EMEB-B.2 In Section 3.3.5, Flow Induced Vibration, of Enclosure 4 of the submittal dated June 25, 2004, states that a detailed evaluation will be performed to examine steam dryer components susceptible to failure under EPU conditions. The report indicates that any necessary modifications will be made prior to EPU operation. The report concludes that flow induced vibration effects are expected to remain within acceptable limits for EPU operation. Provide the basis for this conclusion.

TVA Reply to EMEB-B.2 See the reply to EMEB-B.9 for a discussion of the EPU Steam Dryer Program for BFN.

As discussed in the reply to EMEB-B.9, the EPU Steam Dryer Program for BFN includes testing, analyses, and monitoring that will ensure that necessary modifications will be made to provide adequate structural margin for flow induced vibration and acoustical loads for EPU conditions.

NRC Request EMEB-B.3 Section 3.7, Main Steam Isolation Valves, of Enclosure 4 of the June 25, 2004, submittal states that the 24-percent increase in steam-flow rate will result in a slightly faster closure time for the main steam isolation valves (MSIVs). Describe the basis for the assumption that stroke time will remain with prescribed limits using design, test, and operational experience of the MSIVs.

TVA Reply to EMEB-B.3 The BFN MSIVs have design and testing features to ensure the MSIV closure time is not reduced below the lower stroke time limit during operation. The valve is required by BFN Technical Specifications to have a closing speed of 3 to 5 seconds. Valve closing time is controlled by a valve actuator hydraulic cylinder and damper piston with flow control valves installed in the external piping around the hydraulic cylinder. When closing the valve, the oil in the underside of the piston in the hydraulic cylinder must be displaced through the external piping to the top side of the piston. The rate at which this oil displacement takes place is controlled by the adjustment of the flow control valves which, in turn, control the rate of valve closure.

The BFN MSIV is a wye pattern type valve and upon actuation to close, the valve disk proceeds into the steam flow path with the main steam line flow being over the valve disk. The hydraulic damper piston attached to the valve stem senses a combined driving force which includes the steam drag force. An increased steam line flow would therefore slightly increase the drag force applied on the main disk during closure. The hydraulic damper piston modulates the disk motion. The hydraulic resistance force is proportional to the traveling velocity of the damper piston. The increase in closing force E-16

and valve speed due to EPU conditions would be partially offset by an increase in the hydraulic resistance. Therefore, the net change (reduction) to the valve closing time due to EPU conditions is negligible.

To ensure the MSIV stroke time requirements of the Technical Specifications are met, BFN Units 2 and 3 surveillance procedures require an MSIV fast closure test on a refueling outage frequency. This procedure is performed under a zero steam flow condition. However, it is recognized that the MSIVs should close slightly faster during reactor operation due to the mechanical configuration of the valves since the forces that are developed on the valve poppet from steam flow assist in valve closure. In order to provide margin to the low stroke time limit, the required closure time is designated to be 4 to 5 seconds. This margin ensures that small variations in the effect of steam flow will not cause the MSIVs to exceed the 3 second minimum closure time limit.

NRC Request EMEB-B.4 Section 4.1.3, Containment Isolation, of Enclosure 4 of the June 25, 2004, submittal states that parameters for air-operated valves (AOVs) and solenoid-operated valves (SOVs) were reviewed, and no changes to the functional requirements of any AOVs or SOVs were identified as a result of EPU operating conditions. Discuss, with examples, the evaluation of safety-related AOVs and SOVs used for containment isolation and other safety functions for potential impact from EPU operation.

TVA Replv to EMEB-B.4 The Units 2 and 3 AOV and SOV primary containment isolation valves have been evaluated for the effects of EPU. This evaluation examined the valve pressures and temperatures at EPU conditions and concluded:

• Performance is equivalent to or bounded by the design inputs, analytical scenarios and methodologies of the existing analyses; and

• Existing design pressures and temperatures are adequate.

Evaluation of the Units 2 and 3 AOV and SOV containment isolation valve capability included consideration of valve functional characteristics and potential changes to operating requirements. Valve capability was confirmed by reviewing and comparing calculated EPU pressures/temperatures to the existing valve design bases. The Units 2 and 3 EPU Containment and Reactor Coolant System pressures and temperatures are bounded by the current Units 2 and 3 design bases (uprated to 105% of the original licensed thermal power, with an associated 30 psig increase in reactor pressure). Flow remained unchanged with the exception of the MSIVs, which experience a 20%

increase in steam flow. See Section 3.7 of Enclosure 4 of the initial application E-17

(Reference 1) and the response to EMEB-B.3 for further discussion concerning the MSIVs. The table below provides examples of the evaluation performed.

Table EMEB-B.4-1 Examples of Primary Containment AOV/SOV Evaluations Accident Accident temperature pressure Valve (OF) (psig) Valve Valve ID Description CurrentlEPU CurrentIEPU Type Evaluation FCV-77-2A Drywell Floor 335.9/335.4 50.6/48.5 Air This valve is in a system Drain Sump Operated that may interface with Discharge Gate containment atmosphere.

Valve Design pressure rating is 100 psig.

FSV-84-49 Control Air Supply 335.9/335.4 50.6/48.5 Solenoid This valve is in a system Operated that may interface with Globe containment atmosphere.

Valve Design pressure rating is 100 psig.

NRC Request EMEB-B.5 Section 4.1.4, Generic Letter (GL) 89-10 Program, of Enclosure 4 of the June 25, 2004, submittal states that process and ambient parameters for motor-operated valves (MOVs) were reviewed, and no changes to the functional requirements of GL 89-10 MOVs were identified as a result of EPU operating conditions. In support of the EPU review, discuss with examples its evaluation of safety-related MOVs for the potential impact from EPU operation, including the impact of increased process flows on operating requirements and increased ambient temperature on motor output.

TVA Reply to EMEB-B.5 The BFN MOV Program is established and implemented in administrative procedures.

Evaluation of each MOV in the GL 89-10 program is documented in a controlled calculation. Operation at EPU can affect MOV capability due to changes in the following process conditions:

• Line pressure

• Differential pressure

• Fluid flow

• Fluid temperatures

• Normal environmental temperature Accident environmental temperature E-18

Each MOV in the BFN GL 89-10 program has been screened for impact based on changes that will result from operation at EPU conditions. Examples of how these process changes affect the GL 89-10 MOVs are shown below.

Table EMEB-B.5-1 Examples of BFN Units 2 and 3 Safety-Related MOV Evaluations Current Valve Valve description Safety function Parameter Affected Value EPU Value Line Pressure 102 lbs 102 psig RBCCW Primary Differential Pressure 102 lbs 102 psid 2-FCV-70-47 Containment Outlet Close Accident Temperature 1320 F 1370 F Valve Required thrust 6,568 lbs 6,568 lbs Operator Capability 27,149 lbs 27,037 lbs Margin 313% 312%

RHR Shutdown Line Pressure 133 psig 133 psig Cooing Supply Differential Pressure 133 psid 133 psid 3-FCV-74-47 Outboard Close Accident Temperature 28,131 bs 28131 bs Isolation Valve Operator Capability 47,393 lbs 47,393 Margin 68% 68%

Line Pressure 495 psig 495 psig RHR System Loop I Differential Pressure 495 psid 495 psid 3-FCV-74-53 Inboard Injection Open Accident Temperature 1650 F 1750 F 3-C-4-3Ibard Ineto pn Required thrust 181,241 lbs 181,241 lbs Operator Capability 244,148 lbs 243,853 lbs Margin 34.7% 34.5%

Line Pressure 405 psig 405 psig Differential Pressure 375 psid 375 psid Test Return Line Accident Temperature 140'F 1500 F 2-FCV-75-50 Isolation Close Required thrust 32,380 lbs 32,380 lbs Operator Capability 56,386 lbs 56,001 lbs Margin 74% 73%

The only change for some of these valves was for the accident environmental temperature for EPU. Similar evaluations were prepared for all of the. GL 89-10 MOVs.

For each MOV where the accident environmental temperature changed, a need to revise the "Operator Requirements and Capabilities" calculation was determined. If the temperature change resulted in a decrease in the MOV margin, the calculation for that MOV was identified to be revised. A total of 23 calculations were identified to be revised. None of the margin decreases resulted in any hardware modifications.

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NRC Request EMEB-B.6 Section 4.1.6, GL 95-07, of Enclosure 4 of the June 25, 2004, submittal states that MOVs used for containment or high energy line break isolation have been reviewed for the effects of operations at EPU conditions, including pressure locking and thermal binding. Discuss, with examples, the evaluation of safety-related power-operated gate valves in light of any changes in ambient temperature on the potential for pressure locking or thermal binding resulting from EPU operation.

TVA Reply to EMEB-B.6 Evaluation of MOV susceptibility to thermal binding/pressure locking (GL 95-07) is included in the evaluation of each MOV. Valve susceptibility was identified in a system review of all safety related systems and then on a component level. Valves that are currently not susceptible to thermal binding/pressure locking will not become susceptible under EPU conditions based on valve design. The valve evaluation guidance for thermal binding/pressure locking is based on valve hardware characteristics, system and environmental characteristics. The hardware characteristics for the valves previously evaluated do not change for EPU. The following example demonstrates the impact of EPU on a valve that was modified for GL 95-07.

Two of the valves that were previously identified as being subject to binding/locking are the LPCI injection valves FCV-74-53(67). These valves are a flex wedge design and are normally closed during operation. The reactor side is exposed to high pressure/temperature conditions while the reactor is in operation. This may cause potential pressure locking when the valve has to open in order to accomplish its safety function. Therefore, the reactor side disc face of this valve was modified by drilling a /4" hole in the disc face into the cavity between the disc faces to avoid pressure locking.

This valve is not subject to thermal binding. The ambient temperature for these valves increases from 1650 F to 1750 F for EPU. The design conditions for these valves are not changed for EPU. The slight increase in the accident ambient temperature will have a small impact on valve capability of these valves to perform their safety functions.

Similar evaluations were performed for each valve and any margin decrease was determined and evaluated.

NRC Request EMEB-B.7 Section 10.4.3, Main Steam Line, Feedwater and Reactor Recirculation Piping Flow Induced Vibration Testing, of Enclosure 4 of the June 25, 2004, submittal discusses the plans for vibration monitoring during initial plant operation for the new EPU operating rnnnroirinno r)ii ioc, in mern rAntni the nrimtnA inne for nwrnirfinev nrhinrc firmAt fod

and locations, planned data evaluation, and decision criteria for reducing plant power level or initiating plant shutdown.

TVA Reply to EMEB-B.7 TVA has not yet developed detailed procedures for EPU vibration monitoring and evaluation. The following discussion provides a general response to the NRC request; a more detailed response will be provided in a future submittal as discussed in the cover letter accompanying this response.

However, when developed, these procedures will specify:

• Reactor power hold points and duration,

• Required inspections and plant walkdowns,

• Vibration data collection methods and locations,

• Data evaluation methods and procedure, and

• The decision criteria for reducing plant power level or initiating plant shutdown Specific Hold Points and Duration The testing procedures will specify hold points for EPU vibration testing at 5% power increments above the Current Licensed Thermal Power level through EPU. The duration of the hold points will be the time required to obtain the specified data, complete the required evaluations, and obtain restart organization approval.

Inspections and Plant Walkdowns Vibration inspection/walkdown testing will be performed in areas accessible during power operation and will be conducted utilizing plant inspection/walkdown procedures.

Vibration Data Collection Methods and Locations Piping inside containment will be monitored using remote sensors and piping outside containment will be monitored with remote sensors, cameras and/or hand-held instruments.

Monitoring locations for the piping inside containment will be based on time history analyses that apply loading similar to the loading due to steady-state vibration.

Monitoring locations will be selected where significant analytical responses occur relative to other locations and such that the general overall piping response will be reflected in the data. Monitoring locations for large bore Main Steam and Feedwater E-21

piping outside containment will be determined based on inspection/walkdowns performed during power operation.

Monitoring locations for small bore piping will be based on time history analyses as well as inspection/walkdowns that were completed to identify relative vibration susceptibility.

Planned Data Evaluation Evaluation of the vibration data at each hold point will be performed based on established acceptance criteria. The acceptance criteria will be in accordance with the ASME OM guideline for piping steady-state vibration monitoring and evaluation.

Decision Criteria for Reducing Plant Power Level or Initiating Plant Shutdown In the event that measured vibrations at a given power level exceed the acceptance criteria, the power level would be reduced to a level where vibration amplitudes were previously shown to be acceptable until further evaluation of the data could be completed.

It should be noted that although Unit 2/3 PUSAR Section 10.4.3 refers to vibration monitoring for RRS piping, BFN does not intend to perform vibration monitoring of the RRS piping for Units 2 and 3. The wording in the Unit 2/3 PUSAR was an inadvertent carryover from the Unit 1 PUSAR. For Units 2 and 3, the small recirculation flow increase due to EPU was evaluated and will have a negligible effect on the RRS system piping. Therefore, vibration monitoring during EPU startup is not warranted for Units 2 and 3.

NRC Request EMEB-B.8 In the submittal dated February 23, 2005, TVA lists modifications planned to support EPU operation on pages El -21 to 25. Discuss the modifications planned to safety-related pumps and valves, and the actions to provide assurance of their capability to perform the applicable safety functions under EPU conditions.

TVA Replv to EMEB-B.8 Since the February 23, 2005, submittal, TVA has supplemented its response regarding modifications and testing in our April 25, 2005, letter (Reference 3). In Reference 3, planned EPU modifications were addressed in accordance with NUREG-0800, Standard Review Plan (SRP), Section 14.2.1, Draft, Revision 0, "Generic Guidelines for Extended Power Uprate Testing Programs." Section lll.B of the Enclosure addressed the modifications planned for EPU and the actions to provide assurance of the capability of these components to perform the applicable safety functions under EPU conditions.

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NRC Request EMEB-B.9 In the submittal dated February 23, 2005, the licensee states on page E1-28 that acoustical circuit analyses have been developed to identify the contributions to flow-induced vibration effects from main steam line components, junctions, and connections.

Discuss the capability of such analyses to identify the excitation sources for flow-induced vibration effects in light of recent industry experience, and address the possible alternative methods to identify excitation sources.

TVA Reply to EMEB-B.9 Requests EMEB-B 2, 9, 10, 11, and 13 address the actions and plans regarding the BFN steam dryers under EPU conditions. The following discussion provides an overview of the actions planned to ensure that the BFN steam dryers will adequately perform under EPU conditions.

Initially, a steam dryer evaluation for EPU conditions was performed for BFN and the evaluation was provided as Enclosure 9 to the June 25, 2004 EPU license amendment submittal. The evaluation consisted of a stress analysis which utilized the GE generic dryer load definition for both static equivalent and response spectrum.

Since the time of the initial steam dryer evaluation, considerable developments have taken place with respect to analysis methodologies and the acquisition of additional plant operating data for dryer loads. BFN has been actively participating in the steam dryer evaluation efforts being conducted by Exelon, Vermont Yankee, and the BWROG.

These efforts have included the development of scale model testing, acoustical analysis, main steam line monitoring, and the design and replacement of the two Quad Cities steam dryers. The initial Quad Cities replacement steam dryer was fully instrumented in order to monitor steam dryer loads during power ascension up through EPU operation.

This information is being used to develop the additional actions that BFN will perform to complete the steam dryer evaluations for EPU conditions, determine necessary modifications, and establish monitoring plans for power ascension testing. The current plans for the EPU steam dryer program are delineated below:

• Perform inspection of steam dryer in accordance with BWRVIP-139,

• Collection of as-built configurations of the main steam lines and components,

• Development of a 3D CAD model of the steam dryer, reactor vessel, main steam lines and components,

• Development and testing of a BFN Scale Model Test (SMT) configuration (1/17 scale) utilizing the methodologies developed by GE to operate under the BFN EPU conditions, E-23

• Development of acoustical analyses utilizing GE methodologies and the SMT loading conditions to be utilized in the determination of EPU loading conditions.

This effort will include lessons learned based on the completion of the GE benchmarking effort for the Quad Cities measured loads,

• Development of acoustical analyses utilizing Continuum Dynamics Inc.

methodologies and the SMT loading conditions to be utilized in the determination of EPU loading conditions and monitoring of EPU loading conditions during power ascension,

• Performance of a stress analysis to demonstrate compliance of the steam dryer stresses against allowable limits,

• Determination of steam dryer design modifications based on the stress analysis to replace or structurally reinforce steam dryer components for the expected loads with adequate margins for reliable performance,

• Development of a power ascension monitoring plan to monitor main steam line and component vibration and pressure loads,

• Monitoring of plant conditions will be conducted per the guidance of GE SIL 644, supplements and revisions to determine steam dryer integrity, and

• Inspection of the steam dryer will be performed following successful completion of the first EPU operating cycle to assure that its structural condition is acceptable for continued operation.

TVA's approach is to utilize the GE Scale Model Test Facility (SMT) to develop BFN EPU operating conditions through the Reactor, Main Steam Lines (MSL) and MSL components, HPCI and RCIC piping. The GE SMT is being designed and constructed to replicate precisely the BFN Unit 1 configuration. To increase the SMT accuracy, BFN Unit 1 laser scans have been utilized for MSL inside Containment. System walk-down measurements and component design drawings have been employed for MSL configurations outside Containment. This information has been integrated into a 3D CAD Model, which enhanced the development of the SMT fabrication design.

Additionally, internal dimensions and details for piping wall thickness, and MSL components have been developed for Safety Relief/alves (SRNs), Main Steam Isolation Valves (MSIVs), Flow Elements, and Turbine Stop & Control Valves (TS &

CVs). The SMT replication will contain this increased level of detail in order to measure fluctuating pressure loads from potential MSL sources. SMT characterization tests are conducted to obtain data used to correlate the acoustic Finite Element Model of the BFN plant steam system.

GE has previously reported in Reference 7, the contributions to the test measured fluctuating acoustic loads from various sources from these above referenced MSL components from SMT investigations. GE's sensitivity tests in this referenced E-24

document demonstrated the frequency ranges of response attributed to these potential sources. This approach is applicable to the BFN configuration. Due to the highest acoustical loads being attributed to the high frequency contribution from the SR/V (ERVs, SVs, SR/V in QC terminology) additional 1/6 subscale testing has been conducted to further investigate the SR/V source contributions related to these different valves. BFN has a single SR/V design rather than an assortment of different designs.

Similar subscale tests will be conducted for BFN SRNs to compare frequency response with the SMT.

BFN's SMT will incorporate sensitivity tests focused on key parameters in order to determine bounding conditions for similarity between BFN Units 1, 2, 3. The BFN SMT will represent the most accurate and detailed replication performed to date for use in determining dryer load definition.

GE has subsequently provided an interim report, Reference 8, regarding the accuracy of the GE SMT methodology to reflect the frequency content of loading expected to act on the dryer. The overall SMT loadings have been found to be conservative when compared to measured dryer loads on the replacement dryer for QC 2. Further SMT facility changes were required to directly compare the QC 2 dryer measured data with a QC 2 SMT model and to demonstrate the benchmark qualification.

GE has performed the SMT facility modifications and additional testing and is now preparing the benchmark qualification report relative to QC 2. This benchmark will incorporate use of the SMT facility and the GE finite element acoustical analysis to predict EPU loads on the dryer.

In order to further investigate the BFN dryer loading, TVA will also be performing an acoustical circuit analysis utilizing the Continuum Dynamics (CDI) methodologies. SMT MSL pressure loadings will be obtained and dryer loads developed for comparison. The CDI methodology will also be utilized for EPU power ascension to validate the dryer loads under actual plant operation.

Both methodologies rely on benchmarking against the measured dryer loads from the replacement dryer installed at QC2.

With this approach, TVA is confident that appropriate BFN source contribution will be adequately included in the dryer load definition and expected dryer modifications.

During power ascension, vibration monitoring will be conducted to determine flow induced vibration effects from EPU increased flow. Data obtained will provide additional component response behavior during the EPU power ascension that can be used to further evaluate source contribution.

The current schedule is to complete scale model testing and development of the acoustic circuit model by June 2006.

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NRC Request EMEB-B.10 In the submittal dated February 23, 2005, the licensee states on page El -29 that TVA had performed a detailed peer review of the General Electric Steam Dryer load definition methodology and analysis, and that the peer review had provided TVA with assurance that all phases of the analysis were adequate. Describe the design-load definition for the steam dryers, and the basis for the adequacy of the load definition.

TVA Replv to EMEB-B.10 See the reply to EMEB-B.9 for a discussion of the EPU Steam Dryer Program for BFN.

At the time of the BFN submittal, industry data indicated that steam dryer loads could be correlated to individual plant steam line steam velocity and loading could be derived from historical data from a small number of BWRs. As discussed in the reply to EMEB-B.9, BFN has expanded the actions that are planned for the evaluation of BFN steam dryers. The EPU Steam Dryer Program for BFN will include testing, analyses, and monitoring that will ensure that necessary modifications will be made to provide adequate structural margin for flow induced vibration and acoustical loads for EPU conditions.

NRC Request EMEB-B.11 On page El -28 of the submittal dated February 23, 2005, the licensee states that the uncertainty in its steam dryer analysis will be reduced by the collection of plant-specific data during power ascension. On page El -32, the licensee states that benchmarking of the acoustic circuit analysis for determining plant-specific loads is in process against a scale model test facility. Provide the details of acoustic circuit methodology and analysis, including validation, results, and uncertainty range of the methodology and analysis. Also, discuss the modifications made to its acoustic circuit model based on lessons learned from recent industry operating experience.

TVA Reply to EMEB-B.1 1 See the reply to EMEB-B.9 for a discussion of the EPU Steam Dryer Program for BFN.

As discussed in the reply to EMEB-B.9, the EPU Steam Dryer Program for BFN will include testing, analyses, and monitoring that will ensure that necessary modifications will be made to provide adequate structural margin for flow induced vibration and acoustical loads for EPU conditions.

The current schedule is to complete scale model testing and development of the acoustic circuit model by June 2006. When completed, BFN will submit a summary of this effort that includes the details of the acoustic circuit methodology and analysis, including validation, results, and uncertainty range of the methodology and analysis.

E-26

NRC Request EMEB-B.12 On page El -30 of the submittal dated February 23, 2005, the licensee states that power ascension information will be collected at each of the EPU power ascension test plateaus and compared against the stresses in the design analysis of record. Discuss the specific process for collecting, evaluating, and incorporating plant data into the design stress analysis for the steam dryers during the planned EPU power ascension.

TVA Reply to EMEB-B.12 See the reply to EMEB-B.9 for a discussion of the EPU Steam Dryer Program for BFN.

As discussed in the reply to EMEB-B.9, the EPU Steam Dryer Program for BFN will include testing, analyses, and monitoring that will ensure that adequate structural margin for flow induced vibration and acoustical loads for EPU conditions.

The current schedule is to complete scale model testing and development of the acoustic circuit model by June 2006.

NRC Request EMEB-B.13 On page El -32 of the submittal dated February 23, 2005, the licensee lists proposed modifications to the steam dryers based on lessons learned from recent BWR dryer modifications. Provide detailed descriptions and diagrams of the proposed modifications to the steam dryers. Also, describe the stress analysis performed for the modified steam dryers, and the resulting changes in predicted stress in comparison to the licensee's acceptance criteria at significant locations on the steam dryers.

TVA Reply to EMEB-B.13 See the reply to EMEB-B.9 for a discussion of the EPU Steam Dryer Program for BFN.

As discussed in the reply to EMEB-B.9, the EPU Steam Dryer Program for BFN includes testing, analyses, and modeling to identify whether modifications are necessary to ensure adequate structural margin for flow induced vibration and acoustical loads at EPU conditions.

The current schedule is to complete scale model testing and development of the acoustic circuit model by June 2006. The requested details for any required modifications will be provided following completion of this effort.

NRC Request EMEB-B.14 On pages El -34 to 37 of the submittal dated February 23, 2005, the licensee discusses the potential impact of temperature changes from resulting from EPU operation mechanical equipment environmental qualification. The discussion focuses on the E-27

impact of temperature changes on non-metallic materials. Discuss the evaluation and potential impact of temperature changes on motor output of applicable safety-related MOVs resulting from EPU operation.

TVA Reply to EMEB-B.14 Each MOV in BFN's GL 89-10 program has a "Operator Requirements and Capabilities" calculation. These calculations determine the required thrust/torque that the MOV will need to perform its safety function and also calculate the motor output of the MOV.

The ambient temperature in some areas will increase due to EPU. This increase may impact the actuator thrust/torque output because some motors lose capability at elevated temperatures. An evaluation was performed for each GL 89-10 MOV to calculate the required thrust/torque and the actuator capability of the MOV using EPU conditions. Examples of the impact of the temperature change on MOV capability are provided in the table below.

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Table EMEB-B.14-1 Examples of Impact of Environmental Temperature on BFN Units 2 and 3 Safety-Related MOVs Thrust Output Ambient In the safety Safety temperature direction Valve Function action currentlEPU currentlEPU Notes 3-FCV-01-55 Main Steam close 140 0F/1400F 10,147 psi/ Since the ambient Drain Line 10,147 psi temperature for this valve did Isolation Valve not change the motor capability did not change.

3-FCV-23-46 RHRSW open 1650F/1750F 52,857 psi/ The actuator capability to Throttle Valve 52,196 psi open this valve decreased by to RHR B Heat about 1%. The new value Exchanger was compared to the required thrust and this comparison determined that the actuator still has ample margin for the valve to perform its safety function.

3-FCV-70-47 RBCCW close 1340 F/139.90F 10,793 psi/ The actuator capability to Primary 10,681 psi close this valve decreased Containment by about 1%. The new value Isolation Valve was compared to the required thrust and this comparison determined that the actuator still has ample margin for the valve to perform its safety function.

2-FCV-71-25 RCIC Lube Oil open 1900F/1900F 10,053 psi/ The motor on this actuator is Cooling Water 10,053 psi a DC motor and the actuator Supply Valve output for this particular MOV is not affected by the ambient temperature.

A similar evaluation was done for each MOV in the GL 89-10 program. The largest MOV margin decrease in the close direction was for valve 3-FCV-70-47. In the open direction, the largest margin decrease was for valve 3-FCV-23-46. There is ample margin for the valves to perform their safety function. All of the MOVs maintained positive margins and, accordingly, the impact of increased ambient temperature associated with operation at EPU conditions will not impact capability of the MOVs to perform their safety functions.

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NRC Request IPSB-A.1 Table 1 of the April 25, 2005, submittal provides a comparison of the proposed EPU testing program to the original startup testing described in Updated Final Safety Analyses Report (UFSAR) 13.5.2.3. Table 1, STP 10, describes the intermediate range monitor (IRM) Calibration/Performance test. During the initial test, the IRM-average power range monitor (APRM) overlap was checked and the IRM gains adjusted as necessary to improve the IRM system overlap between the source range monitors and IRMs. This adjustment was performed after the APRM heatup calibration and after the first heat balance calibration of the APRMs. Under the 'Testing Planned for EPU' column, Table 1 states that STP-1 0 is an EPU startup test. However, under the 'EPU Test Conditions' column, Table 1 states that STP-10 is not a startup test, but will be done during the first controlled shutdown following APRM calibration for EPU. Clarify whether IRM Calibration/Performance is a startup test and explain whether the test is proposed to be performed during the first controlled shutdown following APRM calibration versus after the APRM heatup calibration (per the initial test). Provide justification why changing when this test is performed is acceptable and meets the intent of the original test.

TVA Reply to IPSB-A.1 The STP 10 original startup testing adjusted the IRMs to obtain an optimum overlap with the SRMs and APRMs for initial unit startup. For initial unit startups, neutron instrument responses at various thermal power statepoints are relatively unknown and the APRMs have not been calibrated to actual power conditions. Therefore, the IRM system was set to maximum gain for conservatism and to assure overlap. Per current plant procedures, IRM/APRM overlap is verified by operator visual observation during power ascension before exceeding 5% power. The Table 1 note indicates that the overlap is included in plant procedures to be performed during shutdown from power operation to cold shutdown and reductions in power during power operations. This is when it is required by Technical Specifications and surveillance requirements.

NRC Request IPSB-A.2 Page E-3 of the April 25, 2005, submittal states that Table 2 demonstrates that the applicable tests in Attachments 1 and 2 (of NUREG -800, Standard Review Plan (SRP) for the Review of Safety Analysis Reports for Nuclear Power Plants LWR [Light-Water Reactor] Edition, Section 14.2.1) are addressed by the testing planned for BFN EPU implementation. However, Table 2 only provides a comparison of the steady state and transient tests from the initial BFN startup tests to those described in SRP 14.2.1.

Some of the initial tests referenced in Table 2 are not proposed to be performed for EPU implementation (e.g., STP-17, 25, and 27). Further clarification is needed to explain how Table 2 demonstrates that the applicable tests of SRP 14.2.1 are addressed by the proposed EPU testing.

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TVA Replv to IPSB-A.2 Table 2 is intended to be used in conjunction with Table 1 to demonstrate applicable tests of SRP 14.2.1 are addressed by the proposed EPU test program.

Evaluation/justification for those initial BFN startup tests referenced in Table 2 are provided in the notes of Table 1. Therefore, Tables 1 and 2 provide the comparative demonstration of the applicable generic tests of SRP Attachments 1 and 2.

NRC Request IPSB-A.3 Table 2 of the April 25, 2005, submittal lists three SRP 14.2.1 tests (shield and penetration cooling systems, engineered safety feature auxiliary and environmental systems, and calibrate systems used to determine reactor thermal power) which were not part of the BFN initial startup tests but are listed as a standard procedure. Clarify that these tests are performed whether or not an EPU is implemented, or only because of the EPU implementation.

TVA Reply to IPSB-A.3 The BFN design does not include shield and penetration cooling systems. Therefore the indication of testing as plant standard procedure does not apply.

The demonstration of adequate operational performance margins for auxiliary systems required to support the operation of engineered safety features is periodically confirmed during plant operation. The standard BFN refueling test program includes testing to verify the capability of the process computer to monitor plant conditions and to evaluate core performance parameters. This system testing is performed as a part of normal plant operations regardless of EPU implementation.

NRC Request IPSB-A.4 Page E-8 of the April 25, 2005, submittal states that the post-modification testing (of the electro-hydraulic control (EHC) system) can be conducted by inserting simulated signals such as low EHC pressure and stop valve position and that this process has been used for the current operating configuration. Clarify whether the post modification simulated signals will be performed at EPU conditions or at the current operating configuration.

TVA Replv to IPSB-A.4 Simulated signal tests are performed prior to each unit startup. Parameter values used for such testing will be revised to reflect EPU conditions.

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NRC Request IPSB-B.1 Section 8.6, Normal Operations Off-Site Doses, of Enclosure 4 of the June 25, 2004, submittal states that radiation from shine (offsite) is not presently a significant exposure pathway and is not significantly affected by EPU. This conclusion is based on the experience of earlier 5 percent power uprates for Units 2 and 3. Also, Section 8.2.2, Offsite Doses at Power Uprate Conditions, of the Environmental Report states that N-1 6 activity in the Turbine Building will increase linearly with EPU.

The magnitude of the N-1 6 source term in the Turbine Buildings is not a simple linear increase with reactor power. The equilibrium concentration of N-16 in the Turbine Building systems will be effected (an inverse exponential function) by the decreased decay resulting from the increased steam/feed flow between the reactor and the Turbine Building. Implementation of hydrogen injection water chemistry also increases N-16 concentrations in reactor steam independently of reactor power.

Provide the present nominal value for the skyshine external dose component (assuming all three units operating at current licensed power levels), the corresponding estimated dose component following EPU (assuming all three units operating at the requested power, and design basis steam activity, levels). Include all parameters (i.e., flow rates system component dimensions, etc.) used in calculating these values and specify the calculational method used. Identify the limiting dose receptor (i.e., is the dose receptor a member of the public located offsite (and, therefore, subject to the dose limits of 40 CFR Part 190) or a member of the public working onsite (subject to the dose limits of 20.1301)). Describe any increases in doses for onsite spaces (i.e., Administrative offices, guard stations, etc.) continuously or routinely occupied by plant visitors or staff.

TVA Replv to IPSB-B.1 External gamma radiation levels are measured at BFN by thermoluminescent dosimeters (TLDs) deployed around BFN as part of the offsite Radiological Environmental Monitoring Program (REMP). TLD readings from 1996-2001 (which included, during this time frame, data taken with two units operating at original licensed power (3293 MWt), with two units operating at currently licensed thermal power (3458 MWt), and with two units operating at currently licensed thermal power (3458 MWt) with one unit operating with Moderate HWC) were compared. No discernible increase in radiation at onsite or offsite locations were indicated during this time. During this time period, onsite TLD measurements ranged from 15.5 to 16.5 mrem/quarter and offsite TLD measurements ranged from 13.25 to 14.3 mrem/quarter. Fluctuations in natural background dose rates and in TLD readings tend to mask any small increments which may be due to plant operations. Thus, there was no identifiable increase in dose rate levels attributable to direct radiation from plant equipment and/or gaseous effluents.

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Pursuant to the Offsite Dose Calculation Manual (ODCM) section 7.7.5, reviews are performed to determine the highest dose to a member of the public at the site boundary.

This review assumes that onsite TVA employees engaged in work activities not associated with nuclear power electric generation were considered as members of the public. The dose to a member of the public consists of the sum of dose commitments from effluent releases as well as any direct radiation dose. The effluent dose commitment is normally negligible compared to the direct radiation dose. The direct radiation dose is determined from area TLDs located onsite. It consists of gamma dose from the plume, ground contamination and from equipment sources (i.e., tanks, turbine shine, radioactive material storage areas, etc.).

As an example, for 2004, the highest direct radiation dose accounting for background and occupancy was 4.8 mrem (Reference 9). This can be compared to the limit of 100 mrem of 10 CFR 20.1301. Although EPU evaluations assumed a 20% increase in doses, it can be seen that even for a doubling of doses (- 5 mrem to - 10 mrem), the dose rate to a member of the public working onsite would remain well within the limits of 10 CFR 20.1301.

NRC Request IPSB-B.2 Section 8.5.3, Post Accident, of Enclosure 4 of the June 25, 2004, submittal states that plant specific analysis for NUREG 0737, Item II.B.2. "have been performed" but gives no results or indication they meet the NUREG 0737 acceptance criteria. For each BFN Unit 2 and 3 vital area (as defined in Item ll.B.2.), provide the calculated pre-uprate and post-uprate mission doses to an operator performing vital tasks following a loss-of-coolant accident (LOCA). Verify that the mission doses to personnel in these vital areas, as well as the calculated dose estimates for personnel performing required post-accident duties in the plant's Technical Support Center, are within the dose guidelines of GDC-19 (10 CFR Part 50, Appendix A). Is restoring spent fuel cooling a vital action required to mitigate the effects of a design basis LOCA at BFN Units 2 and 3?

TVA Reply to IPSB-B.2 Mission dose analyses for NUREG-0737, Item II.B.2, were evaluated utilizing the Alternative Source Term (AST) in accordance with 10 CFR 50.67. The results of this evaluation were provided in the AST license amendment submittal (Reference 10).

AST for BFN Units 1, 2, and 3 was approved by the NRC in Reference 11. The AST analyses, including mission doses, were performed at EPU conditions and, therefore, did not require re-performance as part of the EPU license amendment. Restoration of spent fuel pool cooling is not an action required to mitigate the effects of a design basis LOCA at BFN.

As previously provided in Enclosure 4, Section 3.1.4 of Reference 10, the results of the revision of post-accident mission doses demonstrated that the previous calculated E-33

doses (based on TID-1 4844 source terms) at 100% OLTP conditions bound the doses calculated at EPU conditions based on AST source terms. The evaluated mission doses for BFN remain less than 5 rem TEDE.

NRC Request IPSB-B.3 Section 8.4.2, Activated Corrosion Products, of Enclosure 4 of the June 28, 2004, [sic]

submittal states that the increase in the activated corrosion product activity will be 3-percent higher than the original design basis activity, and that fission products in reactor water and offgas are well within the original design basis. Provide these calculated values and the basis for this estimated increase.

The increased steam EPU flow is likely to result in an increased moisture carryover in the steam, resulting in an increased transport of non-volatile fission products, actinides, and activated corrosion and wear products from the reactor coolant to the balance of the plant. Provide the levels of moisture carry over expected at the EPU steaming rates, and discuss its potential impact on activity buildup and resultant dose rates in the balance of plant.

TVA Reply to IPSB-B.3 Calculation of activated corrosion and fission products in the reactor coolant was performed in accordance with ANSI/ANS-18.1-1984, "Radioactive Source Term for Normal Operation of Light Water Reactors." Input parameters that change as a result of EPU conditions include core power, weight of water in reactor vessel, cleanup demineralizer flow rate, and steam flow rate. Based on the methodology in ANSI/ANS-18.1-1984, calculated values for activated corrosion products and fission products for EPU conditions is provided in the table below. Design basis values based on GE design specifications is provided for comparison. The noble radiogas release after 30 minutes delay is 3.16E+04 pCi/sec (well below the original design basis of 0.35 curies/sec).

Table IPSB-B.3-11 Activated Corrosion and Fission Products Design-Basis EPU Reactor Water Reactor Water Item (Wlml1) l(Cilg)

Fission Products 5.73E+00 1.07E-01 Activated Corrosion Products 6.36E-02 6.52E-02 Total 5.79E+00 1.72E-01

'The mass of 1 ml of water is 1 g at 40C.

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Evaluation of the expected carryover rate for EPU conditions do not result in moisture carryover values above 0.11 wt%. This magnitude of moisture carryover would have an insignificant effect on activity carryover, especially as compared to the design basis margins. As discussed in the reply to IPSB.8, radiation zonings in the turbine building adjacent to steam affected areas were reviewed and monitoring is part of the planned EPU testing.

NRC Request IPSB-B.4 Section 6.3.2, Crud Activity and Corrosion Products, of Enclosure 4 of the June 25, 2004, submittal indicates that the expected increase in spent fuel pool (SFP) crud is 2-percent, based on the expected increase of crud in the reactor coolant system (RCS) due to increased feed flow. Provide a summary of this calculation. Describe the impact of a 20-percent increase in feedwater flow has on condensate demineralizer efficiency.

TVA Replv to IPSB-B.4 The crud in the SFP would increase by less than 2% assuming that all residual crud in the reactor cooling system is transported to the SFP. This increase was calculated using an approach based on a contaminant removal efficiency of 90% for the RWCU system and an approximately 15% increase in feedwater flow for EPU ((100 - 90%) x 15% = 1.5%).

The condensate demineralizers are discussed in Section 7.4.3 of the PUSAR. As part of EPU, an additional condensate demineralizer vessel is being installed for each unit.

This additional vessel will allow an additional condensate demineralizer to be placed in service during full power operation while allowing one vessel to be taken out of service for backwashing and pre-coating. With EPU, the system will experience slightly higher loadings resulting in slightly reduced condensate demineralizer run times.

NRC Request IPSB-B.5 Also, the estimate of the increase in RCS activity does not appear to include pre-outage crud bursts. Recently, a number of BWRs that have implemented hydrogen water and Zinc injection chemistry, have experienced large, unprecedented, crud bursts. Describe any contingencies that will be implemented to compensate for any unexpected build-up and release of crud in Units 2 and 3.

TVA Replv to IPSB-B.5 When the Reactor Coolant chemistry is changed from Normal Water Chemistry to Moderate Hydrogen Water Chemistry (HWC) or Noble Metal Chemical Application (NMCA) with HWC, the crud in the reactor pressure vessel (primarily on the fuel) can E-35

restructure causing crud to be released into the water during power changes and on unit shutdowns. Since Units 2 and 3 have been operating under NMCA with HWC for at least five years, significant crud restructuring and release is not expected to occur at EPU conditions. However, should a crud burst be experienced on any unit, possible contingencies to reduce personnel radiation dose could include maximizing RWCU and Fuel Pool demineralizer operation, additional temporary filters (Tri-Nuc), bleed-and-feed operations and temporary shielding.

NRC Request IPSB-B.6 Section 6.3.3, Radiation Levels, of Enclosure 4 of the June 25, 2004, submittal states that the normal radiation levels around the SFP may increase slightly, primarily during fuel-handling operations. Explain the reason for, and the magnitude of, these postulated increases in dose-rate levels in the area of the SFP. Verify that these postulated dose-rate increases will be bounded by the current radiation zone designations in the SFP area. If this postulated dose-rate increase is due to higher activation of spent fuel assemblies, discuss any effects that the storage of these spent fuel assemblies in the SFP may have on dose rates in accessible areas adjacent to the sides or bottom of the SFP.

TVA Reply to IPSB-B.6 Assuming that the normalized core and fuel bundle activity inventory (Curies/MWth) remains approximately constant from original conditions to EPU conditions, an increase in thermal power would result in a proportional increase in fuel bundle activity. An increase in bundle activity would lead to an increase in bundle dose rates. It is estimated that a core thermal power increase of 20% would result in a 20% increase of dose rates related to spent fuel pool operations. Similarly, the increased dose rates at the SFP could potentially have proportionally increased dose rates in accessible areas adjacent to the SFP.

The radiation zonings in the areas adjacent to the SFP were reviewed. Generally, the dose rates on the refuel floor are less than 10 mrem/hr (typically less than 30 mrem during refueling activities) and the doses rates in the accessible areas adjacent to the sides or bottom of the SFP are less than 1.0 mrem/hr. Zoning in these areas are not expected to change as the result of EPU conditions. Any increase in dose rates around the SFP associated with EPU would not be seen until the first refueling outage following EPU implementation. Further, dose rates at the surface of the pool are primarily due to the presence of radionuclides suspended in the cooling water. These dose rates are controlled by the frequency of the backwash and precoats of the fuel pool demineralizers. Radiation protection surveys in accordance with the current radiation protection program will ensure that refueling activities will continue to be appropriately monitored during these activities.

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NRC Request IPSB-B.7 Section 8.5.2, Normal Post Operations, of Enclosure 4 of the June 25, 2004, submittal states that the post-operation radiation levels in most areas of the plant are expected to increase by no more than the percentage increase in power level. This section also states, however, that there are a few areas near the reactor water piping and liquid radwaste equipment where the expected radiation level increase could be slightly higher. Provide the specific locations of these areas where higher dose rates are predicted, give the reasons for the expected increase in radiation levels in these areas, and state the percentage increase in dose rates expected.

TVA Reply to IPSB-B.7 Post-operation dose rate increases are expected in areas of the plant due to the increase in the production of activated corrosion products. Since activated corrosion products are the primary contributors to crud buildup, it is expected that the dose rates near these areas will increase under post shutdown conditions in proportion to the increase in the activated corrosion products. These corrosion products will be deposited on piping and components containing reactor water. The following systems piping and components are expected to have increased dose rates: recirculation system, reactor water clean up (RWCU) and radioactive waste. Most of this piping is located in the drywell, RWCU heat exchanger room, RWCU pump room, reactor building steam tunnel, pipe tunnels, radwaste building or is embedded. Access to these areas during post operation (outages) is strictly limited by existing Radiation Protection procedures and is controlled by BFN's ALARA program.

NRC Request IPSB-B.8 Section 8.5.1, Normal Operations, of Enclosure 4 of the June 25, 2004, submittal states that, due to the conservative shielding design, the increase in radiation levels resulting from EPU will not effect the radiation zones for the various areas of the plant. This appears to be based on an assumed linear increase in radiation source term with power level. However, the increase in N-16 activity in the turbine building is an inverse exponential function with decay time, not a linear function of reactor power. Verify that the radiation zoning in all areas containing the steam and feed systems will be unaffected by EPU.

TVA Reply to IPSB-B.8 Historical data was reviewed to evaluate the relationship between reactor power level and dose rates in steam affected areas. Also, a study was performed analyzing the effects of EPU conditions at BFN relative to hydrogen injection rates. The study found that although N1 6 production increases with reactor power due to increased neutron flux, the steam flow also increases, which tends to balance this increased production E-37

such that the concentration of N1 6 per gram of steam stays approximately the same as long as moisture carryover does not significantly increase. With the increase in steam flow rate, and correspondingly reduced travel time from the vessel nozzle to the turbines, less radioactive decay occurs in the process flow from the vessel to the turbine. Accordingly, the concentration of N16 in the turbines is larger. Feedback obtained from several EPU recipients indicates that the increase generally runs about 14-15% instead of the assumed 20%.

The radiation zonings in the turbine building adjacent to steam affected areas were reviewed. Generally, the dose rates in the walkways of the turbine buildings adjacent to steam affected areas are less than 1.0 mrem/hr. Most of the steam-affected areas are currently posted as "Locked High Radiation Area," with the exception of the reactor feedpump turbine rooms. These rooms are currently posted as "High Radiation Areas."

The existing shield walls surrounding the steam-affected areas will provide adequate shielding to mitigate any predicted dose increases. Zoning in these areas are not expected to change; however, dose rates in these areas will be monitored during power ascension as part of the planned EPU testing.

NRC Request IPSB-B.9 Enclosure 8, Table 2 of the June 25, 2004, submittal states that the objective of test STP 1, Chemical and Radiochemical, is not applicable to EPU and is not required. The Table 1 entry for STP 1 states that "samples will be taken and measurements will be made at selected EPU power levels...." Describe which samples and measurements will be made and at what power levels.

TVA Reply to IPSB-B.9 Note that Enclosure 8 of the original submittal (Reference 1) was replaced in its entirety by the submittal dated April 25, 2005 (Reference 3). Additional detail regarding STP 1 is provided in Table 1 of that submittal and continues to indicate that parts (b) & (c) of the original test (determination of adequacy for equipment, procedures, and techniques

& evaluation of fuel, equipment, and instrument calibration) are not intended to be performed for EPU.

Samples and measurements will be measured at 90,100,105, 110,115 percent of 3293 MWt and at EPU conditions (approximately 120 percent of 3293 MWt). These include the sampling of reactor water and feedwater and analyzing for chemical and radiochemical properties and determining gaseous effluent releases.

NRC Request IPSB-B.10 , Table 2 of the June 25, 2004, submittal states that the objective of test STP 2, Radiation Measurements, is not applicable to EPU and is not required. The E-38

Table 1 entry for STP 2 states that "Gamma dose rate measurements.. .will be made at specific limiting locations throughout the plant...." Describe the limiting locations for which measurements will be made and at what power levels.

TVA Reply to IPSB-B.10 Note that Enclosure 8 of the original submittal was replaced in its entirety by the submittal dated April 25, 2005 (Reference 3). Additional detail regarding STP 2 is provided in Table 1 of that submittal and continues to indicate that part (a) of the original test (demonstration of background radiation levels prior to operation) is not intended to be performed for EPU.

Dose rate measurements will be made at 90, 100, 105, 110, 115, and 120 percent of 3293 MWT. These measurements will be made at locations susceptible to dose rate increase due to increased N16 and neutron doses as a result of the increase in power level.

General area dose rates will be measured in the following areas. Also, specific survey points will be established in the following survey areas:

• Walkways in the turbine buildings adjacent to steam affected areas,

• General area adjacent to the reactor building steam tunnel,

• Access to the RWCU heat exchanger and pump rooms,

• Drywell penetrations at the core spray penetrations (RXB EL 604) and top of the TIP room (neutron surveys),

• Drywell clean room at the personnel access (neutron surveys),

• Drywell equipment access plugs and drywell CRD access plugs,

• Turbine building roofs,

• Turbine buildings EL 575 near the condensate demineralizers,

• Turbine building near the condensate booster pumps and in the condensate pump pits,

• Feed water pumps and FW pump rooms, Further, remote monitoring will be placed in steam affected areas throughout the turbine building during power ascension to establish a data base for increasing dose rates at the above power levels.

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NRC Request IPSB-B.11 Summarize the major Units 2 and 3 plant hardware or system modifications involved in the requested EPU and discuss any changes with the occupational doses associated with plant operation with the modifications installed.

TVA Replv to IPSB-B.1 1 Table 3, entitled "Browns Ferry EPU Planned Modifications, Setpoint Adjustments and Parameter Changes," provided in TVA's April 25, 2005 submittal (Reference 3), lists the planned modifications for EPU. That list was reviewed for occupational dose impacts.

None of the modifications or setpoint changes would have an impact on occupational dose during plant operation. Parameter changes associated with increased steam flow and increased feedwater flow result in increased N16 sources in the turbine building and increased activation products in plant systems. These are discussed in responses to questions IPSB-B.7 and IPSB-B.8.

NRC Request SPLB-A.1 Section 10.5.5 of the UFSAR, Revision 17 dated August 30, 1999, revised the discussion from the UFSAR that was previously provided regarding the maximum SFP heat load for batch and full core offloads. In order to facilitate NRC review of the capability of the SFPCCS to perform its function for EPU conditions, provide a discussion on the safety-related systems required to maintain fuel pool cooling within design bases temperature limits.

TVA Replv to SPLB-A.1 As discussed in BFN UFSAR Section 10.5.5, spent fuel pool cooling is normally provided by the Spent Fuel Pool Cooling and Cleanup System (SFPCCS). The system for each fuel pool consists of two circulating pumps connected in parallel, two heat exchangers, one filter demineralizer subsystem, two skimmer surge tanks, and the required piping, valves, and instrumentation. The SFPCCS transfers heat to the Reactor Building Closed Cooling Water (RBCCW) System. In addition, the Residual Heat Removal System can be operated in parallel with the fuel pool cooling system (supplemental fuel pool cooling) to maintain the fuel pool temperature if a full core off load is performed. The RHR System transfers heat to the Residual Heat Removal Service Water (RHRSW) System, and provides a source of seismic Class 1 makeup water via the RHR/RHRSW intertie. The design capacities of the SFPCCS and RHR heat exchangers operating in fuel pool cooling assist mode are provided in BFN UFSAR Table 10.5-1.

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Further, the Auxiliary Decay Heat Removal (ADHR) System provides a non-safety related means to remove decay heat and residual heat from the spent fuel pool and reactor cavity of BFN Unit 2 or Unit 3.

Analysis of the cooling capability of these systems is provided in the response to SPLB-A.2 below.

NRC Request SPLB-A.2 For EPU conditions, explain how the SFP water temperature will be maintained below 150 degrees Fahrenheit (F) for the worst-case normal (batch) and full core off load scenarios assuming a loss of offsite power and (for the batch offload only) a concurrent single active failure considering all possible initial configurations that can exist. Include a description of the maximum decay heat load that will exist in the SFP for each case, how these heat loads were determined, such that they represent the worst-case conditions, and what the cooling capacity is for the systems that are credited, including how this determination was made. Also:

a. Describe any operator actions that are required, how long it will take to complete these actions, and how this determination was made; and

b. Describe the maximum core decay heat load that will exist at the onset of fuel movement, how this determination was made, how this heat load will be accommodated while also satisfying the SFP cooling requirements over the duration of the respective fuel off load scenarios, and including the situation where the SFP is isolated from the reactor vessel cavity.

TVA Replv to SPLB-A.2 As described in UFSAR Section 10.5, the capacity of the SFPCCS and ADHR systems is utilized to maintain the fuel pool temperature at or below 1250 F during normal refueling outages. The RHR system can be operated in parallel with the SFPCCS system to maintain the fuel pool temperature less than 1500 F if a full core off load is performed. To assure adequate makeup under all normal and off normal conditions, the RHR/RHRSW crosstie provides a permanently installed seismic Class I qualified makeup water source for the spent fuel pool. This ensures that irradiated fuel is maintained submerged in water and that reestablishment of normal fuel pool water level is possible under all anticipated conditions. Two additional sources of spent fuel pool water makeup are provided via a standpipe and hose connection on each of the two EECW headers. Each hose is capable of supplying makeup water in sufficient quantity to maintain fuel pool water level under conditions of no fuel pool cooling.

Table 6-3 of the PUSAR provides the limiting analyses that were performed for batch and full core off loads considering either one train each of SFPCCS and ADHR systems E-41

or one train each of SFPCCS and RHR supplemental fuel pool cooling systems in service.

The maximum decay heat loadings for the SFP were calculated using the ANSI/ANS 5.1-1979 Standard with two-sigma uncertainty. The heat load in the SFP is the sum of previous fuel off loads and the recent batch (or full core offload) decay heats at the time of transfer. Batch offloads consist of one batch of 332 fuel bundles offloaded to an almost full SFP. The pool is assumed loaded with 2375 bundles allowing space for a full core offload (764 cells). The 2375 bundles are offloaded in eight batches, discharged at 24-month intervals. Full core offloads assume the same as the batch offload case plus 332 additional fuel assemblies, all of which have cooled for 24 additional months, along with the full core (764 bundles) which have operated for 24 months. The initiation of fuel offloading was a minimum of 50 hours5.787037e-4 days <br />0.0139 hours <br />8.267196e-5 weeks <br />1.9025e-5 months <br /> after plant shutdown based upon SDC requirements, head removal time and refueling preparation.

Actual times were determined based on the calculated heat removal capacity of the cooling mode. Fuel transfer time was estimated for the batch and full core offload cases based on a transfer rate of 14 bundles per hour to the fuel pool. These decay heat and off load time estimates establish the limiting case maximum heat loads for fuel pool cooling batch and full core off load cases. The maximum peak heat load calculated for each case is provided in Table SPLB-A.2-1.

Cooling of the fuel pool for each scenario conservatively assumes that only one heat exchanger/pump combination is available for the respective system credited (i.e.

SFPCCS, ADHR, RHR). The heat exchanger effectiveness is based upon original design specifications including standard value fouling factors and tube plugging criteria.

The original design specifications for each heat exchanger is provided in Table SPLB-A.2-2. The evaluation only considers the mass of water in the fuel pool and assumes no circulation of water between the fuel pool and the cavity for the period of time that fuel pool gates are open while the fuel is being transferred to the pool.

For each combination of cooling systems (SFPCCS/AHDR or SFPCCS/RHR), the SPF temperature is maintained below 1250 F for the batch offload cases and below 150OF for the full core off load cases.

The design and analysis basis for the spent fuel pool cooling system does not specifically address scenarios assuming a loss of offsite power and a concurrent single active failure considering all possible initial configurations. Configurations that are considered are those described above. Any other configurations/failures are addressed by the complete loss of SFPCCS as described in the reply to SPLB-A.3.

a. Operation in the SFPCCS mode is a planned evolution. Prior to each refueling outage, calculations are performed to determine the actual pool heat load and determine which equipment must be placed in service to maintain pool temperature. Administrative controls are used to ensure that the fuel pool E-42

cooling capacity is not exceeded during core offload. Operator actions required in the event of a total loss of SFPCCS are discussed in the reply to SPLB-A.3.

b. The maximum core decay heat load that will exist at the onset of fuel movement is determined using ANSI 5.1-1979 with 2 sigma decay heat methods for a core operated at EPU conditions for 24 months. Fuel movement occurs when the decay heat loads (core and spent fuel pool with previous core off loads) are within the capability of the FPC systems aligned for cooling. The evaluation only considers the mass of water in the fuel pool and assumes no circulation of water between the fuel pool and the cavity for the period of time that fuel pool gates are open while the fuel is being transferred to the pool.

Table SPLB-A.2-1 Browns Ferry Spent Fuel Pool Peak Heat Load' Limiting Full Core Conditions I Parameter Batch Offload Offload Configuration 1: One train each of FPCC and ADHR In Service Peak Heat Load (Mbtu/hr) l 27.6 l 57.4 Configuration 2: One train each of FPCC and RHR supplemental fuel pool cooling mode In service Peak Heat Load (Mbtu/hr) 23.7 44.0 l 1 See PUSAR Table 6-3 for applicable notes.

Table SPLB-A.2-2 Browns Ferry Original Heat Exchanger Design Specifications Original Design Heat Removal Heat Exchanger Capacity (Mbtu/hr)

SFPCCS HX Design Heat Removal Capacity @ 125 0F SFP 4.4 temperature / 100F RBCCW water temperature (single HX)

RHR HX Design Heat Removal Rate @ 125 0F and 5Mlb/hr on shell 44.0 side and 80 0F and 2.25 Mlb/hr on tube side)

ADHR HX Design Heat Removal Rate @ 125 0F and 3420 gpm on 70.3 process fluid side and 75.4 0F and 3420 gpm on coolant side NRC Request SPLB-A.3 Discuss how adequate SFP makeup capability is assured for EPU conditions in the unlikely event of a complete loss of SFP cooling capability, including how the maximum possible SFP boil-off rate compares with the assured makeup capability that exists, E-43

operator actions that must be taken, how long it will take to complete these actions and how this determination was made, and boron dilution considerations.

TVA Reply to SPLB-A.3 As discussed in Section 6.3.1 of Enclosure 4 (PUSAR) of the initial application (Reference 1), the maximum boil off rate for the bounding full core offload scenario is 104 gpm. Assuming the SFP is initially at 1250 F, the time to boiling following a loss of all SFP cooling would be approximately four hours. After the SFP reaches boiling, a much greater period of time is required to reduce FPC level to a level of minimum shielding.

A permanently installed, seismic Class I qualified source of makeup water is provided through the RHR/RHR Service Water crosstie to the fuel pool cooling system. The makeup capability via this path is > 150 gpm. Alignment and operation of this feature involves verifying the position of two manual valves in the field, racking out of 2 circuit breakers located in the electrical board rooms and operation of pumps and valves from the main control room. These actions can be performed well within the needed timeframe. There are no boron dilution considerations for a BWR SFP.

NRC Request SPLB-A.4 Provide justification and/or details of the evaluation which concludes that the SFP cooling and makeup systems continue to meet the requirements of draft GDC-4 for EPU conditions, in so far as it requires that reactor facilities shall not share systems or components unless it is shown safety is not impaired by the sharing.

TVA RepIv to SPLB-A.4 The spent fuel pool cooling and makeup system for each unit's fuel pool are separate systems except for a spare filter demineralizer which can be aligned to any of the three units. When utilized, the spare demineralizer is aligned to one unit only. Therefore, the spent fuel pool cooling and makeup system for each unit remains separate.

The ADHR system provides a non-safety related means to remove decay heat and residual heat from the spent fuel pool and reactor cavity. This system is aligned to only one unit at a time and, therefore, is not shared simultaneously between the units.

Separation of the spent fuel pool cooling and makeup systems and the ADHR system will not be affected by EPU. The operation and alignment of these systems will not be changed under EPU conditions.

E-44

NRC Request SPLB-A.5 In Section 6.4.1.1, of Enclosure 4 of the June 25, 2004, submittal regarding the emergency equipment cooling water (EECW) system, it is stated that: "EPU does not significantly increase equipment cooling water loads, and thus, the capacity of the EECW system remains adequate." Discuss, in more detail, the impact of the proposed EPU on EECW heat loads, flow rates, and flow velocities for the worst-case conditions, including limiting assumptions, input parameters, and available margin that will remain.

TVA Replv to SPLB-A.5 System configuration and operation of the EECW system is not modified for EPU conditions. The EECW system continues to take suction from the UHS and provide cooling water to the required systems. System flow rates and, therefore, flow velocities, will not change with EPU implementation. Heat loads to the RHR and CS room coolers will slightly increase due to post-LOCA increases in room temperatures for these areas.

The increase in room temperatures in these area were determined using the current EECW system flows and room coolers. This increase in room temperatures will slightly increase the EECW discharge temperatures of the room coolers but will not be significant since room temperatures increase by less than 30F.

NRC Request SPLB-A.6 In Section 6.4.1.1.2, of Enclosure 4 of the June 25, 2004, submittal regarding the residual heat removal service water (RHRSW) system, it is stated that:

The post-LOCA containment and suppression pool responses have been calculated based on an energy balance between the post-LOCA heat loads and the existing heat removal capacity of the RHR and RHRSW systems. As discussed in Sections 3.11 and 4.1.1, the existing suppression pool structure and associated equipment have been reviewed for acceptability based on this increased suppression pool temperature.. .The RHRSW system flow rate is not changed.

Discuss in more detail, the impact of the proposed EPU on the RHRSW system heat loads (including SFP cooling considerations), flow rates, and flow velocities for the worst-case conditions, including limiting assumptions, input parameters, and available margin that will remain.

TVA Reply to SPLB-A.6 The Containment spray/Suppression Pool cooling mode post-accident containment system response is based on the RHRSW system design requirements. The RHRSW system design requirement to supply the RHR heat exchangers with 4,000 gpm per E-45

RHR heat exchanger is unchanged. The RHRSW maximum inlet temperature corresponds to an ultimate heat sink temperature of 950F. The EPU containment system response results in an increase in the maximum Suppression Pool temperature from 1770 F to 187.40F. The containment cooling analysis results in an increase in the total heat load rejected to the RHRSW system due to post-accident suppression pool cooling from 67.84 x 106 BTU/hr to 75.47 x 106 BTU/hr. The maximum RHRSW fluid outlet temperature from the RHR heat exchanger increases from 126.39F to 132.70F due to the suppression pool temperature increase. The maximum outlet temperature of 132.7QF remains below the current design limit of 1509F RHRSW outlet temperature.

With the exception of the maximum RHRSW outlet temperature increase, system flow rates, flow velocities, and system margins remain the same as for pre-EPU operation.

There is no effect on the system capacity for spent fuel pool cooling considerations (see the response to SPLB-A.2).

NRC Request SPLB-A.7 Provide a description of any impacts that the proposed EPU will have on the issues described in GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment," GL 96-06, "Assurance of Equipment Operability and Containment Integrity During Design Basis Accident Conditions," and GL 96-06, Supplement 1, including the basis for your determination. In particular, confirm that the assumed heat transfer capabilities of heat exchangers are consistent with heat exchanger performance testing that has been completed in accordance with GL 89-13 and corrected for worst-case conditions; and that water-hammer and two-phase flow analyses that were completed in accordance with GL 96-06 continue to be valid.

TVA Replv to SPLB-A.7 The BFN systems within the scope of GL 89-13 are the Emergency Equipment Cooling Water System (EECW) and the Residual Heat Service Water System (RHRSW). These are the only systems that transfer heat from safety related systems, structures and components to the ultimate heat sink. There are no changes to the flow rates of these systems for EPU, therefore the key heat exchanger parameters (such as fouling factors, effectiveness and tube plugging analysis) used in the EPU analysis remain consistent with the existing GL 89-13 program. Current evaluations, testing, and monitoring performed by the TVA Heat Exchanger Program to meet the commitments related to GL 89-13 will support operation at EPU conditions. There are slight increases in some of the system heat exchanger outlet temperatures, but the design of the heat exchangers is not affected and can accommodate the increases.

The Browns Ferry response to Generic Letter 96-06, "Assurance of Equipment Operability and Containment Integrity During Design-Basis Accident Conditions," was accomplished using the peak drywell temperature (336 2 F) for 105% OLTP conditions.

The peak drywell temperature of 3360 F bounds all EPU drywell temperatures.

E-46

GL 96-06 addresses three issues:

• Water hammer during a loss of coolant accident (LOCA) or a main steam line break (MSLB)

• Two-phase flow during a LOCA and MSLB

• Thermally induced over pressurization of isolated water filled piping sections in containment that could jeopardize the ability of accident-mitigating system to perform their safety functions and could lead to a breach of containment integrity through bypass leakage.

Evaluations performed for GL 96-06 determined that the RBCCW was the system most susceptible to water hammer and two-phase flow. Evaluation of the RBCCW coolers for EPU was performed based on the 5% power uprate evaluation. That evaluation determined that two phased flow and water hammer during a LOCA or MSLB with a concurrent loss of offsite power was not a concern. The 5% power uprate containment conditions bound the conditions that will exist for EPU; therefore it was determined that the previous GL 96-06 evaluation for RBCCW remains valid for EPU.

All of the primary containment penetrations were evaluated for susceptibility to thermal overpressurization with previous GL 96-06 implemented. The modifications already implemented are acceptable for EPU because the existing conditions bound EPU conditions).

NRC Request SPLB-A.8 For EPU conditions, provide justification and/or details of the evaluation which concludes that the safety-related service water systems will continue to meet the requirements of draft GDC-4, in so far as it requires that reactor facilities shall not share systems or components unless it is shown safety is not impaired by the sharing.

TVA RePIv to SPLB-A.8 Unit sharing and interactions for BFN are discussed in UFSAR Appendix F.

The safety-related service water systems at BFN include the EECW system, the RHRSW system, and the UHS (which provides the source of water for the EECW and RHRSW systems). The effects of EPU on the EECW and RHRSW systems are discussed in PUSAR Section 6.4.1.1. These changes are minor and will not result in a change to the system configuration or operation and, therefore, will not have an effect on the sharing of these systems.

E-47

The UHS is the Wheeler Reservoir/Tennessee River. Although the maximum temperature assumed in DBA analyses was increased for EPU, there is no change in how the UHS is utilized or shared between the units.

NRC Request SPLB-B.1 Discuss whether any administrative controls or fire protection responsibilities of plant personnel are affected by an increase in decay heat. Also, address why an increase in decay heat will not result in an increase in the potential for a radiological release from a fire.

TVA Reply to SPLB-B.1 Administrative controls associated with fire protection in the Technical Specifications, the Technical Requirements Manual, and the Nuclear Quality Assurance Plan were reviewed and there are no changes required for EPU.

As indicated by the results of the Appendix R analyses, all Appendix R acceptance criteria are met under EPU; therefore, there is no increase in the potential for a radiological release resulting from a fire.

NRC Request SPLB-B.2 Section 6.7.1, of Enclosure 4 of the June 25, 2004, submittal states that:

a plant-specific evaluation was performed to demonstrate safe shutdown capability in compliance with the requirements of 10 CFR 50 Appendix R assuming EPU conditions... The results of the Appendix R evaluation for EPU provided in Table 6-5 demonstrate that fuel cladding integrity, reactor vessel integrity, and containment integrity are maintained and that sufficient time is available for the operator to perform the necessary actions.

Upon reviewing Table 6-5, BFN Appendix R Fire Event Evaluation Results, the NRC staff was able to find references for all but the following values in the EPU submittal:

• Cladding Heatup (PCT), degrees F = 1428 (EPU)

• Suppression Pool Bulk Temperature, degrees F = 227 (EPU), s 227 (Appendix R Criteria), including Note 3

• Primary Containment Pressure, pounds per square inch gage = 13.6 (EPU)

Provide references, including appropriate extracts from the UFSAR, plant-specific Appendix R evaluation, etc., for these values in Table 6-5, including Note 4 [sic].

E-48

TVA Reolv to SPLB-B.2 The analysis to determine the EPU effect on compliance with Appendix R Fire is documented in BFN Calculation MDN-0999-980113, "Appendix R Fire Protection Evaluation." As indicated in PUSAR Table 6-5, key evaluation results included the calculated PCT, the peak bulk suppression pool temperature, and the peak containment pressure shown to be below their respective design limits. In system piping analysis, the EPU Appendix R maximum suppression pool temperature is established as the limiting condition for which the affected piping is evaluated, and Note 3 was intended to clarify that the 2270 F criteria is designated as the limit for the torus attached piping required for the Appendix R case.

NRC Request SPLB-B.3 Section 6.7.1 of Enclosure 4 of the June 25, 2004, submittal states that:

[flor this [bounding PCT] case, the time available to the operator to open three MSRVs [main steam relief valves] is 25 minutes at the EPU conditions. The BFN Units 2 and 3 pre-EPU analysis determined the three MSRVs were required to be opened within 30 minutes. This reduction in the time available does not have any effect because the procedures will require this action to be completed within 20 minutes.

Discuss the time-line analyses, including any assumptions, that may have been made in determining that the action can confidently be accomplished within 20 minutes, such that the 5-minute reduction in available time "does not have any effect."

TVA Reply to SPLB-B.3 BFN Units 2 and 3 Safe Shutdown Instructions currently require operators to depressurize the reactor within 20 minutes following initiation of the fire event. As documented in the NRC's November 2,1995 Safety Evaluation of the post-fire safe shutdown capability of BFN Units 2 and 3 (Reference 12), TVA performed walkdowns of the BFN Safe Shutdown Instructions for the 34 fire areas/zones to confirm the ability of the operators to perform actions both inside and outside of the control room. For a fire in the Control Building, which would require evacuation of the Control Room, TVA performed a timed walkdown of the required actions. The actions were evaluated for feasibility and included adequacy of emergency lighting, labeling, accessibility, logical grouping and sequencing for the operators, and time restraints. TVA concluded that the actions could be successfully completed within the specified time requirements, which included depressurization of the Unit 2 reactor as required within 20 minutes.

Additionally, simulated fires in the Control Building and five additional fire areas were selected and included in operator requalification training based on complexity of the manual actions required, uniqueness of the actions required, and number of time-critical E-49

sections contained in the shutdown instructions. Therefore, TVA has verified, and continues to confirm that operators can accomplish the required depressurization within 20 minutes.

NRC Request SPLB-B.4 The June 6, 2005, Reply 7 of Enclosure 4, states that:

...the plant is compartmentalized and protected in accordance with Appendix R requirements such that a fire in one area will not affect the equipment in another area or, alternate shutdown paths capable of controlling each of the units are available.

Discuss whether that latter phrase "alternate.. .available" is intended as additional to the former phrase "a fire.. .area" or as a contingency if the first phrase does not apply. That is, does Volume 1 of the BFN Fire Protection Report (FPR) ensure "that a fire in one area will not affect the equipment in another area" exclusively, or does it do so only if "alternate shutdown paths capable of controlling each of the units are [not] available?"

TVA Replv to SPLB-B.4 As discussed in Paragraph 4.4.5, Section 1, Volume 1 of the BFN Fire Protection Report (FPR), BFN Units 1, 2, and 3 are divided into a number of fire areas/zones (compartments) to comply with Appendix R requirements. These compartments and associated fire barriers, including fire seals, fire dampers, fire doors, fire wrap, and structural steel protection provide adequate assurance a fire will be contained within one area and not propagate to an adjacent fire area. The BFN Units 1, 2, and 3 Fire Hazards Analysis and Appendix R Safe Shutdown Analysis were performed based on this compartmentalization. Each fire area/zone is evaluated to ensure one train of the minimum safe shutdown systems is available for a postulated fire within the area of concern. As documented in Section 3 of the BFN Fire Protection Report, the Control Building (Control Room and the Cable Spreading Room (Fire Area 16)), is the only BFN fire area/zone where "alternative or dedicated shutdown capability" is required in accordance with Appendix R,Section III.G.3). The remaining fire areas/zones satisfy Appendix R separation criteria III.G.1 and III.G.2 by ensuring one train of the minimum safe shutdown systems is available following a fire in that area/zone. The term "alternative shutdown" applies only to Fire Area 16.

NRC Request SPLB-B.5 Section 6.7.1 of Enclosure 4 of the June 25, 2004, submittal as supplemented by the reply dated June 6, 2005 (including the discussion for the ATRIUM-1 0 fuel), states that "spurious operation of HPCI [high pressure coolant injection] was reviewed in accordance with [Volume 1 of the BFN FPR]. The HPCI system was assumed to initiate E-50

at the onset of the Appendix R event, and flow at its normal flow rate. The time at which the reactor vessel water level would reach the MSLs [main steam lines] is greater than 6 minutes. Therefore, the procedures will require HPCI isolation prior to 6 minutes during an Appendix R event." Volume 1 of the BFN FPR addresses pre-EPU conditions, so the conclusion regarding the greater than 6-minute time for the reactor vessel water level to reach the MSLs presumably applies to pre-EPU conditions.

Discuss whether the conclusion with regard to the timing for isolation of HPCI still remains valid at EPU conditions.

TVA Reply to SPLB-B.5 The conclusion with regard to securing the HPCI System within six minutes following a spurious initiation during an Appendix R event remains valid at EPU conditions.

The current BFN Appendix R analysis determined that a spurious actuation of HPCI would fill the reactor vessel to up to the Main Steam Lines in just over six minutes.

Therefore, BFN Appendix R Safe Shutdown Instructions were written to ensure that operators secure HPCI injection within six minutes should a spurious initiation of the HPCI System occur.

As discussed in Section 6.7.1 of Enclosure 4 of TVA's June 25, 2004, EPU application (Reference 1), the EPU Appendix R analysis for GE-14 fuel determined that the time required for HPCI to fill the reactor vessel to the Main Steam lines during an Appendix R event and following spurious actuation was greater than six minutes. Therefore, based on the analysis for GE fuel, the required operator response time of six minutes was unchanged.

As discussed in TVA's June 6, 2005 response to an NRC request for additional information concerning TVA's EPU application (Reference 4), the Appendix R analysis for Framatome ANP fuel initially determined that spurious operation of HPCI would result in filling the reactor vessel to the Main Steam Lines in less than six minutes. This would have required revising the Safe Shutdown Instructions for BFN Units 2 and 3 to require operator to secure the HPCI System following an Appendix R spurious actuation event within five minutes. However, as discussed further in Reference 4, the Framatome analysis was revised to more accurately model the analysis for the case of spurious HPCI injection. This resulted in the reactor vessel fill time (to the Main Steam Lines) to exceed six minutes. Therefore, the conclusion for the timing for isolation of HPCI (six minutes) remains valid at EPU conditions for both GE-14 and Framatome ANP fuel.

NRC Request SPLB-B.6 Page El 3-ii of Enclosure 13 of the June 25, 2004, submittal states, E-51

Because the BFN construction permits were issued prior to the May 21, 1971, effective date of the GDC, compliance to these criteria [i.e., the acceptance criteria contained in RS-001] is not required as part of the BFN Units 2 and 3 licensing basis.

Correspondingly, the submittal contains a modified version of Section 2.5.1.4, Fire Protection, of Insert 5 for "Section 3.2 - BWR Template Safety Evaluation" from RS-001.

However, Section 1.3, Basis of the Fire Protection Plan, of Volume 1 of the BFN FPR, states the following.

This Fire Protection Plan has been developed for BFN to satisfy the requirements of General Design Criterion (GDC)[-]3 of Appendix A to 10 CFR 50... On November 19,1980, the Nuclear Regulatory Commission (NRC) published its final 10 CFR 50.48, 'Fire Protection,' which established fire protection requirements for operating nuclear power plants. This regulation, which imposed the requirement to have a fire protection plan to satisfy GDC 3, became effective on February 17, 1981.

This regulation is applicable to BFN.

Furthermore, Section 6.7.1 presents an analysis based on the BFN FPR, which acknowledges GDC 3 as the basis for the current Fire Protection Program. Address the discrepancy between the submitted information and the FPR.

TVA Reply to SPLB-B.6 The BFN Fire Protection Plan complies with GDC 3. A revised RIS-001 Section 2.5.1.4 is included in Appendix A of this enclosure to reflect this. (Note that the RIS-001 markup provided in the initial EPU License Amendment Requests was replaced in its entirety in the February 23, 2005 submittals).

NRC Request SPLB-B.7 Some plants credit aspects of their Fire Protection System for other than fire protection activities (e.g., utilizing the fire water pumps and water supply as backup cooling or inventory for non-primary reactor systems). Identify the specific situations and discuss to what extent, if any, the EPU affects these "non-fire-protection" aspects of the plant Fire Protection System.

TVA Reply to SPLB-B.7 BFN does not take credit in any safety analyses for the fire protection system in other than fire protection activities. Procedures are provided under Emergency Operating Instructions (EOI) and Severe Accident Management Guidelines (SAMG) that provide E-52

instructions for utilizing fire protection system pumps to provide water to the reactor, the drywell, or the suppression chamber if necessary. However, this use of the non-safety related fire protection system is not credited in analyses and EPU operation will not require any changes to these procedures regarding the utilization of the fire protection system.

NRC SPSB Branch Requests Introduction The original activities to revise the Unit 2 and 3 PRA models to reflect operation at EPU conditions were accomplished in 2001, prior to the decision to restart Unit 1. As a result, the Unit 2 and 3 EPU model results included in Section 10.5 of Enclosure 4 of the June 25, 2004, (Reference 1) EPU submittal reflect the operating conditions associated with Unit 1 shutdown. Since that submittal, BFN has accomplished revisions to the Unit 2 and 3 models to include the changes associated with the concurrent operation of Units 1, 2 and 3 at EPU operating conditions and the incorporation of enhancements and updated with later plant information. With the completion of these activities, BFN has three PRA models. Specifically, a PRA model for each of the units reflecting the unit at EPU operating conditions and each of two adjacent units operating concurrently at EPU conditions have been developed. These NRC RAls were developed from a review of the Unit 2 and 3 models not reflecting Unit 1 operation. These BFN RAI responses are based on the latest model reflecting three units operating at EPU conditions, enhancements, and updated plant information. If required, appropriate distinctions are made in the response(s). To facilitate the review of the RAI responses by NRC, the PRA tables contained in Section 10.5 of Enclosure 4 of the June 25, 2004, EPU submittal have been changed to reflect the three BFN units at EPU operating conditions and are provided below.

Table 10-3 BFN Units 2 and 3 Summary of CDF and LERF Baseline Values EPU Values Provided In Initial Provided In Initial Updated EPU Application Application Values Unit Parameter (Reference 1) (Reference 1) (Reference 13)

Total CDF (yr', mean value) 1.255 E-6 2.624E-6 1.55 E-6 2

LERF (yr-1 , mean value) 2.455 E-7 3.927E-7 3.51 E-7 Total CDF (yr-', mean value) 1.907 E-6 3.361 E-6 2.76 E-6 3 Fm LERE (yr'1, mean value) 2.688 E-7 4.532E-7 3.84 E-7 E-53

Table 10-4 Summary of Initiator Contributions to CDF and LERF for Browns Ferry Unit 2 Mean frequency 1 Baseline EPU Initiator Category (events per year) CDF LERF CDF LERF Transient initiator categories Inadvertent opening 4.36E-02 4.52E-08 1.92E-08 2.22E-08 1.90E-08 of one MSRV Inadvertent opening 3.42E-04 2.72E-09 6.18E-1 1 2.66E-09 5.77E-1 1 of two or more MSRVs Inadvertent SCRAM 2.57E-01 2.66E-08 4.41 E-10 4.93E-08 1.70E-09 Loss of 500 kV to 9.32E-03 4.35E-09 1.01 E-09 1.58E-08 1.28E-09 plant Loss of 500 kV to one 3.42E-02 1.82E-08 5.32E-09 6.25E-08 5.88E-09 unit Loss of l&C Bus A 4.10E-03 6.25E-09 5.51 E-10 1.21 E-08 1.35E-09 Loss of l&C Bus B 4.1OE-03 6.26E-09 5.56E-10 1.21 E-08 1.35E-09 Loss of all 1.24E-02 9.84E-09 1.82E-09 2.66E-08 2.98E-09 condensate Loss of condenser 1.20E-01 8.81 E-08 2.92E-08 2.83E-07 5.39E-08 heat sink (MSIV closure, turbine trip without bypass, loss of condenser vacuum)

Loss of FW 4.81 E-02 1.1OE-08 7.76E-09 4.81 E-08 1.01 E-08 Loss of plant air 1.20E-02 5.17E-09 2.08E-09 2.33E-08 4.17E-09 Total loss of offsite 7.15E-03 5.05E-07 1.20E-08 2.66E-07 4.71 E-09 power Loss of RBCCW 1.1 OE-02 1.87E-08 2.05E-09 3.56E-08 4.46E-09 Loss of raw cooling 7.95E-03 8.84E-08 1.35E-08 4.18E-08 7.34E-09 water Momentary loss of 7.56E-03 4.31 E-1 0 8.45E-1 1 1.07E-09 2.83E-10 offsite power Turbine trip with 1.43E+00 2.54E-07 8.22E-08 4.42E-07 1.37E-07 bypass I I I I I E-54

Table 10-4 Summary of Initiator Contributions to CDF and LERF for Browns Ferry Unit 2 Initiator Category Mean frequency (events per year) CIDIF TI Baseline LERF CDF EPU IILERF LOCA initiator categories Break outside 6.67E-04 3.79E-09 1.42E-1 0 1.52E-08 1.18E-09 containment Excessive LOCA 9.39E-09 9.39E-09 9.39E-09 9.39E-09 9.39E-09 Interfacing system 4.64E-08 4.64E-08 4.64E-08 4.64E-08 4.64E-08 LOCA Core Spray line A 1.57E-06 2.32E-09 8.47E-1 1 2.60E-09 9.07 -11 break Core Spray line B 1.57E-06 4.05E-09 1.55E-10 4.31 E-09 1.66E-10 break Recirculation 1.1OE-05 6.53E-09 1.59E-10 7.13E-09 1.69E-10 discharge line A break Recirculation 1.1OE-05 5.24E-09 4.66E-1 1 5.57E-09 4.72E-1 1 discharge line B break Recirculation suction 7.85E-07 3.55E-10 0.OOE+00 3.81 E-1 0 0.OOE+00 line A break Recirculation suction 7.85E-07 3.55E-1 0 O.OOE+00 3.81 E-1 0 0.OOE+00 line B break Other large LOCA 1.57E-06 7.88E-10 3.14E-12 8.56E-10 3.36E-12 Medium LOCA 4.OOE-05 2.21 E-08 4.36E-09 5.03E-08 2.93E-08 Small LOCA 5.OOE-04 1.16E-09 9.54E-10 1.18E-09 9.48E-10 Very small LOCA 3.38E-03 2.71 E-10 7.11 E-11 5.71 E-10 1.53E-10 (Recirculation pump seal failure)

Internal flooding Initiator categories EECW flood in 1.20E-02 Reactor Building -

shutdown unit E-55

Table 10-4 Summary of Initiator Contributions to CDF and LERF for Browns Ferry Unit 2 Mean frequency Baseline EPU Initiator Category (events per year) CDF LERF CDF LERF EECW flood in 1.70E-06 3.11E-10 4.48E-11 1.17E-10 O.OOE+00 Reactor Building -

operating unit Flood from the 9.80E-05 2.32E-09 7.07E-1 1 7.83E-1 0 1.72E-1 1 condensate storage tank Flood from the torus 1.34E-05 4.55E-09 1.27E-10 4.03E-09 1.14E-09 Large turbine building 2.20E-03 2.06E-08 3.43E-09 9.07E-09 2.25E-09 flood Small turbine building 1.44E-02 2.52E-08 2.08E-09 4.26E-08 3.68E-09 flood E-56

Table 10-4 Summary of Initiator Contributions to CDF and LERF for Browns Ferry Unit 3 Mean frequency Baseline Initiator Category (events per year) CDF l LERF CDF LERF Transient Initiator categories Inadvertent opening 4.36E-02 5.58E-08 1.930E-08 3.06E-08 2.06E-08 of one MSRV Inadvertent opening 3.42E-04 2.94E-09 7.47E-11 3.05E-09 6.16E-11 of two or more MSRVs Inadvertent SCRAM 2.57E-01 2.89E-08 4.47E-10 5.35E-08 2.15E-09 Loss of 500 kV to 9.32E-03 1.18E-08 2.30E-09 2.04E-08 1.49E-09 plant Loss of 500 kV to one 3.42E-02 4.15E-08 5.13E-09 7.07E-08 5.83E-09 unit Loss of I&C Bus A 4.10E-03 6.33E-09 4.64E-10 1.23E-08 1.32E-09 Loss of I&C Bus B 4.10E-03 6.33E-09 4.64E-10 1.23E-08 1.32E-09 Loss of all 1.24E-02 1.44E-08 1.90E-09 4.67E-08 9.47E-09 condensate Loss of condenser 1.20E-01 8.74E-08 2.96E-08 2.89E-07 5.81 E-08 heat sink (MSIV closure, turbine trip without bypass, loss of condenser vacuum)

Loss of FW 4.81 E-02 1.13E-08 7.93E-09 4.97E-08 1.11 E-08 Loss of plant air 1.20E-02 4.09E-09 1.86E-09 2.28E-08 4.00E-09 Total loss of offsite 7.15E-03 11.07E-06 3.21 E-08 1.34E-06 1.43E-08 power Loss of RBCCW 1.10E-02 1.89E-08 1.78E-09 3.58E-08 4.45E-09 Loss of raw cooling 7.95E-03 7.74E-08 11.26E-08 5.07E-08 1.11 E-08 water E-57

Table 10-4 Summary of Initiator Contributions to CDF and LERF for Browns Ferry Unit 3 Mean frequency Baseline EPU Initiator Category (events per year) CDF LERF CDF LERF Momentary loss of 7.56E-03 4.97E-10 8.44E-11 1.14E-09 2.83E-10 offsite power Turbine trip with 1.43E+00 2.70E-07 8.37E-08 4.74E-07 1.45E-07 bypass LOCA initiator categories Break outside 6.67E-04 4.05E-09 1.45E-10 11.56E-08 1.25E-09 containment Excessive LOCA 9.39E-09 9.39E-09 9.39E-09 9.39E-09 9.39E-09 Interfacing system 4.64E-08 4.64E-08 4.64E-08 4.64E-08 4.64E-08 LOCA Core Spray line A 1.57E-06 2.44E-09 4.72E-1 1 2.43E-09 5.49E-1 1 break Core Spray line B 1.57E-06 3.55E-09 1.04E-1 0 3.53E-09 1.08E-10 break Recirculation 1.10E-05 6.38E-09 4.25E-1 1 6.38E-09 4.58E-1 1 discharge line A break Recirculation 1.1OE-05 6.42E-09 4.34E-1 1 6.42E-09 4.81 E-1 1 discharge line B break Recirculation suction 7.85E-07 3.68E-10 O.OOE+00 3.75E-10 O.OOE+00 line A break Recirculation suction 7.85E-07 3.68E-10 0.OOE+00 3.75E-10 0.OOE+00 line B break Other large LOCA 1.57E-06 7.97E-1 0 0.OOE+00 8.06E-10 0.OOE+00 Medium LOCA 4.OOE-05 2.23E-08 5.22E-09 11.99E-08 4.70E-09 Small LOCA 5.OOE-04 11.28E-09 9.39E-10 1.27E-09 9.34E-10 Very small LOCA 3.38E-03 3.09E-10 7.12E-11 6.20E-10 1.61 E-10 (Recirculation pump seal failure)

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Table 10-4 Summary of Initiator Contributions to CDF and LERF for Browns Ferry Unit 3 Mean frequency Baseline Initiator Category (events per year) j IERFCDF jI LERF Internal flooding Initiator categories EECW flood in 1.20E-02 8.98E-10 1.95E-10 2.02E-09 5.15E-10 Reactor Building -

shutdown unit EECW flood in 1.70E-06 2.82E-09 8.31 E-1 1 2.74E-09 3.89E-1 0 Reactor Building -

operating unit Flood from the 9.80E-05 2.36E-09 9.37E-11 8.31 E-10 3.01 E-11 condensate storage tank Flood from the torus 1.34E-05 2.85E-08 8.74E-10 3.45E-08 1.02E-08 Large turbine building 2.20E-03 1.77E-08 3.16E-09 2.16E-08 5.81 E-09 flood Small turbine building 1.44E-02 4.31 E-08 2.16E-09 7.61 E-08 1.30E-08 flood E-59

Table 10-5 Frequency Weighted Fractional Importance to Core Damage of Operator Actions Used in Browns Ferry Units 2 and 3 PRAs HEP Frequency- Frequency-Changed Weighted Fractional Weighted Fractional from Importance to Core Importance to Core Database Operator Action Base Damage Fraction Damage Fraction Variable Description Case? U2 Base U2050530 Increase U3 Base U3050531 Increase HORVD2 Manual Depressurization of YES 1.OE-01 1.2E-01 2.2E-02 6.8E-02 7.OE-02 2.7E-03 RPV Using MSRVs HOLP2 Operator Fails to Initiate 1.9E-01 1.5E-01 -4.1 E-02 1.7E-01 1.2E-01 -4.2E-02 Wet Well Vent Given Failure to Initiate Suppression Pool Cooling HOSP1 Align RHR for Suppression 1.2E-01 7.3E-02 -4.4E-02 9.6E-02 5.4E-02 -4.2E-02 Pool Cooling U12 Align Alternate Injection to 1.OE-01 5.7E-02 -4.6E-02 O.OE+00 O.OE+00 N/A RPV via the Unit 1/Unit 2 Cross-tie HOU12 Maintain RPV Level 2.3E-02 3.4E-02 1.1 E-02 1.8E-02 4.2E-02 2.5E-02 W/Alternate Source, SP RING HDR Flood .

HOSL1 Initiate SLCS Given ATWS YES 1.2E-02 3.9E-02 2.7E-02 8.1 E-03 2.2E-02 1.4E-02 with Unisolated RPV _

HORP2 Start RHR/CS Pumps for 4.1 E-03 7.1 E-03 3.OE-03 3.OE-03 5.OE-03 1.9E-03 LPCI, Li Signal Not Anticipated HOSL2 Initiate SLCS, Given an YES 6.4E-03 2.1 E-02 1.5E-02 4.2E-03 1.2E-02 8.3E-03

_ATWS with RPV Isolated HOSV1 Defeat MSIV Closure 2.4E-02 1.7E-02 -7.3E-03 1.6E-02 1.OE-02 -5.5E-03 Logic, ATWS with Turbine Trip HOBD1 Depressurize with the 6.8E-04 3.9E-03 3.2E-03 4.5E-04 2.2E-03 1.7E-03 Turbine Bypass Valves after Loss of HPCI and RCIC HOAD1 Inhibit ADS During an YES 3.4E-03 1.OE-02 6.5E-03 2.3E-03 5.6E-03 3.4E-03 ATWS HOLA1 Manual Control of Low 9.5E-03 7.9E-03 -1.6E-03 6.2E-03 4.7E-03 -1.5E-03 Pressure Injection During ATWS HOSW1 Transfer Mode Switch to 3.OE-03 1.7E-03 -1.3E-03 2.4E-03 1.4E-03 -9.4E-04 Refuel/Shutdown HOSP2 Align RHR for Suppression 3.9E-03 3.3E-03 -6.6E-04 2.5E-03 1.8E-03 -7.OE-04 Pool Cooling, ATWS HOLPI Control RPV Level at Low 7.OE-03 1.9E-03 -5.1 E-03 7.8E-03 2.2E-03 -5.6E-03 Pressure Using RHR for Core Spray E-60

Table 10-5 Frequency Weighted Fractional Importance to Core Damage of Operator Actions Used in Browns Ferry Units 2 and 3 PRAs HEP Frequency- Frequency-Changed Weighted Fractional Weighted Fractional from Importance to Core Importance to Core Database Operator Action Base Damage Fraction Damage Fraction Variable Description Case? U2 Base U2050530 Increase U3 Base U3050531 Increase HOAL2 Lower and Control Vessel YES 6.9E-04 2.7E-03 2.OE-03 4.3E-04 1.7E-03 1.3E-03 Level HOUl 1 Cross-tie Adjacent Pumps 3.1 E-03 3.4E-05 -3.1 E-03 1.1 E-01 5.8E-04 -1.OE-02 and HX to Torus HOAD2 Inhibit ADS, ATWS, YES 2.3E-04 1.7E-03 1.5E-03 1.5E-04 8.9E-04 7.4E-04 Isolated Vessel HOEE1 Align and Start RHRSW 7.OE-04 1.1 E-04 -5.9E-04 5.3E-04 1.OE-04 -4.3E-04 Swing Pump After a LOSP with Degraded EECW HOAL1 Level Control Dunng 1.2E-04 1.2E-04 -1.6E-06 7.7E-05 6.9E-05 -8.6E-06 ATWS HORP1 Start RHR & CS Pumps for O.OE+00 O.OE+00 O.OE+00 5.5E-05 2.3E-05 -3.1 E-05 LPCI, Li Signal Not Anticipated NRC Request SPSB-A.1 The second paragraph of Section 10.5 on Enclosure 4 of the June 25, 2004, submittal indicates that all associated plant modifications were systematically reviewed to identify their effect on the elements of the probabilistic risk assessment (PRA) model. Provide the details of these systematic reviews for Units 2 and 3, including the effect of each modification on the PRA model.

TVA Replv to SPSB-A.1 TVA reviewed the EPU Design Change Notice (DCN) packages to identify any effect on the PRA models. This review determined that the PRA models were not affected by the EPU modifications.

The PRA is a model that reflects the design and operation of the BFN plant. An inherent feature of PRAs is the tacit assumption that components are designed to perform the associated functions. For example, an MOV is designed to open against a certain pressure differential. If the pressure differential is changed and the MOV is modified to accommodate the change, there is no effect on the PRA. Likewise, the substitution of an equivalent component qualified for the associated design conditions does not affect the PRA.

It is not necessary to model all plant components in the PRA. In general, components that are non-safety related and do not support or affect power operation are not E-61

included in the model. However, non-safety related components such as the high and low -pressure turbines, and the generator and associated cooling are modeled in the PRA because they can affect the initiating event frequencies. The PRA models this impact by including plant data associated with such components in determining associated initiating event frequencies.

The following table is the list of EPU modifications transmitted to the NRC by letter dated February 23, 2005 (Reference 2), annotated to provide the results of the PRA review.

Table SPSB-A.1-1 Modification PRA Review Results Main Turbine Modeled implicitly as turbine trip. No basis for changing frequency.

Turbine Sealing System Modeled implicitly as turbine trip. No basis for changing frequency.

Condensate Pumps Increased flow of pumps does not change ability of the Condensate and Demineralizer Water systems to provide a low pressure water source for the reactor vessel. Does not impact the initiating event frequency attributes.

Condensate Booster Increased flow of pumps does not change ability of Condensate System as a Pumps low pressure water source for the reactor vessel. Does not impact the initiating event frequency attributes.

Steam Packing This does not affect use of Condensate System as a low pressure water source Exhauster Bypass for reactor vessel.

Condensate The Demineralizers are not credited as a source of water; these modifications Demineralizers will not introduce any adverse effects. The modifications do not impact the initiating event frequency attributes.

Main Condenser Bellows are not explicitly modeled; this change does not affect the availability of Extraction Steam the main condenser. This modification ensures adequate design margin is Bellows maintained.

Feedwater Pumps and The modifications do not affect the modeling of Feedwater System as a post-Turbines trip source of high pressure water to the reactor vessel. The change does not impact the initiating event frequency attributes.

Feedwater Heaters The modifications do not affect the modeling of Feedwater System as a post-trip source of high pressure water to the reactor vessel. The change does not impact the initiating event frequency attributes.

Moisture Separators Modeled implicitly as turbine system. No basis for changing frequency.

Main Generator System The main generator ismodeled through the turbine trip initiating event (including load rejection events). The event is modeled statistically based on generic data and BFN operating experience. There is no basis for changing the process.

Main Bank Does not introduce any new initiators or change frequency of existing initiators.

Transformers E-62

Table SPSB-A.1-1 Modification PRA Review Results Isolation Phase Bus Does not introduce any new initiators or change frequency of existing initiators.

Duct Cooling EHC Software Does not introduce any new initiators or change frequency of existing initiators.

Technical Specification Does not introduce any new initiators or change frequency of existing initiators.

Instrumentation Respan Balance of Plant Does not introduce any new initiators or change frequency of existing initiators.

Instrument Respan Drywell Building Steel Does not change structural ability of building as modeled in the PRA.

Main Steam Supports No changes to the system that impact the capability to adequately perform PRA associated functions.

Torus Attached Piping Does not affect integrity of torus; the modifications ensure design margin is maintained.

Main Steam Isolation Does not affect reliability or function of the MSIVs ability to close or to remain Valves open.

Reactor Recirculation The recirculation pump motors are modeled as a required trip for ATWS Pump Motors sequences. Modifications do not impact this function.

Jet pumps This isan operational improvement not related to safety.

Local Power Range The replacements reflect higher power operation. They provide the same Monitors function and information; not explicitly modeled.

ICS/SPDS The replacements reflect higher power operation. They provide the same function and information; not explicitly modeled.

Main Steam Relief No affect on MSRV challenges and subsequent reseating.

Valves Steam Dryer The steam dryer is not explicitly modeled. This change provides no basis for changing the model.

Vibration monitoring Operational feature; not modeled. Monitoring equipment.

NRC Request SPSB-A.2 Provide the following information related to the treatment of a loss of offsite power (LOOP) in the PRA model:

NRC Request SPSB-A.2.a Describe how the frequencies of LOOP events were determined.

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TVA Reply to SPSB-A.2.a A loss of offsite power (LOOP) (or LOSP) is defined in the PRA as the concurrent loss of the 500kV systems and the 161 kV systems. In this situation, AC power is supplied by the onsite DGs. For BFN, the Station Blackout (SBO) is defined as the complete loss of AC power to one unit and limited AC power provided onsite by the diesel generators (DGs) to the other two units.

The calculation of LOOP frequencies are based on the BFN design in which there are no dependencies between the 500kV system and the 161 kV system with respect to plant-centered and switchyard events. Complete dependencies are modeled for grid and severe weather events.

The BFN PRA partitions loss of offsite power events (sustained loss of offsite power for more than 2 minutes) into four categories of initiating events (lEs):

• Loss of the 500kV supply to a single unit (L500U),

• Loss of the 500kV supply to the plant (L500PA),

• Grid related LOSP events (LOSPG), and

• Severe weather related LOSP (LOSPW).

Note that LOSPG and LOSPW events are combined to form the initiator LOSP. For completeness, a fifth initiating event category is also used, momentary loss of offsite power (MLOSP). Momentary loss of offsite power events are those events that are recovered either manually or automatically in less than two minutes, as defined in NUREG/CR-5496 (Reference 14). Momentary loss of offsite power events do not require the modeling of the emergency diesel generators, but require modeling of the restart demand for any operating equipment powered from the emergency buses.

For all other initiating events, top events representing the 500kV system (OG5) and the 161kV system (OG16) are questioned. The approach used to evaluate these top events is consistent with the discussion in the previous paragraph.

There have been a number of publications prepared by or for the NRC related to LOSP frequency and recovery times. They are summarized as follows:

NUREG-1 032 (Reference 15) was published in June 1988. It documents the findings of technical studies performed as part of the program to resolve the "Station Blackout," Unresolved Safety Issue A-44. Important factors analyzed include: LOSP frequency, reliability of emergency AC power supplies, capability and reliability of decay heat removal systems independent of AC power, and the likelihood of restoring offsite power before core damage could be initiated. The effects of different switchyard designs, plant locations, and operational features on the estimated station blackout events are also E-64

addressed. NUREG-1032 can be seen as definitive in addressing station blackout, and subsequent studies were based on the format and structure developed in NUREG-1032.

• INEEUEXT-97-00887 (Reference 16) was published in November 1997. Its primary objective is to update the NUREG-1 032 LOSP frequency and recovery time, using plant event data from 1980 to 1996. It also extends the scope by considering LOSP events at shutdown.

• NUREG/CR-5496 (Reference 14) was published in November 1998 as the final version of INEEL/EXT-97-00887.

Generic Data The BFN PRA models use the data and information from NUREG/CR-5496 to develop prior distributions. NUREG/CR-5496 continued the practice from NUREG-1032 of classifying LOSP events into one of the following categories:

Plant-centered LOSP events are those in which the design and operational characteristics of the plant itself play a role in the likelihood of LOSP. Plant-centered failures typically involve hardware failures, design deficiencies, human errors (maintenance and switching), and localized weather-induced faults (lightning and ice), or combinations of these types of failures. Switching or repairing faulted equipment at the site can recover plant-centered failures.

Grid-related LOSP events are those attributed to the intrinsic grid unreliability.

Grid unreliability has traditionally been the most prominent factor associated with a loss of offsite power at nuclear power plants. Factors affecting recovery include the existence and implementation of appropriate procedures and the capability and availability of power sources that can supply power during grid blackout.

Severe weather LOSP events occur due to local or area-wide storms. Severe weather only includes weather events that cause severe or extensive damage at or near the site. In such cases, the recovery time is relatively long due to the extensive repair work required. Severe weather does not include weather events that do not cause extensive damage and therefore does not affect the recovery time. Such events may be classified as either grid-related or plant-centered LOSP events.

The following paragraphs describe the development of frequencies for LOSP, MLOSP, L500U, and L500PA events based on the data in NUREG/CR-5496. The sustained plant-centered frequency is partitioned into L500U and L500PA frequencies. Sustained grid-related and severe weather events are mapped into LOSP events. The momentary E-65

frequencies from grid-related, severe weather and plant-centered events are combined into the MLOSP frequency. Table SPSB-A.2-1 provides the results of the analysis.

Plant-Centered L500U (single unit) and L500PA (entire plant. multi-unit) Frequencv The plant-centered events are further partitioned into sustained and momentary events.

The momentary events are included in the MLOSP initiating event and only the sustained plant-centered events (i.e. L500U and L500PA) are considered here. Table B-4 in NUREG/CR-5496 lists the industry distribution that was developed for sustained plant-centered LOSP events. This reference constitutes the generic data used.

The process for developing the sustained plant-centered event distributions is as follows:

In step 1, calculate a generic industry beta factor for L500PA events by assuming the occurrence of L500PA events can be modeled as the fraction of sustained plant-centered LOSP events that result in loss of power to more than one unit, at multi-unit sites. This is analogous to the event by event reviews performed to derive common cause hardware failures. For step 2, develop the generic industry (sustained plant-centered) distributions for L500U and L500PA by using the beta factor calculated in step 1 and the sustained plant-centered LOSP distribution in step 1. In step 3, perform Bayesian updates on the generic distribution to develop plant specific distributions for L500U and L500PA.

The generic industry frequency distribution for sustained plant-centered events in Table B-4 of NUREG/CR-5496 is a gamma distribution with a= 1.844 and j3= 46.12 and a mean of 4.OOE-2, per year.

The next step is to calculate a common cause beta factor for plant-centered LOSP events. Only the statistics for multi-unit sites are used in the development of the beta factor. The common cause beta factor is then estimated as 2N 2/(N1 +2N 2 ), where NJ is the number of events affecting only one unit and N2 is the number of events affecting two or more units. As shown in Table SPSB-A.2-2, N1 is 26 and N2 is 5. Thus the point estimate for the LOSP beta factor is approximately 0.278.

The resulting generic prior distributions are presented in Table SPSB-A.2-3.

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Plant-Specific Data Between late 1984 and mid 1985, all three units were shut down and have undergone substantial changes to design, equipment, maintenance, procedures, and operating policies. It was judged that the old data (prior to this shutdown period) are not applicable to the BFN units, so only data from the period following the shutdowns are used in the development of initiating event frequencies. Due to the fact that the NUREG/CR-5750 (Reference 17) is used as the source document and since that document includes all LERs through 1995, the initiating event collection starts in 1996.

All three units are similar in design (with respect to initiating events) and Unit 1 will be operated with similar procedures and management philosophy as the other units. Unit 1 has been shutdown during the entire period since mid 1985. Hence, there is no Unit 1 initiating event data available. Unit 2 and Unit 3 data through March 2003 are pooled to form a pseudo plant specific database for Unit 1. There are a total of 13.78 calendar years of data for Unit 2 and Unit 3 combined between January 1996 and March 2003.

Since the frequencies in NUREG/CR-5750 are given in terms of critical hours, the calendar years for BFN must be converted to equivalent units. Browns Ferry total critical hours was estimated from NRC operating experience data and the BFN Scram Database (Reference 18). A criticality factor of 0.944 is the average of Units 2 and 3 during the years 1996 through 2002.

Historical losses of offsite power events are recorded in the database regardless of plant power level. In the actual event sequence quantification, the initiating event categories related to losses of offsite power [i.e. loss of offsite power (LOSP), loss of 500-kV line to a single unit (L500U), loss of 500-kV line to the plant (L500PA), and momentary losses of offsite power (MLOSP)] are modified by a scalar factor of 0.944 to account for the average plant availability factor over the data collection period. The resulting, updated distributions for losses of offsite power are indicated in Table SPSB-A.2-4.

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Table SPSB-A.2-1 Browns Ferry Generic Prior Loss of Station Power (LOSP) Frequency Distributions (per Calendar Year)

Category Mean Distribution Sustained LOSP Severe-Weather LOSP 5.20E-3 Gamma(0.197, 37.93)

Grid-Related LOSP 3.OOE-3 Gamma(3.14,1048.3)

Sustained L500PA Total Sustained L500PA 1.11E-2 Gamma(1.844, 165.9)(1)

Sustained L500U Total Sustained L500U 2.89E-2 Gamma(1.844, 63.88)(2)

Momentary MLOSP Plant-Centered MLOSP 3.82E-3 Gamma(4.50, 1178.6)

Severe-Weather MLOSP 2.39E-3 Gamma(2.50, 1048.2)

Grid-Related MLOSP 1.43E-3 Gamma(1.50, 1048.2)

Total Momentary MLOSP 7.64E-3 Gamma(8.24, 1078.7) (3)

Total LOSP 5.58E-2 (1) Gamma(1.844, 46.12) scaled by 0.722 (1 - beta factor).

(2) Gamma(1.844, 46.12) scaled by 0.278 (beta factor).

(3) Best fit distribution for the sum of the three types of MLOSP.

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Table SPSB-A.2-2 Multi-Unit Station Loss of Station Power (LOSP) Events Multi Unit Station Single Unit LOSP Events Multi-Unit LOSP Events Arkansas 0 1 Beaver Valley 1 1 Braidwood 1 Browns Ferry 0 Browns Ferry 0 Brunswick 2 Byron 0 Calvert Cliffs 0 1 Catawba 1 Comanche Peak 0 Cook 1 Diablo Canyon 1 Dresden 2 Farley 0 Hatch 0 Indian Point 1 Lasalle 1 Limerick 0 McGuire 3 Millstone 1 Nine Mile Point 0 North Anna 0 Oconee 1 Palo Verde 2 Peach Bottom 0 Point Beach 1 Prairie Island 0 1 Quad City 1 Salem 0 San Onofre 1 Sequoyah 0 1 South Texas 0 St. Lucie 1 Surry 0 Susquehanna 1 Turkey Point 2 Vogtle 0 Zion 1 Totals 26.00 5.00 LOSP Beta Factor 0.278 E-69

Table SPSB-A.2-3 Generic Prior Distributions Prior Distribution Gamma Mean (per Alphp Beta BFN IE ______

Description

______________________ calendar year) (no units)

(critical years)

LOSPG Loss of Offsite Power Grid Related 2.85E-03 3.14 1048.3 LOSPW Loss of Offsite Power - Weather Related 4.93E-03 0.197 37.93 L500PA Loss of 500kV to Plant 1.1 E-02 1.84 165.9 L500U Loss of 500kV to One Unit 2.7E-02 1.84 63.9 MLOSP Momentary Loss of Offsite Power 7.26E-03 8.24 1078.7 Table SPSB-A2-4 BFN Units 2 and 3 Initiating Event Plant-Specific Updates and Posterior Distributions for Losses of Offsite Power BFN Data Posterior Prior Mean BFN IE Description (per Exposure Mean Beta 5th %ile 95th calendar No. of Time (per Alpha (inverse (per %Ile (per year) Events (critical calendar critical calendar calendar years) year) years) year) year)

Loss of LOSP Offsite 8.20E-03 0 11.48 7.16E-03 N/A' N/A' 7.96E-4 5.82E-3 Power -

Loss of 56E L500PA 5OOkV to 1.11 E-02 0 11.48 1.03E-02 1.84 5.60E 1.55E-3 2.4E-2 Plant 0 Loss of 13E L500U 500kV to 2.89E-02 0 11.48 3.78E-02 2.84 1.33E- 3.59E-3 5.5E-2 One Unit 02 Momentary MLOSP Lossite 7.64E-03 0 11.48 7.56E-03 8.24 9.17E- 3.61 E-3 1.2E-2 Off site 04 Power

1. This is a lognormal distribution.

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NRC Request SPSB-A.2.b Describe how the recovery of offsite power is modeled in the PRA (e.g., use of specific representative times, probabilistic convolutions).

TVA Reply to SPSB-A.2.b The recovery of offsite power is modeled in the PRA by a probabilistic convolution of DG failures by time with offsite power non-recovery curves. The model is a mathematical approximation of the integral evaluated over the time interval from zero to 24 hours2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> of the unavailability of onsite power, times the frequency of not recovering offsite power.

NRC Request SPSB-A.2.c Describe how the probabilities of offsite power recovery events were determined.

TVA Replv to SPSB-A.2.c The non-recovery of offsite power is accounted for in the sequence models via top events [EPR30] and [EPR6]. These top events account for the time-dependent failure of the DGs. Of interest here is the portion of the recovery model related to recovery of power from offsite sources. No credit is given for recovery of the failed DGs.

NUREG/CR-5496 provides generic industry data representing the time to recovery from losses of offsite power (LOSP) at nuclear power plants for actual incidents that occurred from 1980-1996 caused by plant-centered losses, grid losses, or severe weather losses.

Earlier analyses (Reference 16) of nuclear plant incidents through 1985 categorized plant-centered causes of offsite power failure into three plant groups, depending on the plant design factors regarding independence of the offsite power sources, and automatic and manual transfer schemes for class 1E buses. The later analysis of plant incidents through 1996 in NUREG/CR-5496 (Reference 14) indicated no statistically significant unit-to-unit variability for the plant-centered initiating events and recovery times, and hence, this trend was not modeled. Therefore, as shown in NUREG/CR-5032 (Reference 19), the frequency of offsite power non-recovery is obtained or interpolated from the values used to represent the figures and data for the recovery of offsite power due to plant-centered, weather, and grid-related causes.

Plant specific data was not used to adjust the generic industry curves for offsite non-recovery. The values used in the analysis for these three curves are reported in NUREG/CR-5496, Table SPSB-A.2-5. For intermediate times, linear interpolation was used to obtain the non-recovery probability.

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Table SPSB-A.2-5 Probabilities Derived From Data Presented in NUREG/CR-5496 Hours After Offsite Power Is Plant-Centered Weather Related Grid Related Lost Events Events Events

0. 1 1 1 0.8333 0.3999 1.667 0.23351 0.783 0.99617 2.5 0.15758 0.52875 3.333 0.11487 0.59622 0.34578 5 0.069683 0.19429 6.667 0.04699 0.38391 0.12848 10 0.2708 0.07010 13.333 0.20214 16.667 0.010696 0.15685 0.03091 21.667 0.11287 35 0.004368 0.08491 0.01361 NRC Request SPSB-A.2.d Describe how the probability of consequential LOOP was determined.

TVA Reolv to SPSB-A.2.d Generic historical data was used to calculate the loss of the 500kV supply to the unit subsequent to a turbine trip. The value of 3.34E-04 is assigned to this event based on the PLG-0500 database (Reference 20). Note that BFN has not experienced any LOOPs since the recovery of Units 2 and 3. There is insufficient evidence to support a loss of the 500kV grid from a simultaneous trip of two or more units at the site. The concept of multi-unit trips occurring simultaneously is, with the exception of some categories of LOOPs, a PRA simplification. The trips, although expected to be closely spaced, will not occur simultaneously. There may be time for the grid operators to take actions to prevent loss of the grid. Additionally, it is uncertain whether the loss of the three units will endanger the grid. Given these uncertainties, a value of 0.1 was used in previous BFN PRAs. That value is repeated here.

NRC Request SPSB-A.2.e Provide the contribution to the total core damage frequency (CDF) from consequential LOOP events.

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TVA Reply to SPSB-A.2.e The quantification process involves both single unit and multi-unit LOOP initiators. As discussed in TVA Reply to SPSB-A.2.d, the probability of a conditional LOOP is dependent on the type of initiator. For a single unit initiator, a value of 3.34E-4 is used for the subsequent LOOP. For the multi-unit initiator, a value of 0.1 is used. Utilization of these values result in the contribution to the CDF from consequential LOOPs for Unit 2 being 2.8E -11 and Unit 3 is 4.1 E-12.

NRC Request SPSB-A.3 In Section 10.5.2 of Enclosure 4 of the June 25, 2004 submittal, it is stated that the frequencies of loss of feedwater and loss of all condensate are expected to decrease for the post-EPU plant. Explain why.

TVA Reply to SPSB-A.3 The statement regarding frequencies for the loss of feedwater and loss of all condensate are expected to decrease was based on the anticipated effects associated with the implementation of planned balance-of-plant (BOP) modifications concurrent with the implementation of EPU. For example, larger capacity BOP pumps will be installed to provide added margins to accommodate various postulated pump trip transients and equipment out of service conditions. The horse power capability of the condensate pumps will be increased by approximately 37 percent, the condensate booster pumps 76 percent, and the feedwater pumps 54 percent. The modifications will provide added margins regarding the capability of the integrated BOP to inherently recover with minimum adverse effects on the capability to maintain acceptable plant conditions.

Note, however, as stated in the June 25, 2004, response, the initiating event (group) frequencies for the post-EPU models were not adjusted to reflect the expected decrease in the frequencies associated with the loss of condensate and feedwater that do not result in a scram.

NRC Request SPSB-A.4 Section 10.5.1 of Enclosure 4 of the Unit 1 submittal dated June 28, 2004, indicates that the Unit 1 PRA uses more detailed initiating event categories as compared to the Unit 2 and Unit 3 PRAs in order to facilitate the tracing of success criteria in the PRA model.

Explain why it was not necessary to use more detailed initiating event categories in the Units 2 and 3 PRA models.

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TVA Reply to SPSB-A.4 It was necessary to use more detailed initiating event categories for Unit 1 as compared to Unit 2 and Unit 3 PRAs in order to be consistent with the ASME PRA Standard (Reference 21).

The ASME PRA Standard approach facilitates the tracing of success criteria in that more detailed categories can remove conservative assumptions. As an example, the Unit 2 and 3 loss of feedwater initiating event was changed for Unit 1 by being partitioned into a total loss of feedwater and a partial loss of feedwater. The partial loss of feedwater implies that feedwater was available at the time of the scram and that HPCI and RCIC may not be required.

It was not necessary to use more detailed initiating event categories in the Unit 2 and 3 PRA models because they have not been updated to the ASME PRA standard (Reference 21). Also, the Unit 2 and 3 initiating event categories represent a complete set of internal initiators. This set was developed prior to the availability of RG 1.200.

These categories are an evolution of the event categories developed initially for the Unit 2 IPE and minor refinements accomplished as the BFN PRA models evolved.

Additionally, they were evaluated as part of the BWROG Certification process and found acceptable. They are sufficient for calculating CDF and LERF values and supporting risk-informed decisions.

NRC Request SPSB-A.5 The following questions/requests relate to the internal flooding initiating event frequencies:

NRC Request SPSB-A.5.a For "emergency equipment cooling water (EECW) flood in reactor building - shutdown units," the Unit 1 frequency is given as 1.2E-3. For Unit 2, this frequency is given as 1.2E-5, and for Unit 3, as 1.2E-2. Provide an explanation and bases for these widely different estimates.

TVA Reply to SPSB-A.5.a The 1.2E-5 value for Unit 2 is a typographical error and should be 1.2E-2. The correct value of 1.2E-2 is used in the Unit 2 PRA model.

The IE frequencies are based on the assumption that maintenance can occur any time a unit is shutdown, so with the Unit 1 return to power operation, the probability of a unit being shutdown drops dramatically.

The Unit 1 IE frequency value has been updated to reflect the likelihood that one of the other two units was shutdown. This accounts for the IE value used for Unit 1.

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The Units 2 and 3 model initiating event values for EECW flood in the turbine building were not revised in the recent model updates to reflect the restart of Unit 1. The existing Units 2 and 3 IE value is acceptable based on the fact that when the IE is changed to reflect the operating states of the other units, the IE goes from 1.2E-2 to 1.2E-3. Also the contribution of the postulated event "Emergency cooling water (EECW) flood in reactor building - shutdown units," to the total CDF is not significant.

Taking these factors into consideration, the existing model results are conservative.

NRC Request SPSB-A.5.b For the remaining flooding initiators (EECW flood in reactor building - operating unit, flood from the condensate storage tank, flood from the torus, large turbine building flood and small turbine building flood), the Unit 1 frequencies are higher than the corresponding Unit 2 and Unit 3 frequencies. Explain and provide a basis for these differences.

TVA Reply to SPSB-A.5.b Each of the IEs are discussed below.

EECW Flood in the RB - Operating Unit The Unit 2/3 values (from the IPE) were calculated based on zero events in 1081 plant years. The Unit 1 frequency was based on a prior frequency distribution based on 0.5 (consistent with recommended practice with zero events) events in 740 reactor operating years. The 1081 plant years included shutdown data not applicable to this initiator. The impact was to slightly increase the flood frequency. A Bayesian update was then performed to incorporate BFN plant specific data (0 events in 13.78 plant operating years) and the plant availability factor was applied. The failure probability for the operator action to isolate the flood was not changed. The result is a Unit 1 initiator frequency approximately 10% higher than the IPE values used in the Unit 2 and Unit 3 models.

Flood from the Condensate Storage Tank The Unit 2/3 values (from the IPE) were calculated based on one event in 1081 plant years. The Unit 1 frequency was based on a prior frequency distribution based on 1 events in 740 reactor operating years. The impact was to slightly increase the flood frequency. A Bayesian update was then performed to incorporate BFN plant specific data (0 events in 13.78 plant operating years) and the plant availability factor was applied. The failure probability for the operator action to isolate the flood was not changed. The result is a Unit 1 initiator frequency approximately 25% higher than the IPE values used in the Unit 2 and Unit 3 models.

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Flood from the Torus The Unit 1 frequency is consistent with the IPE calculation (i.e., 16 pipe segments, 7.5E-6 rupture frequency per segment year). The IPE value of 9.6E-5 is raised to 1.2E-4 for the Unit 1 model based on revising the availability factor from 0.8 (IPE) to 0.95 (Unit 1 PRA). Updated data was used to obtain the value of 1.34E-5 frequency (cited for the Unit 2/3 PUSAR).

Large and Small Turbine Building Floods The Unit 2 and Unit 3 large and small turbine building flood frequencies were developed under the condition that Unit 1 was in lay-up (Unit 2 PRA with Unit 3 Operating). The Unit 1 initiating event frequencies were developed, as part of the Unit 1 PRA, under the condition that both Units 2 and 3 are operating. This leads to an increase in both large and small turbine building flood initiating event frequencies since the frequencies are directly correlated to the number of units assumed in operation.

The Units 2 and 3 model initiating event values for the large turbine building flood were not revised in the recent model updates to reflect the restart of Unit 1. The existing Units 2 and 3 IE values are acceptable based on the fact that when the IE is changed to reflect the operating state of Units 1, the IE goes from 2.2E-3 to 3.6E-3. Also the contribution of the postulated event "Large Turbine Building Floods," to the total CDF is not significant. Taking these factors into consideration, the existing model results are appropriately representative of the effects of the postulated large turbine flooding for Units 2 and 3.

Several other factors also account for small changes in the initiating event frequencies calculated for the Unit 1 PRA. The prior distribution for the small turbine building flood was based on 6 events in 740 reactor operating years. The prior distribution for the large building flood was based on one event in 740 reactor operating years. A Bayesian update was then performed to incorporate BFN plant specific data. The prior distributions were both updated with zero events in 13.78 plant operating years (instead of zero in 1.69). Also, an availability factor of 0.95 was applied (in place of 0.8).

NRC Request SPSB-A.6 Section 10.5 of Enclosure 4 of the June 28, 2004, submittal states that the Unit 1 PRA assumes that Units 2 and 3 are operational at EPU power levels. Provide the following information related to the treatment of multi-unit interactions in the Units 1, 2, and 3 PRA models:

NRC Request SPSB-A.6.a Describe how various combinations of plant operating states (at-power, shutdown, transition) are addressed.

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TVA Retly to SPSB-A.6.a The BFN PRAs are structured to address the plant operating states appropriately. The risk models focuses on identifying and quantifying the scenarios that could potentially occur when each of the three BFN units are at-power. The status (at-power, startup, shutdown) of each unit was evaluated to determine the potential impact on the availability of shared systems that have a role in responding to postulated events. The availability of such equipment would be impacted if the configuration of the part of the system that could support another unit is changed (e.g., through maintenance or alignment changes). This scenario is addressed in the PRA models by considering this case in the IE probabilities. Another situation is that the mode of a unit could impact the shared systems success criteria. In practice, for this case regarding shared systems, the limiting success criteria are if each of the three BFN units is at-power.

The systems potentially impacted by configuration are under the control of each units technical specifications (e.g., RHR cross-connect) or, in practice, minimally impacted (e.g., diesel generators).

Multiple diesel generators are not voluntarily removed from service simultaneously (the same personnel at BFN perform maintenance on each generator in series). Moreover, a situation where such a need would be required is extremely unlikely. BFN historical evidence justifies a very low frequency for unplanned maintenance in general.

There is one unique situation and that is the modeling associated with the common accident signal. The logic model in the unit 1 PRA does explicitly track the status (at-power or not) of unit 2.

NRC Request SPSB-A.6.b Describe which initiating events impact more than one unit and describe how these are modeled.

TVA Replv to SPSB-A.6.b Multi-unit interactions have been modeled in each of the Unit 1, 2, and 3 PRA models.

This modeling approach provides realistic and comprehensive PRA results for the three BFN units. Table SPSB-A.6-1 below provides information regarding the multi-unit initiating events (IlEs) and how each of these IlEs is modeled.

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Table SPSB-A.6-1 BFN Multi-Unit Initiating Events Initiating Event Probabilistic Failures Modeling Loss of Plant Control Air Plant Control Air Failure Fails the following components for resulting in complete three Units:

loss of control air - Drywell Control Air (Unit 3 only, Unit 2 Drywell Control is supplied from Containment Inerting System; Unit 1 will be modified prior to restart)

- Outboard main steam isolation valves

- Primary Containment air-operated isolation valves fail based on the associated failure mode for a loss of air event

- Control Rod Drive Hydraulic System flow control valves

- Temperature control valves in Raw Cooling Water System Loss of Raw Cooling Water Raw Cooling Water Fails the following for three Units:

System failure resulting - Plant Control Air in complete loss of the - Control Rod Drive pumps system Large Turbine Building Flood Large pipe failure Fails affected systems - Raw Cooling resulting in fluid loss Water and Plant Control Air and impact on associated equipment Loss of Offsite Power Complete loss of offsite All DGs challenged power Loss of 500kV Switchyard to 500kV failure 161kV system and associated transfer the Plant challenged.

NRC Request SPSB-A.6.c Identify the systems that are shared among units and describe how these shared systems are modeled in the PRA. Specifically address when credit is taken to recover failed key safety functions by using cross-connects among units.

TVA Reply to SPSB-A.6.c Table SPSB-A.6-2 below provides information regarding the BFN PRA modeling approach for the shared systems defined in UFSAR Appendix F. A column is included in the table to address the situations where credit is taken for shared systems to fulfill key safety functions.

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Table SPSB-A.6-2 BFN Shared System Modeling Approach Shared System Unit 1 Unit 2 Unit 3 Basis for Credit Taken (From UFSAR Modeling Modeling Modeling Modeling for Shared Appendix F) Approach Approach Approach Approach System?

Normal Auxiliary 500kV and 500kV and 500kV and Modeling No Power (Includes 161 kV are 161 kV are 161 kV are approach is Offsite and Station modeled modeled. modeled. consistent with Sources) the shared system configuration and operational approach.

Environmental Modeling not Modeling not Modeling not Not modeled No Radiological required. required. required. because the Monitoring system does not provide a causal relationship that supports safe operation or shutdown of the unit.

Control and Control and Control and Control and Each unit's air No Service Air Service Air Service Air Service Air supplied System is System is System is equipment modeled. modeled. modeled. share common system components including compressors, receivers, etc.

Modeling approach is consistent with the shared system configuration and operational approach.

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Table SPSB-A.6-2 BFN Shared System Modeling Approach Shared System Unit 1 Unit 2 Unit 3 Basis for Credit Taken (From UFSAR Modeling Modeling Modeling Modeling for Shared Appendix F) Approach Approach Approach Approach System?

Condenser Normally Normally Normally Modeling No Circulating System operated as a operated as a operated as a approach is unitized unitized unitized consistent with system. system. system. the shared system configuration and normal operational configuration.

Raw Cooling Common to Common to Common to Modeling No Water Units 1, 2, and Units 1,2, and Units 1, 2, and approach is 3 operational 3 operational 3 operational consistent with loads. loads. loads. the shared system configuration and normal operational configuration.

Raw Service Modeling not Modeling not Modeling not Not modeled No Water required. required. required. because the system does not provide a causal relationship that supports safe operation or shutdown of the unit.

Radioactive Waste Modeling not Modeling not Modeling not Not modeled No Control required. required. required. because the system does not provide a causal relationship that supports safe operation or shutdown of the unit.

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Table SPSB-A.6-2 BFN Shared System Modeling Approach Shared System Unit 1 Unit 2 Unit 3 Basis for Credit Taken (From UFSAR Modeling Modeling Modeling Modeling for Shared Appendix F) Approach Approach Approach Approach System?

Drywell Equipment Modeling not Modeling not Modeling not Not modeled No and Floor Drain required. required. required. because the system does not provide a causal relationship that supports safe operation or shutdown of the unit.

Fire Protection Modeling not Modeling not Modeling not Not modeled No required. required. required. because the system does not provide a causal relationship that supports safe operation or shutdown of the unit.

Condensate Normally Normally Normally Modeling No Storage and operated as a operated as a operated as a approach is Transfer unitized unitized unitized consistent with system. system. system. the normal operational configuration.

Potable Water and Modeling not Modeling not Modeling not Not modeled No Sanitary required. required. required. because the system does not provide a causal relationship that supports safe operation or shutdown of the unit.

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Table SPSB-A.6-2 BFN Shared System Modeling Approach Shared System Unit 1 Unit 2 Unit 3 Basis for Credit Taken (From UFSAR Modeling Modeling Modeling Modeling for Shared Appendix F) Approach Approach Approach Approach System?

Auxiliary Boiler Modeling not Modeling not Modeling not Not modeled No required. required. required. because the system does not provide a causal relationship that supports safe operation or shutdown of the unit.

Plant Modeling not Modeling not Modeling not Not modeled No Communications required. required. required. because the system does not provide a causal relationship that supports safe operation or shutdown of the unit.

Lighting Modeling not Modeling not Modeling not Not modeled No required. required. required. because the system does not provide a causal relationship that supports safe operation or shutdown of the unit.

Plant Preferred Modeling not Modeling not Modeling not Not modeled No and Nonpreferred required. required. required. because the AC system does not provide a causal relationship that supports safe operation or shutdown of the unit.

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Table SPSB-A.6-2 BFN Shared System Modeling Approach Shared System Unit 1 Unit 2 Unit 3 Basis for Credit Taken (From UFSAR Modeling Modeling Modeling Modeling for Shared Appendix F) Approach Approach Approach Approach System?

Auxiliary DC Modeling not Modeling not Modeling not Not modeled No Power Supply and required. required. required. because the Distribution system does not provide a causal relationship that supports safe operation or shutdown of the unit.

Demineralized Modeling not Modeling not Modeling not Not modeled No Water required. required. required. because the system does not provide a causal relationship that supports safe operation or shutdown of the unit.

Reactor Building Modeling not Modeling not Modeling not Normally No and Closed required. required. required. operated as Cooling Water unitized with a System common spare pump and heat exchanger. A loss of RBCCW would result in a unit trip. It is not uniquely modeled but tacitly included the unit trips are evaluated as lEs on a statistical basis.

Reactor Building Modeling not Modeling not Modeling not A common No Equipment and required. required. required. drain header is Floor Drain the only portion of the system that isshared.

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Table SPSB-A.6-2 BFN Shared System Modeling Approach Shared System Unit I Unit 2 Unit 3 Basis for Credit Taken (From UFSAR Modeling Modeling Modeling Modeling for Shared Appendix F) Approach Approach Approach Approach System?

Hardened Wetwell In the PRA In the PRSA In the PRA Shared No Vent model as a model as a model as a portioned in unitized unitized unitized common header feature. feature. feature. to the stack.

Control Bay HVAC Modeling not Modeling not Modeling not Loss of Control No required. required. required. Bay HVAC not modeled due to low frequency and remote shutdown facilities.

Spent Fuel Modeling not Modeling not Modeling not Not modeled No Storage Facilities required. required. required. because the system does not provide a causal relationship that supports safe operation or shutdown of the unit.

Reactor Building Modeling not Modeling not Modeling not Not modeled No Crane required. required. required. because the system does not provide a causal relationship that supports safe operation or shutdown of the unit.

Process Radiation Modeling not Modeling not Modeling not Not modeled No Monitoring required. required. required. because the system does not provide a causal relationship that supports safe operation or shutdown of the unit.

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Table SPSB-A.6-2 BFN Shared System Modeling Approach Shared System Unit 1 Unit 2 Unit 3 Basis for Credit Taken (From UFSAR Modeling Modeling Modeling Modeling for Shared Appendix F) Approach Approach Approach Approach System?

Standby AC Shared Shared Shared Modeling Yes - Credit is Power Supply and equipment equipment equipment approach is taken in the Distribution includes the includes the includes the consistent with PRA model for 4160-kV 4160-kV 4160-kV the shared shared Shutdown Shutdown Shutdown system systems Boards and Boards and Boards and configuration between units Shutdown Shutdown Shutdown and operational consistent with Buses. Also a Buses. Also a Buses. Also a approach. the physical portion of the portion of the portion of the configuration, electrical electrical electrical procedures, distribution distribution distribution and operator configuration is configuration is configuration is training.

unitized unitized unitized including the including the including the 480-V boards. 480-V boards. 480-V boards.

250V DC Power Shared Shared Shared Modeling Yes - Credit is Supply and equipment equipment equipment approach is taken in the Distribution includes the includes the includes the consistent with PRA model for 250V DC 250V DC 250V DC the shared shared Batteries. Also Batteries. Also Batteries. Also system systems the portion of the portion of the portion of configuration between units the 250V the 250V the 250V and operational consistent with electrical electrical electrical approach. the physical distribution distribution distribution configuration, configuration in configuration in configuration in procedures, unitized unitized unitized and operator including the including the including the training.

250V boards. 250V boards. 250V boards.

Subsections of the Modeling not Modeling not Modeling not This is Control No Heating and required. required. required. Building cooling Ventilating, which is not Ventilation, and modeled due to Air-Conditioning low occurrence Systems probability and affect.

Control rod Drive Units 1 and 2 Units 1 and 2 Unit 3 has 2 Each unit No (shared portion share a pump. share a pump. dedicated models CRD not Class I) pumps. injection.

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Table SPSB-A.6-2 BFN Shared System Modeling Approach Shared System Unit 1 Unit 2 Unit 3 Basis for Credit Taken (From UFSAR Modeling Modeling Modeling Modeling for Shared Appendix F) Approach Approach Approach Approach System?

Gaseous Modeling not Modeling not Modeling not Not modeled No Radwaste required. required. required. because the system does not provide a causal relationship that supports safe operation or shutdown of the unit Standby Coolant Unit 1and Unit Unit 1, Unit 2, Unit 2 and 3 Modeling Yes - Credit is 2 shared piping and Unit 3 shared piping approach is taken inthe modeled in shared piping modeled in consistent with PRA model for PRA. modeled in PRA. the shared shared PRA. system systems configuration between units and operational consistent with approach. the physical configuration, procedures, and operator training.

RHR Service System is System is System is Modeling Yes - Credit is Water configured to configured to configured to approach is taken in the support all support all support all consistent with PRA model for three units and three units and three units and the shared shared is modeled is modeled is modeled system systems consisted with consisted with consisted with configuration between units the physical the physical the physical and operational consistent with configuration. configuration. configuration. approach. the physical configuration, procedures, and operator training.

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Table SPSB-A.6-2 BFN Shared System Modeling Approach Shared System Unit 1 Unit 2 Unit 3 Basis for Credit Taken (From UFSAR Modeling Modeling Modeling Modeling for Shared Appendix F) Approach Approach Approach Approach System?

Emergency System is System is System is Modeling Yes - Credit is Equipment configured to configured to configured to approach is taken in the Cooling Water support all support all support all consistent with PRA model for System three units and three units and three units and the shared shared is modeled is modeled is modeled system systems consisted with consisted with consisted with configuration between units the physical the physical the physical and operational consistent with configuration. configuration. configuration. approach. the physical configuration, procedures, and operator training.

Standby Gas Modeling not Modeling not Modeling not Does not have No Treatment required. required. required. any use regarding core damage scenarios.

NRC Request SPSB-A.7 Provide the detailed human reliability analysis (HRA) calculation sheets (e.g., as generated by the Electric Power Research Institute (EPRI) HRA calculator) for all human interactions ("operator actions") that have (a) Fussell-Vesely importance measure greater than 0.005 or a risk-achievement worth greater than 2, or (b) were modified to represent the post-EPU plant.

TVA Reply to SPSB-A.7 Table SPSB-A.7-1 and SPSB-A.7-2 list the actions with a Fussell-Vesely importance measure greater than 0.005 or a risk-achievement worth greater than 2, based on importance reports from the model quantifications for Units 2 and 3 respectively.

Table SPSB-A.7-3 lists the actions that changed as a result of the EPU. The HRA evaluation for the EPU considered two factors, 1) the reduction in the amount of time available for the operators to complete an action, and 2) whether limitations to available time was a significant enough influence on the error rates estimated for the human action. None of the Human Failure Events that were modified for operation at EPU conditions had Fussell-Vesely values greater than .005 or RAW values greater than 2.

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Table SPSB-A.7-1 BFN Unit 2 Significant Human Failure Events Risk Basic Event Fussell-Vesely Achievement Name Importance Worth Basic Event Description BEHORVD2 6.17E-01 1325 Operator failure to depressurize given HPCI/RCIC hardware failed Operator fails to open hardened wetwell vent OPERROLP2 6.70E-02 <2 - AC power avail -OP action to init SPC failed OPERROSP1 4.29E-02 567 Operator fails to align for suppression pool cooling OU12 2.33E-02 <2 Operator actions to align RHRSW to Unit 2 RHR loop I failed OUl 1 1.87E-02 2.0 Operators fail to align Ul RHR loop iI thru X-tie to U2 RHR loop BEHORVD3 1.70E-02 3.7 Operator fails to depressurize given HPCI/RCIC level control failed OHC1 1.66E-02 16.6 Operator fails to take early action to control HPCI/ RCIC inject HRAOBD 1 8.79E-03 <2 Operator fails to use TBVs for cooldown given HPCI and RCIC unavailable OPERROLP1 <.005 41.6 Operator fails to manually control LPCI/CS OPERROSP3 <.005 2.1 Operator fails to align for suppression pool cooling E-88

Table SPSB-A.7-2 BFN Unit 3 Significant Human Failure Events Fussell- Risk Basic Event Vesely Achievement I Name Importance Worth Basic Event Description BEHORVD2 4.35E-01 934.2 Operator failure to depressurize given HPCI/RCIC

.2 hardware failed OPERR OLP2 8.43E-02 <2 Operator fails to open HWWV - AC power avail - OP

_O action for SPC failed OPERROSP1 4.60E-02 608.6 Operator fails to align for suppression pool cooling OPERROLP1 < .0005 109.3 Operator fails to manually control LPCI/CS OU12 3.50E-02 <2 Operator actions to align RHRSW to Unit 2 RHR OU12 .50E-2 <2 loop 11fail OUl1 3.47E-02 3.0 Operators fail to align U3 RHR loop I thru X-tie to O~l3.4E-023.0 U2 RHR loop BEHORVD3 1.65E-02 3.6 Operator fails to depressurize given HPCI/RCIC BEHOVD3

.6E-023.6 level control failed OHC1 1.53E-02 15.4 Operator fails to take early action to control HPCI/

OH~l1.53-02 5.4 RCIC inject HRA OBD 1 6.09E-03 <2 Operator fails to use TBVs for cooldown given HPCI and RCIC unavailable OPERROSP3 < .0005 5.1 Operator fails to align for suppression pool cooling E-89

Table SPSB-A.7-3 BFN Units 2 and 3 Human Failure Events Modified to Represent the Post-EPU Plant HEP CLTP EPU Database Ouant Mean Mean Range Variable Definition Time Constraints, CLTP Method Time Constraints, EPU HEP HEP Factor Comments HOAD1 Inhibit ADS Time to -122" dependent on CBDT Approx 8.5 min to -122' and 3.45E- 4.89E- 7 Removed compensatory action based on actuation, given suppression pool heatup, but 4 min provided by timer 03 03 STA.

ATWS with an approx. 10 minutes. Four unisolated RPV min. provided by timer after reaching -122" for 14 min.

HOAD2 Inhibit ADS Level drops to -122" within 2 HCR Approx 105 sec to -122'. 4.64E- 9.52E- 7 No change in available time. Per Figure 3-9, actuation, given min. without injection, Cont. Must inhibit prior to 115 sec 03 03 corrected In of T112 Std Dev from 0.4 to 0.45 ATWS with an Press. > 2.45 psig when timeout, which controls to reflect high stress.

isolated RPV RPV is isolated. Must inhibit action.

prior to 115 sec-timeout.

HOAL2 Allow RPV level Initiate and gain control of HCR Initiate and gain control of 3.91 E- 1.29E- 3 Lowered Tw in HCR model from 120 to 105 to drop and injection within 2 min (120 injection within 105 sec. of 02 01 seconds to reflect 7/8 available time due to control at TAF, sec.) of reaching -162" to reaching -162" to avoid going assumed 1200/%/105% power ratio. Also, per given ATWS with avoid going below -190", below -190". Figure 3-9, corrected In of T1o2 Std Dev from isolated RPV which agrees with ATWS3, 0.4 to 0.45 to reflect high stress.

RPV LVL plot HORPS1 Backup SCRAM Within 1 minute HCR Within 1 minute 5.92E- 1.25E- 5 Lowered T. in HCR model from 60 to 53 03 02 seconds to reflect 7/8 available time due to assumed 1200/%/105% power ratio.

HOSLI Activate SLC 3 to 5min available to avoid HCR Slightly less than 3 to 5min 6.74E- 1.61 E- 5 Lowered T. in HCR model from 240 to 210 unisolated RPV level/ power control available to avoid level 03 02 seconds to reflect 7/8 available time due to requirement. (HCR used power control requirement. assumed 1200/%/105% power ratio.

240 sec.)

HOSL2 Activate SLC At 50% power SP reaches HCR At 50%/6 power SP reaches 3.50E- 7.71 E- 4 Lowered T. in HCR model from 180 to 158 isolated RPV 110 F in about 2 min and 110 F in about 2 min and 02 02 seconds t to reflect 7/8 available time due to 170 F in about 7min 170 F in about 7 min. assumed 120%/61105% power ratio. (NOTE:

However, ATWS runs The range factor was reduced slightly to indicate that power may be allow the upper tail of the distribution to lower, at about 30% remain below one. The mean value remains the same.)

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NRC Request SPSB-A.8 Provide a discussion of large early release frequency (LERF) from external events or a basis for concluding that any increases due to EPU are not significant.

TVA Replv to SPSB-A.8 Potential vulnerabilities due to external events were formally evaluated in accordance with the guidance contained in Generic Letter 88-20, Supplement 4, as part of the BFN IPEEE program. The table below lists the industry sanctioned and acceptable approach used at BFN to evaluate each category of external event.

Table SPSB-A.8-1 External Events Evaluation Methodology External Event Category Methodology Seismic Events EPRI Seismic Margins Internal Fire EPRI Fire Induced Vulnerability Evaluation (FIVE) methodology g wd Progressive screening and plant walkdown High winds leading to a bounding analysis External Floods Progressive screening and plant walkdown Transportation and nearby facility accidents Progressive screening and plant walkdown Regarding seismic events, the implementation of EPU does not adversely impact the conclusion previously made regarding seismic margins. Please refer to the BFN response to NRC Request SPSB-A.1 4 for additional information.

As discussed in the introduction section, the BFN Unit 1 PRA has been updated. This update was performed subsequent to performance of the initial EPRI Fire Induced Vulnerability Evaluation (FIVE). Based on update of the PRA model, the BFN FIVE calculation was revised, using the latest BFN PRA model as input. The results of the revised FIVE calculation continue to support the conclusion that no fire induced vulnerabilities exist for BFN Unit 1. From the Unit 1 results, it is expected that EPU updates to the Units 2 and 3 evaluations would support the same conclusions for Units 2 and 3. Please refer to the BFN response to NRC Request SPSB-A.13 for additional information.

For the last three external event categories, the IPEEE evaluation found that no plant-unique accident sequences different from those determined by the IPE for internal E-91

events were predicted or identified. In addition, any impacts of potential maximum physical impact fell below the screening criteria for further evaluation. Therefore, it was concluded that no additional containment performance assessment was needed, and absolute numerical values for CDF and LERF were not required.

NRC Request SPSB-A.9 The frequency-weighted fractional importance to core damage of operator action HORVD2, Manual depressurization of reactor pressure vessel using MSRVs, for the post-EPU plant is 55 percent for Unit 2 and 43 percent for Unit 3 CDF. For Unit 1, the corresponding operator action appears to be HPRVD1, Operator fails to initiate depressurization, which has a frequency-weighted fractional importance to core damage of 26.7 percent. Explain, in detail, why these apparently similar events have such different importance to core damage in light of the similarity of the PRA models. Also, describe the programmatic activities (e.g., training) intended to make this operator action reliable.

TVA Reply to SPSB-A.9 Because the post-EPU models showed a relatively high importance for manual depressurization, sequences where manual depressurization failed were scrutinized for the Units 1, 2, and 3 PRAs. The sequences are characterized by:

1. A loss of feedwater,

2. A common cause failure (CCF) of HPCI and RCIC, and

3. A failure to depressurize.

The Unit 1 operator action corresponding to Units 2 and 3 action HORVD2 is HPRVD1.

Additional information regarding the HRA analysis approach and results is provided in the response to NRC Request SPSB-A.7.

Each of the BFN PRAs was updated since the original EPU licensing applications to incorporate enhancements. As a result of these updates, the fractional importance and Fussell-Vesely (FV) importance values have changed.

The Fractional importance and Fussell-Vesely (FV) importance both reflect the "weight" of a variable in the CDF sequences. In the revised Units 1 and 2 PRAs, the fractional importance for the operator action to depressurize are similar and now have values of 0.280 for Unit 1 and 0.293 for Unit 2. Unit 3 has a slightly higher CDF than the other Units, principally due to LOOP sequences, and this accounts for the Unit 3 value of 0.166. These values reflect an acceptable variation between the units and also represent absolute values that are consistent with the relative importance of this human action.

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Licensed operator training at Browns Ferry reviews the circumstances and events that would require emergency depressurization in the classroom annually. In addition, the operator requalification training includes a number of scenarios run over the course of the training cycle that require emergency depressurization. Therefore, BFN is assured that operators are adequately trained to recognize and perform emergency reactor vessel depressurization if required.

NRC Request SPSB-A.10 Section 10.5.3 of Enclosure 4 of the submittal dated June 25, 2004, states:

Recovery actions take credit for those actions performed by the on-shift personnel either in response to procedural direction or as skill-of-the-craft to recover a failed function, system or component that is used in the performance of a response action in dominant sequences.

Does this include repair of failed equipment? If yes:

a. Provide a list of repair events credited in each PRA model, including the basis for the non-recovery probabilities used.

b. How have these repair human error probabilities been adjusted as the result of EPU?

c. Provide a sensitivity of CDF and LERF to repair activities, if credited, by removing all credit for repair of failed equipment.

TVA Replv to SPSB-A.10 The recovery actions in accident sequences of the PRA take no credit for repair of systems or components that failed earlier in that sequence.

NRC Request SPSB-A.11 As part of its EPU submittal, the licensee has proposed taking credit (Unit 1) or extending the existing credit (Units 2 and 3) for containment accident pressure to provide adequate net positive suction head (NPSH) to the ECCS pumps. Section 3.1 in to Matrix 13 of Section 2.1 of RS-001, Revision 0 states that the licensee needs to address the risk impacts of the extended power uprate on functional and system-level success criteria. The staff observes that crediting containment accident pressure affects the PRA success criteria; therefore, the PRA should contain accident sequences involving ECCS pump cavitation due to inadequate containment pressure.

Section 1.1 of RG 1.174 states that licensee-initiated licensing basis change requests that go beyond current staff positions may be evaluated by the staff using traditional engineering analyses as well as a risk-informed approach, and that a licensee may be E-93

requested to submit supplemental risk information if such information is not submitted by the licensee. It is necessary to consider risk insights, in addition to the results of traditional engineering analyses, while determining the regulatory acceptability of crediting containment accident pressure.

Considering the above discussion, please provide an assessment of the credit for containment accident pressure against the five key principles of risk-informed decision-making stated in RG 1.174 and SRP Chapter 19. Specifically, demonstrate that the proposed containment accident pressure credit meets current regulations, is consistent with the defense-in-depth philosophy, maintains sufficient safety margins, results in an increase in core-damage frequency and risk that is small and consistent with the intent of the Commission's Safety Goal Policy Statement, and will be monitored using performance measurement strategies. With respect to the fourth key principle (small increase in risk), provide a quantitative risk assessment that demonstrates that the proposed containment accident pressure credit meets the numerical risk acceptance guidelines in Section 2.2.4 of RG 1.174. This quantitative risk assessment must include specific containment failure mechanisms (e.g., liner failures, penetration failures, primary containment isolation system failures) that cause a loss of containment pressure and subsequent loss of NPSH to the ECCS pumps.

TVA Replv to SPSB-A.1 1 As discussed in the cover letter, this response will be provided in a future submittal.

NRC Request SPSB-A.12 Explain how the impact of increasing the ultimate heat sink temperature from 91 to 95 degrees F has been incorporated into the PRA. Which PRA basic events are affected by this change?

TVA Replv to SPSB-A.12 The change in UHS temperature from 91 to 95 degrees F has no effect on the Unit 1 PRA model. Engineering analysis has shown that systems and components perform their functions with the higher value. The PRA does depend on MAAP analyses for some success criteria and post core damage behavior. A Unit 1 MAAP model was developed and verified. An examination of the parameter file shows that parameter TWSW, the RHR (LPCI) heat exchangers service water inlet temperature, is set to 95 degrees Fahrenheit.

NRC Request SPSB-A.13 The existing fire risk evaluations are based on the EPRI Fire Induced Vulnerability Evaluation (FIVE) methodology, which uses a quantitative screening criterion of 1 -6 per year. This screening criterion appears too large because the core-damage frequency E-94

from internal events is of the same order of magnitude. As the fire risk evaluations for Units 2 and 3 have not been updated since the individual plant external event evaluation was performed, provide an updated FIVE analysis for each unit that reflects the post-EPU plant configuration and uses an appropriate screening criterion.

TVA Reply to SPSB-A.13 UNIT 2 The EPRI FIVE methodology calls for 1E-6 as a quantitative screening criterion to distinguish critical fire area/zones vs. non-critical fire area/zones for fire vulnerability.

This EPRI quantitative screening criterion remains valid when compared to the CDF from internal events calculated for BFN. However, TVA performed an evaluation of the fire area/zones previously screened out to respond to this concern, and determined that the use of 1E-6 as a quantitative screening criterion had no adverse impact on the FIVE analysis results.

The BFN Unit 2 FIVE analysis was initially transmitted to the NRC by letter dated July 25, 1995 (Reference 22), and was performed based on the current Unit 2 configuration.

Quantitative screening was performed for each fire area/zone assuming all the fire initiating components as well as "target" cables and equipment are damaged by fire. If the fire induced core damage frequency (CDF) was less than 1E-6 for a fire in a fire area/zone, no further analysis was performed. If it was greater than 1E-6 for a fire area/zone, then detailed fire analyses for fire initiating components were performed, resulting in component related fire scenarios and associated CDF. When the total fire-induced frequency was summed, the CDF contributions from both "screened" fire area/zone and fire area/zones with detailed analysis were included.

The CDF contributions for the "screened" fire area/zones were typically well below the quantitative screening criteria of 1E-6. The table below contains excerpts from Table 5-2 of Reference 22 identifying the CDF contributions for the screened fire area/zones.

Note that the BFN Unit 2 FIVE analysis has been updated since its initial submittal in 1995; the numbers in the table below represent the current calculated core damage frequencies for these areas. As shown in the below table, the CDF associated with the screened fire area/zones range from 1E-9 to 1E-7, with five fire area/zones having CDF contribution values greater than 1E-7 it can be observed that Fire Area/Zone 11 has the highest CDF of 7.51 E-7.

The failure of Fire Area/Zone 11 can potentially affect a number of systems. The potential impact on RBCCW of sectionalizing valve FCV-70-48 (due to the fire) would be fail the system following a loss of offsite power. The potential impact on HPCI of failing test return valve FCV-73-35 is minor as FCV-75-35 is normally isolated by a second valve, FCV-73-36. However, because this degradation was not modeled in the HPCI system analyses, HPCI was conservatively set to guaranteed failure. The potential failure of the 480V load sequencing logic circuits in panels 2-PNL-25-44A-12 and 2-E-95

PNL-44B-12 was conservatively modeled by failing division 1 diesel generators C and D, in addition to failing shutdown board recovery at top event SDREC. This treatment is conservative in that it fails 41 60V switchgear following a loss of offsite power, in addition to the supplied 480V loads. All fires are assumed to result in MSIV closure or loss of condensate heat sink with failure of 480V Shutdown Board 2A, regardless of fire severity or manual fire suppression.

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Excerpt from Table 5-2 (Reference 22)

Fire Induced CDF Summary for Screened Fire Area/Zones Fire Area/Zone Description Fire Area CDF1 6 480V Shutdown Board Room 1A (Unit 1 Reactor Building, 621' 4.45E-09 Elevation) 7 480V Shutdown Board Room 1B (Unit 1 Reactor Building, 621' 3.52E-08 Elevation) 10 480V Shutdown Board Room 2A (Unit 2 Reactor Building, 621' 1.84E-08 Elevation) 11 480V Shutdown Board Room 2B (Unit 2 Reactor Building, 621' 7.51 E-07 Elevation) 12 Shutdown Board Room F (Unit 3 Reactor Building, 593' 6.82E-09 Elevation) 13 Shutdown Board Room E (Unit 3 Reactor Building, 621' 4.62E-09 Elevation) 14 480V Shutdown Board Room 3A (Unit 3 Reactor Building, 621' 4.31 E-09 Elevation) 15 480V Shutdown Board Room 3B (Unit 3 Reactor Building, 621' 4.42E-09 Elevation) 17 Unit 1 Battery and Battery Board Room, Control Building 593' 7.06E-08 Elevation 18 Unit 2 Battery and Battery Board Room, Control Building 593' 4.75E-07 Elevation 19 Unit 3 Battery and Battery Board Room, Control Building 593' 3.43E-07 Elevation 20 Unit 1 and 2 Diesel Generator Building 5.58E-08 21 Unit 3 Diesel Generator Building 2.05E-07 22 4kV Shutdown Board Room 3EA and 3EB, 583' Elevation, Unit 3 1.60E-07 Diesel Generator Building 23 4kV Shutdown Board Room 3EC and 3ED, 583' Elevation, Unit 3 1.83E-08 Diesel Generator Building

1. Note that the BFN Unit 2 FIVE analysis has been updated since its initial submittal in 1995; the numbers in this table represent the current calculated core damage frequencies for these areas.

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UNIT 3 The EPRI FIVE methodology calls for 1E-6 as a quantitative screening criterion to distinguish critical fire area/zones vs. non-critical fire area/zones for fire vulnerability.

This EPRI quantitative screening criterion remains valid when compared to the CDF from internal events calculated for BFN. However, TVA performed an evaluation of the fire area/zones previously screened out to respond to this concern, and determined that the use of 1E-6 as a quantitative screening criterion had no adverse impact on the FIVE analysis results.

The BFN Unit 3 FIVE analysis was initially transmitted to the NRC by letter dated July 11, 1997 (Reference 23) and was performed based on the current Unit 3 configuration.

Quantitative screening was performed for each fire area/zone assuming all the fire initiating components as well as "target" cables and equipment are damaged by fire. If the fire induced core damage frequency (CDF) was less than 1E-6 for a fire in a fire area/zone, no further analysis was performed. If it was greater than 1E-6 for a fire area/zone, then detailed fire analyses for fire initiating components were performed, resulting in component related fire scenarios and associated CDF.

The CDF contributions for the "screened" fire area/zones were typically well below the quantitative screening criteria of 1E-6. The table below contains excerpts from Table 5-2 of Reference 23 identifying the CDF contributions for the screened fire area/zones.

Note that the BFN Unit 3 FIVE analysis has been updated since its initial submittal in 1997; the numbers in the table below represent the current calculated core damage frequencies for these areas. As shown in the below table, the CDF associated with the screened fire area/zones range from 1E-9 to 1E-7, with four fire area/zones having CDF contribution values greater than 1E-7.

It can be observed that Fire Area/Zone 22 has the highest associated CDF of 9.29 E-7.

A plant trip would not be expected following the loss of 4kV shutdown boards 3EA and 3EB. However, all fires in this area are assumed to result in a turbine trip and cause the loss of all plant equipment located in this fire area, regardless of fire severity or availability of manual fire suppression.

Excerpt from Table 5-2 (Reference 23)

Fire Induced CDF Summary for Screened Fire Area/Zones Fire Area/Zone Description Fire Area CDF' 6 480V Shutdown Board Room 1A (Unit 1 Reactor Building, 2.34E-09 621' Elevation) 480V Shutdown Board Room 1B (Unit 1 Reactor Building, 2.50E-09 621' Elevation) _ _ _ _ _ _ _ _

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Excerpt from Table 5-2 (Reference 23)

Fire Induced CDF Summary for Screened Fire ArealZones Fire Area/Zone Description Fire Area CDF1 10 480V Shutdown Board Room 2A (Unit 2 Reactor Building, 2.83E-09 10 ~621' Elevation) 28E0 11 480V Shutdown Board Room 2B (Unit 2 Reactor Building, 5.26E-08 621' Elevation) 14 480V Shutdown Board Room 3A (Unit 3 Reactor Building, 1.33E-08 621' Elevation) 15 480V Shutdown Board Room 3B (Unit 3 Reactor Building, 8.06E-08 621' Elevation) 17 Unit 1 Battery and Battery Board Room, Control Building 4.46E-08 593' Elevation 18 Unit 2 Battery and Battery Board Room, Control Building 2.30E-07 593' Elevation 19 Unit 3 Battery and Battery Board Room, Control Building 4.14E-07 593' Elevation 20 Unit 1 and 2 Diesel Generator Building 2.97E-08 21 Unit 3 Diesel Generator Building 1.40E-07 22 4kV Shutdown Board Room 3EA and 3EB, 583' Elevation, 9.29E-07 Unit 3 Diesel Generator Building

1. Note that the BFN Unit 3 FIVE analysis has been updated since its initial submittal in 1997; the numbers in this table represent the current calculated core damage frequencies for these areas.

NRC Request SPSB-A.14 of the submittal dated June 25, 2004, identifies planned modifications of the drywell building steel (building steel beams and connections), main steam supports, and torus attached piping (supports and snubbers) due to the EPU conditions. With respect to these planned modifications, address the following issues:

NRC Request SPSB-A.14.a Confirm that these planned modifications will not change the high confidence of low probability of failure values used in the seismic margins analysis.

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TVA Replv to SPSB-A.14.a The analysis of building steel (beams and connections), main steam supports, and torus attached piping (supports and snubbers) have been or will be performed in accordance with the BFN design criteria for the planned modifications. The design criteria specifies the loads and load combinations to apply in the design calculations. The loads associated with EPU are being incorporated into the analyses of these features, in combination with the other applicable loading as prescribed by the design criteria.

Consequently, the planned modifications will not change the high confidence of low probability of failure (HCLPF) values as determined by the seismic margins analysis.

NRC Request SPSB-A.14.b Describe the impact that the proposed modifications have on the probability distribution function of containment strength used in the LERF analysis.

TVA Reply to SPSB-A.14.b Following the review of EPU-related plant changes, the assumption was made that the probability distribution function of containment strength used in the LERF analyses for Unit 2 and unit 3 would not be significantly changed. This assumption that EPU-related changes do not significantly impact the containment strength was confirmed via the unit 1 containment response analysis. Unit-specific containment response notebooks were not updated for Unit 2 or Unit 3.

NRC Request SPSB-A.15 TVA has previously requested a full-scope application of an alternative source term. As part of this request, it was proposed that the standby liquid control system be used to help control suppression pool pH during severe accidents. Has suppression pool pH control been credited in the LERF analysis? If so, provide the details.

TVA Replv to SPSB-A.15 Suppression pool pH control using the Standby Liquid Control (SLC) System has not been credited in the LERF analysis for BFN. SLC injection of sodium pentaborate solution assists in buffering suppression pool pH thereby preventing accident iodine fission product re-evolution from the pool to the containment. This use of the SLC system does not adversely impact the BFN severe accident management program, i.e.,

it has no effect on initiating events or equipment requirements to mitigate core damage.

Therefore, it is not relevant to the concept of core damage and large releases as analyzed in the BFN PRA.

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NRC Request SPSB-A.16 Describe the operator actions considered in the estimation of LERF. How are the Severe Accident Management Guidelines accounted for in the LERF analysis?

TVA Reply to SPSB-A.16 The operator actions considered in the LERF analysis are all associated with implementing the Severe Accident Management Guidelines (SAMGs). These actions are provided in the table below.

Table SPSB-A.17-1 Operator Actions Considered In LERF Analysis Action Comment Depressurize Late depressurization or maintaining successful depressurization from level 1. This Reactor Pressure allows use of low pressure injection systems to inject to the RPV to prevent or mitigate Vessel (RPV) continued core melt progression and, prevention of high pressure blowdown induced failure modes of containment if the RPV is breached.

RPV Injection Post core damage injection with Core Spray or RHR in the LPCI mode. Injection of water into the vessel can mitigate the consequences of a core melt by preventing or substantially mitigating containment challenges.

Drywell Spray RHR in the Drywell Spray mode. The spray system can be employed to accomplish two important functions: (1)scrubbing fission products that are not otherwise scrubbed and, (2)providing water to cool the core debris on the drywell floor to limit non-condensable gas generation and to limit drywell heating and the associated temperature induced failures that can lead to containment failure.

Containment Entry into the SAMGs calls for flooding of containment from external water sources.

Flooding Prior to vessel breach, limitations are imposed to maintain the pressure suppression function by terminating containment flooding within the torus. After vessel breach has been identified, the operators are requested to once again flood containment. Flooding of containment has desirable effects of cooling the core debris, maintaining a low drywell temperature, and scrubbing airborne fission products and fission products from the melt release.

NRC Request SPSB-A.17 Address the questions in the SRP, Chapter 19, Table 111-1 concerning low power and shutdown PRA.

TVA ReDlv to SPSB-A.17 BFN does not have a low power or shutdown PRA. Therefore, the SRP questions relating to low power and shutdown PRA are not applicable. BFN uses the EPRI Outage Risk Assessment and Management (ORAM) technology software. This E-101

evaluation process assists with maintaining adequate defense-in-depth of safety functions when planning and conducting outages.

NRC Request SPSB-A.18 Provide an assessment of the PRA's technical adequacy as discussed in RG 1.200.

Note that it is acceptable to perform the assessment by making either (a) a direct assessment against the requirements of the American Society of Mechanical Engineers (ASME) PRA Standard Addendum A (ASME SA-Ra-2003), or (b) a self-assessment using the guidance issued on August 16, 2002, by the Nuclear Energy Institute (NEI) that supplements NEI 00-02.

TVA Reply to SPSB-A.18 As discussed in Section 10.5.7 of Enclosure 4 (PUSAR) of the initial application (Reference 1), the BFN Units 2 and 3 PRAs underwent a Peer Review Certification under the BWROG Peer Certification Committee. The observations identified during that review were transmitted to the NRC by letter dated August 17, 2004, letter (Reference 24) to support NRC review and closure of the NRC Generic Letter 88-20 for BFN Unit 1. In 2001, TVA performed an assessment of the BFN Units 2 and 3 PRA program. The scope of that assessment included:

• Review of the BWROG PSA Peer Certification and evaluation of BFN corrective actions.

• Determination of the current BWROG PSA Peer Certification element and overall grade based on the updated Unit 2 and Unit 3 models.

• Interview of PSA "customers" to determine areas of need for model expansion and/or future PSA use, with emphasis on future applications.

• Review of the PSA notebook documentation for accuracy and improvements.

• Review of the PSA computer code control and computer code training (e.g. MAAP, RISKMAN, STADIC).

• Review of past Problem Evaluation reports (PERs) on PSA and determine if problems were appropriately resolved.

• Review of PSA overview training for site organizations to determine if population is appropriate and training is sufficient.

• Review of on-line maintenance risk assessment practices to determine sufficiency.

• Review of Corporate PSA policies and directives to evaluate BFN compliance.

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• Review update data sources (e.g. initiating events, common cause, etc.) to evaluate appropriate use/enhancements.

• Evaluation of staffing/training requirements for current and future PSA needs.

The above objectives were met by reviewing materials at the BFNP site and by interviewing personnel familiar with the use of the model at the site. The Thermal Hydraulic Analysis, Data, and Containment Performance Facts and Observations were determined to have been satisfactorily resolved and those sub-elements with a grade 2 were considered reclassified to a sub-element grade of 3.

The following strengths were observed:

1. The PSA model was determined to have been extensively updated and the BWR Owners Group significant peer team findings resolved.

2. Although a number of Corrective Action documents were written, they had been resolved except for two that were subsequently resolved. This demonstrated a good attention to the model fidelity and resolution of issues.

No new findings were identified. Several recommendations were identified.

Since performance of that assessment, and as discussed in the introduction provided at the front of this SPSB section, TVA has updated the BFN Units 2 and 3 models to reflect operation of all three BFN units at EPU conditions. This is considered a significant enhancement to the BFN Units 2 and 3 PRA programs. These updates provided another opportunity to review the models and make identified enchantments.

TVA's application for extended power uprate is not a risk-informed application as defined in Regulatory Guide 1.174, in that this application does not "go beyond current staff positions." The BFN Units 2 and 3 applications were developed consistent with NRC-established positions as documented, largely, in Enclosure 4 (PUSAR) of the initial applications (Reference 1). Notwithstanding this position, TVA recognizes the value that risk insights, based on a high-quality PRA model, adds to the process of evaluating plant operation including evaluating plant changes. Accordingly, TVA actively uses and reviews its PRA models.

NRC Request SPSB-A.19 Provide an explanation the following:

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NRC Request SPSB-A.19.a Why does CDF decrease and LERF increase (EPU compared to baseline) for inadvertent opening of one MSRV, inadvertent opening of two or more MSRVs and flood from torus?

TVA Reply to SPSB-A.19.a During the EPU model development for Unit 2, the model development for EPU included changes to event tree structure to allow questioning of the condenser as a heat sink and allowed for successful mitigation if the condenser and condensate were available with level control. In the previous model the condenser was not asked following loss of high-pressure injection. The successful mitigation rules require success of the condenser acting as a heat sink, i.e.; top event CD=S. This difference allowed the core damage value to decrease slightly for initiator categories inadvertent opening of a single safety relief valve and inadvertent opening of two or more relief valves.

The LERF for these initiators increased due to ATWS sequences. The human error probability for failure to initiate SLC increased from 4.41 E-3 in the pre-EPU model to 1.161 E-2 in the EPU model.

The rules to determine the level 1 end sates also included model refinements. One result of these changes was to characterize some sequences such that they were evaluated for LERF in the post-EPU models where they had not been evaluated for LERF in the pre-EPU models. There were two ramifications of this. First, passing such sequences through the LERF event trees tended to increase truncation sensitivity as the LERF event tree contains some large split fractions. This tends to lower the CDF estimates. The ramification is that evaluating additional sequences in the LERF event tree acts to increase the frequency of LERF.

For the initiator category flood from the torus both ramifications occurred.

NRC Request SPSB-A.19.b For "flood from torus," why is the LERF increase greater than the magnitude of the CDF decrease?

TVA Reply to SPSB-A.19.b The response to NRC Request SPSB-A. 19.a discusses the reasons why the LERF increases is greater than the magnitude of the CDF decrease.

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NRC Reauest SPSB-A.19.c For Unit 2, why does CDF decrease and LERF increase for "EECW flood in reactor building - shutdown unit?"

TVA Reply to SPSB-A.19.c The CDF decreases because of the event tree structural changes discussed in the response to NRC Request SPSB-A.19.a. The LERF decrease is due to increases in the HEP for initiating SLC in ATWS sequences.

NRC Request SPSB-A.19.d For Unit 3, why does CDF decrease and LERF increase for "EECW flood in reactor building - operating unit?"

TVA Reply to SPSB-A.19.d The reasons are the same as the reasons specified for flood from the torus in response to NRC Request SPSB-A.19.a.

NRC Request SPSB-A.20 Explain why the CDF estimates for some initiating events have notably increased for the post-EPU plant as compared to the pre-EPU plant. Relate the explanation to one or more of the PRA model changes identified in Section 10.5 of Enclosure 4 of the June 25, 2004, submittal. As a minimum, increases in the CDF estimates for the following initiating events must be explained:

a. Loss of 500 kilovolt (kV) to one unit

b. Loss of condenser heat sink

c. Turbine trip with bypass

d. Small turbine building flood (Unit 3 only)

TVA Reply to SPSB-A.20 Following EPU implementation, enhanced CRD flow to the reactor vessel is no longer viable as the sole source of early high pressure as it was prior to EPU conditions. This is the reason for the increases in the CDF estimate for the four initiating event categories in parts a through d.

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NRC Request SPSB-A.21 Explain why the CDF estimates for some initiating events have decreased for the post-EPU plant as compared to the pre-EPU plant. Based on the description (Section 10.5 of Enclosure 4 of the June 25, 2004, submittal) the PRA model changes made to reflect the post-EPU plant configuration, the NRC staff noted a slight decrease in the CDF estimate for any initiating event. Specifically:

a. Inadvertent opening of one MSRV

b. Inadvertent opening of two or more MSRVs (Unit 2 only)

c. Total loss of offsite power

d. Loss of raw cooling water (Unit 2 only)

e. Small LOCA

f. EECW flood in reactor building - shutdown unit (Unit 2 only)

g. EECW flood in reactor building - operating unit h.. Flood from the condensate storage tank

i. Flood from the torus

j. Large turbine building flood (Unit 2 only)

TVA RepIv to SPSB-A.21 The reasons for the decreases are discussed in the following paragraphs. In some cases, the reasons have already been addressed in responses to other RAls. For such cases, please refer to the other RAI responses.

a. Inadvertent opening of one MSRV See the response to RAI 19a.

b. Inadvertent opening of two or more MSRVs (Unit 2 only)

See the response to RAI 19a.

c. Total loss of offsite power The reason for the difference is the structural difference in the frontline event tree.

d. Loss of raw cooling water E-106

The loss of raw cooling water initiating event in the EPU model uses the same event tree as discussed in the response to Question 19a. The structure of the tree is such that there exists branches for some sequences that are not minimal. This structure together with truncation limitations accounts for the slight difference.

e. Small LOCA The reason is the same reason specified in the response to RAI 19a regarding structural changes to the event tree.

f. EECW flood in reactor building- shutdown only (unit 2 only)

See the response to RAI 19c.

g. EECW flood in reactor building - operating unit See the response to RAI 19d.

h. Flood from the condensate storage tank The reason for the decrease is the same reason discussed in the response to 21 d.

i. Flood from the torus.

See the response to RAI 19 a.

j. Large turbine building flood (Unit 2 only)

See the response to 19d.

NRC Request SPSB-A.22 Provide a list of the significant basic events contained in the PRA logic model (including both the basic event name, the basic event description, the Fussell-Vesely importance measure and the Risk Achievement Worth) for the post-EPU plant configuration. Note that term "significant basic event" is defined in RG 1.200, Appendix A, Table A-1, Index Number 2.2.

TVA Reply to SPSB-A. 22 The following tables provide significant basic events by Fussell-Vesely (FV) importance and by Risk Achievement Worth (RAW), respectively for Units 2 and 3.

BFN Unit 2 Significant Basic Events by Fussell-Vesely Importance Measure Rank Basic Event Name Description Fussell-Vesely Importance 1 HERHPRVD1 Operator Failure to Depressurize Given HPCI/RCIC 2.9252E-001 Hardware Failed 2 RODS5 Generic RPS Failure Rate per NUREG 1.4332E-001I E-107

BFN Unit 2 Significant Basic Events by Fussell-Vesely Importance Measure Rank Basic Event Name Description Fussell-Vesely Importance 3 OPERR-OLP2 Operator fails to Open Hardened Wetwell Vent - AC 1.3642E-001

_PERFLOLP2 Power Available - Action To 0 Initiate SPC Failed 4 Ul FALLHUMAN Top Event Ul Fails All Support, Human Contribution 1.2896E-001 5 OH2Operator Fails to Control HPCl/ RCIC Injection 1.2477E-001 5 OHL2 GIVEN OHC Failed 6 OHC1 Operator Fails to take early action to Control HPCI/ 1.1495E-001 RCIC Injection ______ _____

7 CONDENSER_2A212C Main Condenser Unavailable After Plant Trip 1.0461 E-001 8 PTSFS2PMP0730054 HPCI Pump Fails to Start On Demand 8.6238E-002 9 PTSFR2PMP71019_6 RCIC Turbine Driven Pump Fails to Run 7.4141 E-002 10 OPERROSP1 Operator Fails to Align for Suppression Pool Cooling 7.3300E-002 11 [DGAS] Common Cause: Group Unit 1/2 DGs 1/4 6.6680E-002

[MOVFO2FCV0230040 MOVFO2FCV0230034 5.7334E-002 12 MOVFO2FCV0230046 MOVFO2FCV0230052] Common Cause: Group RHR Heat Exchangers, 4/4 13 PTSFS2PMP0710019 Turbine Driven Pump Fails to Start On Demand 5.6459E-002 14 PTSFR2PMP73054_6 HPCI Pump Fails During Operation 5.4494E-002 15 [DGAS DGBS DGCS DGDS] Common Cause: Group Unit 1/2 DGs, 4/4 4.7032E-002 16 [DG3AS] Common Cause: Group Unit 3 DGs, 1/4 4.6180E-002 17 OUIll Operators Fail to Align Ul RHR Loop II though X- 3.6267E-002 TIE to U2 RHR LOOP I 18 [DGBS] Common Cause: Group Unit 1 and 2 DGs, 1/4 3.5607E-002 19 OU12 Operator Action to Align RHRSW to Unit 2 RHR 2.7902E-002 Loop I Fail 20 IRL1 FD2RLY1 OAK9A Common Cause: Group RHR Pump Actuation 2.7492E-002 RL1 FD2RLY1 OAK9B] Relays (K9), 2/2 21 PTSFR2PM73054_18 HCIC Pump Fails to Run for 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> 2.6800E-002 22 PTSFR2PM71019_18 HPCI Pump Fails to Run for 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> 2.5614E-002 23 BEIVR10 Recovery of RHRSW 2.3671 E-002 24 PTSFS1CCF_RCIHPI HPCI and RCIC Common Cause Failure to Start 2.2918E-002 25 MOVFC2FCV0710034 Valve FCV-71-34 Fails to Close On Demand 2.0865E-002 26 [PMSFS2PMP0740028] Common Cause: Group RHR Pumps Fail to Start, 1.9391 E-002 1/4 27 [MOVFO2FCV0710008] Common Cause: Group RCIC Steam Supply, 1/2 1.9189E-002 28 [MOVFO2FCV0710039] Common Cause: Group HPCI RCIC Pump 1.9189E-002 Discharger MOV failure, 1/2 29 PTSFR1CCFRCIHPI HPCI and RCIC Pumps Failure to Run 1.6112E-002 30 MOVFC2FCV0730040 MOV 2-FCV-73-40 Fails to Close On Demand 1.5896E-002 E-108

BFN Unit 2 Significant Basic Events by Fussell-Vesely Importance Measure Rank Basic Event Name Description Fussell-Vesely Importance 31 MOVFO2FCV0730027 MOV 2-FCV-73-27 Fails to Open On Demand 1.5896E-002 32 MOVFO2FCV0730026 MOV 2-FCV-73-26 Fails to Open On Demand 1.5896E-002 33 [MOVFO2FCV0710008 1.5499E-002 MOVFO2FCV0730016] Common Cause: Group RCIC Steam Supply, 2/2 34 [MOVFO2FCV0710039 Common Cause: Group HPCI RCIC Pump 1.5499E-002 MOVFO2FCV0730044] Discharger MOV failure, 2/2 35 BE FRACT3 Unit 2 Large or Medium LOCA and Unit 1 not at 1.5454E-002 BEFACT3Power - Macro CASB 36 [DG3BS] Common Cause: Group Unit DGs, 1/4 1.5133E-002 37 [MOVFO2FCV0730016] Common Cause: Group RCIC Steam Supply, 1/2 1.461 OE-002 38 [MOVFO2FCV0730044] Common Cause: Group HPCI RCIC Pump 1.4610E-002 Discharger MOV failure, 1/2 39 [DGCS] Common Cause: Group Unit 1/2 DGs, 1/4 1.4307E-002 40 [MOVF02FCV0230034] Common Cause: Group RHR Heat Exchangers, 1/4 1.3554E-002 41 BERBE5 Reactor Building Essentially Bypassed 1.1 949E-002 42 MOVFO2FCV0740100 Valve 2-FCV-74-100 Fails to Open On Demand 1.1299E-002 43 [DGAS DGBS DGCS] Common Cause: Group Unit 1/2 DGs, 3/4 1.0421 E-002 44 U1 FHXHUMAN Top Event Ul Fails Loss of Support To RHR 1B 9.9190E-003 And HX, Human action 45 MOVF01 FCV0740101 Unit 1 RHR HX Outlet X-TIE 1-FCV-74-101 Fails to 8.5658E-003 MOVF1 FCO74O 01 Open On Demand 46 BSBCD Battery SB-C Fails On Demand. 8.4786E-003 47 [PMSS2PM0740Common Cause: Group RHR Pumps Fail to Start, 78899E-003 47 [PMSFS2PMP0740005] 1/4789E03

[PMSFS2PMP0740005 48 PMSFS2PMP07400166.16-0 PMSFS2PMP0740028 Common Cause: Group RHR Pumps Fail to Start, 7.0156E-003 PMSFS2PMP0740039] 4/4 49 SWCS CCF (Failure to Start) of All RHRSW Pumps 6.7449E-003 50 CHSBC2R SB-C Fails During Operation 6.7092E-003 51 BEIVR1 C1 & C3, RPV at High Pressure 5.6750E-003 52 [B1iD] Common Cause: Group Battery Boards 1, 2, and 3, 5.6001 E-003 1/2 53 MOVFO2FCV0740047 Valve FCV-74-47 Fails to Open On Demand 5.4386E-003 54 MOVF02FCV0740048 Valve FCV-74-48 Fails to Open On Demand 5.4386E-003 55 OHC3 Operator Fails to Take Early Action to Control RCIC 5.3937E-003 5OHC2 4 neCtmmon ____Cas:GopLoIan11PCTet503E0 56 [MOVFC2FCV0740057] Common Cause: Group Loop I and II LPCI Test 5.0337E-003 Return, 1/2 E-109

BFN Unit 2 Significant Basic Events by Fussell-Vesely Importance Measure Rank Basic Event Name Description Fussell-Vesely Importance 57 [MOVFC2FCV0740012] Common Cause: Group Shutdown Cooling Valves 5.0337E-003 (Required to Close),1/4 5.0337_-003 58 [MOVFC2FCV0740001] Common Cause: Group Shutdown Cooling Valves 5.0337E-003 (Required to Close), 1/4 E-110

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 1 RODS5 Generic RPS Failure Rate per NUREG 5.5730E+004 2 SWCS CCF (Failure to Start) of All RHRSW Pumps 1.6085E+004 3 SWCR CCF (Failure to Run) of All RHRSW Trains 1.6085E+004 4 [B1D B2D B3D] Common Cause: Group Battery Boards 1, 2, and 3, 4.0414E+003 3/3 5 [CH12R CH22R CH32R] Common Cause: Group Chargers for Battery 3.9541 E+003 Boards, 3/3 6 ECCS-SUPPLYTRAN Insufficient Flow to ECCS Suction Ring Header 3.1263E+003

_ During Transient

[PMSFS2PMP0740005 7 PMSFS2PMP0740016 Common Cause: Group RHR Pumps Fail to Start, PMSFS2PMP0740028 4/4 1.6569E+003 PMSFS2PMP0740039]

[RL1 FD2RLY1OA117B RL1 FD2RLY1 OA119B 8 RL1FD2RLY1OA123A Common Cause: Group RHR Pumps Actuation 1.6569E+003 RL1FD2RLY1OA111B Relays, 6/6 RL1 FD2RLY1OA124A RL1 FD2RLY1OA130A]

[RL1FD2RLY1OAK18A RL1FD2RLY1OAK18B 9 RL1 FD2RLY1OAK21A Common Cause: Group RHR Pumps Actuation 1.6569E+003 RL1FD2RLY10AK21B Relays (2nd Set), 6/6 RL1 FD2RLY1 OAK25A RL1 FD2RLY1OAK25B]

10 [RLI FD2RLY10AK9A Common Cause: Group RHR Pump Actuation 1.6569E+003 RL1 FD2RLY1 OAK9B] Relays (K9), 2/2 11 HER_HPRVD1 Operator Failure to Depressurize Given HPCI/RCIC 1.5560E+003 Hardware Failed

[PMSFS2PMPO740005 Common Cause: Group RHR Pumps Fail to Start, 1.34E+003 PMSFS2PMP0740028]

13 [BID B2D] Common Cause: Group Battery Boards 1, 2, and 3, 1.1195E+003 2.12 14 [CH12RCH22R] Common Cause: Group Chargers for Battery 1.0913E+003

[CH1R CH2R]Boards, 2/2 15 OPERR_OSP1 Operator Fails to Align for Suppression Pool Cooling 9.6883E+002 16 FN2FR2FAN098062] Common Cause: Group SAI Panel Coolers, 2/2 4.0213E+002

[MOVF02FCV0230040 17 MOVF02FCV0230046 Common Cause: Group RHR Heat Exchangers, 4/4 3.8400E+002 MOVF02FCV0230052]

E-111

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 18 WABCD Motor Operated Ventilation Dampers Fail to Open or 3.4151 E+002 Fans Fail to Start or Run.

19 DGAS D Common Cause: Group Unit 1/2 DGs, 4/4 3.4151 E+002 DGDS]__ _ _ _ _ _ _ _ _ _ _

[PMOFR2_02300A3 20 PMOFR2=02300B3 Common Cause: Group EECW Pumps, 4/4 2.1344E+002 PMSFR2 02300C3 PMSFR2 02300D3]__ _ _ _ _ _ _ _ _ _ _ _ _

[RL1 FD2_00374A1 21 RL1 FD2 00374B1 Common Cause: Group Low RX Pressure 1.4418E+002 RL1 FD2 0680951 Permissive Output Relays, 4/4 RL1 FD2_0680961 ]

[RL1 FD214A0750K9A 22 RL1 FD214A0750K9B Common Cause: Group Low RX Pressure 1.4418E+002 RL1FD214A075K23A Permissive Relays (CSS), 4/4 RL1 FD214A075K23B]

[SWDFD2PIS003074A 23 SWDFD2PIS003074B Common Cause: Group Low RX Pressure 1.4417E+002 SWDFD2PIS0680095 Permissive Bistables, 4/4 SWDFD2PIS0680096]

24 [RL1 FD214A075K13A Common Cause: Group Low RX Pressure 1 447E+02 RL1FD214A075K13B] Permissive Logic Relays, 2/2

[PMSFR2_02300B1 25 PMSFR2_02300B2 Common Cause: Group RHRSW South Header 1.2418E+002 PMSFR2_02300D1 Pumps, 4/4 PMSFR2_02300D2]1

[PMSFS2_02300B1 26 PMSFSZ_02300B2 Common Cause: Group RHRSW South Header 1.2418E+002 PMSFS2_02300D1 Pumps, 4/4 PMSFS2O02300D2]

27 OHC1 Operator Fails to take early action to Control HPCU 1.0927E+002 RCIC Injection__ _ _ _ _ _ _ _ _ _ _ _ _ _

28 OPERROLP1 Operator Fails to Manually Control LPCI/CS 1.0791 E+002 29 [DGAS DGBS DGCS] Common Cause: Group Unit 1/2 DGs, 3/4 8.8614E+001 30 [B16140 B16160 B17180] Common Cause: Group Unit 1 and 2 4kV Shutdown 7.4055E+001 Board Feeder Breakers, 3/4 31 [B16140 B16160 B17180 Common Cause: Group Unit 1 and 2 4kV Shutdown 7.4055E+001 B117240] Board Feeder Breakers, 4/4

[MOVFO2FCV0230034 32 MOVFO2FCV0230040 Common Cause: Group RHR Heat Exchangers, 3/4 5.6980E+001 MOVFO2FCV0230046]

[PMOFS2_02300B3 33 PMSFS2 02300C3 Common Cause: Group EECW Pumps, 4/4 5.3624E+001 PMSFS2=02300D3]

1.

E- 112

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 35 [MO VFO2FCV071 0008 MOVFO2FCV0730016 Common Cause: Group RCIC Steam Supply, 2/2 4.5923E1+001 MOVF02FCV073001 6] ______________

36 [MOVFO2FCV0710039 Common Cause: Group HPCI RCIC Pump 45923E+01 MOVFO2FCV0730044] Discharge MOV failure, 2/2 34 PTSFS1CCFRCIHPI HPCI and RCIC Common Cause Failure to Start 4.5923E+001 3 [RL12RLY23AK25 Common Cause: Group HPCVRCIC Actuation 4.5923E+001 RL1FD2RLY0710K22] Relays, 2/4 38 [RL1 FD223AK21 Common Cause: Group HPCVRCIC Actuation 45923E001 RL1 FD2RLY071 0K22] Relays, 2/4 39 PTSFR1CCFRCIHPI HPCI and RCIC Pumps Failure to Run 4.5923E+001 40 [RL1 FD223AK22 Common Cause: Group HPCI/RCIC Actuation 45923E+01 RL1 FD2RLY071 0K22] Relays, 2/4

[RL1 FD223AK21 41 RL12RLY23AK25 Common Cause: Group HPCI/RCIC Actuation 4.5540E+001 RL1 FD223AK22 Relays, 4/4 RL1 FD2RLY071 OK22]

[RL12RLY23Ai25 Common Cause: Group HPCI/RCIC Actuation 42 RL1 FD223AK21 Common3 u4 4.5447E+001 RL1 FD2RLY071 OK22] ys,

[RL1 FD223AK21 Common Cause: Group HPCI/RCIC Actuation 43 RL1 FD223AK2 Reas,3 4.5447E-i001 RL1 FD2RLY071 OK22] ys,

[RL12RLY23A_i22 Common Cause: Group HPCI/RCIC Actuation 45447E+1 44 RL1 FD223AK22Reas34454701 RL1 FD2RLY071 OK22] ys, 45 ECCS_ SUPPLYLOST Insufficient Flow Available to Ring Header During 4.1763E+001 ECCSUPPLLOST LOCA 46 PRESSSPRESLOST PSP Fails to Quench Steam During LOCA 4.1763E+001 Blowdown

[PMSFS2PMP0740005 Common Cause: Group RHR Pumps Fail to Start, 3.9076E+001 47 PMSFS2PMP07400166 43976+

PMSFS2PMP0740039]

48 HOVXC2HCV0740085 Unit 2 SPC Isolation 2-HCV-74-85 Transfers Closed 3.6165E+001

[PMOFR2_02300A3 49 PMOFR2_02300B3 Common Cause: Group EECW Pumps, 3/4 3.5674E+001 PMSFR2_02300C3]

50 MOVXC2FCV0740007 FCV-74-7 Transfers Closed 3.4609E+001 51 HOVXC2HCV0670565 Valve 67-565 Transfers Closed 3.4300E+001 52 [PMSFS2PMP0740005 Common Cause: Group RHR Pumps Fail to Start, 3.3537E+001 PMSFS2PMP0740016] 2/4 53 [DGAS DGBS DGDS] Common Cause: Group Unit 1/2 DGs, 3/4 3.1780E+001 E-1 13

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth

[PMSFS2PMP0740005 Common Cause: Group RHR Pumps Fail to Start, 3.091 OE+001 PMSFS2PMP0740039]

[PMSFS2PMP0740016 Common Cause: Group RHR Pumps Fail to Start, 2.9663E+001 PMSFS2PMP0740039]

56 OHL2 Operator Fails to Control HPCI/ RCIC Injection 2.8644E+001 GIVEN OHC Failed 57 DG3DS Common Cause: Group Unit 3 DGs, 4/4 2.8186E+001 D G 3D S] _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

58 W3ABCD Motor Operated Ventilation Dampers Fail to Open or 2.81 86E+001 Fans Fail to Start 59 ESDAR Shutdown Board A Bus Fault 2.7537E+001 60 B1614to Breaker 1614 Transfers Open 2.6644E+001 61 [PMSFS2PMP0740005 Common Cause: Group RHR Pumps Fail to Start, 2.4565E+001 PMSFS2PMP0740028] 2/4

[PMOFR2_02300A3 62 PMOFR2_02300B3 Common Cause: Group EECW Pumps, 3/4 2.4273E+001 PMSFR2_02300D3]

[RV2FOPCV001 0005 RV2FOPCV0010019 63 RV2FOPCV0010022 Common Cause: Group SRVs (Depressurization), 2.3503E+001 RV2FOPCV0010030 6/6 RV2FOPCV0010031 RV2FOPCV0010034]

[RV2FOPCV0010019 RV2FOPCV001 0022 64 RV2FOPCV0010030 Common Cause: Group SRVs (Depressurization), 2.3503E+001 RV2FOPCVO010031 5/6 RV2FOPCV0010034]

[RV2FOPCV0010005 65 RV2FOPCV0010022 Common Cause: Group SRVs (Depressurization), 2.3503E+001 RV2FOPCV001 0031 RV2FOPCV0010034]

[RV2FOPCV0010005 RV2FOPCV0010019 Common Cause: Group SRVs (Depressurization), 2.3503E+001 66 RV2FOPCV0010030 5/6 RV2FOPCV0010031 RV2FOPCV001 0034]

[RV2FOPCV0010005 67 RV2FOPCV0010019 Common Cause: Group SRVs (Depressurization), 2.3503E+001 RV2FOPCV0010030 5/6 RV2FOPCV0010034]

E-114

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth

[RV2FOPCV0010005 RV2FOPCV0010019 Common Cause: Group SRVs (Depressurization), 2.3503E+001 68 RV2FOPCV001 0022 5/6235E01 RV2FOPCV001 0030 RV2FOPCV0010031]

[RV2FOPCV0010005 69 RV2FOPCV0010019 Common Cause: Group SRVs (Depressurization), 2.3503E+001 RV2FOPCV001 0031 5/6 RV2FOPCV001 0034]

70 [RL1 FD2RLY10AK18A Common Cause: Group Relay3, 2/6 2.2912E+001 RL1lFD2RLYIOQAKi18B]

71 [RL1FD2RLY1OA111B Common Cause: Group Relayl, 2/6 2.2912E+001 72 [PMSFS2PMP0740016 Common Cause: Group RHR Pumps Fail to Start, 2.2250E+001 PMSFS2PMP0740028] 2/4 73 [DGAS DGCS DGDS] Common Cause: Group Unit 1/2 DGs, 3/4 2.2145E+001

[PMOFR2_0230083 74 PMSFR2_02300C3 Common Cause: Group EECW Pumps, 3/4 2.1912E+001 PMSFR2_02300D3]

75 [DGBS DGCS DGDS] Common Cause: Group Unit 1/2 DGs, 3/4 2.1282E+001 76 [BID B3D] Common Cause: Group Battery Boards 1, 2, and 3, 2.1212E+001 213

[RV2FOPCV0010019 77 RV2FOPCV0010022 Common Cause: Group SRVs (Depressurization), 2.0760E+001 RV2FOPCV001 0030 4/6 RV2FOPCV001 0034]

[RV2FOPCV0010022 78 RV2FOPCV0010030 Common Cause: Group SRVs (Depressurization), 2.0760E+001 RV2FOPCV001 0031 4/6 RV2FOPCV0010034]

79 [B16140 B16160] Common Cause: Group Unit 1 and 2 4 Shutdown 1.9896E+001 0 [B16140 B16160] BBoard Feeder Breakers, 2/4 Common Cause: Group Unit 1 and 2 4kV Shutdown 80 [B16140 B16160 B17240] BoredrBekr,341 .9896E-i001 81 [DG3AS DG3BS DG3CS] Common Cause: Group Unit 3 DGs, 3/4 1.8553E+001 82 E1201 R Unit 1 Preferred Bus 2 BD 9-9 Failed 1.8490E+001 83 ZFESFD Auto Bus Transfer Switch 1 Fails 1.8490E+001 84 [CH12R CH32R] Common Cause: Group Chargers for Battery 1.8273E+001 Boards, 2/3

[RV2FOPCVOO10019 85 RV2FOPCV0010022 Common Cause: Group SRVs (Depressurization), 1.8174E+001 RV2FOPCV0010030 4/6 RV2FOPCV0010031]

E-115

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth

[RV2FOPCVO010019 86 RV2FOPCV0010030 Common Cause: Group SRVs (Depressurization), 1.8171 E+001 RV2FOPCV0010031 4/6 RV2FOPCV0010034]

[RV2FOPCV0010019 87 RV2FOPCV0010022 Common Cause: Group SRVs (Depressurization), 1.8150E+001 RV2FOPCV001 0031 4/6 RV2FOPCV0010034]

88 CHSBC2R SB-C Fails During Operation 1.7912E+001 89 LXC2R Output Fuse Switch-X Fails Open. 1.7912E+001 90 B17B12T Input Breaker 17B1 Fails Open. 1.7912E+001 91 ESBCR SB-C Bus Fails 1.7830E+001 92 BSBCD Battery SB-C Fails On Demand. 1.7830E+001

[PMOFSZ-02300A3 93 PMOFS2_02300B3 Common Cause: Group EECW Pumps, 3/4 1.7537E+001 PMSFS2_02300C3]

[PMSFRZ-02300B1 Common Cause: Group RHRSW South Header 94 PMSFR2-02300B2 Pup,41 .7395E+001 PMSFR2 02300D1] Pu

[PMSFS2_02300B1 Common Cause: Group RHRSW South Header 1.7376E+001 95 PMSFS2-02300B32 Pms 1 .36+

PMSFS2-02300D1] Pu 96 [DGAS DGBS] Common Cause: Group Unit 1/2 DGs, 2/4 1.7000E+001

[PMSFR2=02300B2 Common Cause: Group RHRSW South Header 1.6206E+001 97 PMSFR2-02300132 Pms 1 .26+

PMSFR2_02300D2] Pumps, 3/4

[PMSFS2_02300B1 Common Cause: Group RHRSW South Header 1.6184E+001 98 PMSFS2ZO2300B2 Pms 1 .14+0 PMSFS2=02300D2] Pumps, 3/4

[MOVFO2FCV0230034 99 MOVFO2FCV0230040 Common Cause: Group RHR Heat Exchangers, 3/4 1.4583E+001 MOVFO2FCV0230052]

100 [B2D B3D] Common Cause: Group Battery Boards 1, 2, and 3, 1.3611 E+001 2/3 101 [BiD] Common Cause: Group Battery Boards 1, 2, and 3, 1.2150E+001 1/2 102 EBB1R Battery BD. 1 Bus Fails. 1.1516E+001 103 B2A1CT Output Breaker IC Transfers Open 1.1301EE+001 104 BE2A5T Input Breaker 5 Transfers Open 1.1301E+001 105 [CH22R CH32R] Common Cause: Group Chargers for Battery 1.1290E+001 Boards, 2C3 106 MOF FC0304 Common Cause: Group RHR Heat Exchangers, 2/4 1.1285E-e001 MOVF02FCV0230040]______________

E-116

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 107 B16072T Output Breaker 607 Transfers Open During 1.1194E+001 Operation.

108 [CH12R] Common Cause: Group Chargers for Battery 1.1132E+001 Boards, 1/2 109 B16D2T Input Breaker 6D Fails Open. 1.1101 E+001 110 ZTS2AR Transformer TS2A Fails During Operation 1.1048E+001 111 ESD2AR 480V Shutdown Bus 2A Fails 1.1032E+001 112 HOVXC2HCV0740088 Unit 2 SPC Isolation 2-HCV-74-88 Transfers Closed 9.6007E+000 113 [DG3AS DG3BS DG3DS] Common Cause: Group Unit 3 DGs, 3/4 9.5864E+000 114 B2D2AT Breaker 2D Transfers Open 9.5198E+000 115 B302T Feeder Breaker 302 Transfers Open During 9.5198E+000 Operation.

116 E2A250R 250V RMOV BD 2A Bus Failed. 9.5198E+000 117 HOVXC2HCV0670606 Valve 67-606 Transfers Closed 9.5019E+000

[PMOFR2_02300A3 118 PMSFR2_02300C3 Common Cause: Group EECW Pumps, 3/4 9.4045E+000 PMSFR2_02300D3]

119 MOVXC2FCV0740030 FCV-74-30 Transfers Closed 9.2901 E+000

[PMOFS2_02300A3 120 PMSFS2_02300C3 Common Cause: Group EECW Pumps, 3/4 9.2854E+000 PMSFS2_02300D3]

121 [DG3AS DG3BS] Common Cause: Group Unit 3 DGs, 2/4 9.0077E+000 122 [PMSFS2PMP0740028 Common Cause: Group RHR Pumps Fail to Start, 8.8652E+000 2 PMSFS2PMP0740039] 2/4 123 OHC3 Operator Fails to TAKE EARLY ACTION to Control 8.3241 E+000 RCIC Injection

[MOVFO2FCV0230034 124 MOVFO2FCV0230046 Common Cause: Group RHR Heat Exchangers, 3/4 8.2709E+000 MOVFO2FCV0230052]

125 OPERR_OSP3 125 . Operator Fails to ALIGN For SUPPRESSION POOL OPERFLOSP3COOLING805E00 8.0558E+000 126 [PMSFR2_02300B1 Common Cause: Group RHRSW South Header 7.8462E+000 PMSFR2_02300B2] Pumps, 2/4 127 [PMSFS2_02300B1 Common Cause: Group RHRSW South Header 7.8438E+000 PMSFS2_02300B2] Pumps, 2/4 128 [DGAS DGCS] Common Cause: Group Unit 1/2 DGs, 2/4 7.3618E+000 129 [PMSFS2PMP0740028] Common Cause: Group RHR Pumps Fail to Start, 7.3284E+000 1/4 130 [DGBS DGCS] Common Cause: Group Unit 1/2 DGs, 2/4 6.4992E+000 E-117

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 131 [MOVFO2FCV0710034 Common Cause: Group HPCI RCIC Return Lines 6.3719E+000 MOVXC2FCV0730036] MOVs, 2/4

[PMOFS2_02300A3 132 PMOFS2_02300B3 Common Cause: Group EECW Pumps, 3/4 6.2626E+000 PMSFS2.02300D3]

[MOVFO2FCV0710034 133 MOVXC2FCV0710038 Common Cause: Group HPCI RCIC Retum Lines 6.2125E+000 MOVXC2FCV0730035 MOVs, 4/4 MOVXC2FCV0730036]

134 OHC2 Operator Fails to TAKE EARLY ACTION to Control 6.1295E+000 HPCI Injection__ _ _ _ _ _ _ _ _ _ _ _ _ _

135 [MOVFO2FCV0710034 Common Cause: Group HPCI RCIC Retum Lines 6.0856E+000 MOVXC2FCV0730036]

136 [MOVF02FCV0710034 Common Cause: Group HPCI RCIC Retum Lines 6.0856E+000 MOVXC2FCV0730036] MOVs, 3/4

[MOVF02FCV0710034 Common Cause: Group HPCI RCIC Retum Lines 6.0856E+000 137 MOVXC2FCV071 0038 MOs 4608E00 MOVXC2FCV0730035] MOVs, 3/4 138 [MOVFO2FCV0710034 Common Cause: Group HPCI RCIC Retum Lines 5.9381 E+000 MOVXC2FCV0710038] MOVs, 2/4 139 [MOVFO2FCV0710008] Common Cause: Group RCIC Steam Supply, 1/2 5.8971E+000 140 [MOVF02FCV071 0039] Common Cause: Group HPCI RCIC Pump 5.8971 E+000 Discharge MOV failure, 1/2 141 MOVFC2FCV0710034 Valve FCV-71 -34 Fails to Close On Demand 5.8911 E+000

[PMSFR2_02300A1 142 PMSFR2=02300A2 Common Cause: Group RHRSW A and C Pumps, 4.9832E+ooo PMSFR2.02300C1 4/4 PMSFR2_02300C2]

[PMSFS2_02300A1 143 PMSFS2_02300A2 Common Cause: Group RHRSW South Header 4.9832E+000 PMSFS2_02300C1 Pumps, 4/4 PMSFS2_02300C2]

144 [RL1 FD2RLY0710K22] Common Cause: Group HPCVRCIC Actuation 4.9775E+000 Relays, 1/4 145 [MOVFO2FCV0230034 Common Cause: Group RHR Heat Exchangers, 2/4 4.9725E+000 MOVF02FCV0230046]______________

146 CSVFO2HCV0710014 Stop Check Valve HCV-71-14 Fails to Open On 4.9491 E+000 Demand 147 CKVFC2CKV0030568 Check Valve 3-568 Fails to Close On Demand 4.9464E+000 148 CKVFO2FCV0710040 Check Valve FCV-71 -40 Fails to Open On Demand 4.9464E+000 149 CKVFO2CKV0710580 Check Valve 71-580 Fails to Open On Demand 4.9464E+000 150 CKVFO2CKV0710502 Check Valve 71-502 Fails to Open On Demand 4.9464E+000 E-1 18

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 151 CKVFO2CKV0030572 RFW Line B Injection Valve 2-3-572 Fails to Open 4.9464E+000 On Demand

[MOVFO2FCV0230040 152 MOVFO2FCV0230046 Common Cause: Group RHR Heat Exchangers, 3/4 4.9090E+000 MOVF02FCV0230052]

153 SWLFD2 LS0710029 Level Switch 2-LS-71 -29 Fails to Operate On 4.8929E+000 Demand 154 MOVXC2FCV7102L6 Valve FCV-71 -2 Transfers Closed 4.8811 E+000 155 MOVXC2FCV7101936 Valve FCV-71 -19 Transfers Closed 4.8811 E+000 156 MOVXC2FCV071037_6 Valve FCV-71 -3 Transfers Closed 4.88 1E+000 157 MOVXC2FCV71037_6 Valve FCV-71 -37 Transfers Closed 4.8806E+000 158 MOVX02FCV71 038-6 Valve FCV-71 -38 Transfers Open 4.8806E+O000 159 Bi 1 2to Breaker 1112 Transfers Open 4.8788E+000 160 EUB1AR 4KV Unit Board 1A Fails 4.8788E+000 161 PTSFS2PMP0710019 Turbine Driven Pump Fails to Start On Demand 4.8644E+000 162 [B133340 B13360 B13380] Common Cause: Group Unit 3 4kV Shutdown Board 4.8598E+000 Feeder Breakers, 3/4 163 [B1 3360 B1]3340 B3380 Common Cause: Group Unit 3 4kV Shutdown Board 4.8598E+000 1313420] Feeder Breakers, 4/4 1 [PMSFR2_02300Al Common Cause: Group RHRSW A and C Pumps, 4.8425E+000 PMSFR2._02300C2]

[PMSFS2_02300A1 Common Cause: Group RHRSW South Header 165 PMSFS2-02300A2 Pup,344.8424E+000 PMSFS2_02300C2] ump, 166 PTSFR2PMP71 0196 RCIC Turbine Driven Pump Fails to Run 4.7934E+O0O 167 CKVLK2CK030568-6 Check Valve 3-568 Gross Back Leakage 4.7408E+000 168 [MOVFO2FCV0730016] Common Cause: Group RCIC Steam Supply, 1/2 4.7114E+000 169 [MO VFO2FC V0730044] Common Cause: Group HPCI RCIC Pump 4.7114E+000 Discharge MOV failure, 1/2 170 MOVFC2FCV0730040 MOV 2-FCV-73-40 Fails to Close On Demand 4.7097E+000 171 MOVFO2FCV0730027 MOV 2-FCV-73-27 Fails to Open On Demand 4.7097E+000 172 MOVFO2FCV0730026 MOV 2-FCV-73-26 Fails to Open On Demand 4.7097E+000

[PMSFR2_02300B2 173 Common Cause: Group RHRSW South Header 4.7006E+000 PMSFR2 02300D2] Pumps, 3/4

[PMSFS2=02300B2 Common Cause: Group RHRSW South Header 4.6mE+o0 174 PMSFS2 __02300D1 Pup,3467E+0 PMSFS2 02300D2] Pumps, 3/4 175 MOVX02FCV71034_6 Valve FCV-71 -34 Transfers Open 4.6017E+000 E-119

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 176 MOVXC2FCV07108-6 Valve FCV-71 -8 Transfers Closed 4.6017E+000 177 MOVXC2FCV71039-6 Valve FCV-71 -39 Transfers Closed 4.6017E+000 178 [MOVFO2FCV0230034 Common Cause: Group RHR Heat Exchangers, 2/4 4.5785E+000 IMOVF02FCV0230052]_______________

179 [B2D] Common Cause: Group Battery Boards 1, 2, and 3, 4.5597E+000 1/2 180 [MOVFO2FCV0230034] Common Cause: Group RHR Heat Exchangers, 1/4 4.4578E+000 181 HOVXC2HCV0230031 Valve HCV-23-31 Transfers Closed 4.4175E+000 182 CKVFO2CKV0730517 Check Valve 2-CKV-73-517 Fails to Open On 4.4140E+000 Demand 183 CKVF02CKV0230579 Check Valve CKV-23-579 Fails to Open On Demand 4.4130E+000 184 CKVXC2CKV0230579 Check Valve CKV-23-579 Transfers Closed 4.4113E+000 185 HXRPL2HEX074900A Heat Exchanger 2A Plugs 4.411 OE+000 186 MOVXC2FCV0230034 Valve FCV-23-34 Transfers Closed 4.4108E+000 187 CONDENSER_2A2B2C Main Condenser Unavailable After Plant Trip 4.2416E+000 188 SMDFR2 _047 _ EHC Instrument Signal Modifier Failure 4.2247E+000 189 El VFD2FCV0470067 Master Trip Valve FCV 47-67 Fail to Operate On 4.2247E+000 190 E1VFC2FCV0010068 Turbine Bypass Valve FCV 1-68 Fail to Close 4.2247E+000 191 ElVFC2FCV0010069 Turbine Bypass Valve FCV 1-69 Fail to Close 4.2247E+000 192 El VXO2FCV0010068 Turbine Bypass Valve FCV 1-68 Transfers Open 4.2247E+000 193 ElVXO2FCV0010069 Turbine Bypass Valve FCV 1-69 Transfers Open 4.2247E+000 194 El VXO2FCV0010066 Turbine Bypass Valve FCV 1-66 Transfers Open 4.2247E+000 195 El VFC2FCV0010066 Turbine Bypass Valve FCV 1-66 Fail to Close 4.2247E+000 196 E1VFC2FCV0010067 Turbine Bypass Valve FCV 1-67 Fail to Close 4.2247E+000 197 TRPFR2_PT001016A PT 1-16A Fail During Operation 4.2247E+000 198 TRPFR2_PT0010106B PT 1-16B Fail During Operation 4.2247E+000 199 HOVXC2 0240587 Manual Valve 24-587 Transfers Closed 4.2247E+000 200 RL1 FD2XKT0470801 Master Trip Relay COIL XKT801 Fails to ENERGIZE 4.2247E+000 201 El VX02FCV0470067 Master Trip Valve FCy 47-67 Transfers Open 4.2247E+000 202 AOVXC2FCV0240065 FCV 24-65 Transfers Closed 4.2247E+000 203 HOVXC2_024589B Manual Valve 24-589B Transfers Closed 4.2247E+000 204 HOVXC2_024589A Manual Valve 24-589A Transfers Closed 4.2247E+000 205 HXRRP2_047__2B EHC Fluid Cooler 2B Ruptures 4.2247E+000 206 ElVFD2FCV0010064 Turbine Bypass Valve FCV 1-64 Fail to Regulate 4.2247E+000 207 ElVFD2FCV0010062 Turbine Bypass Valve FCV 1-62 Fail to Regulate 4.2247E+000 E-120

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 208 ElVFD2FCV0010063 Turbine Bypass Valve FCV 1-63 Fail to Regulate 4.2247E+000 209 ElVFD2FCV0010061 Turbine Bypass Valve FCV 1-61 Fail to Regulate 4.2247E+000 210 TCVXC2TCV0240070 TCV 24-70 Transfers Closed 4.2247E+000 211 HOVXC2_0240593 Manual Valve 24-593 Transfers Closed 4.2247E+000 212 HOVXC2 0240592 Manual Valve 24-592 Transfers Closed 4.2247E+000 213 HOVXC. 024588B Manual Valve 24-588B Transfers Closed 4.2247E+000 214 HOVXC2 024588A Manual Valve 24-588A Transfers Closed 4.2247E+000 215 [PMOFR2HFP047000A Common Cause: Group EHC Pump, 2/2 4.2247E+000

_ __ PMOFR2HFP047000B] __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

216 CB2XO2 047_613 Circuit Breaker 613 AT Board 9-9 Cabinet 6 4.2247E+000 Transfers Open__ _ _ _ _ _ _ _ _ _ _ _ _ _

217 [SOVFD2FSVO47067A Common Cause: Group Turbine Trip Master Trip 4.2247E+000 SOVFD2FSVO47067B] Solenoid Valves, 2/2 218 ElVFC2FCV0010065 Turbine Bypass Valve FCV 1-65 Fail to Close 4.2247E+000 219 El VXO2FCV0010067 Turbine Bypass Valve FCV 1-67 Transfers Open 4.2247E+000 220 ElVXO2FCV0010065 Turbine Bypass Valve FCV 1-65 Transfers Open 4.2247E+000 221 HXRRP2_047_2A EHC Fluid Cooler 2A Ruptures 4.2247E+000 222 CSVFO2HCV0730023 Stop Check Valve 2-HCV-73-23 Fails to Open On 4.1941 E+000 Demand 223 ElVFO2FCV0010065 Turbine Bypass Valve FCV 1-65 Fail to Open 4.1297E+000 224 E1VFO2FCV0010064 Turbine Bypass Valve FCV 1-64 Fail to Open 4.1297E+000 225 ElVF02FCV0010067 Turbine Bypass Valve FCV 1-67 Fail to Open 4.1297E+000 226 E1VFO2FCV0010066 Turbine Bypass Valve FCV 1-66 Fail to Open 4.1297E+000 227 E1VFO2FCV0010061 Turbine Bypass Valve FCV 1-61 Fail to Open 4.1297E+000 228 ElVFO2FCV0010063 Turbine Bypass Valve FCV 1-63 Fail to Open 4.1297E+000 229 ElVFO2FCV0010062 Turbine Bypass Valve FCV 1-62 Fail to Open 4.1297E+000 230 ElVFO2FCV0010069 Turbine Bypass Valve FCV 1-69 Fail to Open 4.1297E+000 231 EIVFO2FCV0010068 Turbine Bypass Valve FCV 1-68 Fail to Open 4.1297E+000 232 MOVXC2FCV73040_6 MOV 2-FCV-73-40 Transfers Closed During 4.1207E+000 Operation 233 MOVXC2FCV73003_6 MOV 2-FCV-73-3 Transfers Closed During 4.1207E+000 M0VXCFCV70036 Operation 234 [SWL2_LS073056A Common Cause: Group CST Level Switches for 4.1204E+000 SWL2_LS073056B] HPCI Switch, 2/2 235 MOVXC2FCV73002_6 MOV 2-FCV-73-2 Transfers Closed During 4.1197E+000 236__ B303T__________ _ FeedOperation 303TrasfespenDurng4.189E00 236 B303T Feeder Breaker 303 Transfers Open During 4.1 189E+000 Operation.

E-121

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 237 CKVFO2CKV0030558 RFW Check Valve 2-3-558 Fails to Open On 4.0862E+000 Demand 238 CKVFO2FCV0730045 Testable Check Valve 2-FCV-73-45 Fails to Open 4.0862E+000 On Demand 239 CKVFC2CKV0030554 Feedwater Check Valve 2-CKV-3-554 Fails to Close 4.0862E+000 On Demand 240 CKVFO2CKV0730505 Check Valve 2-CKV-73-505 Fails to Open On 4.0862E+000 Demand 241 CKVFO2CKV0730603 Check Valve 2-CKV-73-603 Fails to Open On 4.0862E+000 Demand 242 [RL12RLY23AK25] Common Cause: Group HPCI/RCIC Actuation 4.0509E+000 Relays, 1/4 243 [RL1FD223A_K221] Common Cause: Group HPCIIRCIC Actuation 4.0509E+000

___ ____ ___ Relays, 1/4 244 [RL1IFD223AJK211 Common Cause: Group HPCV/RCIC Actuation 4.0509E+000 Relays, 1/4 245 B3D2AT Bus Feeder Breaker 3D Transfers Open During 4.0320E+000 Operation.__ _ _ _ _ _ _ _ _ _ _ _ _

246 B3A2AT Feeder Breaker 3A Transfers Open During 4.0320E+000 Operation.__ _ _ _ _ _ _ _ _ _ _ _ _ _

247 E2AR 480V RMOV BD 2A Bus Fails. 4.0319E+000 248 PTSFS2PMP0730054 HPCI Pump Fails to Start On Demand 3.9837E+000 249 [FN2FR2FAN098061] Common Cause: Group SAI Panel Coolers, 1/2 3.9776E+000 250 B26082T Output Breaker 608 Transfers Open During 3.9484E+000 Operation.

251 [DGAS DGDS] Common Cause: Group Unit 1/2 DGs, 2/4 3.9366E+000 252 EBB2R Battery BD. 2 Bus Fails. 3.9259E+000 253 PTSFR2PMP73054_6 HPCI Pump Fails During Operation 3.9216E+000 254 CKVLK2CKV30554_6 Feedwater Check Valve 2-CKV-3-554 Develops 3.9086E+000 Gross Reverse Leakage 255 [CH22R] Common Cause: Group Chargers for Battery 3.8887E+000 255 [CH22R] ~Boards, 1/2 .87+0 256 MOV)2C2FCV73027_6 256 MOM2FCV73027~_6MOV 2-FCV-73-27 Transfers Closed During Operation386500 38645E+0 257257 MOVXC2FCV73026_6

__MOVXC2FCV73026_6 MOV 2-FCV-73-26 Transfers Closed During Operation 38645E+0 3___________________

258 MOVXC2FCV73016_6 MOV 2-FCV-73-16 Transfers Closed During 3.8645E+000 Operation__ _ _ _ _ _ _ _ _ _ _ _ _ _

259 MOVXO2FCV73040-6 MOV 2-FCV-73-40 Transfers Open After Switchover 3.8645E+000 260 MOVXC2FCV73034_6 260 MOM2FCV73034~_6MOV 2-FCV-73-34 Transfers Closed During Operation386500 38645E+

E-122

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 261 MOVXC2FCV73044 6 MOV 2-FCV-73-44 Transfers Closed During 3.8645E+000 Operation__ _ _ _ _ _ _ _ _ _ _ _ _ _

262 [RL12RLY23AK25 Common Cause: Group HPCVRCIC Actuation 3.8588E+0O RL1 FD223AJi22] Relays, 2/4 263 [RL12RLY23AK25 Common Cause: Group HPCI/RCIC Actuation 3.8588E+000 RL1FD223Aji21] Relays, 2/4 264 [RL1 FD223A_K21 Common Cause: Group HPCI/RCIC Actuation 38588E00 RL1 FD223Ai22] Relays, 2/4 265 B26D2T Input Breaker 6D Fails Open. 3.8585E+000 266 AOVXC2FCV0320063 Containment Isolation Valve FCV-32-63 Transfers 3.8304E+000 Shut 267 AOVXC2FCV0320062 Containment Isolation Valve FCV-32-62 Transfers 3.8304E+000 Shut 268 HOVXC2 0322515 Manual Valves32-2515,2520, 2522,2523,2524, 2526 3.8304E+000 Transfers Shut 269 HOVXC2_0320302 Manual Valve 32-302 Transfers Shut 3.8304E+000 270 COVPLZ_0322163 Check Valves32-2163 and 336 Plugged 3.8304E+000 271 [AOVFO2FCV0320064 Common Cause: Group Drywell Control Air RBCCW 38304EO0 AOVFO2FCV0320067] Supply AOVs, 2/2 272 COVPL2_0322516 Check Valves32-25116 and 2521 Plugged 3.8304E+000 273 [CMPFR2CMP032002A Common Cause: Group Drywell Air Compressors, 3830E00 CMPFR2CMP032002B] 2/2 274 [CMPFS2CMP032002A Common Cause: Group Drywell Air Compressors, 38304E+00 CMPFS2CMP032002B] 2/2 275 HOVXC2 0322253 Manual Valves32-2253,2160,1452,1451,1736, 3.8304E+000 Transfers Shut 276 FLTPL2_032CFLT Drywell Loads (C)Air Filter Plugged 3.8304E+000 277 FLTPL2_032PFLT Suction Prefilter Plugs 3.8304E+000 278 HOVXC2_0320301 Manual Valve 32-301 Transfers Shut 3.8304E+000 279 FLTPL2_032BFLT Drywell LOADS (B)Air Filter Plugged 3.8304E+000 280 HOVXC2HCV3066_6 RFW Line B Valve 2-66 Transfers Closed 3.7657E+000 281 E2B250R 250V RMOV BD 2B Bus Failed. 3.7296E+000 282 B2D2Bto Breaker 2D Transfers Open 3.7296E+000

[RV2FOPCV0010005 283 RV2FOPCV0010022 Common Cause: Group SRVs (Depressurization), 3.6585E+000 RV2FOPCV0010031 4/6 RV2FOPCV0010034]

[RV2FOPCVW010005 284 RV2FOPCV0010030 Common Cause: Group SRVs (Depressurization), 3.6585E+000 RV2FOPCV0010031 4/6 RV2FOPCV001 0034]

E-123

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth

[RV2FOPCV0010005 285 RV2FOPCVOO10019 Common Cause: Group SRVs (Depressurization), 3.6585E+000 RV2FOPCV0010030 4/6 RV2FOPCV0010034]

[RV2FOPCV0010005 286 RV2FOPCV0010019 Common Cause: Group SRVs (Depressurization), 3.6585E+000 RV2FOPCV0010022 4/6 RV2FOPCV0010030]

[RV2FOPCV0010005 287 RV2FOPCV0010019 Common Cause: Group SRVs (Depressurization), 3.6585E+000 RV2FOPCV0010022 4/6 RV2FOPCV0010034]

[RV2FOPCV0010005 288 RV2FOPCV001 0022 Common Cause: Group SRVs (Depressurization), 3.6585E+000 RV2FOPCV001 0030 4/6 RV2FOPCV001 0034]

[RV2FOPCV0010005 289 RV2FOPCV0010022 Common Cause: Group SRVs (Depressurization), 3.6585E+000 RV2FOPCV001 0030 4/6 RV2FOPCV00100311

[RV2FOPCV0O10022 Common Cause: Group SRVs (Depressurization),

290 RV2FOPCV001 0030 363.6553E+000 RV2FOPCV0010034]

291 [PMSFS2PMP0740005 Common Cause: Group RHR Pumps Fail to Start, 3.6332E+000 PMSFS2PMP0740039] 2/4

[RV2FOPCV0010005 Common Cause: Group SRVs (Depressurization), 3.6210E+000 292 RV2FOPCV001 0030 36361O+0 RV2FOPCV001 0034]

[RV2FOPCV0010005 Common Cause: Group SRVs (Depressurization), 3.6210E+000 293 RV2FOPCV001 0022 36361O+0 RV2FOPCV0010030] 3/6

[RV2FOPCVOO10005 Common Cause: Group SRVs (Depressurization), 3.6210E+000 294 RV2FOPCV001 0022 36361O+0 RV2FOPCV0010034]

[PMSFR2_02300B1 Common Cause: Group RHRSW South Header 3.5892E+000 295 PMSFR2~-02300D11 Pup,3358200 PMSFR2_02300D2] umps,

[PMSFS2=02300D1 Common Cause: Group RHRSW South Header 296 PMSFS2 _02300D1 Pup,343.5677E-e000 PMSFS2_02300D2] umps, 297 [PMSFS2PMP0740005] Common Cause: Group RHR Pumps Fail to Start, 3.5620E+000

[PMSS2PMO74O05] 1/4 298 PMOFR3_027_CC Loss of All Unit 3 CCW Pumps 3.5381 E+000 299 HOVXC2_0240500 Unit 1 CCW Intake Valve 2-24-500 Transfers Closed 3.5381 E+000 300 HOVXC1_0240504 Crosstie Valve 1-24-504 Transfers Closed 3.5381 E+000 301 HOVXC1_0240500 Unit 1 CCW Intake Valve 1-24-500 Transfers Closed 3.5381 E+000 E-124

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 302 HOVXC2_0240521 RCW Header Isolation Valve 2-24-521 Transfers 3.5381 E+000 Closed 303 HOVXC20240524 RCW Header Isolation Valve 2-24-524 Transfers 3.5381 E+000 Closed

[PMOFR1=024001A PMOFR1-024001 B PMOFR2-024002A 304 PMOFR2=022B Common Cause: Group ROW Pumps Fail to Run, 3.5381 E+000 PMOFR2_024002C 7/

PMOFR3_024003A PMOFR3_024003B]

305 H0VXC2_0240691 RCW Header Isolation Valve 2-24-691 Transfers 3.5381 E+000 Closed 306 HOVXC3_0240500 Unit 3 CCW Intake Valve 3-24-500 Transfers Closed 3.5381 E+000 307 HOVXC2_0240594 RCW Header Isolation Valve 2-24-594 Transfers 3.5381 E+000 Closed 308 HOVXC2_0240515 Crosstie Valve 2-24-515 Transfers Closed 3.5381 E+000 309 PMOFR1_027_CC Loss OF All Unit 1 CCW Pumps 3.5381 E+000 310 PMOFR2_027_CC Loss OF All Unit 2 CCW Pumps 3.5381 E+000 311 HOVXC2_0240693 RCW Header Isolation Valve 2-24-693 Transfers 3.5381 E+000 Closed

[PMSFR2=02300A2 Common Cause: Group RHRSW A and C Pumps, 312 PMSFR2 02300A2 343.5098E+000 PMSFR2_02300C1]

[PMSFS2=02300A2 Common Cause: Group RHRSW South Header 313 PMSFS2__02300A2 Pup,343.5095E+000 PMSFS2_02300C1] Pups, 314 [1B1334O1313360] Common Cause: Group Unit 3 4kV Shutdown Board 3.492E+000 Feeder Breakers, 2/4 315 [B13340 B13360 B13420] Common Cause: Group Unit 3 4kV Shutdown Board 3.4892E+000 Feeder Breakers, 3/4 316 [DG3AS DG3CS DG3DS] Common Cause: Group Unit 3 DGs, 3/4 3.4731 E+000 317 MOVFO2FCV0740100 Valve 2-FCV-74-100 Fails to Open On Demand 3.4625E+000 318 MOVXC2FCV0740100 Valve 2-FCV-74-100 Transfers Closed 3.4625E+000 319 RPDRP2RP71011A_6 Inboard Rupture DISC Failure 3.3949E+000 320 [PMSFR2_02300A1 Common Cause: Group RHRSW A and C Pumps, 3.3690E+000 PMSFR2_02300A2] 2/4 321 [PMSFS2_02300A1 Common Cause: Group RHRSW South Header 3.3687E+000 PMSFS2_02300A2] Pumps, 2/4 322 HOVXC2HC30066_6 RFW Valve HCV-3-67 Transfers Closed 3.3505E+000 323 HOVXC2HCV73025_6 Manual Valve 2-HOV-73-25 Transfers Closed 3.3505E+000

_ During Operation E-125

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth

[RL12RLY23AK25 Common Cause: Group HPCI/RCIC Actuation 324 RL1 FD223AK21 Rly,343.3401 E+000 RL1 FD223Aj221 Ys 325 [PMOFR2-02300A3 Common Cause: Group EECW Pumps, 2/4 3.3112E+000 326 HOVXO2 0630013 Manual Valve 63-13 to Drain Tank Transfers Open 3.2666E+000 327 HOVXC2_0630524 Manual Valve 63-524 Transfers Closed 3.2666E+000 328 HOVXC2_0630500 Manual Valve 63-500 Transfers Closed 3.2666E+000

[MOVFC2FCV0690001 Common Cause: RWCU MOVs Fail to Isolate for 3.2666E+000 MOVFC2FCV06900121 330 COVPL2_0630526 Check Valve 63-526 Transfers Closed / Plugs 3.2666E+000 331 COVF02_0630525 Check Valve 63-525 Fails to Open 3.2666E+000 332 COVFO2 0630526 Check Valve 63-526 Fails to Open 3.2666E+000 333 [PMSFS2_063002A Common Cause: Standby Liquid Control Pumps 3.2666E+000 PMSFS2-063002B] FTS, 2/2 334 [PMSFR2O063002A Common Cause: Standby Liquid Control Pimps 3.2666E+000 PMSFR2_063002B] FTR, 2/2 335 [EOVFD2-063008A Common Cause: Standby Liquid Control Explosive 3.2666E+000 EOVFD2Z063008B] Valves, 2/2 336 TK2RP2_0630001 Standby Liquid Control Storage Tank Ruptures 3.2666E+000 337 HOVXC2HCV0630012 Manual Valve 63-12 Transfers Closed 3.2666E+000 338 COVPL2_0630525 Check Valve 63-525 Transfers Closed / Plugs 3.2666E+000 339 [PMOFS2 02300A3 Common Cause: Group EECW Pumps, 2/4 3.2351 E+000 PMSFS2.-02300C3] ___________________ ______________

340 [PMOFR2__02300A3 Common Cause: Group EECW Pumps, 2/4 3.1622E+000 PM OFR2 .. 02300133] __ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _ _ _ _ _

341 [DGBS DGDS] Common Cause: Group Unit 1/2 DGs, 2/4 3.0740E+000 342 OU1 1 Operators Fail to ALIGN UL1 RHR LOOP II THRU X- 2.9643E+000 TIE to U2 RHR LOOP 343 [PMOFS2_02300A3 Common Cause: Group EECW Pumps, 2/4 2.8934E+000 PMOFS2_02300B3]

344 B3B2BT Feeder Breaker 3B Transfers Open During 2.8933E+000 Operation.__ _ _ _ _ _ _ _ _ _ _ _ _ _

345 E2BR 480V RMOV BD 2B Bus Fails. 2.8933E+000 346 B2D2BT Bus Feeder Breaker 2D Transfers Open During 2.8933E+000 Operation.

347 (DG3AS DG3CS] Common Cause: Group Unit 3 DGs, 2/4 2.8916E+000 348 HOVXC1 HCV0670606 Valve 1-67-606 Transfers Closed 2.8655E+000 E-126

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 349 [MOVFO1 FCV0230046 Common Cause: Group EECW to Unit 1 Loop II 2.8655E+000 MOVFO1 FCV0230052] RHR Room Coolers, 2/2 350 [FN2FR1 ROOM74001 B Common Cause: Group Unit 1 Loop II RHR Room 2.8655E+000 FN2FR1 ROOM74001 D] Coolers, 2/2 351 [FN2FS1 ROOM74001 B Common Cause: Group Unit 1 Loop II RHR Room 2.8655EO00 FN2FS1 ROOM74001 D] Coolers, 2/2 352 [PMSFR1PMP074001B Common Cause: Group Unit 1 Loop II RHR 2.8655E+000 PMSFR1 PMP074001 D] Pumps,, 2/2 353 [PMSFS1PMP074001B Common Cause: Group Unit 1 Loop II RHR Pumps, 2.8655E+000 PMSFS1 PMP074001 D] 2/2 354 MOVF01 FCV0740101 Unit 1 RHR HX Outlet X-TIE 1-FCV-74-101 Fails to 2.8655E+000 MOVF1 FC0740 01 Open On Demand 355 MOVXCI FCV0740101 Unit 1 RHR HX Outlet X-TIE 1-FCV-74-101 2.8655E+000 MOVX1 FCO74O 01 Transfers Closed 356 [MOVFC1 FCV0740024 Common Cause: Group Unit 1 Pump Suction MOVs 2.8655E+000 MOVFC1 FCV0740035] (XTIE FTC), 2/2 3 [MOVFO1 FCV0740098 Common Cause: Group Unit 1 Pump B and D 2.8855E+000 MOVFO1FCV0740099] Suction (XTIE FTO), 2/2 358 [MOVFO2FCV0740096 Common Cause: Group Unit 2 Suppression Pool 2.8655E+000 MOVFO2FCVW740097] Path (XTIE U2), 2/2 359 CKXlK0758 Discharge to YARD Drainage Check Valve 1-67-598 2.8655E+000 9

CKVXC1CKV0670598 Transfers Closed 360 [DGAS] Common Cause: Group Unit 1/2 DGs, 1/4 2.8623E+000 361 [PMSFR2_02300D13 Common Cause: Group EECW Pumps, 2/4 2.8359E+000 362 [PMSFS2_02300B1 Common Cause: Group RHRSW South Header 2.8347E+000 PMSFS2 02300D1] Pumps, 2/4 363 BE-FRACT3 Unit 2 Large or Medium LOCA and Unit 1 not at 2.7426E+000 Power - Macro CASB

[PMOFS2_02300B3 364 PMSFS2_02300C3 Common Cause: Group EECW Pumps, 3/4 2.6833E+000 PMSFS2_02300D3]

365 [D64TC D65TC] Common Cause: Group Diesel Generator Dampers, 2.6765E+000 2/2 366 [VAAS VBAS] Common Cause: Group Diesel Generator Fans, 2/2 2.6718E+000 367 E125AR 125V DC 1BD. Bus or Battery Fails or Fused Switch 2.6508E+000 to DG CONT TRAN 368 CHARGA2R A', In/Out Fuse Fail, Charger Input Output Breaker 2.6450E+000 Transfers Open__ _ _ _ _ _ _ _ _ _ _ _ _ _

369 M861T Manual Valves532, 861 Transfers Closed or 2.6377E+000 Expansion Joint Leak.

E-127

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 370 [RL1 FD2RLY1 OAK9B] Common Cause: Group RHR Pump Actuation 2.6349E+000 Relays (K9), 1/2 371 W23TC Fire Dampers 1023, 1019 Transfers Closed 2.6340E+000 372 SAAR Sequencer Fails, Breaker 1818 Transfers Open, or 2.6295E+000 1614 Transfers Closed 373 [PMSFS2o02300B1 Common Cause: Group RHRSW South Header 2.6092E+000 PMSFS2_02300D2] Pumps, 2/4 374 [PMSFR2-02300D2] Common Cause: Group PMR, 2/4 2.6090E+000 375 [DG3BS DG3CS DG3DS] Common Cause: Group Unit 3 DGs, 3/4 2.5983E+000 376 [PMSFR2_02300B1] Common Cause: Group PMR, 1/4 2.5521 E+000 377 [PMSFS2_0230011] Common Cause: RHRSW South Header Pumps, 2.5520E+000

[P8 F2 00B CeVl7-5T1/4 378 CKVXC2CK710502_6 Check Valve 71-502 Transfers Closed 2.5506E+000 379 CKVXC2CK71 0580-6 Check Valve 71-580 Transfers Closed 2.5506E-i-00 380 CKVXC2CK30572 6 RFW Line B Injection Valve 2-3-572 Transfers 2.5506E+000 Closed 381 CKVXC2FCV71040-6 Check Valve FCV-71 -40 Transfers Closed 2.5506E+000 382 COVF02_0230522 Check Valve 0-23-522 Fails to Open On Demand 2.5497E+000 383 HOVXC2_0230523 Manual Valve 0-23-523 Transfers Closed 2.5494E+000 384 HOVXC2_0230524 Manual Valve 0-23-524 Transfers Closed 2.5494E+000 385 COVXC2_0230522 Check Valve 0-23-522 Transfers Closed 2.5479E+000 386 CSVXC2HCV71014-6 Stop Check Valve HCV-71 -14 Transfers Closed 2.5411 E+000 387 [PMOFR2_0230OA3 Common Cause: Group EECW Pumps, 2/4 2.5048E+000 PMSFR2 0230oD3o 388 PTSFS1CCFRCHP 2 RCIC AMD HPCI CC Failure to Start on Second demand 2.4909E+000 389 PTSFSICCF_RCHP_1 RCIC and HPCI Pumps CC Failure to Start on First 2.4909E+000

_ demand 390 PTSFR1CCRCHP18 RCIC and HPCI CC FALURE to Run For 18 HOURS 2.4909E+000 39.1 [DGCS DGDS] Common Cause: Group Unit 1/2 DGs, 2/4 2.4638E+000 392 HOVXC2_0240523 Manual ValvesO-24-523, -554 Transfers Shut 2.4317E+000 393 COVXC2_0240563 Check Valve 0-24-563 and Manual Valve 0-24-562 2.4317E+000 COXC-04063 Transfers Shut 394 COVXC2_0240577 Check Valve 0-24-577 and Manual Valve 0-24-578 2.4317E+00 34 COVXC2 _0240577 Transfers Shut243700 395 [PMOFS2_02300A3 Common Cause: RHRSW South Header Pumps, 2.4204E+000 PMSFS2_02300D3] 2/4 E-128

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 396 COVLK2 002051 7 Condensate Pump B Discharge Check Valve 2-517 2.4034E+000 Gross Reverse Leakage ____ _______

[PMOFR2_CP002002A 397 PMOFR2_CP002002B Common Cause: Group Condensate Pumps, 3/3 2.4034E+000 PMOFR2_CP002002C]

398 DIMFR2 002CODM Insufficient Flow Thru Dem in Path 2.4034E+000 399 HXRPL2_002OFGA Excessive Rupture/Rupture OF Off-Gas Main 2.4034E+000 P O2 A Condenser Unavailable After Plant Trip

[PMOFR2CBP0O2002A Common Cause: Group Condensate Pumps Fail to 400 PMOFR12CBP0O2002B Ru,332.4034E+000 PMOFR2CBP0O2002C] Run, 3/3 401 COVFT2 0020517 Condensate Pump B Discharge Check Valve 2-517 2.4034E+000 Fails to Reseat 402 COVFT2_0020558 Condensate Booster Pump B Discharge Check 2.4034E+000 Valve 2-558 Fails to Reseat 403 COL2 0258 COND Booster Pump B Discharge Check Valve 2- 2.4034E+000 C0VLK20020558 558 Gross Reverse Rupture_______________

404 HXRPL2_002EXHA Excessive Leakage/Rupture OF Steam Packing 2.4034E+000 HOXRPL2_

405 2E A O tExhauster 405 MOVXC2FCV0020041 Outlet Valve FCV 2-41 Transfers Closed 2.4034E+000 406 MOVXC2FCV0020036 Inlet Valve FCV2-36 Transfers Closed 2.4034E÷000 407 HXRPL2_002SJAE Excessive Leakage/Rupture (SJAE) 2.4034E+000

[RL1 FD2RLY1 OAK66A 408 RL1 FD2RLY10AK66B Common Cause: Group LPCI I and 11Auto Actuation 2.4020E+000 RL1 FD2RLY1 OAK67A Relays, 4/4 RL1 FD2RLY1 OAK67B]

[RL1FD2RLY1oAK66A Common Cause: Group LPCI I and 11Auto Actuation 2.4020E+000 409 RLI FD2RLY10OAK67A Reas 4240E00 RL1 FD2RLY1 OAK67B] Relays, 3/4 410 [MOVFO2FCV0740053 Common Cause: Group LPCI LOOP Injection 2.4020E+000 MOVFO2FCV0740067] MOVs, 2/2 411 HOVXC2_0320996 Valves545 or 996 Transfers Shut given Receivers B 2.3885E+000 and C Path is failed 412 HOVXC2_0240681 Manual Valve 0-24-681 Transfers Shut 2.3885E+000 413 R2VPO2_0320546 Relief Valve 0-32-546 Premature Open 2.3885E+000 414 R2VP02_0320556 Relief Valve 0-32-556 Premature Open 2.3885E+000 415 R2VPO2_0320551 Relief Valve 0-32-551 Premature Open 2.3885E+000 416 FLTPL2 032AFLT Afterfilter Plugs 2.3885E+000 417 HOVXC2_0322375 Manual Valve 32-2375 Transfers Shut 2.3885E+000 418 COVPL2_0322171 Check Valve 32-2171 Plugs 2.3885E+000 419 COVPL2_0322170 Check Valve 32-2170 Plugs 2.3885E+000 E-129

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 420 RCVRP2_032RCVRC Air Receiver C Rupture 2.3885E+000 421 RCVRP2_032RCVRB Air Receiver B Rupture 2.3885E+000 422 FLTPL2__032PRFLT Prefilter Plugs 2.3885E+000 423 HOVXC2_0241052 Manual Valve 0-24-1052 Transfers Shut 2.3885E+000 424 RCVRP2_032RCVRA Air Receiver A Rupture 2.3885E+000 425 HOVXC2=0321680 Manual Valve 32-1680 Transfers Shut 2.3885E+000

[COVLK2=032872 Common Cause: Check Valves in Air Lines to SRVs3780E+000 426 COVLK2_032892 (Depressurization) 3/6 2.3780E+000 COVLKZ2032919] (Depressurization) 3/6

[COVLK2-032869 Common Cause: Check Valves in Air Lines to SRVs2.7E+0 COVLK2_032869 4

[COVLK2_032869 Common Cause: Check Valves in Air Lines to SRVs 2.3780E+000 429 COVLK2_032872 (Depressurization) 3/6 2.3780E+000 COVLK2_032892 4

[COVLK2_032869 Common Cause: Check Valves in Air Lines to SRVs 2.3780E+000 429 430 COVLK2_032892 COVLi<2_-032872 (Depressurization)

(Depressurization) 4/6 3/6237000 COVLKZ2032919]

[COVLK2_032869 430 COVLK2_032872 Common Cause: Check Valves in Air Lines to SRVs 2.3780E+000 COVLK2_032892 (Depressurization) 4/6 COVLK2_032919]

[COVLK2_032869 433 COVLK2 032872 Common Cause: Check Valves in Air Lines to SRVs 2.3780E+000 COVLK2 032915 (Depressurization) 4/6 COVLK2__032919]

[COVLK2_032869 432 COVLK2_032872 Common Cause: Check Valves in Air Lines to SRVs 2.3780E+000 COVLK2_032892 (Depressurization) 4/6 COVLK2_032915]

[COVLK2_032862 133 COVLK2_032872 Common Cause: Check Valves inAir Lines to SRVs 2.3780E+000 COVLK2_032892 (Depressurization) 4/6 COVLKZ_032919]

[COVLK2_032869 434 COVLK2_032892 Common Cause: Check Valves inAir Lines to SRVs 2.3780E+000 COVLK2_032915 (Depressurization) 4/6 COVLK2_032919]

[CO VLK2-032872 45 COVLK2__032892 Common Cause: Check Valves in Air Lines to SRVs 2.3780E+000 COVLK2-032915 (Depressurization) 4/6 COVLK2-03291 9]_____ _______

[COVLK2-032862 436 COVL(2-032869 Common Cause: Check Valves in Air Lines to SRVs 2.3780E+000 COVLK2_032892 (Depressurization) 4/6 COVLK2__032919] _ _ _ _ _ _ _ _ _ _ _ _ _ _

E-130

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth

[COVLK2_032862 437 COVLK2_032869 Common Cause: Check Valves in Air Lines to SRVs 2.3780E+000 COVLK2_032872 (Depressurization) 4/6 COVLK2_032919]

[COVLK2_032862 438 COVLK2_032869 Common Cause: Check Valves in Air Lines to SRVs 2.3780E+000 COVLK2_032872 (Depressurization) 4/6 COVLK2_032892]

[COVLK2_032862 COVLK2_032869 COVLK2 0329195 439 COVLK2_032892 CommonrCase:ztin Ch5/6 vs nArLne oS~ 2.3773E+o000

[COVLK2_032869 COVLK2_032872 Common Cause: Check Valves in Air Lines to SRVs 2.3773E+000

[COVLK2_0328692________________

COVLK2_032892 (Depressurization) 5/6 COVLK2_032919]

[COVLK2_032862 COVLK2_-032915 COVLK2L--032869 41COVLK2__032872 Common Cause: Check Valves in Air Lines to SRVs 2.3773E+000 COVLK2_032892 (Depressurization) 6/6 COVLK2 032915

[COVLK2_032862 COVLK2.032869 Common Cause: Check Valves in Air Lines to SRVs2.73+0 4COVLK2_032862 COVLK2_032915]

443 COVLK2_--032872 (Depressurization) 5/6 2.3773E+000

[COVLK2_032862 13COVL(2 032872 Common Cause: Check Valves in Air Lines to SRVs .7EOO (Depressurization) 5/62.73+0 44544COVLK2=032872 COVLK2_032892 (Depressurization) 5/6 2.3773E+000 COVLK2_032919]

[CO VLK2Z032862 COVLK2 032869 Common Cause: Check Valves inAir Lines to SRVs 2.37E+000 444 COVLK2_032872 COVLK2 032915 (Depressurization) 5/6 COVLK2 -032919] _ _ _ _ _ _ _ _ _ _ _ _ _ _

[CO VLK2-032862 COVLK2 -032869 Common Cause: Check Valves in Air Lines to SRVs2.73+0 445 COVLK2 -032892 (ersuiain / .73+0 COVLK2-032915 ~ (ersuiain /

COVLK2 _032919] 1_ _ _ _ _ _ _ _ _ _ _ _ _

[PMSFR2O_2300A1 Common Cause: Group RHRSW A and C Pumps, 446 PMSFR2 02300C1 342.3764E-i000 PM SFR2 02300C2] _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _

[PMSFSZO--2300A1 447 PMSFS2_02300C1 Common Cause: Group RHRSW A and C, 3/4 2.3760E+000 PMSFS2_02300C2]

E-131

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 448 [PMSFR2 02300A1 Common Cause: Group RHRSW A and C Pumps, 2.3658E+000 PMSFR2 02300C1] 2/4 449 [PMSFS2_02300A1 Common Cause: Group RHRSW A and C, 2/4 2.3658E+000 450 [DG3AS DG3DS] Common Cause: Group Unit 3 DGs, 2/4 2.3518E+000 451 [PMSFR2O0230OB2 Common Cause: RHRSW South Header Pumps, 2.3381 E+000 PMSFR2_02300D1] 2/4 452 [PMSFS2O02300B2 Common Cause: Group RHRSW South Header 2.3358E+000 PMSFS2_02300D1] Pumps, 2/4

[RL1 FD2RLY10AK66A Common Cause: Group LPCI I and 11Auto Actuation 453 RLl FD2RLY10OAK66B Rly,342.3295E+O000 RL1FD2RLY10AK67A] Relays, 3/4 454 [RL1 FD2RLY1 OAK66A Common Cause: Group LPCI I and 11Auto Actuation 2.3295E+000 RL1FD2RLY10AK67A] Relays, 2/4 455 [DG3AS] Common Cause: Group Unit 3 DGs, 1/4 2.3010E+000

[RL1 FD214A0750K9A Common Cause: Group Low RX Pressure 456 RL1 FD214A075K23A PfisieRly CS,342.2833E+000 RL1 FD214A075K233] Prisv eas(S) /

[RL1 FD214A0750K9A Common Cause: Group Low RX Pressure 457 RL1 FD214A0750K9B Pemissive Relays Relay, 3/4 2.2833E+000

[RL FD2_00374A1 Common Cause: Group Low RX Pressure 458 RL1 FD2 _00374Pe1eCmmon CusGup RHRS, 3 d4 2.2833E+000 RLPFD2_00680951] Pemiss O R 4RL FD2_00374A1 Common Cause: Group Low RX Pressure 2.2 E+000 459 ALI FD2-0680951 PemsieOtuRea, 4228300 RL1 FD2 0680961] Pemisv Output Rea S, 3/4 460 [PMSFR2_02300A1 Common Cause: Group RHRSW A and C Pumps, 2.2797E+000 PMSFR2-02300C2] 2/4 461 CPMSFSO02300C2 Common Cause: Group RHRSW A and C, 2D 4 2.2793E+000 462 HPMSFS2 0230032 Common Cause: Group RHRSW South Header 2.2774E+000 PMSFSZ2 0230002] Pumps, 2/4 46 PMSFR2 0230002] Common Cause: Group PMR, 2/4 2.2769E-e000 464 [PSR _20A] Common Cause: Group RHRSW A and C Pumps, 2.2692E+000

[PMSFZ.0230A1] 1/4 465 [PMSFS2O02300Al] Common Cause: Group RHRSW A and C, 1/4 2.2691 E+000 466 COVF02_0230502 Check Valve 0-23-502 Fails to Open On Demand 2.2690E+000 467 HOVXC2_0230503 Manual Valve 0-23-503 Transfers Closed 2.2690E+000 468 HOVXC2 -0230504 Manual Valve 0-23-504 Transfers Closed 2.2690E+000 469 CO VXC2-0230502 Check Valve 0-23-502 Transfers Closed 2.2668E-,000 E-132

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 470 RPDRP2RP73O713_6 Inboard Rupture DISC 2-RPD-073- 0713 Ruptures 2.2623E-i000 Causing HPCI Isolation 471 SPUR1 Spurious Accident Signal From Unit 1 2.2551 E+000 472 [D230TC D231TC] Common Cause: Group Unit 3 DGs Dampers, 2/2 2.2527E+000 473 [VA3AS VB3AS] Common Cause: Group Unit 3 Fans Fail to Start, 2/2 2.2503E+000 474 CHR32 3A', In/Out Fuses Fail, Charger Input, Output 2.2382E+000 CHARG3A2R 4 Breaker Transfers Open 475 COVFT2__0020526 Condensate Pump C Discharge Check Valve 2-526 2.2311 E+000 6 COVFT20020526 Falls to Reseat 476 COVFT2-0020550 Condensate Booster Pump C Discharge Check 2.231 1 E+o00 Valve 2-550 Fails to Reseat 477 W35TC Fire Dampers 1035, 1031 Transfers Closed 2.2306E+000 478 El1253AR 125V DC Bus or Battery Fails or Fused Switch to 2.2300E+000 DG Cont Transfers 479 M862T Manual Valves862, 699 Transfers Closed or 2.2273E+000 MExpansion Joint Leak.

480 MOVXO2FCV0740057 Valve FCV-74-57 Transfers Open 2.2264E+000 481 [MOVFC2FCV0740057] Common Cause: Group Loop I and 11LPCI Test 2.2264E+000 Return, 1/2 482 [MOVFC2FCV0740057 Common Cause: Group Loop I and 11LPCI Test 2.2264E+000 MOVFC2FCV0740071] Return, 2/2 483 RL1 FD2RLY1 OAK98A Relay RLY-1 OA-K98A Fails to Drop Out On Demand 2.2264E+000 484 RL1 FD2RLY1 OAK98B Relay RLY-1 OA-K98B Fails to Drop Out On Demand 2.2264E+000 485 [MOVFO2FCV0740013] Common Cause. Group Shutdown Cooling Valves 2.2264E+000

___ ___ ___ (Required to Open), 1/4 486 [MOVFO2FCV0740002 Common Cause: Group Shutdown Cooling Valves 2.2264E+000 MOVFO2FCV0740013] (Required to Open), 2/4 487 [MOVFO2FCV0740013 Common Cause: Group Shutdown Cooling Valves 2.2264E+000 MOVFO2FCV0740036] (Required to Open), 2/4 2.2264E+000 (RequiredCause: Group 488 [MOVFO2FCV07400113 MOVFO2FCV0740025] Common to Open), 2/4 Shutdown Cooling Valves 489 [MOVFO2FCV0740002] Common Cause: Group Shutdown Cooling Valves 2.2264E+000

[MOVO2FCO74002] (Required to Open), 1/4 490 [MOVFO2FCV0740002 Common Cause: Group Shutdown Cooling Valves 2.2264E+000 MOVFO2FCV0740025] (Required to Open), 2/4

[MOVFC2FCV0740001 491 MOVFC2FCV0740012 Common Cause: Group Shutdown Cooling Valves 2.2264E+000 MOVFC2FCV0740024 (Required to Close), 4/4 MOVFC2FCV0740035]

492 [MOVFC2FCV0740012 Common Cause: Group Shutdown Cooling Valves 2.2264E+000 MOVFC2FCV0740035] (Required to Close), 2/4 E-133

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 493 RL1 FD2RLY10AK97B Relay RLY-1 OA-K97B Fails to Drop Out On Demand 2.2264E+000 494 RL1 FD2RLY1 OAK97A Relay RLY-1 OA-K97A Fails to Drop Out On Demand 2.2264E+000 495 HOVXC2HCV0740049 Valve HCV-74-49 Transfers Closed 2.2264E+000 496 [MOVFC2FCV0740012 Common Cause: Group Shutdown Cooling Valves 2.2264E+000 MOVFC2FCV0740024] (Required to Close), 2/4 497 [MOVFC2FCV0740001 Common Cause: Group Shutdown Cooling Valves 2.2264E+000 MOVFC2FCV0740035] (Required to Close), 2/4 498 [MOVFC2FCV0740012] Common Cause: Group Shutdown Cooling Valves 2.2264E+000 (Required to Close), 1/4 499 [MOVFC2FCV0740001] Common Cause: Group Shutdown Cooling Valves 2.2264E+000

[MOVC2FCO74001] (Required to Close), 1/4

[MOVFO2FCV0740002 500 MOVFO2FCV0740013 Common Cause: Group Shutdown Cooling Valves 2.2264E+000 MOVFO2FCV0740025 (Required to Open), 4/4 MOVFO2FCV0740036]

501 [MOVFO2FCV0740002 Common Cause: Group Shutdown Cooling Valves 2.2264E+000 MOVFO2FCV0740036] (Required to Open), 2/4 502 [MOVFC2FCV0740001 Common Cause: Group Shutdown Cooling Valves 2.2264E+000 MOVFC2FCV0740024] (Required to Close), 2/4 503 [MOVFC2FCV0740001 Common Cause: Group Shutdown Cooling Valves 2.2264E+000 MOVFC2FCV0740012] (Required to Close), 2/4 504 MOVXC2FCV0740047 Valve FCV-74-47 Transfers Closed 2.2264E+000 505 MOVXC2FCV0740013 Valve FCV-74-13 Transfers Closed 2.2264E+000 506 MOVXC2FCV0740048 Valve FCV-74-48 Transfers Closed 2.2264E+000 507 MOVXO2FCV0740012 Valve FCV-74-12 Transfers Open 2.2264E+000 508 MOVFO2FCVo740047 Valve FCV-74-47 Fails to Open On Demand 2.2264E+000 509 MOVXO2FCV0740001 Valve FCV-74-1 Transfers Open 2.2264E+000 510 SWPFD2SWP0680093 Pressure Switch PS-68-93 Fails to Operate On 2.2264E+000 Demand 511 MOVXC2FCV0740002 Valve FCV-74-2 Transfers Closed 2.2264E+000 512 SWPFD2SWPO680094 Pressure Switch PS-68-94 Fails to Operate On 2.2264E+000 Demand 513 MOVFO2FCV0740048 Valve FCV-74-48 Fails to Open On Demand 2.2264E+000 514 S ARSequencer Fails, Breaker 1838 Transfers Open or 2.2250E+000 4 SA3AR Breaker 1334 Transfers Closed 515 COVLK2Z0020526 Condensate Pump C Discharge Check Valve 2-526 2.2238E+O000 Gross Reverse Leakage 2.2238E+000 516 COVLK2_0020550 Condensate Booster Pump C Discharge Check 2.2238E+000 Valve 2-550 Gross Reverse Leakage E-134

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 517 [RL1 FD2RLY1 OAK9A] Common Cause: Group RHR Pump Actuation 2.2100E+000 Relays (K9), 1/2 518 ZTS1BR Transformer TS1B Fails During Operation 2.1393E+000 519 B1B1CT Output Breaker 1C Transfers Open 2.1393E+000 520 BE1B5T Input Breaker 5 Transfers Open 2.1393E+000 521 ESD1BR 480V Shutdown Bus 1B Fails 2.1393E+000 522 [PMSFS2_02300B2] Common Cause: Group RHRSW South Header 2.1239E+000

[PMSF2.0230B2] Pumps, 1/4 523 [PMSFR2_02300B2] Common Cause: RHRSW South Header Pumps, 2.1237E+000 1/4 524 COVF02_0230526 Check Valve 0-23-526 Fails to Open On Demand 2.1217E+000 525 HOVXC2Z0230527 Manual Valve 0-23-527 Transfers Closed 2.1217E+000 526 COVXC2_0230526 Check Valve 0-23-526 Transfers Closed 2.1197E+000 527 [B136140 81 7180] Common Cause: Group Unit l and 2 4kV Shutdown 2.1031 E+000 Board Feeder Breakers, 2/4 528 [B16140 B17180 B17240] Common Cause: Group Unit 1 and 2 4kV Shutdown 2.1010E+000 Board Feeder Breakers, 3/4

[MOVFO2FCV0740057 529 MOVF02FCV0740059 Common Cause: Group Suppression Pool Cooling 2.0930E+000 MOVFO2FCV0740071 MOVs, 4/4 MOVF02FCV0740073]

530 [MOVFO2FCV0740057 Common Cause: Group Suppression Pool Cooling 2.0930E+000 MOVFO2FCV0740073] MOVs, 2/4 531 [MOVFO2FCV0740057 Common Cause: Group Suppression Pool Cooling 2.0930E+000 MOVFO2FCVW740071] MOVs, 2/4 532 [MOVFO2FCV0740059 Common Cause: Group Suppression Pool Cooling 2.0930E+000 MOVFO2FCV0740073] MOVs, 2/4 533 [MOVFO2FCV0740059 Common Cause: Group Suppression Pool Cooling 2.0930E+000 MOVFO2FCV0740071] MOVs, 2/4 534 ESDB1 R Shutdown Bus 1 Fails 2.0358E+000 535 [MOVFC2FCV0710002 Common Cause: Group RCIC Fails to Isolate on 2.0357E+000 MOVFC2FCV0710003] Breaks Outside Containment, 2/2 536 B13Ato Breaker 13A Transfers Open 2.0173E+000 537 [MGAR MGBR] Common Cause: Group Motor Generator Sets Fail, 2.0173E+000 538 [MGAR] Common Cause: Group Motor Generator Sets Fail, 2.0173E+000 1/2 539 ERPSAR RPS Bus A Fails During Operation 2.0169E+000 540 [DG3BS DG3CS] Common Cause: Group Unit 3 DGs, 2/4 2.0167E+000 541 B2A1to Protection Contactor 2A1 Transfers Open 2.0164E+000 E-135

BFN Unit 2 Significant Basic Events By Risk Achievement Worth Risk Achievement Rank Basic Event Description Worth 542 B2A2to Protection Contactor 2A2 Transfers Open 2.01 64E+000 543 B902T DIST. PNL. Feeder Breaker 902 Transfers Open 2.01 64E+000 544 [B16140 B17240] Common Cause: Group Unit 1 and 2 4kV Shutdown 2.0158E+000 Board Feeder Breakers, 214 55 1364]Common Cause: Group Unit 1 and 2 4kV Shutdown 2.01 51 E+000 fB16140]Board Feeder Breakers, 1/4 E-136

BFN Unit 3 Significant Basic Events by Fussell-Vesely Importance Measure Rank Basic Event Name Basic Event Description Fussell-Vesely Importance 1 HER HPRVD1 Operator Fails to Initiate Depressurization 1.6546E-001 2 [DG3AS] Common Cause: Group Unit 3 DGs, 1/4 1.6291E-001 3 [DGAS DGBS DGCS DGDS] Common Cause: Group Unit 1/2 DGs, 4/4 1.1799E-001 4 [DG3BS] Common Cause: Group Unit 3 DGs, 1/4 9.2084E-002 Operator fails to Open Hardened wetwell Vent - Ac Power 5 OPERR-OLP2 Available - SPC Initiation Failed 8.9234E-002 6 [DGAS] Common Cause: Group Unit 1/2 DGs, 1/4 8.6650E-002 7 RODS5 Generic RPS Failure Rate per NUREG 8.5296E-002 Operator Fails to Control HPCI/ RCIC Injection GIVEN 8 OHL2 OHC Failed 7.0112E-002 Operator Fails to take early action to Control HPCV RCIC 9 OHC1 Injection 6.4587E-002 10 PTSFS2PMP0730054 HPCI Pump Fails to Start On Demand 6.4105E-002 11 [DG3CS] Common Cause: Group Unit 3 DGs, 1/4 6.3529E-002 12 [B1D B2D B3D] Common Cause: Group Battery Boards 1, 2, and 3,3/3 6.1970E-002 13 CONDENSER_2A2B2C Main Condenser Unavailable After Plant Trip 6.1598E-002

[DG3AS DG3BS DG3CS 14 DG3DS] Common Cause: Group Unit 3 DGs, 4/4 5.6991 E-002 15 PTSFR2PMP71019-6 RCIC Turbine Driven Pump Fails to Run 5.6353E-002 16 OPERROSP1 Operator Fails to Align for Suppression Pool Cooling 5.3998E-002 17 PTSFR2PM71019_18 RCIC Turbine Driven Pump Fails to Run for 18 hours2.083333e-4 days <br />0.005 hours <br />2.97619e-5 weeks <br />6.849e-6 months <br /> 5.3538E-002

[MOVF2FCV0230040 MOVFO2FCV0230034 MOVFO2FCV0230046 18 MOVFO2FCV0230052] Common Cause: Group RHR Heat Exchangers, 4/4 5.2626E-002 19 [DGBS] Common Cause: Group Unit 3 DGs, 1/4 4.9261 E-002 20 [DG3AS DG3BS DG3CS] Common Cause: Group Unit 3 DGs, 3/4 4.9055E-002 21 PTSFS2PMP0710019 RCIC Turbine Driven Pump Fails to Start On Demand 4.2787E-002 22 PTSFR2PMP73054-6 HPCI Pump Fails During Operation 4.0581 E-002 23 PTSFR2PM73054-18 HPCI Pump Fails Long Term 4.0327E-002 24 [DGCS] Common Cause: Group Unit 1/2 DGs, 1/4 3.3984E-002 Operator Actions to Align RHRSW to Unit 2 RHR Loop I 25 OU12 Fail 3.3874E-002 Operators Fail to Align U1 RHR Loop II Thru X-Tie to U2 26 OUll RHR Loop I 3.3702E-002 27 COVFO2_0030528 Bypass Startup Check Valve 528 Fails To Open 2.3820E-002 28 [DGAS DGBS DGCS] Common Cause: Group Unit 1/2 DGs, 3/4 2.2176E-002 E-1 37

BFN Unit 3 Significant Basic Events by Fussell-Vesely Importance Measure Rank Basic Event Name Basic Event Description Fussell-Vesely Importance 29 PTSFS1CCFRCIHPI HPCI and RCIC Common Cause Failure to Start 1.5723E-002 30 MOVFC2FCV0710034 Valve FCV-71-34 Fails to Close On Demand 1.5489E-002 31 BEIVR10 Recovery of RHRSW 1.461 OE-002 32 [MOVFO2FCV0710008] Common Cause: Group RCIC Steam Supply, 1/2 1.4240E-002 Common Cause: Group HPCI RCIC Pump Discharge 33 [MOVFO2FCV0710039] MOV failure, 1/2 1.4240E-002 Unit 2 RHR Heat Exchanger Outlet X-Tie 2-FCV-74-101 34 MOVFO2FCV0740101 Fails To Open On Demand 1.2703E-002 35 [DGDS] Common Cause: Group Unit 1/2 DGs, 1/4 1.2159E-002 36 MOVFC2FCV0730040 MOV 2-FCV-73-40 Fails to Close On Demand 1.1618E-002 37 MOVFO2FCV0730027 MOV 2-FCV-73-27 Fails to Open On Demand 1.1618E-002 38 MOVFO2FCV0730026 MOV 2-FCV-73-26 Fails to Open On Demand 1.1618E-002 39 PTSFR1CCF-RCIHPI HPCI and RCIC Pumps Failure to Run 1.1052E-002 40 [MOVFO2FCV0730016] Common Cause: Group RCIC Steam Supply, 1/2 1.0677E-002 Common Cause: Group HPCI RCIC Pump Discharge 41 [MOVFO2FCV0730044] MOV failure, 1/2 1.0677E-002

[MOVFO2FCV0710008 42 MOVFO2FCVW730016] Common Cause: Group RCIC Steam Supply, 2/2 1.0639E-002

[MOVFO2FCV0710039 Common Cause: Group HPCI RCIC Pump Discharge 43 MOVF02FCV0730044] MOV failure, 2/2 1.0639E-002 44 [DG3AS DG3BS] Common Cause: Group Unit 3 DGs, 2/4 9.9680E-003 Motor Operated Ventilation Dampers Fail to Open or Fans 45 WABCD Fail to Start or Run. 9.6747E-003 Unit 3 RHR Heat Exchanger Outlet X-Tie 3-FCV-74-100 46 MOVFO3FCV0740100 Fails To Open On Demand 9.0990E-003

[RL1FD2RLY10AK9A Common Cause: Group RHR Pump Actuation Relays 47 RL1FD2RLY10AK9B] (K9), 2/2 8.0828E-003 48 [MOVFO2FCV0230034] Common Cause: Group Heat Exchanger MOV, 1/4 7.9768E-003 49 [DGAS DGBS DGDS] Common Cause: Group Unit 1/2 DGs, 3/4 6.9286E-003 Insufficient Flow to ECCS Suction Ring Header During 50 ECCSSUPPLYTRAN Transient 6.8892E-003 51 [DG3AS DG3CS] Common Cause: Group Unit 3 DGs, 2/4 6.7230E-003 52 [DG3BS DG3CS] Common Cause: Group Unit 3 DGs, 2/4 6.2112E-003 53 [DGAS DGCS DGDS] Common Cause: Group Unit 1/2 DGs, 3/4 6.1006E-003 54 [DGBS DGCS DGDS] Common Cause: Group Unit 1/2 DGs, 3/4 5.9726E-003 55 [PMSFS2PMP0740005] Common Cause: Group RHR Pumps Fail to Start, 1/4 5.9704E-003 56 BERBE5 Reactor Building Essentially Bypassed 5.7667E-003 57 [DGAS DGBS] Common Cause: Group Unit 1/2 DGs, 2/4 4.9552E-003 E-138

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Acieveen 1 [TB1D B2D B3D]3l Common Cause: Group Battery Boards 1, 2, and 1.1 I567E+005 3, 3/3 2 RODS5 Generic RPS Failure Rate per NUREG 3.3168E+004 3 SWCS CCF (Failure to Start) of All RHRSW Pumps 1.0013E+004 4 SWCR CCF (Failure to Run) of All RHRSW Trains 1.0013E+004 5 ECSSPPYTA Insufficient Flow to ECCS Suction Ring Header 6.5333E+003 ECCSSUPPLY_TRAN During Transient 6 HERHPRVD1 Operator Failure to Depressurize Given 8.6350E+002 HPCI/RCIC Hardware Failed 7 WABCD Motor Operated Ventilation Dampers Fail to Open 8.5600E+002 or Fans Fail to Start or Run.

8 [DGAS DGBS DGCS DGDS] Common Cause: Group Unit 1/2 DGs, 4/4 8.5600E+002 9_ __ OPERROSP1

_ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ C ooling Fails to Align for Suppression Pool Operator _

6.7169E+002 10 [8313360 B13340 B13380 1313420] Common Cause: Group Unit 3 4kV Shutdown 5.4350E+002 Board Feeder Breakers , 4/4 11 [PMSFS2PMP0740005 PMSFS2PMP0740016 Common Cause: Group RHR Pumps Fail to Start, 4.8497E+002 PMSFS2PMP0740028 PMSFS2PMP0740039] 4/4

[RL1 FD2RLY1 OA1 17B RL1 FD2RLY1 OA1 19B Common Cause: Group RHR Pumps Actuation 12 RL1FD2RLY10A123A RL1FD2RLY1OA111B Relays 6/6 4.8497E+002 RL1 FD2RLY1 OA124A RL1 FD2RLY1 OA130A] ,

[RL1 FD2RLY1 OAK18A RL1 FD2RLY1 OAK18B Common Cause: Group RHR Pumps Actuation 13 RL1FD2RLY1OAK21A RL1FD2RLY1OAK21B Rela (2nd Setj 6/6 4.8497E+002 RLI FD2RLY1 OAK25A RL1 FD2RLY1 OAK25B] ys 14 RI1F2Y1OKAI-FDRYOA9] Common Cause: Group RHR Pump Actuation 4.895E+02 14 [RL1FD2RLY10AK9A RL1 FD2RLY10AKsB] Relays (K9), 2/2 15 [CH12R CH22R CH32R] Common Cause: Group Chargers for Battery 4.5739E+002 Boards, 3/3 16 [8136140 81 6160 81 7180 8137240] Common Cause: Group Unit 1 and 2 4kV 4.232E+02 Shutdown Board Feeder Breakers, 4/4 17 [DG3AS DG3BS DG3CS] Common Cause: Group Unit 3 DGs, 3/4 4.1023E+002 18 [DG3AS DG3BS DG3CS DG3DS] Common Cause: Group Unit 3 DGs, 4/4 4.1023E+002 19 W3ABCD Motor Operated Ventilation Dampers Fail to Open 4.1023E+002 or Fans Fail to Start 20 [B1D B2D] Common Cause: Group Battery Boards 1, 2, and 4.0333E+002 3, 2/2 21 [Bi1D 13D1] Common Cause: Group Battery Boards 1, 2, and 3.9284E+02 3, 2/3 E-139

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Risk 22 [B2D B3D] Common Cause: Group Battery Boards 1, 2, and 3.7666E+002 3, 2/3 23 [FN2FR2FAN098061 FN2FR2FAN098062] Common Cause: Group SAI Panel Coolers, 2/2 3.5890E+002 24 [MOVFO2FCV0230040 MOVF02FCV0230034 Common Cause: Group RHR Heat Exchangers, 3.51 89E+002 MOVFO2FCV0230046 MOVFO2FCV0230052] 4/4 25 [CH22R CH32R] Common Cause: Group Chargers for Battery 2.9333E+002 Boards, 213 26 [B13340 B13360 B13380] Common Cause: Group Unit 3/4k Shutdown 2.5757E+002 Board Feeder Breakers , 314 27 [DGAS DGBS DGCS] Common Cause: Group Unit 1/2 DGs, 3/4 1.8770E+002 28 [PMSFS2PMP0740005 PMSFS2PMP0740016 Common Cause: Group RHR Pumps Fail to Start, 1.8092E+002 PMSFS2PMP0740028] 3/4 29 EPMOFR2__0230oA3 PMOFR202300B3 Common Cause: Group EECW Pumps, 4/4 1.7330E+002 PMSFR2_02300C3 PMSFR2L_02300D3]

30 [B16140 B16160 B17180] Common Cause: Group Unit 1 and 2 4kV 1.4860E+002 Shutdown Board Feeder Breakers, 3/4 31 [RL1 FD2_00374A1 RL1 FD2_00374B1 Common Cause: Group Low RX Pressure 1.3790E+002 RL1 FD2_0680951 RL1 FD2_0680961] Permissive Output Relays, 4/4 32 [RL1 FD214A0750K9A RL1 FD214A0750K9B Common Cause: Group Low RX Pressure 1.3790E+002 RL1 FD214A075K23A RL1 FD214A075K23B] Permissive Relays (CSS), 4/4 33 [SWDFD2PIS003074A SWDFD2PIS003074B Common Cause: Group Low RX Pressure 1.3790E+002 SWDFD2PIS0680095 SWDFD2PIS0680096] Permissive Bistables, 4/4 2/2 RX Pressure 1.3790E+002 34 [RL1FD214A075K13A RL1 FD214A075K13B] Common Logic Group PermissiveCause: Relays,Low 35 [PMSFR2_02300B1 PMSFR2_02300B2 Common Cause: Group RHRSW South Header 1.3361 E+002 PMSFR2_02300D1 PMSFR2_02300D2] Pumps, 4/4 36 [PMSFS2 0230O61 PMSFS2_02300B2 Common Cause: Group RHRSW South Header 1.3361 E+002 PMSFS2_02300D1 PMSFS2_02300D2] Pumps, 4/4 37 OPERROLP1 Operator Fails to Manually Control LPCI/CS 1.1797E+002 38 COVXC2_0030528 rBypass Startup Check Valve 528 Transfers Closed 9.2119E+001 38 COVXC2--0030528or Becomes Plugged921E01 39 COVF02 0030528 Bypass Startup Check Valve 528 Fails To Open 9.2116E+001 40 [PMOFS2_02300B3 PMOFS2_02300A3 Common Cause: Group EECW Pumps, 4/4 7.8445E+001 PMSFS2_02300C3 PMSFS2-02300D3J __________________

41 OHC1 Operator Fails to take early action to Control HPCI/ 6.1832E+001 RCIC Injection CsGo Ut/ s,4.0 0 42 [DGAS DGBS DGDS] Common Cause: Group Unit 1/2 DGs, 3/4 5.9905E+001 43 [DGAS DGCS DGDS] Common Cause: Group Unit 1/2 DGs, 3/4 5.2993E+001 44 [DGBS DGCS DGDS] Common Cause: Group Unit 1/2 D~s, 3/4 5.1955E+001 45 B1326T Breaker 1326 to 4kV SD Board 3EA Transfers 4.7860E+001 Open E-140

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description l cRise n 46 [8313340 B13360 B13420] CCommon Cause: Group Unit 3 4kV Shutdown 4.4728E-0O1 Board Feeder Breakers , 3/4 47 [B13340 B13360] Common Cause: Group Unit 3 4kV Shutdown 4.4230E+001 4 [D13340BG3BS DGBoard Feeder Breakers , 2/4 48 [DG3AS DG3BS DG3DS] Common Cause: Group Unit 3 DGs, 3/4 4.0897E+001 49 [DG3AS DG313S] Common Cause: Group Unit 3 DGs, 2/4 4.0867E-i001 50 PTSFS1CCFRCIHPI HPCI and RCIC Common Cause Failure to Start 3.1790E+001 51 [MOVFO2FCV0710008 MOVFO2FCV0730016] Common Cause: Group RCIC Steam Supply, 2/2 3.1790E+001 52 [MOVFO2FCV0710039 MOVF02FCV0730044] Common Cause: Group HPCI RCIC Pump 3.1790E+001 Discharge MOV failure, 2/2 53 RY23 K25 FD2Y01Common Cause: Group HPCI/RCIC Actuation 3.1790E+001

[RL1 2RLY23A_K25 RL1 FD2RLY071 OK22]

3 Relays, 2/4 54 (ALl FD223AjK21 RL1 FD2RLY071O0K22] Common Cause: Group HPCVRCIC Actuation 3.1790E+001 Relays, 2/4 55 PTSFRICCFRCIHPI HPCI and RCIC Pumps Failure to Run 3.1790E+001 56 [RL1FD223AK22 RL1 FD2RLY071 0K22] Common Cause: Group HPCI/RCIC Actuation 3.1790E+001 Relays, 2/4 57 [RL1FD223AK21 RL12RLY23AK25 Common Cause: Group HPCI/RCIC Actuation 3.1532E+001 RL1 FD223AK22 RL1 FD2RLY071 0K22] Relays, 4/4 58 [RL12RLY23Aji25 RL1FD223AK21 Common Cause: Group HPCURCIC Actuation 3.1469E+001 RL1FD2RLY0710K22] Relays, 3/4 59 [RLI FD223AK21 RL1 FD223AK22 Common Cause: Group HPCI/RCIC Actuation 3.1469E+001 RL1 FD2RLY071 OK22] Relays, 3/4 60 [RLI 2RLY23AK25 RL1 FD223A_K22 Common Cause: Group HPCI/RCIC Actuation 3.1469E+001 RL1 FD2RLY071OK22] Relays, 3/4 61 [MOVFO2FCV0230034 MOVFO2FCV0230040 Common Cause: Group RHR Heat Exchangers, 2.9393E+001 MOVFO2FCV0230046] 3/4 62 [DG3AS DG3CS DG3DS] Common Cause: Group Unit 3 DGs, 3/4 2.7873E+001 63 [DG3AS DG3CS] Common Cause: Group Unit 3 DGs, 2/4 2.7837E+001 64 [DG3BS DG3CS DG3DS] Common Cause: Group Unit 3 DGs, 3/4 2.5878E+001 65 [DG3BS DG3CS] Common Cause: Group Unit 3 DGs, 2/4 2.5842E+001 66 [PMOFR2_02300A3 PMOFR]O2300B3 Common Cause: Group EECW Pumps, 3/4 2.5527E+001 PMSFR2--02300D3]

67 [PMOFR2 0---030230B3 Common Cause: Group EECW Pumps, 3/4 2.5468E+001 PMSFR2.02300C31 _ _ _ _ _ _ _ _ __ _ _ _ _ _ _ _ _

68 ECCSSUPPLY_LOST insufficient Flow Available to Ring Header During 2.3922E+001 LOCA 69 PRESSSPRESLOST PSP Fails to Quench Steam During LOCA 2.3922E+001 Blowdown 70 [DGAS DGBS] Common Cause: Group Unit 1/2 DGs, 2/4 2.0851 E+001 E-141

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Achievekent 71 ESD3EAR Shutdown Board 3EA Fails Bus Fault 1.9030E+001 72 [816140 B16160 B17240] Common Cause: Group Unit 1 and 2 4kV 1.8754E+001 Shutdown Board Feeder Breakers, 3/4 73 313641166]Common

[B16140 B16160] Shutdown Cause: Group Unit Board Feeder 1 and 2, 2/4 Breakers 4kV 1.8286E+001 74 [PMSFR2_0230OB1 PMSFR2 0230082 Common Cause: Group RHRSW South Header 1.7056E+001 PMSFR2O02300D1] Pumps, 3/4 75 [PMSFS2 02300B1 PMSFS2_0230082 Common Cause: Group RHRSW South Header 1.7036E+001 PMSFS2_02300D1] Pumps, 3/4 76 OHL2 Operator Fails to Control HPCI/ RCIC Injection 1.653E+001 GIVEN OHC Failed 77 [CH12R CH22R] Common Cause: Group Chargers for Battery 1.6040E+001 Boards, 2/2 78 [PMSFS2PMP0740005 PMSFS2PMP0740016 Common Cause: Group RHR Pumps Fail to Start, 1.4891 E+001 PMSFS2PMP0740039] 3/4 79 [PMOFS2 02300A3 PMOF] 202300B3 Common Cause: Group EECW Pumps, 3/4 1.4743E+001

[PMSFS2 02300C3] PMOFS2 _02300B3 80 [PMOFS2=02300A3 PMOFS202300B3 Common Cause: Group EECW Pumps, 3/4 1.4647E+001

__ __ PMS FS2.-02300D3]__ _ _ _ _ _ _ _ _ _ _ _ _ _ _ _ __ _ _ _ _ _ _

81 B1334T Breaker 1334 to Unit Board 3EA Transfers Open 1.4335E+001 82 [DGAS DGCS] Common Cause: Group Unit 1/2 DGs, 2/4 1.3938E+001 8 [PMSFR2_02300B1 PMSFR2_02300B2 Common Cause: Group RHRSW South Header 1.3674E+001 PMSFR2_02300D2] Pumps, 3/4 84 [PMSFS2_02300B1 PMSFS2_02300B2 Common Cause: Group RHRSW South Header 1.3651 E+001 PMSFS2_02300D2] Pumps, 3/4 85 [PMOFR2_02300B3 PMSFR2_02300C3 Common Cause: Group EECW Pumps, 3/4 1.3613E+001 PMSFR2-02300D3]

86 ESDAR Shutdown Board A Bus Fault 1.3385E+001 87 [DGBS DGCS] Common Cause: Group Unit 1/2 DGs, 2/4 1.2900E+001 88 [MOVFO2FCV0230034 MOVFO2FCV0230040 Common Cause: Group RHR Heat Exchangers, 1.2492E+001 MOVFO2FCV0230052] 3/4 89 E1201R Unit 1 Preferred Bus 2 BD 9-9 Failed 1.2080E+001 90 ZFESFD Auto Bus Transfers Switch 1 Fails 1.2080E+001 91 HOVXC2HCV0740085 Unit 2 SPC Isolation 2-HCV-74-85 Transfers 1.1263E+001 Closed 92 HOVXC2HCV0670565 Valve 67-565 Transfers Closed 1.1263E+001 93 MOVXC2FCV0740007 FCV-74-7 Transfers Closed 1.1000E+001 94 [PMSFS2PMP0740005 PMSFS2PMP0740028 Common Cause: Group RHR Pumps Fail to Start, 1.0998E+001 PMSFS2PMP0740039] 3/4 E-142

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Achievement 95 T

[PMSFS2PMP0740005 PMSFS2PMP0740016] Common Cause: Group RHR Pumps Fail to Start, 2/4 1.0982E+001 96 B1614TO Breaker 1614 to 4kV Shutdown Board A Transfers 1.0706E+001 Open _ _ _ _ _ _ _

97 [PMSFS2PMP0740016 PMSFS2PMP0740028 Common Cause: Group RHR Pumps Fail to Start, 9.4124E+000 PMSFS2PMP0740039] 3/4 98 [PMSFR2 02300A1 PMSFR2.02300A2 Common Cause: Group RHRSW A and C Pumps 9.3693E+000 PMSFR2 02300C1 PMSFR2 02300C2] Fail to Run 4/4 99 [PMSFS2_02300A1 PMSFS2 02300A2 Common Cause: Group RHRSW South Header 9.3693E+000 PMSFS2 02300C1 PMSFS2_02300C2] Pumps, 4/4 100 [MOVFO2FCV0230034 MOVFO2FCV0230040] Common Cause: Group RHR Heat Exchangers, 9.2387E+000 2/4 101 [PMSFR2_02300A1 PMSFR2__02300A2 Common Cause: Group RHRSW A and C Pumps 9.0979E+000 PMSFR2_02300C2] Fail to Run 3/4 102 [PMSFS2 02300A1 PMSFS2_02300A2 Common Cause: Group RHRSW South Header 9.0978E+000 PMSFS2_02300C2] Pumps, 3/4 103 PMSFR2=02300D3- Common Cause: Group EECW Pumps, 3/4 8.8269E+000 104 [PMOFS2O2300A3 PMSFS2_02300C3 Common Cause: Group EECW Pumps, 3/4 8.8029E+000 105 B1332T Breaker 1332 to 4kV Shutdown Board 3EB 8.7432E+000 Transfers Open 106 [PMSFR2L 02300B11 PMSFR2L 02300B2J Common Cause: Group RHRSW South Header 7.7862E+000 106___ [PMSFR2___________023001_PMSR2_0200B2 Pumps, 2/4 107 [PMSFS2.02300B1 PMSFS2L_02300B2] Common Cause: Group RHRSW South Header 7.7845E+000 107___ [PMSFS2_____________0_02300B2]_____ Pumps, 2/4 108 [BID] Common Cause: Group Battery Boards 1, 2, and 6.9084E+000 3,112 109 [MOVF02FCV0230034 MOVFO2FCV0230046 Common Cause: Group RHR Heat Exchangers, 6.5643E+000 MOVFO2FCV0230052] 3/4 110 [B13340 B13380 B13420] Common Cause: Group Feeder Breakers for Unit 6.4988E+000 3 4kV SD Boards Fail To Open On Demand, 3/4 111 EBBIR Battery BD. 1 Bus Fails. 6.2799E+000 112 [DGAS DGDS] Common Cause: Group Unit 1/2 DGs, 2/4 6.2358E+000 113 [B13340 B13380] Common Cause: Group Feeder Breakers for Unit 6.0039E+000 3 4kV SD Boards Fail To Open On Demand, 214 114 B203T Feeder Breaker 203 Transfers Open During 5.9934E+000 Operation 115 E3A250R 250V RMOV BD 3A Bus Failed. 5.9934E+000 116 B2D3AT Breaker 2D Transfers Open 5.9934E+000 117 [PMSFS2PMP0740005 PMSFS2PMP0740028] Common Cause: Group RHR Pumps Fail to Start, 5.9002E+000 2/4 E-143

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Risk 118 [PMSFR2 02300B2 PMSFR2 02300D1 Common Cause: Group RHRSW South Header 5.7203E+000 PMSFR2O02300D2j Pumps, 3/4 119 [PMSFS2_0230082 PMSFSZO02300D1 Common Cause: Group RHRSW South Header 5.6963E+000 PMSFS2_02300D2] Pumps, 3/4 120 IPMSFRZ-02300B1 PMSFR2_02300D1 Common Cause: Group RHRSW South Header 5.6893E+000 PMSFR2 02300D2] Pumps, 3/4 121 [PMSFS2_0230081 PMSFS2_02300D1 Common Cause: Group RHRSW South Header 5.6667E+000 PMSFS2O02300D2] Pumps, 3/4 122 [B133340 B13420] Common Cause: Group Feeder Breakers for Unit 5.6562E+000 3 4kV SD Boards Fal To Open On Demand, 2/4 123 [RL1 FD2RLY1 OA111 B RL1 FD2RLY1OA124A] Common Cause: Group Relayl, 2/6 5.6393E+000 124 [RL1 FD2RLY1OAK18A RL1 FD2RLY1 OAK1 8B] Common Cause: Group Relay3, 2/6 5.6390E+000 125 [813340] Common Cause: Group Feeder Breakers for Unit 5.6341 E+000 3 4kV SD Boards Fail To Open On Demand, 1/4 126 [DG3AS DG3DS] Common Cause: Group Unit 3 DGs, 2/4 5.6066E+000 127 [DG3AS] Common Cause: Group Unit 3 DGs, 1/4 5.5711 E+000 128 [CH12R CH32R] Common Cause: Group Chargers for Battery 5.5472E+000 Boards, 2/3 129 HOVXC2HCV0740088 Unit 2 SPC Isolation 2-HCV-74-88 Transfers 5.5421 E+000 Closed 130 COVLK2 -0020517 Condensate Pump B Discharge Check Valve 2- 5.2368E+000 517 Gross Reverse Leakage 131 [PMOFR2_CP002002A PMOFR20CP002002B Common Cause: Group Condensate Pumps, 3/3 5.2368E+000 PMOFR2_CP002002C]

132 DIMFR2_002CODM Insufficient Flow Thru Demin Path 5.2368E+000 133 HXRPL2 0020FGA Excessive Leakage/Rupture OF Off-Gas Main 5.2368E+000 Condenser Unavailable After Plant Trip 134 [PMOFR2CBPOO2002A PMOFR2CBPOO2002B Common Cause: Group Condensate Pumps Fail 5.2368E+000 PMOFR2CBP002002C] to Run, 3/3 135 COVFT2_0020517 Condensate Pump B Discharge Check Valve 2- 5.2368E+000 517 Fails to Reseat 136 COVFT2 -0020558 Condensate Booster Pump B Discharge Check 5.2368E+000 Valve 2-558 Fails to Reseat 137 COVLK2_0020558 Condensate Booster Pump B Discharge Check 5.2368E+000 Valve 2-558 Gross Reverse Leakage 138 HXRPL2_002EXHA Excessive Leakage/Rupture OF Steam Packing 5.2368E+000 Exhauster 139 MOVXC2FCV0020041 Outlet Valve FCV 2-41 Transfers Closed 5.2368E+000 140 MOVXC2FCV_020036 Inlet Valve FCV2-36 Transfers Closed 5.2368E+000 141 1HXRPL2 OO2SJAE Excessive Leakage/Rupture (SJAE) 5.2368E+000 E-144

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Achievement 142 [DGBS DGDS] Common Cause: Group Unit 1/2 DGs, 2/4 5.1978E+000 143 [D230TC D231TC] Common Cause: Group Unit 3 DG Dampers, 2/2 5.1322E+000 144 [VA3AS VB3AS] Common Cause: Group Unit 3 DG Fans Fail to 5.1061 E+000 Start, 2/2 145 OHC3 Operator Fails to Take Early Action to Control 5.0630E+000 RICIC Injection 146 CHARG3A2R *3A-, IN/Out Fuses Fail, Charger Input, Output 4.9478E+000 Breaker Transfers 0 147 [MOVF02FCV071 0034 MOVXC2FCV0730036] Common Cause: Group HPCI RCIC Retum Lines 49350E+00 MOVs, 2/4 148 M862T Manual Valves 862,699 Transfers Closed or 4.9297E+000 Expansion Joint Leak.

149 W35TC Fire Dampers 1035, 1031 Transfers Closed 4.8748E+000 150 E12S3AR 125V DC Bus or Battery Fails or Fused Switch to 4.8725E-i000 DG CONT Transfers 151 [PMSFR2_02300B1 PMSFR2_02300D1] Common Cause: Group EECW Pumps, 2/4 4.8666E+000 152 [PMSFS2_02300B1 PMSFS2O02300D1] Common Cause: Group RHRSW South Header 4.8663E+000 Pumps, 2/4 153 SA3 153 A3ARBreaker Sequencer Fails, Breaker 1838 Transfers Open or 1334 Transfer's Closed 4.8590E+000 1 4 [MOVFO2FCV0710034 MOVXC2FCV0710038 Common Cause: Group HPCI RCIC Retum Lines 4.8277E+000 MOVXC2FCV0730035 MOVXC2FCV0730036] MOVs, 4/4 155 [DGCS DGDS] Common Cause: Group Unit 1/2 DGs, 2/4 4.7602E+000 156 [MOVFO2FCV0710034 MOVXC2FCV0730035 Common Cause: Group HPCI RCIC Retum Lines 4.7422E+000 MOVXC2FCVW730036] MOVs, 3/4 157 [MOVFO2FCV0710034 MOVXC2FCV0710038 Common Cause: Group HPCI RCIC Return Lines 4.7422E+000 MOVXC2FCV0730036] MOVs, 3/4 158 [MOVFO2FCVW710034 MOVXC2FCV0710038 Common Cause: Group HPCI RCIC Retum Lines 4.7422E+o00 MOVXC2FCV0730035] MOVs, 3/4 159 COVFT2_0020526 Condensate Pump C Discharge Check Valve 2- 4.7174E+000 526 Fails to Reseat 160 COVFT2R 0020550 Condensate Booster Pump C Discharge Check 4.7174E+000 Valve 2-550 Fails to Reseat 161 COVLK2_0020526 Condensate Pump C Discharge Check Valve 2- 4.6959E+000 526 Gross Reverse Leakage 162 COVLK2 0020550 Condensate Booster Pump C Discharge Check 4.6959E+000 Valve 2-550 Gross Reverse Leakage_______

163 B16072T Output Breaker 607 Transfers Open During 4.6593E+000 Operation.

164 [CH12R] Common Cause: Group Chargers for Battery 4.6593E+000 Boards, 1/2 E-145

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Achievement 165 B16D2T Input Breaker 6D Fails Open. 4.6592E+000 166 [MOVFO2FCV0710034 MOVXC2FCV0710038] Common Cause: Group HPCI FCIC Retum ines 4.6406E+000 MOVs, 2/4 167 [MOVFO2FCV0230040 MOVFO2FCV0230046 Common Cause: Group RHR Heat Exchangers, 4.6131 E+000 MOVFO2FCV0230052] 3/4 168 [MOVFO2FCV0710008] Common Cause: Group RCIC Steam Supply, 1/2 4.6130E+000 169 [MOVF02FCV0710039] Common Cause: Group HPCI RCIC Pump 4.6130E+o00 Discharge MOV failure, 1/2 170 MOVFC2FCV0710034 Valve FCV-71-34 Fails to Close On Demand 4.6089E+000 171 PTSFS1 CCF-RCHP 2 RCIC AMD HPCI CC Failure to Start on Second 4.5989E+000 demand 172 PTSFS1 CCF_RCHP 1 RCIC and HPCI Pumps CC Failure to Start on 4.5989E+000 First demand 173 PTSFR1CCRCHP18 RCIC and HPCI CC Failure to Run For 18 Hours 4.5989E+000 174 B3A10T Breaker 10 Transfers Open During Operation. 4.5874E+000 175 B3A1CT Breaker 1C Transfers Open During Operation. 4.5874E+000 176 ESD3AR 480V Shutdown Bus 3A Fails 4.5841 E+000 177 ZTS3AR TS3A Fails During Operation. 4.5824E+000 178 B3B1CT Breaker 1C Transfers Open During Operation. 4.5069E+000 179 ESD3BR 480V Shutdown Bus 3B Fails 4.5036E+000 180 ZTS3BR TS3B Fails During Operation. 4.5017E+000 181 B1338T Breaker 1338 Transfers Open 4.4981 E+000 182 13B7T Input Breaker 7 Transfers Open 4.4291 E+000 183 [PMSFR2_02300A1 PMSFR2_02300A2 Common Cause: Group RHRSW A and C Pumps 4.4097E+000 PMSFR2_02300C1] Fail to Run 3/4 184 [PMSFS2_02300A1 PMSFS2_02300A2 Common Cause: Group RHRSW South Header 4.4088E+000 PMSFS2_02300C1] Pumps, 3/4 185 [B16140 B17180 B17240] Common Cause: Group Unit 1 and 2 4kV 4.4002E+000 Shutdown Board Feeder Breakers , 3/4 186 OPERROSP3 Operator Fails to Align For Suppression Pool 4.3659E+000 Cooling__ _ _ _ _

187 [PMSFR2 02300A1 PMSFR2_02300A2] Common Cause: Group RHRSW A and C Pumps 4.1383E+000 Fail to Run 2/4 188 [PMSFS2_02300A1 PMSFS2_02300A2] Common Cause: Group RHRSW South Header 4.1374E+000 Pumps, 2/4 189 [PMSFS2PMP0740016 PMSFS2PMP0740028] Common Cause: Group RHR Pumps Fail to Start, 4.1097E+000 2/4 190 [RL1 FD2RLY071 OK2 Common Cause: Group HPCVRCIC Actuation 3.9932E+000 Relays, 1/4 E-146

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Achievement 191 CSVF02HCV071 0014 Stop Check Valve HCV-71-14 Fails to Open On 3.9741 E+00 Demand 192 CKVFC2CKV0030568 Check Valve 3-568 Fails to Close On Demand 3.9723E+000 193 CKVFO2FCV0710040 Check Valve FCV-71 -40 Fails to Open On 3.9723E+000 Demand 194 CKVFO2CKV0710580 Check Valve 71-580 Fails to Open On Demand 3.9723E+000 195 CKVF02CKV071 0502 Check Valve 71-502 Fails to Open On Demand 3.9723E+000 196 CKVFO2CKV0030572 RFW Line B Injection Valve 2-3-572 Fails to Open 3.9723E+000 On Demand 197 SWLFD2_LS0710029 Level Switch 2-LS-71 -29 Fails to Operate On 3.9362E+000 Demand 198 [816140 B17180] Common Cause: Group Unit 1 and 2 4kV 3.9340E+000 Shutdown Board Feeder Breakers , 2/4 199 MOVXC2FCV7102-6 Valve FCV-71 -2 Transfers Closed 3.9283E+000 200 MOVXC2FCV71019_6 Valve FCV-71 -19 Transfers Closed 3.9283E+000 201 MOVXC2FCVO7103_6 Valve FCV-71 -3 Transfers Closed 3.9283E+000 202 MOVXC2FCV71037-6 Valve FCV-71 -37 Transfers Closed 3.9279E+000 203 MOVX02FCV71 038-6 Valve FCV-71 -38 Transfers Open 3.9279E+000 204 PTSFS2PMP0710019 Turbine Driven Pump Fails to Start On Demand 3.9170E+000 205 PTSFR2PMP71019_6 RCIC Turbine Driven Pump Fails to Run 3.8691 E+000 206 MOVXC2FCV07401 01 Unit 2 RHR Heat Exchanger Outlet X-Tie 2-FCV- 3.8426E+000 74-1 01 Transfers Closed 207 MOVF02FCV0740101 Unit 2 RHR Heat Exchanger Outlet X-Tie 2-FCV- 3.8426E+000 74-101 Fails To Open On Demand 208 CKVLK2CKo30568-6 Check Valve 3-568 Gross Back Leakage 3.8337E+000 209 OHC2 Operator Fails to TAKE EARLY ACTION to Control 3.7800E+000 HPCI Injection 210 MOVXO2FCV710348_6 Valve FCV-71 -34 Transfers Open 3.7399E+000 211 MOVXC2FCVO71008_6 Valve FCV-71 -8 Transfers Closed 3.7399E+000 212 MO0VXC2FCV71 039_6 Valve FCV-71 -39 Transfers Closed 3.7399E+000 213 [816140 817240] Common Cause: Group Unit 1 and 2 4kV 3.7246E+000 Shutdown Board Feeder Breakers , 2/4 214 [MOVFO2FCV0730016] Common Cause: Group RCIC Steam Supply, 1/2 3.7023E+000 215 [MOVFO2FCV0730044] Common Cause: Group HPCI RCIC Pump 3.7023E+000

____ ____ ___ ____ ___ ___ Discharge MOV failure, 1/2 216 (83161 40] Common Cause: Group Unit 1 and 2 4kV 3.7019E+000 Shutdown Board Feeder Breakers , 1/4 217 MOVFC2FCV0730040 MOV 2-FCV-73-40 Fails to Close On Demand 3.7011 E+000 E-147

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Achievement 218 MOVFO2FCVA730027 MOV 2-FCV-73-27 Fails to Open On Demand 3.7011 E+000 219 MOVFO2FCV0730026 MOV 2-FCV-73-26 Fails to Open On Demand 3.7011 E+000 220 [PMSFS2_02300B1 PMSFS2 02300D2] Common Cause: Group RHRSW South Header 3.6261 E+000 221 [PMSFR2 02300B1 PMSFR2 02300D2] Common Cause: Group RHRSW South Header 3.6253E+000 Pumps, 2/4 222 PMOFR3_027_CC Loss of All Unit 3 CCW Pumps 3.6135E+000 223 HOVXC 0240500Unit 1 CCW Intake Valve 2-24-500 Transfers 3.6135E+000 HVXC20240500 2 Closed 224 HOVXC1_0240504 Crosstie Valve 1-24-504 Transfers Closed 3.6135E+000 225 HOVXC1 0240500 Unit 1 CCW Intake Valve 1-24-500 Transfers 3.6135E+000 Closed 226 HOVXC2 0240521 RCW Header Isolation Valve 2-24-521 Transfers 3.6135E+000 Closed 227 HOVXC2L 0240524 RCW Header Isolation Valve 2-24-524 Transfers 3.6135E+000 Closed

[PMOFR1 024001A PMOFR1 024001 B 228 PMOFR2_024002A PMOFR2_024002B Common Cause: Group RCW Pumps Fail to Run, 3.6135E+000 PMOFR2_024002C PMOFR3O024003A 77 PMOFR3_1024003B]

229 HOVXC2 0240691 RCW Header Isolation Valve 2-24-691 Transfers 3.6135E+000 Closed 230 HOVXC3 0240500 Unit 3 CCW Intake Valve 3-24-500 Transfers 3.61 35E+000 Closed 231 HOVXC2L 0240594 RCW Header Isolation Valve 2-24-594 Transfers 3.6135E+000 Closed 232 HOVXC2_0240515 Crosstie Valve 2-24-515 Transfers Closed 3.6135E+OOO 233 PMOFR1_027_.CC Loss OF All Unit 1 CCW Pumps 3.6135E+000 234 PMOFR2_027-CC Loss OF All Unit 2 CCW Pumps 3.6135E+000 235 HOVXC2_0240693 RCW Header Isolation Valve 2-24-693 Transfers 3.6135E+000 Closed 236 [DG3BS DG3DS] Common Cause: Group Unit 3 EDGs, 2/4 3.6111 E+000 237 CKVFO2CKV0730517 Check Valve 2-CKV-73-517 Fails to Open On 3.6016E+000 Demand 238 [PMSFS2_.02300B1] Common Cause: RHRSW South Header Pumps, 3.5857E+000 1/4 239 [PMSFR2_0230081] Common Cause: Group RHRSW South Header 3.5856E+000

___ ___ ___ ___ ___ ___ Pum ps, 1/4 240 COVFO2_0230522 Check Valve 0-23-522 Fails to Open On Demand 3.5834E+000 241 HOVXC2_0230523 Manual Valve 0-23-523 Transfers Closed 3.5833E+000 E-148

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Risk Ach2evement 242 HOVXC2_0230524 Manual Valve 0-23-524 Transfers Closed 3.5833E+000 243 COVXCZ2_-0230522 Check Valve 0-23-522 Transfers Closed 3.5821 E+000 244 [DG3BS] Common Cause: Group Unit 3 DGs, 1/4 3.5756E+000 245 HOVXC2HCV0670606 Valve 67-606 Transfers Closed 3.4737E+000 246 [DGAS] Common Cause: Group Unit 1/2 DGs, 1/4 3.4210E+000 247 MOVXC2FCV0740030 FCV-74-30 Transfers Closed 3.3959E+000 248 CSVF02HCV0730023 Stop Check Valve 2-HCV-73-23 Fails to Open On 3.3536E+000 Demand 249 [MOVFO2FCV0230034 MOVFO2FCV0230046] Common Cause: Group RHR Heat Exchangers, 3.3112E+000 2/4 250 MOVXC2FCV730406 MOV 2-FCV-73-40 Transfers Closed During 3.3042E+000 Operation__ _ _ _ _ _

251 MOVXC2FCV73003-6 MOV 2-FCV-73-3 Transfers Closed During 3.3042E+000 Operation__ _ _ _ _ _

252 [SWL2-LS073056A SWL2LLS073056B] Common Cause: Group CST Level Switches for 3.3040E+000 HPCI Switch, 2/2 253 MOVXC2FCV73002_6 MOV 2-FCV-73-2 Transfers Closed During 3.3035E+000 Operation 254 [RL1FD2RLY1OAK9A] Common Cause: Group RHR Pump Actuation 3.2989E+000 Relays (K9), 1/2 255 CKVFO2CKV0030558 RFW Check Valve 2-3-558 Fails to Open On 3.2809E+000 Demand 256 CKVFO2FCV0730045 Testable Check Valve 2-FCV-73-45 Fails to Open 3.2809E+000 On Demand 257 CKVFC2CKV0030554 Feedwater Check Valve 2-CKV-3-554 Fails to 3.2809E+000 Close On Demand 258 CKVFO2CKV0730505 Check Valve 2-CKV-73-505 Fails to Open On 3.2809E+000 Demand 259 CKVF02CKV0730603 Check Valve 2-CKV-73-603 Fails to Open On 3.2809E+000 Demand 260 [PMSFS2PMP0740028 PMSFS2PMP0740039] Common Cause: Group RHR Pumps Fail to Start, 3.2794E+000 224 261 [RL12RLY23A_K25] Common Cause: Group HPCI/RCIC Actuation 3.2571 E+000 Relays, 1/4 262 [RL1 FD223AJK22] Common Cause: Group HPCI/RCIC Actuation 3.2571 E+000 Relays, 1/4 263 [RL1 FD223A K21 Common Cause: Group HPCI/RCIC Actuation 3.25712E+000 Relays, 1/4 264 [PMOFR2_02300A3 PMSFR2_02300C3] Common Cause: Group EECW Pumps, 2/4 3.2361 E+000 265 SMDFR2_047 EHC Instrument Signal Modifier Failure 3.2249E+000 E-149

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Risk Achievement 266 E1VFD2FCV0470067 Master Trip Valve FCV 47-67 Fail to Operate On 3.2249E+000 Demand 267 ElVFC2FCV0010068 Turbine Bypass Valve FCV 1-68 Fail to Close 3.2249E+000 268 E1VFC2FCV0010069 Turbine Bypass Valve FCV 1-69 Fail to Close 3.2249E+000 269 El VX02FCV0010068 Turbine Bypass Valve FCV 1-68 Transfers Open 3.2249E+000 270 ElVXO2FCV0010069 Turbine Bypass Valve FCV 1-69 Transfers Open 3.2249E+000 271 ElVX02FCV0010066 Turbine Bypass Valve FCV 1-66 Transfers Open 3.2249E+000 272 ElVFC2FCV0010066 Turbine Bypass Valve FCV 1-66 Fail to Close 3.2249E+000 273 ElVFC2FCV0010067 Turbine Bypass Valve FCV 1-67 Fail to Close 3.2249E+000 274 TRPFR2YPT001016A PT 1-16A Fail During Operation 3.2249E+000 275 TRPFR2PT001016B PT 1-16B Fail During Operation 3.2249E+000 276 HOVXC2 0240587 Manual Valve 24-587 Transfers Closed 3.2249E+000 277 RL1 FD2XKT0470801 Master Trip Relay COIL XKT801 Fails to 3.2249E+000 ENERGIZE 278 El VX02FCV0470067 Master Trip Valve FCV 47-67 Transfers Open 3.2249E+000 279 AOVXC2FCV0240065 FCV 24-65 Transfers Closed 3.2249E+000 280 HOVXC2_024589B Manual Valve 24-589B Transfers Closed 3.2249E+000 281 HOVXC2_024589A Manual Valve 24-589A Transfers Closed 3.2249E+000 282 HXRRP2_047 2B EHC Fluid Cooler 2B Ruptures 3.2249E+000 283 EIVFD2FCV0010064 Turbine Bypass Valve FCV 1-64 Fail to Regulate 3.2249E+000 284 ElVFD2FCV0010062 Turbine Bypass Valve FCV 1-62 Fail to Regulate 3.2249E+000 285 ElVFD2FCV0010063 Turbine Bypass Valve FCV 1-63 Fail to Regulate 3.2249E+000 286 ElVFD2FCV0010061 Turbine Bypass Valve FCV 1-61 Fail to Regulate 3.2249E+000 287 TCVXC2TCV0240070 TCV 24-70 Transfers Closed 3.2249E+000 288 HOVXC2_0240593 Manual Valve 24-593 Transfers Closed 3.2249E+000 289 HOVXC2_0240592 Manual Valve 24-592 Transfers Closed 3.2249E+000 290 HOVXC2_024588B Manual Valve 24-588B Transfers Closed 3.2249E+000 291 HOVXC2_024588A Manual Valve 24-588A Transfers Closed 3.2249E+000 292 [PMOFR2HFP047000A PMOFR2HFP047000B] Common Cause: Group EHC Pump, 2/2 3.2249E+000 293 CB2XO2_047_613 Circuit Breaker 613 AT Board 9-9 Cabinet 6 3.2249E+000 Transfers Open 294 [SOVFD2FSV047067A SOVFD2FSVO47067B] Common Cause: Group Turbine Trip Master Trip 3.2249E+000 Solenoid Valves, 2/2 295 El VFC2FCV0010065 Turbine Bypass Valve FCV 1-65 Fail to Close 3.2249E+000 296 El VXO2FCV001 0067 Turbine Bypass Valve FCV 1-67 Transfers Open 3.2249E+000 297 El VX02FCV0010065 Turbine Bypass Valve FCV 1-65 Transfers Open 3.2249E+000 E-1 50

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Risk 298 HXRRP2 047_2A EHC Fluid Cooler 2A Ruptures 3.2249E+000 299 PTSFS2PMP0730054 HPCI Pump Fails to Start On Demand 3.2118E+000 300 [PMOFS2_02300A3 PMSFS2 02300C3] Common Cause: Group EECW Pumps, 2/4 3.1980E+000 301 HOVXC2HCV3066-6 RFW Line B Valve 2-66 Transfers Closed 3.1765E+000 302 ElVFO2FCV0010065 Turbine Bypass Valve FCV 1-65 Fail to Open 3.1702E+000 303 ElVFO2FCV0010064 Turbine Bypass Valve FCV 1-64 Fail to Open 3.1702E+000 304 ElVFO2FCV0010067 Turbine Bypass Valve FCV 1-67 Fail to Open 3.1702E+000 305 E1VFO2FCV0010066 Turbine Bypass Valve FCV 1-66 Fail to Open 3.1702E+000 306 ElVFO2FCV0010061 Turbine Bypass Valve FCV 1-61 Fail to Open 3.1702E+000 307 E1VFO2FCV0010063 Turbine Bypass Valve FCV 1-63 Fail to Open 3.1702E+000 308 ElVFO2FCV0010062 Turbine Bypass Valve FCV 1-62 Fail to Open 3.1702E+000 309 E1VFO2FCV0010069 Turbine Bypass Valve FCV 1-69 Fail to Open 3.1702E+000 310 EIVFO2FCV0010068 Turbine Bypass Valve FCV 1-68 Fail to Open 3.1702E+000 311 PTSFR2PMP73054'6 HPCI Pump Fails During Operation 3.1699E+000 312 CKVLK2CKV30554-6 Feedwater Check Valve 2-CKV-3-554 Develops 3.1612E+000 Gross Reverse Leakage_______

313 [MOVFO2FCV0230034 MOVFO2FCV0230052] Common Cause: Group RHR Heat Exchangers, 3.1541 E+000 2./4 314 [D232TC D233TC] Common Cause: Group Unit 3 DGs Dampers, 2/2 3.1366E+000 315 MOVXC2FCV73027_6 MOV 2-FCV-73-27 Transfers Closed During 3.1315E+000 Operation 2C 3 TaeC rDi.1+

316 MOVXC2FCV73026_6 MOV 2-FCV-73-26 Transfers Closed During 3.1315E+000 Operation 2C74 rssp Ae.1+

317 MOVXC2FCV73031_6 MOV 2-FCV-73-16 Transfers Closed During 3.1315E+000 Operation__ _ _ _ _ _

318 MOVXO2FCV7304OL6 MOV 2-FCV-73-40 Transfers Open After 3.1315E+000 Switchover 319 MOVXC2FCW3O3&6MOV 2-FCV-73-34 Transfers Closed During311500 Operation__ _ _ _ _ _

320 MOVXC2FCV73044-6 MOV 2-FCV-73-44 Transfers Closed During 3.1315E+000 OperationCsGo H U I can .7+

321 [RL1 2RLY23AK25 RL1 FD223AK22] Common Cause: Group HPCURCIC Actuation 3.1276E+000 Relays, 2/4 322 [R12RY2A-25 I- F223-K1]Common Cause: Group HPCI/RCIC Actuation 3.1276E+000 RL FD23AJ21]Relays, 2/4

[RL1RLY2AJ(5 323 [RL1FD223AK21 RL1FD223AK22] Common Cause: Group HPCVRCIC Actuation 3.1276E+000 Relays, 2[4 324 [VA3BS VB3BS] Common Cause: Group Unit 3 DG Fans, 2/2 3.1 106E+000 E-151

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Achievement 325 [D64TC D65TC] Common Cause: Group Diesel Generator 3.0990E+000 Dampers, 212 326 [VAAS VBAS] Common Cause: Group Diesel Generator Fans, 3.0901 E+000 2/2 327 OU11 Operators Fail to Align Ul RHR Loop II Thru X-Tie 3.0683E+000 to U2 RHR Loop 1 328 HOVXC3HCV0670565 Valve 3-67-565 Transfers Closed 3.0683E+000 329 MOVXC3FCV0740100 Unit 3 RHR Heat Exchanger Outlet X-Tie 3-FCV- 3.0683E+000 74-1 00 Transfers Closed 330 [PMSFR3PMP074003A PMSFR3PMP074003C] Common Cause: Group Unit 3 RHR Pumps Fail to 3.0683E+000 Run, 2/2 331 [PMSFS3PMP074003A PMSFS3PMP074003C] Common Cause: Group Unit 3 RHR Pumps Fail to 3.0683E+000 Start, 2/2 332 [FN2FS3ROOM74003A FN2FS3ROOM74003C] Common Cause: Group U3 RHR Room Coolers, 3.0683E+000 333 MOF3C0410Unit MOVFO3FCVO74100 333 74-1003 RHR FailsHeat Exchanger To Open Outlet X-Tie 3-FCV-On Demand 3.0683E+000 334 [MOVFO3FCV0230034 MOVFO3FCV0230040] Common Cause: Group RHR Heat Exchanger 3.0683E+000 MOVs, ,22 335 FNF3OM40ANF3OCommon Cause: Group U3 RHR Room Coolers, 3.0683E+000 S

[FN2FR3ROOM74003A FN2FR3ROOM74003C] 2/2 336 [MOVFC3FCV0740001 MOVFC3FCV0740012] Common Cause: Group U3 Shutdown Cooling 3.0683E+000 Valves (Required to Close), 2/2 337 [MOVF03FCV0740096 MOVF03FCV0740097] Common Cause: Group U3XTIN, 2/2 3.0683E+000 338 [MOVFO2FCV0740098 MOVFO2FCVW740099] Common Cause Group U2 Loop II RHR Suction 3.0683E+000 339 E15A 125V DC BD1.Bus or Battery Fails or Fused Swvitch 3.0532E+000 to DG Control transformer 340 CHARGA2R 'A', In/Out Fuse Fail, Charger Input Output 3.0477E+000 Breaker Transfers Open 341 [MOVFO2FCV0230034] Common Cause: Group Heat Exchanger MOV, 1/4 3.0350E+000 342 M861T Manual Valves 532, 861 Transfers Closed or 3.0347E+000 Expansion Joint Leak.

343 [PMSFS2_02300B2 PMSFS2_02300D2] Common Cause: Group RHRSW South Header 3.03002E+000 Pumps, 2/4 344 [PMSFR2 02300132 PMSFR2 023001D2] Common Cause: Group RHRSW South Header 3.0289E+000 Pumps, 2/4 345 [R1F2LY014 R1F2LYCommon Cause: Group RHR Actuation Relays, 3.0251 E-000 346 [RL1 FD2RLY1 OAK18A RL1 FD2RLY1 OAK21 A] Common (2nd set), Cause:

2/6 Group RHR Actuation Relays 3.0251 E+000 E-152

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description AcRisk 347 SARSequencer Fails, Breaker 1818 Transfers Open, or 3.01 88E+000 1614 Transfers Closed 348 W23TC Fire Dampers 1023, 1019 Transfers Closed 3.0029E+000 349 HOVXC2HCV0230031 Valve HCV-23-31 Transfers Closed 3.0011 E+000 350 CKVF02CKV0230579 Check Valve CKV-23-579 Fails to Open On 2.9968E+000 Demand 351 CKVXC2CKV0230579 Check Valve CKV-23-579 Transfers Closed 2.9953E+000 352 HXRPL2HEX074900A Heat Exchanger 2A Plugs 2.9950E+000 353 MOVXC2FCV0230034 Valve FCV-23-34 Transfers Closed 2.9949E+000 354 [PMSFR2 02300B2 PMSFR2 02300D1] Common Cause: RHRSW South Header Pumps, 2.9835E+000 2/4 355 [PMSFS2 02300B2 PMSFS2.02300D1] Common Cause: RHRSW South Header Pumps, 2.9819E+000 356 [PMSFS2PMP0740005 PMSFS2PMP0740039] Common Cause: Group RHR Pumps Fail to Start, 2.9753E+000 357 CHARG3B2R 3aBrg er, In/Out Fuse Fail, Charger Input 2.9523E+000 CHARG3B2R ~~Output Breaker Transfers Open ______

358 M863 Manual Valves 863,709 Transfers Closed or 2.9342E+000 Expansion Joint Leak 359 RPDRP2RP71011A_6 Inboard Rupture Disc Failure 2.9266E+000 360 [PMSFS2PMP0740005] Common Cause: Group RHR Pumps Fail to Start, 2.9231 E+000 3 1 1/4 361 CKVFO2CKV074559A Check Valve 74-559A Fails To Open On Demand 2.9213E+000 362 CKVF02CKV074560A Check Valve 74-560A Fails To Open On Demand 2.921 3E-e000 363 MOVXC2FCV0740001 RHR A SPC Suction FCV-74-1 Transfers Closed 2.9164E+000 364 [RL1FD2RLY10A124A] Common Cause; Group Actuation Relays, 1/6 2.9160E+000 365 [RL1FD2RLY10AK18A] Common Cause: Group RHR Actuation Relays 2.9160E+000 (2nd set), 1/6 366 HOVXC21SV0670566 Valve 67-566 Transfers Closed 2.9104E+000 367 HOVXC21SV0670569 Valve 67-569 Transfers Closed 2.9104E+000 368 HOVXC21SV0670571 Valve 67-571 Transfers Closed 2.9104E+000 369 HOVXC21SV0670574 Valve 67-574 Transfers Closed 2.9104E+000 370 HOVXC2HCV0740086 HCV-74-86 Transfers Closed 2.9104E+000 371 HOVXC2HCV0740010 HCV-74-1 0 Transfers Closed 2.9104E+000 372 HOVXC2HCV0670572 Valve 67-572 Transfers Closed 2.9104E+000 373 CONDENSER_2A2B2C Main Condenser Unavailable After Plant Trip 2.9087E+000 374 HXRRP2HXR074002A Pump Room Cooler A (Heat Exchanger A) 2.9086E+000 HXR2XO40ARupturesI E-153

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Risk 375 HXRRP2HEXA74900A Heat Exchanger A Ruptures 2.9086E+000 376 HXRRP2SEAL74002A Seal Heat Exchanger Ruptures 2.9086E+000 377 RLF2Y1A18 LF2Y1Common Cause: Group RHR Actuation Relays 2.9018E+000 37

[RL1 FD2RLY1 OAK18A RL1 FD2RLY1 OAK25A] (2nd set), 2/6 378 [RL1FD2RLY1OA123A RL1FD2RLY10A124A] Common Cause: Group RHR Actuation Relays, 2.9015E+000 2/6 379 [RL1FD2RLY10A117 RL1 FD2RLY1OAI24A] Common Cause: Group RHR Actuation Relays, 2.8992E+000 380 [RL1FD2RLY1OAK18A RL1 FD2RLY1OAK25B] Common Cause: Group RHR Actuation Relays 2.8992E+000 (2nd set), 2/6 381 [RL1 FD2RLY1 OAK1 8A RL1 FD2RLYI OAK21 B] Common Cause: Group RHR Actuation Relays 2.8992E+000 (2nd set), 2/6 382 [RL1 FD2RLY1 OA119B RL1 FD2RLY1OA124A] Common Cause: Group RHR Actuation Relays, 2.8992E+000 2/6 383 CKVXC2CKV074559A Check Valve 74-559A Transfers Closed 2.8816E+000 384 CKVXC2CKV074560A Check Valve 74-560A Transfers Closed 2.881 6E+000 385 W36TC Fire Dampers 1036, 1032 Transfer Closed 2.8793E+000 386 E1253BR 125V DC Bus or Battery Fails Or Fused Switch To 2.8770E+000 DG Cont Transfer 387 SA3BR Sequencer Fails, Breaker 1842 Transfers Open Or 2.8635E+000 Breaker 1336 Transfers Closed 388 [PMOFS2_2__003230C3 Common Cause: Group EECW Pumps, 3/4 2.8047E+000 PMSFS2-02300D3]

389 [DG3CS DG3DS] Common Cause: Group Unit 3 DGs, 2/4 2.7884E+000 390 HOVXC2HC30066_6 RFW Valve HCV-3-67 Transfers Closed 2.7851 E+000 391 HOVXC2HCV73025 6 Manual Valve 2-HCV-73-25 Transfers Closed 2.7851 E+000

__ _ _ __ _ _ __ _ _ _ __ _ _ __ _ _ _ During Operation 392 [RL12RLY23A_K25 RL1 FD223AK21 Common Cause: Group HPCVRCIC Actuation 2.7780E+000 RL1 FD223A_K22] Relays, 3/4 393 [PMSFS2_02300B2]

[PM5F20230B2]1/4 Common Cause: RHRSW South Header Pumps, 2.7763E+000 394 [PMSFR2_02300B2]

[PMSFZ.0230B211/4 Common Cause: RHRSW South Header Pumps, 2.7758E+000 395 HOVXC2_0230527 Manual Valve 0-23-527 Transfers Closed 2.7741 E+000 396 COVFO2_0230526 Check Valve 0-23-526 Fails To Open On Demand 2.7741 E+000 397 COVXC2_0230526 Check Valve 0-23-526 Transfers Closed 2.7729E+000 398 [DG3CS] Common Cause: Group Unit 3 DGs, 1/4 2.7704E+000 399 [PMOFR2_02300A3 PMSFR2_02300D3] Common Cause: Group EECW Pumps, 2/4 2.6803E+000 400 [PMOFR2_02300A3 PMOFR2_02300B3] Common Cause: Group EECW Pumps, 2/4 2.6559E+000 E-1 54

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Risk Rank Basic Event Description Achievement Common Cause: RHRSW South Header Pumps, 401 [PMOFS2 02300A3 PMSFS2_02300D3] 2/4 2.6445E+000 402 AOVXC2FCV0320063 Containment Isolation Valve FCV-32-63 Transfers 2.5786E+00 Shut 403 AOVXC2FCV0320062 Containment Isolation Valve FCV-32-62 Transfers 2.5786E+000 Shut 404 HOX2L0221 Manual Valves 32-2515,2520, 2522,2523,2524, 2.5786E+000 44 HOVXC20322515 2526 Transfers Shut 405 HOVXC2 0320302 Manual Valve 32-302 Transfers Shut 2.5786E+000 406 COVPL2 0322163 Check Valves 32-2163 and 336 Plugged 2.5786E+000 407 [AOVF02FCV0320064 AOVF02FCV0320067] Common Cause: Group Drywell Control Air 2.5786E+000

[AOVO2FVO32064AOVF2FCO32067] RBCCW Supply AOVs, 2/2 408 COVPL2_0322516 Check Valves 32-2516 and 2521 Plugged 2.5786E+000 409 [CMPFR2CMP032002A CMPFR2CMP032002B] Common Cause: Group Drlell Air Compressors, 2.5786E+000 410 [CMPFS2CMP032002A CMPFS2CMP032002B] Common Cause: Group Drywell Air Compressors, 2.5786E+000 2/2 411 HOVXC2 0322253 Manual Valves 32-2253,2160, 1452,1451,1736, 2.5786E+000 Transfers Shut 412 FLTPL2_032CFLT Drywell LOADS (C) Air Filter Plugged 2.5786E+000 413 FLTPL2_032PFLT Suction Prefilter Plugs 2.5786E+000 414 HOVXC2_0320301 Manual Valve 32-301 Transfers Shut 2.5786E+000 415 FLTPL2_032BFLT Drywell LOADS (B)Air Filter Plugged 2.5786E+000 416 [PMSFR2 02300A1 PMSFR2_02300C1 Common Cause: Group RHRSW A and C Pumps 2.5006E+000 PMSFR2_02300C2] Fail to Run 3/4 417 [PMSFS2_02300A1 PMSFS2_02300C1 Common Cause: Group RHRSW A and C Pumps 2.4995E+000 PMSFS2O02300C2] Fail to Start 3/4 418 [PMOFS2_02300A3 PMOFS2_02300B3] Common Cause: Group EECW Pumps, 2/4 2.4932E+000 419 [PMSFR2_02300A1 PMSFR2 02300C1] Common Cause: Group RHRSW A and C Pumps 2.4652E+000 Fail to Run 2/4 Common Cause: Group RHRSW A and C Pumps 420 [PMSFS2_02300A1 PMSFS2_02300C1] Fail to Start, 2/4 2.4651 E+000 421 [PMSFR2_02300A2 PMSFR2_02300C1 Common Cause: Group RHRSW A and C Pumps 2.4640E+000 PMSFR2_02300C2] Fail to Run, 3/4 422 [PMSFS2_02300A2 PMSFS2_02300C1 Common Cause: Group RHRSW A and C Pumps 2.4632E+000 PMSFS2_02300C2] Fail to Run, 3/4 423 [PMSFR2_02300A2 PMSFR2_0230OC2] Common Cause: Group RHRSW A and C Pumps 2.4578E+000 Fail to Run, 2.4 424 [PMSFS2 02300A2 PMSFS2 02300C2] Common Cause: RHRSW A and C Pumps Fail to 2.4570E+000 start, 2/4 E-155

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Achievement 425 [FN2FR2FAN098061] Common Cause: Group SAI Panel Coolers, 1/2, 2.4443E+000 1/2 426 [D234TC D235TC] Common Cause: Group Unit 3 DG Building 2.4124E+000 Dampers, 2/2 427 [VA3CS VB3CS] Common Cause: Group Unit 3 Dg Building Fans, 2.3907E+000 2/2 428 [DGBS] Common Cause: Group Unit 3 DGs, 1/4 2.3830E+000 429 CKVXC2CK710502_6 Check Valve 71-502 Transfers Closed 2.3576E+000 430 CKVXC2CK710580_6 Check Valve 71-580 Transfers Closed 2.3576E+000 431 CKVXC2CK30572 6 RFW Line B Injection Valve 2-3-572 Transfers 2.3576E+000 Closed 432 CKVXC2FCV71040_6 Check Valve FCV-71 -40 Transfers Closed 2.3576E+000 433 CSVXC2HCV71014_6 Stop Check Valve HCV-71 -14 Transfers Closed 2.3511 E+000 434 [PMSFR2O02300A1 PMSFR2_02300C2] Common Cause: Group RHRSW A and C Pumps 2.3434E+000 Fail to Run 2/4 435 [PMSFS2L-02300A1 PMSFS2_02300C2] Common Cause: Group RHRSW A and C Pumps 2.3423E+000 Fail to Start, 2/4 436 [PMSFR2O.-...02300A1J Common Cause: Group RHRSW A and C Pumps 2.3080E-000 Fail to Run 1/4 437 Common Cause: Group RHRSW A and C Pumps 2.3079E+000

[PMSFS2_02300A1]

7 Fail to Start, 1/4 438 COVFO2_0230502 Check Valve 0-23-502 Fails To Open On Demand 2.3076E+000 439 HOVXC2_0230503 Manual Valve 0-23-503 Transfers Closed 2.3075E+000 440 HOVXC2_0230504 Manual Valve 0-23-504 Transfers Closed 2.3075E+000 441 COVXC2_0230502 Check Valve 0-23-502 Transfers Closed 2.3037E+000 442 HOVXO2_0630013 Manual Valve 63-13 to Drain Tank Transfers Open 2.2650E+000 443 HOVXC2_0630524 Manual Valve 63-524 Transfers Closed 2.2650E+000 444 HOVXC2_0630500 Manual Valve 63-500 Transfers Closed 2.2650E+000 445 [MOVFC2FCV0690001 MOVFC2FCV0690002 Common Cause: RWCU MOVs Fail to Isolate for 2.2650E+000 MOVFC2FCV0690012] SLC, 3/3 446 COVPL2_0630526 Check Valve 63-526 Transfers Closed / Plugs 2.2650E+000 447 COVFOZ_0630525 Check Valve 63-525 Fails to Open 2.2650E+000 448 COVF02 0630526 Check Valve 63-526 Fails to Open 2.2650E+000 449 [PMSFS2_063002A PMSFS2_063002Bj Common Cause: Standby Liquid Control Pumps 2.2650E+000 (PMSS2~03002 PMFS2_0630281 FTS, 2/2 450 [PMSFR2_063002A PMSFR2_063002B] Common Cause: Standby Liquid Control Pimps 2.2650E+000 F45, 2/2 451 [EOVFD2-063008A EOVFD2 -063008B] Common Cause: Standby Liquid Control Explosive 2.2650E+000 Valves, 2/2 E-156

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Risk Achievement 452 TK2RP2_0630001 Standby Liquid Control Storage Tank Ruptures 2.2650E+000 453 HOVXC2HCV0630012 Manual Valve 63-12 Transfers Closed 2.2650E+000 454 COVPL2 0630525 Check Valve 63-525 Transfers Closed / Plugs 2.2650E+000 455 M719T Manual Valves 719,864 Transfers Closed or 2.2549E+000 Expansion Joint Leak 466 CHARG3C2R Charger e3Ce,In/Out Fuses Fail; Charger Input, 2.2502E+000 Output Breaker Transfers Open 457 RlF2Y1A9]Common Cause: Group RHR Pump Actuation 2.1961 E+o000 47 [RL1 FD2RLY1 OAK9B] Relays (K9), 1/2 458 W37TC Fire Dampers 1037, 1033 Transfer Closed 2.1898E+000 459 E15C 125V DC Bus or Battery Fails OR Fused Switch to 2.1 890E+000 DG CONT Transfer 460 SA3CR Sequencer Fails, Breaker 1832 Transfers Open 2.1856E+000 OR Breaker 1338 Transfers Closed 461 [B2D]

461 [B2D] ~Common 3,11/2 Cause: Group Battery Boards 1, 2, and 2.6400 2.1644E+000 462 [MGAR MGBR] Common Cause: Group Motor Generator Sets 2.1456E+000 Fail, 2/2 463 [B3D] Common Cause: Group Battery Boards 1, 2, and 2.1316E+000 3,11/3 464 ZTS2AR TS2A Fails During Operation. 2.0843E+000 465 ESD2AR 480V Shutdown Bus 2A Fails 2.0843E+000 466 B2A1CT Output Breaker 1C Transfers Open 2.0843E+000 467 BE2A5T Input Breaker 5 Transfers Open 2.0843E+000 468 (MGAR] Common Cause: Group Motor Generator Sets 2.0630E+000 Fail, 1/2 469 B13ATO Breaker 13A Transfers Open 2.0627E+000 470 ERPSAR RPS Bus A Fails During Operation 2.0624E+000 471 B2A1TO Protection Contactor 2A1 Transfers Open 2.0621 E+000 472 B2A2TO Protection Contactor 2A2 Transfers Open 2.0621 E+000 473 B902T Distribution Panel Feeder Breaker 902 Transfers 2.0621 E+000 Open 474 [D66TC D67TC]

[D66C D6TC]Dampers, Common Cause:2/2 Group Unit 1/2 DG Building 2.0611 E+000 475 ESD3ECR Shutdown Board 3EC Fails Bus Fault 2.0546E+000 476 [VABS VBBS] Common Cause: Group Unit 1/2 DG Building 2.0522E+000 Dampers, 2/2 477 RPR2P3736Inboard Rupture Disc 2-RPD-073- 0713 Ruptures 2.051 6E+000 RPDRPRP737136Causing HPCI ISOLA E-157

BFN Unit 3 Significant Basic Events By Risk Achievement Worth Rank Basic Event Description Risk 478 E125BR 125V DC BD. Bus or Battery Fails OR Fused 2.0152E+000 Switch to DG Cont Tran 479 CHARGB2R CHARGB2R ChargerBreaker

~~Output '8", In/Out Fuses Open_______

Transfers Fail; Charger Input 2.0097E+000 480 [PMSFR2_02300A2 PMSFR2 02300C1] Common Cause: Group RHRSW A and C Pumps 2.0083E+000 Fail to Run, 2/4 481 (PMSFS2a--02300A2 PMSFS2_02300C1] Common Cause: Group RHRSW A and C Pumps 2.0083E+000 Fail to Start, 2/4 482 [PMSFR2L_023OA2] Common Cause: Group RHRSW A and C Pumps 2.0022E+000 Fail to Run, 1/4 483 PSCommon Cause: Group RHRSW A and C Pumps 2.0022E+000 43

[PMSFS202300A2 Fail to Start, 1/4 484 COVFO2_0230506 Check Valve 0-23-506 Fails To Open On Demand 2.0017E+000 485 HOVXC2_0230507 Manual Valve 0-23-507 Transfers Closed 2.0013E+000 NRC Request SPSB-A.23 Identify the key sources of uncertainty and the key assumptions in the PRA. Note that the terms "key source of uncertainty" and "key assumption" are defined in RG 1.200, Appendix A, Table A-1, Index Number 2.2.

TVA Reply to SPSB-A. 23 The following are the key sources of uncertainty and key assumptions as defined in RG 1.200.

One SRV Thermal-hydraulic analyses were not available for Units 2 and 3 to determine whether a single stuck open safety relief valve (SRV) would depressurize the vessel such that low-pressure injection systems would be effective in mitigating core damage. Instead, additional depressurization, obtained either by the operation of HPCI or RCIC, or by the opening of an additional SRV, is assumed to be necessary to permit low-pressure injection systems to operate in a timely manner to avoid fuel damage. This may not be applicable generically and is regarded as a key source of uncertainty. A key assumption is that a single stuck open SRV would not depressurize the vessel such that low-pressure injection systems would be effective in mitigating core damage.

E-158

CRD for Vessel Protection Thermal-hydraulic analyses were not available to determine if enhanced CRD injection in some circumstances, would prevent vessel melt-through. As CRD injection to prevent vessel melt-through is modeled for selected scenarios, this is a key source of uncertainty. The key assumption made with respect to enhanced CRD injection is that credit was taken for this in the BFN Unit 2 and Unit 3 models for selected scenarios.

Common Cause Failures for RHRSW Pumrs There are a total of 12 RHRSW pumps. There are four pumps normally dedicated to EECW, four pumps dedicated to RHRSW, and four "swing" pumps normally aligned to RHRSW but capable of being aligned to EECW. The pumps are similar in design and draw from the same suction source. There is no industry consensus on modeling a common cause group of 12. The key assumption made was that these pumps are modeled in three common cause groups: the EECW pumps, the RHRSW pumps, and the swing pumps. There is no credible loss of suction event for all pumps. Further, if the EECW pumps are failed, then the RHRSW pumps are irrelevant. This is the same model as used in the Unit 1 PRA.

Common Cause Failures for HPCI and RCIC There is not a consensus in the industry on the extent of inter-system common cause failure (CCF) modeling. Although HPCI/RCIC common cause failure events are in the INEEL database they may not always be modeled. A key assumption was to model CCF between HPCI and RCIC. The CCF also accounts for different failure rates for HPCI and RCIC. This raises the frequency of the dominant class of sequences where all high-pressure injection is lost and the operators fail to depressurize. Elimination of this dependency significantly reduces core damage. When the Unit 2 and Unit 3 PRA models were updated to reflect the operation of Unit 1, the Unit 1 HCPI/RCIC CCF model was adopted.

NRC Request IROB-B-1 Describe how the proposed EPU will change the plant emergency and abnormal operating procedures.

TVA Reply to IROB-B-1 For BFN, Emergency Operating Procedures and Abnormal Operating Procedures are designated as Emergency Operating Instructions (EOls) and Abnormal Operating Instructions (AOls). The EOls for Browns Ferry are symptom based. Changes in the EOls and the AOls required for EPU implementation consist of revisions to previously defined numerical values (e.g., rated reactor thermal power, heat capacity temperature E-1 59

limit, etc.). The definition of these parameters has not been altered, only the numerical value of the parameter has changed.

NRC Request IROB-B-2 Describe any new operator actions needed as a result of the proposed EPU. Describe changes to any current operator actions related to emergency or abnormal operating procedures that will occur as a result of the proposed EPU.

TVA Reply to IROB-B-2 As previously stated in the PUSAR, operator responses to transient, accident and special events are not affected by EPU conditions. Accordingly, no new operator actions in the EOls and AQ1s have been created as a result of the proposed EPU for these events. Although AQ1s also include actions outside of transient, accident and special events, no significant AOI revision to operator actions are expected. AQ1s will be reviewed for EPU conditions and necessary revisions will be completed as part of EPU implementation.

The change in parameter values (e.g., core decay heat, thermal power level, etc.)

associated with EPU conditions could affect the timing of actions provided in the EOls and AOls. However, the EOls are symptom based and the EOls and AOls do not contain specific times for the operator actions. Since the operator will continue to follow the sequence of actions required, there is no change in the current operator actions.

Steps taken by the operator to mitigate events are not being changed as a result of EPU.

NRC Request IROB-B-3 Describe any changes the proposed EPU will have on the operator interfaces for control room controls, displays, and alarms. For example, what zone markings (e.g., normal, marginal and out-of-tolerance ranges) on meters will change? What setpoints will change? How will the operators know of the change? Describe any controls, displays, or alarms that will be upgraded from analog to digital instruments as a result of the proposed EPU and how operators will be tested to determine they could use the instruments reliably.

TVA Renlv to IROB-B-3 There are no major changes to the control room controls, displays, or alarms planned as a result of EPU. Some changes are required to the instrumentation spans, alarm settings or actuation setpoints to accommodate increased process conditions or due to the installation of new equipment required for EPU. Where recorders, indicators, or instrumentation are changed to accommodate EPU, digital equipment may be selected where it is deemed technically acceptable; however, no such changes are currently E-160

planned. Banding will be reviewed and revised as necessary (for example, condensate booster pump ammeters).

There are various instructional aids in the main control room that will also be revised due to power uprate. These instructional aids are labels, sketches, or markings, which are posted and used as memory or instructional guidance (for example, power/flow map).

Setpoint changes as a result of EPU include the following. The Technical Specification setpoint changes are described in Section 5 of the PUSAR.

• APRM Flow Biased Scram and Rod Block Setpoints

• Turbine Stop Valve Closure and Turbine Control Valve Fast Closure Scram Bypass

• Main Steam Line High Flow Isolation The changes in instrumentation and instructional aids in the main control room will be prepared in accordance with the plant modification process, which incorporates detailed review of the proposed control room design change package. All required changes will be implemented prior to operation at uprated conditions. The change control process includes an impact review by operations and training personnel. Training and implementation requirements are identified and tracked, including simulator impact.

Verification of operator training is required as part of the design change closure process.

NRC Request IROB-B-4 Describe any changes to the safety parameter display system resulting from the proposed EPU. How will the operators be informed of the changes?

TVA Reply to IROB-B-4 The changes to the Safety Parameter Display System (SPDS) include recalibration of Input/Output points, changes to constants which input to the displayed points (e.g.,

rated core thermal power), and changes to the EOI Limit graphs. The design and intent of the SPDS remain unchanged. The information presented on the SPDS display (top level display) and the method of presentation remain the same as before EPU. These changes will not affect EOI execution and will be included in operator simulator training utilizing the SPDS.

E-1 61

REFERENCES:

1. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Units 2 and 3 - Proposed Technical Specifications (TS) Change TS - 418- Request for License Amendment Extended Power Uprate (EPU) Operation," dated June 25, 2004.

2. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Units 2, and 3 - Response to NRC's Acceptance Review Letter and Request for Additional Information Related to Technical Specifications (TS) Change No. TS-418, Request for Extended Power Uprate Operation, (TAC Nos MC3743 and MC3744)," dated February 23, 2005.

3. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Units 2, and 3 - Response to NRC's Request for Additional Information Related to Technical Specifications (TS) Change No. TS-41 8- Request for Extended Power Uprate Operation (TAC Nos MC3743 and MC3744)," dated April 25, 2005.

4. TVA letter, W. D. Crouch to NRC, "Browns Ferry Nuclear Plant (BFN) - Units 2 and 3 - Response to NRC's Request for Additional Information Related to Technical Specifications (TS) Change No. TS - 418 - Request for License Amendment - Extended Power Uprate (EPU) Operation (TAC Nos MC3743 and MC3744)," dated June 6, 2005.

5. NRC letter, E. A. Brown to TVA, "Browns Ferry Nuclear Plant, Units 2 and 3 -

Request for Additional Information for Extended Power Uprate (TS-431)(TAC Nos.

MC3743 and MC3744)," dated October 3, 2005.

6. TVA Letter, M. J. Burzynski to NRC, "Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3, Application for Renewed Operating Licenses," dated December 31, 2003.

7. GE Engineering Report for Quad Cities Unit 1 Scale Model Testing, GENE-OOOO-0032-2219-01, April 2005.

8. Interim Comparison of Quad Cities Unit 1 Scale Model Test Data with Quad Cities Unit 2 Plant Data, GENE-0000-0042-7471 -01, July 2005.

9. TVA Letter to NRC letter dated, "Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 - Annual Radioactive Effluent Release (AREOR) Report - January Through December 2004," dated April 28, 2005.

10. TVA letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Units 1, 2, and 3 - License Amendment - Alternative Source Term," dated July 31, 2002.

11. NRC letter to TVA, "Browns Ferry Nuclear Plant, Units 1, 2, and 3 - Issuance of Amendments Regarding Full-Scope Implementation of Alternative Source Term E-162

(TAC Nos. MB5733, MB5734, MB5735, MC0156, MC0157 and MC0158) (TS-405)," dated September 27, 2004.

12. NRC Letter to TVA, "Safety Evaluation of Post-Fire Safe Shutdown Capability and Issuance of Technical Specification Amendments for the Browns Ferry Nuclear Plant Units 1, 2, AND 3 (TAC Nos. M85254, N87900, M87901, and M87902) (TS 337), dated November 2,1995.

13. TVA Letter, W. D. Crouch to NRC, "Browns Ferry Nuclear Plant (BFN) - Unit 1 -

Technical Specifications (TS) Change 426 - Response to Request for Additional Information Regarding Revision to Diesel Generators Allowed Outage Time (TAC No. MC5254)," dated October 28, 2005.

14. NUREG/CR-5496, "Evaluation of Loss of Offsite Power Events at Nuclear Power Plants: 1980-1996," U.S. Nuclear Regulatory Commission, November 1998.

15. NUREG-1 032, "Evaluation of Station Blackout Accidents At Nuclear Power Plants,"

U.S. Nuclear Regulatory Commission, June 1988.

16. NEEUEXT-97-00887, Draft Version of NUREG/CR-5496, Idaho National Engineering and Environmental Laboratories.

17. NUREG/CR-5750, "Rates of Initiating Events at Nuclear Power Plants: 1987-1995," U.S. Nuclear Power Plants, February 1999.

18. Tennessee Valley Authority, "Browns Ferry Nuclear Plant Scram Database" Updated as of March 31, 2003.

19. U.S. Nuclear Regulatory Commission, "Modeling Time to Recovery and initiating Event Frequency for Loss of Off-Site Power incidents at Nuclear Power Plants,"

NUREG/CR-5032, January 1988.

20. Database For Probabilistic Risk Assessment Of Light Water Nuclear Power Plants, PLG-0500.

21. Standard for Probabilistic Risk Assessment For Nuclear Power Plant Applications, ASME RA-S-2002, April 5, 2002.

22. TVA Letter, P. Salas to NRC, Browns Ferry Nuclear Plant (BFN) -Generic Letter (GL) 88-20, Supplement 4, Individual Plant Examination of External Events (IPEEE) For Severe Accident Vulnerabilities - Partial Submittal of Report," dated July 25, 1995.

23. TVA Letter, T. E. Abney to NRC, Browns Ferry Nuclear Plant (BFN) - Unit 3 -

Generic Letter (GL) 88-20, Supplement 4, Individual Plant Examination of External E-163

Events (IPEEE) For Severe Accident Vulnerabilities -Submittal of Internal Fires Analysis, (TAC No. M83597)," dated July 11, 1997.

24. TVA Letter, T. E. Abney to NRC, "Browns Ferry Nuclear Plant (BFN) - Unit 1 -

Response to Request for Additional Information Related to Generic Letter 88-20, Individual Plant Examination for Severe Accident Vulnerability (TAC No. MC1895),

dated August 17, 2004.

E-164

APPENDIX A REVISED RS-001 TEMPLATE SAFETY EVALUATIONS

2.3.2 Offsite Power System Regulatory Evaluation The offsite power system includes two or more physically independent circuits capable of operating independently of the onsite standby power sources. The NRC staff's review covered the descriptive information, analyses, and referenced documents for the offsite power system; and the stability studies for the electrical transmission grid. The NRC staff's review focused on whether the loss of the nuclear unit, the largest operating unit on the grid, or the most critical transmission line will result in the loss of offsite power (LOOP) to the plant following implementation of the proposed EPU. The NRC's acceptance criteria for offsite power systems are based on GDC-17. Specific review criteria are contained in SRP Sections 8.1 and 8.2, Appendix A to SRP Section 8.2, and Branch Technical Positions (BTPs) PSB-1 and ICSB-1 1.

Technical Evaluation

[Insert technical evaluation. The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.]

Conclusion The NRC staff has reviewed the licensee's assessment of the effects of the proposed EPU on the offsite power system and concludes that the offsite power system will continue to meet the requirements of GDC-17 following implementation of the proposed EPU. Adequate physical and electrical separation exists and the offsite power system has the capacity and capability to supply power to all safety loads and other required equipment. The NRC staff further concludes that the impact of the proposed EPU on grid stability is insignificant.

Therefore, the NRC staff finds the proposed EPU acceptable with respect to the offsite power system.

INSERT 3 FOR SECTION 3.2 - BWR TEMPLATE SAFETY EVALUATION DECEMBER 2003

2.5.1.4 Fire Protection Regulatory Evaluation The purpose of the fire protection program (FPP) is to provide assurance, through a defense-in-depth design, that a fire will not prevent the performance of necessary safe plant shutdown functions and will not significantly increase the risk of radioactive releases to the environment. The NRC staff's review focused on the effects of the increased decay heat on the plant's safe shutdown analysis to ensure that SSCs required for the safe shutdown of the plant are protected from the effects of the fire and will continue to be able to achieve and maintain safe shutdown following a fire. The NRC's acceptance criteria for the FPP are based on (1) 10 CFR 50.48 and associated Appendix R to 10 CFR Part 50, insofar as they require the development of an FPP to ensure, among other things, the capability to safely shut down the plant; (2) GDC-3, insofar as it requires that (a) SSCs important to safety be designed and located to minimize the probability and effect of fires, (b) noncombustible and heat resistant materials be used, and (c) fire detection and fighting systems be provided and designed to minimize the adverse effects of fires on SSCs important to safety; (3) draft GDC-4, insofar as it requires that reactor facilities shall not share systems or components unless it is shown safety is not impaired by the sharing. Specific review criteria are contained in SRP Section 9.5.1, as supplemented by the guidance provided in Attachment 2 to Matrix 5 of Section 2.1 of RS-001.

Technical Evaluation

[Insert technical evaluation. The technical evaluation should (1) clearly explain why the proposed changes satisfy each of the requirements in the regulatory evaluation and (2) provide a clear link to the conclusions reached by the NRC staff, as documented in the conclusion section.]

Conclusion The NRC staff has reviewed the licensee's fire-related safe shutdown assessment and concludes that the licensee has adequately accounted for the effects of the increased decay heat on the-ability of the required systems to achieve and maintain safe shutdown conditions.

The NRC staff further concludes that the FPP will continue to meet the requirements of 10 CFR 50.48, Appendix R to 10 CFR Part 50, GDC-3, and draft GDC 4 following implementation of the proposed EPU. Therefore, the NRC staff finds the proposed EPU acceptable with respect to fire protection.

INSERT 5 FOR SECTION 3.2 - BWR TEMPLATE SAFETY EVALUATION DECEMBER 2003